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, 33240-33420 [2023-10141]
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Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed Rules
40 CFR Part 60
[EPA–HQ–OAR–2023–0072; FRL–8536–02–
OAR]
RIN 2060–AV09
New Source Performance Standards
for Greenhouse Gas Emissions From
New, Modified, and Reconstructed
Fossil Fuel-Fired Electric Generating
Units; Emission Guidelines for
Greenhouse Gas Emissions From
Existing Fossil Fuel-Fired Electric
Generating Units; and Repeal of the
Affordable Clean Energy Rule
Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
AGENCY:
In this document, the
Environmental Protection Agency (EPA)
is proposing five separate actions under
section 111 of the Clean Air Act (CAA)
addressing greenhouse gas (GHG)
emissions from fossil fuel-fired electric
generating units (EGUs). The EPA is
proposing revised new source
performance standards (NSPS), first for
GHG emissions from new fossil fuelfired stationary combustion turbine
EGUs and second for GHG emissions
from fossil fuel-fired steam generating
units that undertake a large
modification, based upon the 8-year
review required by the CAA. Third, the
EPA is proposing emission guidelines
for GHG emissions from existing fossil
fuel-fired steam generating EGUs, which
include both coal-fired and oil/gas-fired
steam generating EGUs. Fourth, the EPA
is proposing emission guidelines for
GHG emissions from the largest, most
frequently operated existing stationary
combustion turbines and is soliciting
comment on approaches for emission
guidelines for GHG emissions for the
remainder of the existing combustion
turbine category. Finally, the EPA is
proposing to repeal the Affordable Clean
Energy (ACE) Rule.
DATES: Comments. Comments must be
received on or before July 24, 2023.
Comments on the information collection
provisions submitted to the Office of
Management and Budget (OMB) under
the Paperwork Reduction Act (PRA) are
best assured of consideration by OMB if
OMB receives a copy of your comments
on or before June 22, 2023.
Public Hearing. The EPA will hold a
virtual public hearing on June 13, 2023
and June 14, 2023. See SUPPLEMENTARY
INFORMATION for information on
registering for a public hearing.
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SUMMARY:
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You may send comments,
identified by Docket ID No. EPA–HQ–
OAR–2023–0072, by any of the
following methods:
• Federal eRulemaking Portal:
https://www.regulations.gov (our
preferred method). Follow the online
instructions for submitting comments.
• Email: a-and-r-docket@epa.gov.
Include Docket ID No. EPA–HQ–OAR–
2023–0072 in the subject line of the
message.
• Fax: (202) 566–9744. Attention
Docket ID No. EPA–HQ–OAR–2023–
0072.
• Mail: U.S. Environmental
Protection Agency, EPA Docket Center,
Docket ID No. EPA–HQ–OAR–2023–
0072, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington,
DC 20460.
• Hand/Courier Delivery: EPA Docket
Center, WJC West Building, Room 3334,
1301 Constitution Avenue NW,
Washington, DC 20004. The Docket
Center’s hours of operation are 8:30
a.m.–4:30 p.m., Monday–Friday (except
Federal holidays).
Instructions: All submissions received
must include the Docket ID No. for this
rulemaking. Comments received may be
posted without change to https://
www.regulations.gov, including any
personal information provided. For
detailed instructions on sending
comments and additional information
on the rulemaking process, see the
SUPPLEMENTARY INFORMATION section of
this document.
FOR FURTHER INFORMATION CONTACT: For
questions about these proposed actions,
contact Mr. Christian Fellner, Sector
Policies and Programs Division (D243–
02), Office of Air Quality Planning and
Standards, U.S. Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711; telephone
number: (919) 541–4003; and email
address: fellner.christian@epa.gov or
Ms. Lisa Thompson, Sector Policies and
Programs Division (D243–02), Office of
Air Quality Planning and Standards,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina
27711; telephone number: (919) 541–
9775; and email address:
thompson.lisa@epa.gov.
SUPPLEMENTARY INFORMATION:
Participation in virtual public
hearing. The public hearing will be held
via virtual platform on June 13, 2023
and June 14, 2023 and will convene at
11:00 a.m. Eastern Time (ET) and
conclude at 7:00 p.m. ET each day. If
the EPA receives a high volume of
registrations for the public hearing, the
EPA may continue the public hearing on
June 15, 2023. On each hearing day, the
ADDRESSES:
ENVIRONMENTAL PROTECTION
AGENCY
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EPA may close a session 15 minutes
after the last pre-registered speaker has
testified if there are no additional
speakers. The EPA will announce
further details at https://www.epa.gov/
stationary-sources-air-pollution/
greenhouse-gas-standards-andguidelines-fossil-fuel-fired-power.
The EPA will begin pre-registering
speakers for the hearing no later than 1
business day following the publication
of this document in the Federal
Register. The EPA will accept
registrations on an individual basis. To
register to speak at the virtual hearing,
please use the online registration form
available at https://www.epa.gov/
stationary-sources-air-pollution/
greenhouse-gas-standards-andguidelines-fossil-fuel-fired-power or
contact the public hearing team at (888)
372–8699 or by email at
SPPDpublichearing@epa.gov. The last
day to pre-register to speak at the
hearing will be June 6, 2023. Prior to the
hearing, the EPA will post a general
agenda that will list pre-registered
speakers in approximate order at:
https://www.epa.gov/stationary-sourcesair-pollution/greenhouse-gas-standardsand-guidelines-fossil-fuel-fired-power.
The EPA will make every effort to
follow the schedule as closely as
possible on the day of the hearing;
however, please plan for the hearings to
run either ahead of schedule or behind
schedule.
Each commenter will have 4 minutes
to provide oral testimony. The EPA
encourages commenters to provide the
EPA with a copy of their oral testimony
by submitting the text of your oral
testimony as written comments to the
rulemaking docket.
The EPA may ask clarifying questions
during the oral presentations but will
not respond to the presentations at that
time. Written statements and supporting
information submitted during the
comment period will be considered
with the same weight as oral testimony
and supporting information presented at
the public hearing.
Please note that any updates made to
any aspect of the hearing will be posted
online at https://www.epa.gov/
stationary-sources-air-pollution/
greenhouse-gas-standards-andguidelines-fossil-fuel-fired-power. While
the EPA expects the hearing to go
forward as described in this section,
please monitor our website or contact
the public hearing team at (888) 372–
8699 or by email at
SPPDpublichearing@epa.gov to
determine if there are any updates. The
EPA does not intend to publish a
document in the Federal Register
announcing updates.
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Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed Rules
If you require the services of an
interpreter or a special accommodation
such as audio description, please preregister for the hearing with the public
hearing team and describe your needs
by May 30, 2023. The EPA may not be
able to arrange accommodations without
advanced notice.
Docket. The EPA has established a
docket for these rulemakings under
Docket ID No. EPA–HQ–OAR–2023–
0072. All documents in the docket are
listed in the Regulations.gov index.
Although listed in the index, some
information is not publicly available,
e.g., Confidential Business Information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the internet and will be publicly
available only in hard copy.
Written Comments. Direct your
comments to Docket ID No. EPA–HQ–
OAR–2023–0072 at https://
www.regulations.gov (our preferred
method), or the other methods
identified in the ADDRESSES section.
Once submitted, comments cannot be
edited or removed from the docket. The
EPA may publish any comment received
to its public docket. Do not submit to
the EPA’s docket at https://
www.regulations.gov any information
you consider to be Confidential
Business Information (CBI) or other
information whose disclosure is
restricted by statute. This type of
information should be submitted as
discussed in the Submitting CBI section
of this document.
Multimedia submissions (audio,
video, etc.) must be accompanied by a
written comment. The written comment
is considered the official comment and
should include discussion of all points
you wish to make. The EPA will
generally not consider comments or
comment contents located outside of the
primary submission (i.e., on the Web,
cloud, or other file sharing system).
Please visit https://www.epa.gov/
dockets/commenting-epa-dockets for
additional submission methods; the full
EPA public comment policy;
information about CBI or multimedia
submissions; and general guidance on
making effective comments.
The https://www.regulations.gov
website allows you to submit your
comment anonymously, which means
the EPA will not know your identity or
contact information unless you provide
it in the body of your comment. If you
send an email comment directly to the
EPA without going through https://
www.regulations.gov, your email
address will be automatically captured
and included as part of the comment
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that is placed in the public docket and
made available on the internet. If you
submit an electronic comment, the EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
digital storage media you submit. If the
EPA cannot read your comment due to
technical difficulties and cannot contact
you for clarification, the EPA may not
be able to consider your comment.
Electronic files should not include
special characters or any form of
encryption and should be free of any
defects or viruses.
Submitting CBI. Do not submit
information containing CBI to the EPA
through https://www.regulations.gov.
Clearly mark the part or all of the
information that you claim to be CBI.
For CBI information on any digital
storage media that you mail to the EPA,
note the docket ID, mark the outside of
the digital storage media as CBI, and
identify electronically within the digital
storage media the specific information
that is claimed as CBI. In addition to
one complete version of the comments
that includes information claimed as
CBI, you must submit a copy of the
comments that does not contain the
information claimed as CBI directly to
the public docket through the
procedures outlined in Written
Comments section of this document. If
you submit any digital storage media
that does not contain CBI, mark the
outside of the digital storage media
clearly that it does not contain CBI and
note the docket ID. Information not
marked as CBI will be included in the
public docket and the EPA’s electronic
public docket without prior notice.
Information marked as CBI will not be
disclosed except in accordance with
procedures set forth in 40 Code of
Federal Regulations (CFR) part 2.
Our preferred method to receive CBI
is for it to be transmitted electronically
using email attachments, File Transfer
Protocol (FTP), or other online file
sharing services (e.g., Dropbox,
OneDrive, Google Drive). Electronic
submissions must be transmitted
directly to the OAQPS CBI Office at the
email address oaqpscbi@epa.gov and, as
described above, should include clear
CBI markings and note the docket ID. If
assistance is needed with submitting
large electronic files that exceed the file
size limit for email attachments, and if
you do not have your own file sharing
service, please email oaqpscbi@epa.gov
to request a file transfer link. If sending
CBI information through the postal
service, please send it to the following
address: OAQPS Document Control
Officer (C404–02), OAQPS, U.S.
Environmental Protection Agency,
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Research Triangle Park, North Carolina
27711, Attention Docket ID No. EPA–
HQ–OAR–2023–0072. The mailed CBI
material should be double wrapped and
clearly marked. Any CBI markings
should not show through the outer
envelope.
Preamble acronyms and
abbreviations. Throughout this
document the use of ‘‘we,’’ ‘‘us,’’ or
‘‘our’’ is intended to refer to the EPA.
The EPA uses multiple acronyms and
terms in this preamble. While this list
may not be exhaustive, to ease the
reading of this preamble and for
reference purposes, the EPA defines the
following terms and acronyms here:
ACE Affordable Clean Energy rule
BACT best available control technology
BSER best system of emissions reduction
Btu British thermal unit
CAA Clean Air Act
CBI Confidential Business Information
CCS carbon capture and sequestration/
storage
CCUS carbon capture, utilization, and
sequestration/storage
CFR Code of Federal Regulations
CHP combined heat and power
CO2 carbon dioxide
CO2e carbon dioxide equivalent
CPP Clean Power Plan
CSAPR Cross-State Air Pollution Rule
DOE Department of Energy
DOI Department of the Interior
DOT Department of Transportation
EGU electric generating unit
EIA Energy Information Administration
EJ environmental justice
E.O. Executive Order
EOR enhanced oil recovery
EPA Environmental Protection Agency
FEED front-end engineering and design
FGD flue gas desulfurization
FR Federal Register
FrEDI Framework for Evaluating Damages
and Impacts
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GW gigawatt
HHV higher heating value
HRSG heat recovery steam generator
IBR incorporate by reference
ICR information collection request
IGCC integrated gasification combined
cycle
IIJA Infrastructure Investment and Jobs Act
IPCC Intergovernmental Panel on Climate
Change
IRC Internal Revenue Code
IRP integrated resource plan
kg kilogram
kWh kilowatt-hour
LCOE levelized cost of electricity
LHV lower heating value
LNG liquefied natural gas
MMBtu/hr million British thermal units per
hour
MMst million short tons
MMT CO2e million metric tons of carbon
dioxide equivalent
MW megawatt
MWh megawatt-hour
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NAAQS National Ambient Air Quality
Standards
NAICS North American Industry
Classification System
NCA4 2017–2018 Fourth National Climate
Assessment
NETL National Energy Technology
Laboratory
NGCC natural gas combined cycle
NOX nitrogen oxides
NREL National Renewable Energy
Laboratory
NSPS new source performance standards
NSR New Source Review
OMB Office of Management and Budget
PM particulate matter
PSD Prevention of Significant Deterioration
PUC public utilities commission
RIA regulatory impact analysis
RPS renewable portfolio standard
RTO Regional Transmission Organization
SCR selective catalytic reduction
SIP State Implementation Plan
U.S. United States
U.S.C. United States Code
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Organization of this document. The
information in this preamble is
organized as follows:
I. Executive Summary
A. Climate Change and the Power Sector
B. Overview of the Proposals
C. Recent Developments in Emissions
Controls and the Electric Power Sector
D. How the EPA Considered
Environmental Justice in the
Development of These Proposals
II. General Information
A. Action Applicability
B. Where to Get a Copy of This Document
and Other Related Information
C. Organization and Approach for These
Proposed Rules
III. Climate Change and Its Impacts
IV. Recent Developments in Emissions
Controls and the Electric Power Sector
A. Introduction
B. Background
C. CCS
D. Natural Gas Co-Firing
E. Hydrogen Co-Firing
F. Recent Changes in the Power Sector
G. GHG Emissions From Fossil Fuel-Fired
EGUs
H. The Legislative, Market, and State Law
Context
I. Projections of Power Sector Trends
V. Statutory Background and Regulatory
History for CAA Section 111
A. Statutory Authority To Regulate GHGs
From EGUs Under CAA Section 111
B. History of EPA Regulation of
Greenhouse Gases From Electricity
Generating Units Under CAA Section
111 and Caselaw
C. Detailed Discussion of CAA Section 111
Requirements
VI. Stakeholder Engagement
VII. Proposed Requirements for New and
Reconstructed Stationary Combustion
Turbine EGUs and Rationale for
Proposed Requirements
A. Overview
B. Combustion Turbine Technology
C. Overview of Regulation of Stationary
Combustion Turbines for GHGs
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D. Eight-Year Review of NSPS
E. Applicability Requirements and
Subcategorization
F. Determination of the Best System of
Emission Reduction (BSER) for New and
Reconstructed Stationary Combustion
Turbines
G. Proposed Standards of Performance
H. Reconstructed Stationary Combustion
Turbines
I. Modified Stationary Combustion
Turbines
J. Startup, Shutdown, and Malfunction
K. Testing and Monitoring Requirements
L. Mechanisms To Ensure Use of Actual
Low-GHG Hydrogen
M. Recordkeeping and Reporting
Requirements
N. Additional Solicitations of Comment
and Proposed Requirements
O. Compliance Dates
VIII. Requirements for New, Modified, and
Reconstructed Fossil Fuel-Fired Steam
Generating Units
A. 2018 NSPS Proposal
B. Eight-Year Review of NSPS for Fossil
Fuel-Fired Steam Generating Units
C. Projects Under Development
IX. Proposed ACE Rule Repeal
A. Summary of Selected Features of the
ACE Rule
B. Developments Undermining ACE Rule’s
Projected Emission Reductions
C. Developments Showing That Other
Technologies are the BSER for This
Source Category
D. Insufficiently Precise Degree of
Emission Limitation Achievable From
Application of the BSER
E. ACE Rule’s Preclusion of Emissions
Trading or Averaging
X. Proposed Regulatory Approach for
Existing Fossil Fuel-Fired Steam
Generating Units
A. Overview
B. Applicability Requirements for Existing
Fossil Fuel-Fired Steam Generating Units
C. Subcategorization of Fossil Fuel-Fired
Steam Generating Units
D. Determination of BSER for Coal-Fired
Steam Generating Units
E. Natural Gas-Fired and Oil-Fired Steam
Generating Units
F. Summary
XI. Proposed Regulatory Approach for
Emission Guidelines for Existing Fossil
Fuel-fired Stationary Combustion
Turbines
A. Overview
B. The Existing Stationary Combustion
Turbine Fleet
C. BSER for Base Load Turbines Over 300
MW
D. Areas That the EPA is Seeking Comment
on Related to Existing Combustion
Turbines
E. BSER for Remaining Combustion
Turbines
XII. State Plans for Proposed Emission
Guidelines for Existing Fossil Fuel-Fired
EGUs
A. Overview
B. Compliance Deadlines
C. Requirement for State Plans To Maintain
Stringency of the EPA’s BSER
Determination
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D. Establishing Standards of Performance
E. Compliance Flexibilities
F. State Plan Components and Submission
XIII. Implications for Other EPA Programs
A. Implications for New Source Review
(NSR) Program
B. Implications for Title V Program
XIV. Impacts of Proposed Actions
A. Air Quality Impacts
B. Compliance Cost Impacts
C. Economic and Energy Impacts
D. Benefits
E. Environmental Justice Analytical
Considerations and Stakeholder
Outreach and Engagement
F. Grid Reliability Considerations
XV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act of 1995
(UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks Populations and
Low-Income Populations
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and
Advancement Act (NTTAA) and 1 CFR
Part 51
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
Executive Summary
In 2009, the EPA concluded that GHG
emissions endanger our nation’s public
health and welfare.1 Since that time, the
evidence of the harms posed by GHG
emissions has only grown and
Americans experience the destructive
and worsening effects of climate change
every day. Fossil fuel-fired EGUs are the
nation’s largest stationary source of
GHG emissions, representing 25 percent
of the United States’ total GHG
emissions in 2020. At the same time, a
range of cost-effective technologies and
approaches to reduce GHG emissions
from these sources are available to the
power sector, and multiple projects are
in various stages of operation and
development—including carbon capture
and sequestration/storage (CCS) and cofiring with lower-GHG fuels. Congress
has also acted to provide funding and
other incentives to encourage the
deployment of these technologies to
1 74
FR 66496 (December 15, 2009).
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achieve reductions in GHG emissions
from the power sector.
In this document, the EPA is
proposing several actions under section
111 of the Clean Air Act (CAA) to
reduce the significant quantity of GHG
emissions from new and existing fossil
fuel-fired EGUs by establishing new
source performance standards (NSPS)
and emission guidelines that are based
on available and cost-effective
technologies that directly reduce GHG
emissions from these sources.
Consistent with the statutory command
of section 111, the proposed NSPS and
emission guidelines reflect the
application of the best system of
emission reduction (BSER) that, taking
into account costs, energy requirements,
and other statutory factors, is adequately
demonstrated.
Specifically, the EPA is proposing to
update and establish more protective
NSPS for GHG emissions from new and
reconstructed fossil fuel-fired stationary
combustion turbine EGUs that are based
on highly efficient generating practices,
hydrogen co-firing, and CCS. The EPA
is also proposing to establish new
emission guidelines for existing fossil
fuel-fired steam generating EGUs that
reflect the application of CCS and the
availability of natural gas co-firing. The
EPA is simultaneously proposing to
repeal the Affordable Clean Energy
(ACE) rule because the emission
guidelines established in ACE do not
reflect the BSER for steam generating
EGUs and are inconsistent with section
111 of the CAA in other respects. To
address GHG emissions from existing
fossil fuel-fired stationary combustion
turbines, the EPA is proposing emission
guidelines for large and frequently used
existing stationary combustion turbines.
Further, the EPA is soliciting comment
on how the Agency should approach its
legal obligation to establish emission
guidelines for the remaining existing
fossil fuel-fired combustion turbines not
covered by this proposal, including
smaller frequently used, and less
frequently used, combustion turbines.
Each of the NSPS and emission
guidelines proposed here would ensure
that EGUs reduce their GHG emissions
in a manner that is cost-effective and
improves the emissions performance of
the sources, consistent with the
applicable CAA requirements and
caselaw. These proposed standards and
emission guidelines, if finalized, would
significantly decrease GHG emissions
from fossil fuel-fired EGUs and the
associated harms to human health and
welfare. Further, the EPA has designed
these proposed standards and emission
guidelines in a way that is compatible
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with the nation’s overall need for a
reliable supply of affordable electricity.
A. Climate Change and the Power Sector
These proposals focus on reducing the
emissions of GHGs from the power
sector. The increasing concentrations of
GHGs in the atmosphere are, and have
been, warming the planet, resulting in
serious and life-threatening
environmental and human health
impacts. The increased concentrations
of GHGs in the atmosphere and the
resulting warming have led to more
frequent and more intense heat waves
and extreme weather events, rising sea
levels, and retreating snow and ice, all
of which are occurring at a pace and
scale that threatens human welfare.
The power sector in the United States
(U.S.) is both a key contributor to the
cause of climate change and a key
component of the solution to the climate
challenge. In 2020, the power sector was
the largest stationary source of GHGs,
emitting 25 percent of the overall
domestic emissions.2 These emissions
are almost entirely the result of the
combustion of fossil fuels in the EGUs
that are the subjects of these proposals.
The power sector possesses many
opportunities to contribute to solutions
to the climate challenge. Particularly
relevant to these proposals are several
key technologies (co-firing of low-GHG
fuels and CCS) that can allow steam
generating EGUs and stationary
combustion turbines (the focus of these
proposals) to provide power while
emitting significantly lower GHG
emissions. Moreover, with the increased
electrification of other GHG-emitting
sectors of the economy, such as personal
vehicles, heavy-duty trucks, and the
heating and cooling of buildings, a
power sector with lower GHG emissions
can also help reduce pollution coming
from other sectors of the economy.
B. Overview of the Proposals
As noted above, these actions include
proposed BSER determinations and
accompanying standards of performance
for GHG emissions from new and
reconstructed fossil fuel-fired stationary
combustion turbines, proposed repeal of
the ACE Rule, proposed BSER
determinations and emission guidelines
for existing fossil fuel-fired steam
generating units, proposed BSER
determinations and emission guidelines
for large, frequently used existing fossil
fuel-fired stationary combustion
turbines, and solicitation for comment
on potential BSER options and emission
guidelines for existing fossil fuel-fired
2 https://www.epa.gov/ghgemissions/sourcesgreenhouse-gas-emissions.
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33243
stationary combustion turbines not
otherwise covered by the proposal.
The EPA is taking these actions
consistent with the process that CAA
section 111 establishes. Under CAA
section 111, once the EPA has identified
a source category that emits dangerous
air pollutants, it proceeds to regulate
new sources and, for GHGs and certain
other air pollutants, existing sources.
The central requirement is that the EPA
must determine the ‘‘best system of
emission reduction . . . adequately
demonstrated,’’ taking into account the
cost of the reductions, non-air quality
health and environmental impacts, and
energy requirements. CAA section
111(a)(1). The EPA may determine that
different sets of sources have different
characteristics relevant for determining
the BSER and may subcategorize
sources accordingly.
Once it determines the BSER, the EPA
must determine the ‘‘degree of emission
limitation’’ achievable by application of
the BSER. For new sources, the EPA
determines the standard of performance
with which the sources must comply,
which is a standard for emissions that
reflects the degree of emission
limitation. For existing sources, the EPA
includes the information it has
developed concerning the BSER and
associated degree of emission limitation
into emission guidelines and directs the
states to adopt State plans that contain
standards of performance that are
consistent with the emission guidelines.
Since the early 1970s, the EPA has
promulgated regulations under section
111 for more than 60 source categories,
which has established a robust
regulatory history. During this period,
the courts, primarily the U.S. Court of
Appeals for the D.C. Circuit and the
Supreme Court, have developed a body
of caselaw interpreting section 111. As
the Supreme Court has recognized, in
these CAA section 111 actions, the EPA
has determined the BSER to be
‘‘measures that improve the pollution
performance of individual sources,’’
including add-on controls and clean
fuels. West Virginia v. EPA, 142 S. Ct.
2587, 2614 (2022). For present purposes,
several of a BSER’s key features include
that costs of controls must be
reasonable, that the EPA may determine
a control to be ‘‘adequately
demonstrated’’ even if it is new and not
yet in widespread commercial use, and,
further, that the EPA may reasonably
project the development of a control
system at a future time and establish
requirements that take effect at that
time. The actions that the EPA is
proposing are consistent with the
requirements of CAA section 111 and its
regulatory history and caselaw.
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1. New and Reconstructed Fossil FuelFired Combustion Turbines
For new and reconstructed fossil fuelfired combustion turbines, the EPA is
proposing to create three subcategories
based on the function the combustion
turbine serves: a low load (‘‘peaking
units’’) subcategory that consists of
combustion turbines with a capacity
factor of less than 20 percent; an
intermediate load subcategory for
combustion turbines with a capacity
factor that ranges between 20 percent
and a source-specific upper bound that
is based on the design efficiency of the
combustion turbine; and a base load
subcategory for combustion turbines
that operate above the upper-bound
threshold for intermediate load turbines.
This subcategorization approach is
similar to the current NSPS for these
sources, which includes separate
subcategories for base load and non-base
load units; however, the EPA is now
proposing to subdivide the non-base
load subcategory into a low load
subcategory and a separate intermediate
load subcategory. This revised approach
to subcategories is consistent with the
fact that utilities and power plant
operators are building new combustion
turbines with plans to operate them at
varying levels of capacity, in
coordination with existing and expected
energy sources. These patterns of
operation are important for the type of
controls that the EPA is proposing as the
BSER for these turbines, in terms of the
feasibility of, emissions reductions that
would be achieved by, and costreasonableness of, those controls.
For the low load subcategory, the EPA
is proposing that the BSER is the use of
lower emitting fuels (e.g., natural gas
and distillate oil) with standards of
performance ranging from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu,
depending on the type of fuel
combusted.3 For the intermediate load
and base load subcategories, the EPA is
proposing an approach in which the
BSER has multiple components: (1)
Highly efficient generation; and (2)
depending on the subcategory, use of
CCS or co-firing low-GHG hydrogen.
These components of the BSER for the
intermediate and base load
subcategories form the basis of a
standard of performance that applies in
multiple phases. That is, affected
facilities—which are facilities that
3 In the 2015 NSPS, the EPA referred to clean
fuels as fuels with a consistent chemical
composition (i.e., uniform fuels) that result in a
consistent emission rate of 69 kilograms per
gigajoule (kg/GJ) (160 lb CO2/MMBtu). Fuels in this
category include natural gas and distillate oil. In
this rulemaking, the EPA refers to these fuels as
both lower emitting fuels or uniform fuels.
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commence construction or
reconstruction after the date of
publication in the Federal Register of
this proposed rulemaking—must meet
the first phase of the standard of
performance, which is based exclusively
on application of the first component of
the BSER (highly efficient generation),
by the date the rule is promulgated.
Affected sources in the intermediate
load and base load subcategories must
also meet the second and in some cases
third and more stringent phases of the
standard of performance, which are
based on the continued application of
the first component of the BSER and the
application of the second and in some
cases third component of the BSER. For
base load units, the EPA is proposing
two pathways as potential BSER—(1)
the use of CCS to achieve a 90 percent
capture of GHG emissions by 2035 and
(2) the co-firing of 30 percent (by
volume) low-GHG hydrogen by 2032,
and ramping up to 96 percent by
volume low-GHG hydrogen by 2038.
These two BSER pathways both offer
significant opportunities to reduce GHG
emissions but, may be available on
slightly different timescales. Depending
upon the phase in periods for both CCS
and hydrogen, the CCS pathway could
provide greater cumulative emission
reductions than the low GHG hydrogen
pathway. The EPA seeks comment
specifically upon the percentages of
hydrogen co-firing and CO2 capture as
well as the dates that meet the statutory
BSER criteria for each pathway. The
EPA solicits comment on the differences
in emissions reductions in both scale
and time that would result from the two
standards and BSER pathways,
including how to calculate the different
amounts of emission reductions, how to
compare them, and what conclusions to
draw from those differences. The EPA
also seeks comment on whether the
Agency should finalize both pathways
as separate subcategories with separate
standards of performance, or whether it
should finalize one pathway with the
option of meeting the standard of
performance using either system of
emission reduction, e.g., a single
standard based on application of CCS
with 90 percent capture, which could
also be met by co-firing 96 percent (by
volume) low-GHG hydrogen.
It should be noted that utilization of
highly efficient generation is a logical
complement to both CCS and co-firing
of low-GHG hydrogen because, from
both an economic and emissions
perspective, that configuration will
provide the greatest reductions at the
lowest cost. This approach reflects the
EPA’s view that the BSER for the
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intermediate load and base load
subcategories should reflect the deeper
reductions in GHG emissions that can
be achieved by implementing CCS and
co-firing low-GHG hydrogen with the
most efficient stationary combustion
turbine configuration available.
However, in proposing that compliance
begins in 2032 (for co-firing with lowGHG hydrogen) and 2035 (for use of
CCS), the EPA recognizes that building
the infrastructure required to support
wider use of CCS and qualified lowGHG hydrogen in the power sector will
take place on a multi-year time scale.
More specifically, with respect to the
first phase of the standards of
performance, the EPA is proposing that
the BSER for both the intermediate load
and base load subcategories includes
highly efficient generating technology
(i.e., the most efficient available
turbines). For the intermediate load
subcategory, the EPA is proposing that
the BSER includes highly efficient
simple cycle combustion turbine
technology with an associated first
phase standard of 1,150 lb CO2/MWhgross. For the base load subcategory, the
EPA is proposing that the BSER
includes highly efficient combined
cycle technology with an associated first
phase standard of 770 lb CO2/MWhgross for larger combustion turbine
EGUs with a base load rating of 2,000
MMBtu/h or more. For smaller base load
combustion turbines (with a base load
rating of less than 2,000 MMBtu/h), the
proposed associated standard would
range from 770 to 900 lb CO2/MWhgross depending on the specific base
load rating of the combustion turbine.
These standards would apply
immediately upon the effective date of
the final rule.
With respect to the second phase of
the standards of performance, for the
intermediate load subcategory, the EPA
is proposing that the BSER includes cofiring 30 percent by volume low-GHG
hydrogen (unless otherwise noted, all
co-firing hydrogen percentages are on a
volume basis) with an associated
standard of 1,000 lb CO2/MWh-gross,
compliance with which would be
required starting in 2032. For the base
load subcategory, to elicit comment on
both pathways, the EPA is proposing to
subcategorize further into base load
units that are adopting the CCS pathway
and base load units that are adopting the
low-GHG hydrogen co-firing pathway.
For the subcategory of base load units
that are adopting the CCS pathway, the
EPA is proposing that the BSER
includes the use of CCS with 90 percent
capture of CO2 with an associated
standard of 90 lb CO2/MWh-gross,
compliance with which would be
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required starting in 2035. For the
subcategory of base load units that are
adopting the low-GHG hydrogen cofiring pathway, the EPA is proposing
that the BSER includes co-firing 30
percent (by volume) low-GHG hydrogen
with an associated standard of 680 lb
CO2/MWh-gross, compliance with
which would be required starting in
2032, and co-firing 96 percent (by
volume) low-GHG hydrogen by 2038,
which corresponds to a standard of
performance of 90 lb CO2/MWh-gross.
In both cases, the second (and
sometimes third) phase standard of
performance would be applicable to all
combustion turbines that were subject to
the first phase standards of
performance.
Existing and Modified Fossil Fuel-Fired
Steam Generating Units and ACE Repeal
With respect to existing coal-fired
steam generating units, the EPA is
proposing to repeal and replace the
existing ACE Rule emission guidelines.
The EPA recognizes that, since it
promulgated the ACE Rule, the costs of
CCS have decreased due to technology
advancements as well as new policies
including the expansion of the Internal
Revenue Code section 45Q tax credit for
CCS in the Inflation Reduction Act
(IRA); and the costs of natural gas cofiring have decreased as well, due in
large part to a decrease in the difference
between coal and natural gas prices. As
a result, the EPA considered both CCS
and natural gas co-firing as candidates
for BSER for existing coal-fired steam
EGUs.
Based on the latest information
available to the Agency on cost,
emission reductions, and other statutory
criteria, the EPA is proposing that the
BSER for existing coal-fired steam EGUs
that expect to operate in the long-term
is CCS with 90 percent capture of CO2.
The EPA has determined that CCS
satisfies the BSER criteria for these
sources because it is adequately
demonstrated, achieves significant
reductions in GHG emissions, and is
highly cost-effective.
Although the EPA considers CCS to
be a broadly applicable BSER, the
Agency also recognizes that CCS will be
most cost-effective for existing steam
EGUs that are in a position to recover
the capital costs associated with CCS
over a sufficiently long period of time.
During the early engagement process
(see Docket ID No. EPA–HQ–OAR–
2022–0723–0024), industry stakeholders
requested that the EPA ‘‘[p]rovide
approaches that allow for the retirement
of units as opposed to investments in
new control technologies, which could
prolong the lives of higher-emitting
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EGUs; this will achieve maximum and
durable environmental benefits.’’
Industry stakeholders also suggested
that the EPA recognize that some units
may remain operational for a severalyear period but will do so at limited
capacity (in part to assure reliability),
and then voluntarily cease operations
entirely (see Docket ID No. EPA–HQ–
OAR–2022–0723–0029).
In response to this industry
stakeholder input and recognizing that
the cost effectiveness of controls
depends on the unit’s expected
operating time horizon, which dictates
the amortization period for the capital
costs of the controls, the EPA believes
it is appropriate to establish
subcategories of existing steam EGUs
that are based on the operating horizon
of the units. The EPA is proposing that
for units that expect to operate in the
long-term (i.e., those that plan to operate
past December 31, 2039), the BSER is
the use of CCS with 90 percent capture
of CO2 with an associated degree of
emission limitation of an 88.4 percent
reduction in emission rate (lb CO2/
MWh-gross basis). As explained in
detail in this proposal, CCS with 90
percent capture of CO2 is adequately
demonstrated, cost reasonable, and
achieves substantial emissions
reductions from these units.
The EPA is proposing to define coalfired steam generating units with
medium-term operating horizons as
those that (1) Operate after December
31, 2031, (2) have elected to commit to
permanently cease operations before
January 1, 2040, (3) elect to make that
commitment federally enforceable and
continuing by including it in the State
plan, and (4) do not meet the definition
of near-term operating horizon units.
For these medium-term operating
horizon units, the EPA is proposing that
the BSER is co-firing 40 percent natural
gas on a heat input basis with an
associated degree of emission limitation
of a 16 percent reduction in emission
rate (lb CO2/MWh-gross basis). While
this subcategory is based on a 10-year
operating horizon (i.e., January 1, 2040),
the EPA is specifically soliciting
comment on the potential for a different
operating horizon between 8 and 10
years to define the threshold date
between the definition of medium-term
and long-term coal-fired steam
generating units (i.e., January 1, 2038 to
January 1, 2040), given that the costs for
CCS may be reasonable for units with
amortization periods as short as 8 years.
For units with operating horizons that
are imminent-term, i.e., those that (1)
Have elected to commit to permanently
cease operations before January 1, 2032,
and (2) elect to make that commitment
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33245
federally enforceable and continuing by
including it in the State plan, the EPA
is proposing that the BSER is routine
methods of operation and maintenance
with an associated degree of emission
limitation of no increase in emission
rate (lb CO2/MWh-gross basis). The EPA
is proposing the same BSER
determination for units in the near-term
operating horizon subcategory, i.e.,
units that (1) Have elected to commit to
permanently cease operations by
December 31, 2034, as well as to adopt
an annual capacity factor limit of 20
percent, and (2) elect to make both of
these conditions federally enforceable
by including them in the State plan. The
EPA is also soliciting comment on a
potential BSER based on low levels of
natural gas co-firing for units in these
last two subcategories.
The EPA is not proposing to revise the
NSPS for newly constructed or
reconstructed fossil fuel-fired steam
generating units, which it promulgated
in 2015 (80 FR 64510; October 23,
2015). This is because the EPA does not
anticipate that any such units will
construct or reconstruct and is unaware
of plans by any companies to construct
or reconstruct a new coal-fired EGU.
The EPA is proposing to revise the
standards of performance that it
promulgated in the same 2015 action for
coal-fired steam generators that
undertake a large modification (i.e., a
modification that increases its hourly
emission rate by more than 10 percent)
to mirror the emissions guidelines,
discussed below, for existing coal-fired
steam generators. This will ensure that
all existing fossil fuel-fired steam
generating sources are subject to the
emission controls whether they modify
or not.
The EPA is also proposing emission
guidelines for existing natural gas-fired
and oil-fired steam generating units.
Recognizing that virtually all of these
units have limited operation, the EPA is,
in general, proposing that the BSER is
routine methods of operation and
maintenance with an associated degree
of emission limitation of no increase in
emission rate (lb CO2/MWh-gross).
3. Existing Fossil Fuel-Fired Stationary
Combustion Turbines
The EPA is also proposing emission
guidelines for large (i.e., greater than
300 MW), frequently operated (i.e., with
a capacity factor of greater than 50
percent), existing fossil fuel-fired
stationary combustion turbines. Because
these existing combustion turbines are
similar to new stationary combustion
turbines, the EPA is proposing a BSER
that is similar to the BSER for new base
load combustion turbines. The EPA is
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not proposing a first phase efficiencybased standard of performance; but the
EPA is proposing that BSER for these
units is based on either the use of CCS
by 2035 or co-firing of 30 percent (by
volume) low-GHG hydrogen by 2032
and co-firing 96 percent low-GHG
hydrogen by 2038.
For the emission guidelines for
existing fossil fuel-fired steam
generating units and large, frequently
operated fossil fuel-fired combustion
turbines, the EPA is also proposing State
plan requirements, including submittal
timelines for State plans and
methodologies for determining
presumptively approvable standards of
performance consistent with BSER. This
proposal also addresses how states can
implement the remaining useful life and
other factors (RULOF) provision of CAA
section 111(d) and how states can
conduct meaningful engagement with
impacted stakeholders. Finally, the EPA
is proposing to allow states to include
trading or averaging in State plans so
long as they demonstrate equivalent
emissions reductions, and this proposal
discusses considerations related to the
appropriateness of including such
compliance flexibilities.
Finally, the EPA is soliciting
comment on a number of variations to
the subcategories and BSER
determinations, as well as the associated
degrees of emission limitation and
standards of performance, summarized
above. The EPA is soliciting comment
on the capacity and capacity factor
threshold for inclusion in the
subcategory of large, frequently operated
turbines (e.g., capacities between 100
MW and 300 MW for the capacity
threshold and a lower capacity factor
threshold (e.g., 40 percent). The EPA is
also soliciting comment on BSER
options and associated degrees of
emission limitation for existing fossil
fuel-fired stationary combustion
turbines for which no BSER is being
proposed (i.e., fossil fuel-fired stationary
combustion turbines that are not large,
frequently operated turbines).
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C. Recent Developments in Emissions
Controls and the Electric Power Sector
Several recent developments
concerning emissions controls and the
state of the electric power sector are
relevant for the EPA’s determination of
the BSER for existing coal-fired steam
generating EGUs and natural gas-fired
combustion turbines. These include
developments that have led to
significant reductions in the cost of
CCS; expected increases in the
availability and expected reductions in
the cost of low-GHG hydrogen; and
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announced and planned retirements of
coal-fired power plants.
In recent years, the cost of CCS has
declined in part because of process
improvements learned from earlier
deployments of CCS and other
advances. In addition, the IRA, enacted
in 2022, extended and significantly
increased the tax credit for CCS under
Internal Revenue Code (IRC) section
45Q. As explained in detail in the BSER
discussions later in this preamble, these
changes support the EPA’s proposed
conclusion that CCS is the BSER for a
number of subcategories in these
proposals.
In addition, in both the Infrastructure
Investment and Jobs Act (IIJA), enacted
in 2021, and the IRA, Congress provided
extensive support for the development
of hydrogen produced through low-GHG
methods. This support includes
investment in infrastructure through the
IIJA and the provision of tax credits in
the IRA to incentivize the manufacture
of hydrogen through low GHG-emitting
methods. These changes also support
the EPA’s proposal that co-firing lowGHG hydrogen is BSER for certain
subcategories of stationary combustion
turbines.
The IIJA and IRA have also been part
of the reason why many utilities and
power generating companies have
recently announced plans to change the
mix of their generating assets. State
legislation, technology advancements,
market forces, consumer demand, and
the fact that the existing fossil fuel-fired
fleet is aging are also leading to, in most
cases, decreased use of the fossil fuelfired units that are the subjects of these
proposals. Between 2010 and 2021,
fossil fuel-fired generation declined
from approximately 70 percent of total
net generation to approximately 60
percent, with coal generation dropping
from 46 percent to 23 percent of net
generation during the period.
Many utilities and power generating
companies have announced GHG
reduction commitments as they further
analyze and consider the incentives of
the IRA. These utilities and companies
have also announced their intention to
permanently cease operating many of
their remaining coal-fired EGUs. Some
companies are planning to install
combustion turbines with advanced
technologies to limit GHG emissions,
including CCS and hydrogen co-firing 4
(with some companies having
announced plans to ultimately move to
4 See section VII.F.3.b of this preamble for
discussion of CCS demonstrations and section
VII.F.3.c for discussion of hydrogen co-firing
demonstrations. Also see the GHG Mitigation
Measures for Steam Generating Units TSD included
in the rulemaking docket for this proposal.
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100 percent hydrogen firing) and
advanced energy storage technologies.
As more renewables come online and as
these technologies become more widely
deployed, the utilization of natural gasfired combustion turbine EGUs will be
impacted. The EPA’s post-IRA 2022
reference case modeling projects lower
utilization relative to current levels of
stationary combustion turbines.
The power sector has also been
influenced by the actions of State
governments to reduce GHG emissions.
More than two-thirds of states have
enacted policies to require utilities to
increase the amount of electricity
generated from sources that emit no
GHGs. Other states have recently
enacted significant legislation requiring
the decarbonization of their utility
fleets, using devices such as carbon
markets, low-GHG emission standards,
carbon capture and storage mandates,
utility planning, or mandatory
retirement schedules.
Additionally, Congress has recently
enacted investments in GHG reductions.
As noted earlier, Congress enacted IRC
section 45Q by section 115 of the Energy
Improvement and Extension Act of
2008, to provide a credit for the
sequestration of CO2; IRC section 45Q
was amended significantly by the
Bipartisan Budget Act of 2018 and most
recently by the IRA. The IIJA provided
more than $65 billion for infrastructure
investments and upgrades for
transmission capacity, pipelines, and
low-carbon fuels (including low-GHG
hydrogen, as noted above). In addition,
the Creating Helpful Incentives to
Produce Semiconductors and Science
Act (CHIPS Act) authorized billions
more in funding for development of
low- and non-GHG emitting energy
technologies that will provide
additional low-cost options for power
companies to reduce overall GHG
emissions.5
Finally, the EPA has carefully
considered the importance of
maintaining resource adequacy and grid
reliability in developing these proposals
and is confident that these proposed
NSPS and emission guidelines—with
the extensive lead time and compliance
flexibilities they provide—can be
successfully implemented in a manner
that preserves the ability of power
companies and grid operators to
maintain the reliability of the nation’s
electric power system. The EPA has
evaluated the reliability implications of
the proposal in the Resource Adequacy
Analysis TSD; conducted dispatch
modeling of the proposed NSPS and
5 https://www.congress.gov/bill/117th-congress/
house-bill/4346.
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proposed emission guidelines in a
manner that takes into account resource
adequacy needs; and consulted with the
DOE and the Federal Energy Regulatory
Commission (FERC) in the development
of these proposals. Moreover, the EPA
has included in these proposals the
flexibility that power companies and
grid operators need to plan for achieving
feasible and necessary reductions of
GHGs from these sources consistent
with the EPA’s statutory charge while
ensuring grid reliability. Furthermore,
the EPA is soliciting comment on
localized impacts of these proposals on
resource adequacy and reliability, and
on opportunities to enhance reliable
integration of the proposals into the
power system.
D. How the EPA Considered
Environmental Justice in the
Development of These Proposals
Consistent with E.O. 12898, E.O.
13985 and the EPA’s commitment to
upholding environmental justice across
its policies and programs, the EPA
carefully considered the impacts of
these proposals on communities with
potential environmental justice
concerns. As part of its pre-proposal
outreach to stakeholders, the EPA
engaged on multiple occasions with
environmental justice organizations and
representatives of communities that are
affected by various forms of pollution
from the power sector. The EPA took
this feedback and analysis into account
in its development of these proposals.
The EPA’s consideration of
environmental justice in these proposals
is briefly summarized here and
discussed in further detail in sections
XIV.E and XV.J of the preamble and
section 6 of the RIA.
These proposals are focused on
establishing NSPS and emission
guidelines for GHGs, and these
proposed actions will, in conjunction
with other policies such as the IRA, play
a significant role in reducing GHGs and
move us a step closer to avoiding the
worst impacts of climate change, which
is already having a disproportionate
impact on EJ communities. Beyond the
GHG reductions, the EPA also has
conducted a thorough evaluation of the
impacts that these proposals would
have on emissions of other healthharming air pollutants from EGUs, as
well as how these changes in emissions
would affect air quality and public
health, particularly for historically
overburdened populations including
people of color, indigenous peoples, and
people with low incomes.
The EPA’s national-level analysis of
emission reduction and public health
impacts, which is documented in
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sections 3 and 4 of the RIA and
summarized in greater detail in section
XIV.A and XIV.D of this preamble, finds
that these proposals would achieve
nationwide reductions in EGU
emissions of multiple health-harming
air pollutants including nitrogen oxides
(NOX), sulfur dioxide (SO2), and fine
particulate matter (PM2.5). These
reductions in health-harming pollution
would result in significant public health
benefits including avoided premature
deaths, reductions in new asthma cases
and incidences of asthma symptoms,
reductions in hospital admissions and
emergency department visits, and
reductions in lost work and school days.
The EPA has also evaluated how the
air quality impacts associated with these
proposals would be distributed, with
particular focus on potentially
vulnerable populations. As discussed in
section 6 of the RIA, these proposals are
anticipated to lead to modest but
widespread reductions in ambient levels
of PM2.5 for a large majority of the
nation’s population, as well as
reductions in ambient PM2.5 exposures
that are similar in magnitude across all
racial, ethnic, income and linguistic
groups. Similarly, the EPA found that
the proposed standards are anticipated
to lead to modest but widespread
reductions in ambient levels of groundlevel ozone for the majority of the
nation’s population, and that in all but
one of the years evaluated the proposed
standards would lead to reductions in
ambient ozone exposures across all
demographic groups. Although these
reductions in PM2.5 and ozone
exposures are small relative to baseline
levels, and although disparities in PM2.5
and ozone exposure would continue to
persist following these proposals, the
EPA’s analysis indicates that the air
quality benefits of these proposals
would be broadly distributed.
Where authorized under section 111
of the Clean Air Act, the EPA has also
incorporated provisions in these
proposals to better address the needs
and concerns of communities with
environmental justice concerns.
Specifically, the EPA’s proposed
emission guidelines for existing steam
EGUs as well as existing fossil fuel-fired
stationary combustion turbines would
require states to undertake meaningful
engagement with affected stakeholders,
including communities that are most
affected by and vulnerable to emissions
from these EGUs. These meaningful
engagement requirements are intended
to ensure that the perspectives,
priorities, and concerns of affected
communities are included in the
process of establishing and
implementing standards of performance
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33247
for existing EGUs, including decisions
about compliance strategies and
compliance flexibilities that may be
included in a State plan.
In the Agency’s pre-proposal
outreach, some environmental justice
organizations and community
representatives raised strongly held
concerns about the potential health,
environmental, and safety impacts of
CCS. The EPA believes that deployment
of CCS can take place in a manner that
is protective of public health, safety,
and the environment, and should
include early and meaningful
engagement with affected communities
and the public. As stated in the Council
on Environmental Quality’s (CEQ)
February 2022 Carbon Capture,
Utilization, and Sequestration
Guidance, ‘‘the successful widespread
deployment of responsible CCUS will
require strong and effective permitting,
efficient regulatory regimes, meaningful
public engagement early in the review
and deployment process, and measures
to safeguard public health and the
environment.’’ See 87 FR 8808
(February 16, 2022).
The EPA gave close consideration to
these concerns as it developed its
proposed determinations on the BSER
for these proposed NSPS and emission
guidelines, and addresses certain of the
substantive issues that were raised in
pre-proposal discussions in sections
VII.F.3.b.iii(C) and X.D.1.a.iii of this
preamble. As explained in these
sections, the EPA is proposing to
determine that CCS is the BSER for
certain subcategories of new and
existing EGUs based on its
consideration of all of the statutory
criteria for BSER, including emission
reductions, cost, energy requirements,
and non-air health and environmental
considerations. In evaluating concerns
raised by stakeholders in connection
with CCS, the EPA is mindful that
Federal agencies have ‘‘taken actions in
the past decade to develop a robust
CCUS regulatory framework to protect
the environment and public health
across multiple statutes.’’ 6
This framework includes, among
other things, the EPA regulation of
geologic sequestration wells under the
Underground Injection Control (UIC)
program of the Safe Drinking Water Act;
required reporting and public disclosure
of geologic sequestration activity, as
well as implementation of rigorous
monitoring, reporting, and verification
of geologic sequestration, under the
6 Carbon Capture, Utilization, and Sequestration
Guidance, 87 FR 8808, 8809 (February 16, 2022),
https://www.govinfo.gov/content/pkg/FR-2022-0216/pdf/2022-03205.pdf.
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EPA’s Greenhouse Gas Reporting
Program; and safety regulations for CO2
pipelines administered by the Pipeline
and Hazardous Materials and Safety
Administration (PHMSA). With respect
to air emissions, some CCS projects may
also require pre-construction permitting
under the Clean Air Act’s New Source
Review (NSR) program and the adoption
of additional emission limitations for
non-GHG air pollutants based on
applicable control technology
requirements. The EPA invites public
comment and feedback from
stakeholders on all aspects of its
proposed determination that CCS
represents the BSER for certain new and
existing fossil fuel-fired EGUs,
including its evaluation of the various
regulatory frameworks that apply to
CCS.
CEQ’s guidance, and the EPA’s
evaluation of BSER, recognizes that
multiple Federal agencies have
responsibility for regulating and
permitting CCS projects, along with
State and Tribal governments. The EPA
is committed to working with Federal,
State, and Tribal partners to ensure the
responsible deployment of CCS, to
protect communities from pollution,
and to foster meaningful engagement
with communities. This can be
facilitated through the existing detailed
regulatory framework for CCS projects
and further supported through robust
and meaningful public engagement
early in the project development
process. Furthermore, the EPA is
requesting comment on what assistance
states and pertinent stakeholders may
need in conducting meaningful
engagement with affected communities
to ensure that there are adequate
opportunities for public input on
decisions to implement emissions
control technology (including but not
limited to CCS or low-GHG hydrogen).
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II. General Information
A. Action Applicability
The source category that is the subject
of these actions is comprised of the
fossil fuel-fired electric utility
generating units regulated under CAA
section 111. The North American
Industry Classification System (NAICS)
codes for the source category are 221112
and 921150. The list of categories and
NAICS codes is not intended to be
exhaustive, but rather provides a guide
for readers regarding the entities that
these proposed actions are likely to
affect.
The proposed amendments to 40 CFR
part 60, subpart TTTT, once
promulgated, will be directly applicable
to affected facilities that began
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construction after January 8, 2014, and
affected facilities that began
reconstruction or modification after
June 18, 2014. The proposed NSPS,
proposed to be codified in 40 CFR part
60, subpart TTTTa, once promulgated,
will be directly applicable to affected
facilities that begin construction or
reconstruction after the date of
publication of the proposed standards in
the Federal Register. Federal, State,
local, and Tribal government entities
that own and/or operate EGUs subject to
40 CFR part 60, subparts TTTT or
TTTTa would be affected by these
proposed amendments and standards.
The proposed emission guidelines for
GHG emissions from fossil fuel-fired
EGUs proposed to be codified in 40 CFR
part 60, subpart UUUUb, once
promulgated, will be applicable to states
in the development and submittal of
State plans pursuant to CAA section
111(d). After the EPA promulgates a
final emission guideline, each State that
has one or more designated facilities
must develop, adopt, and submit to the
EPA a State plan under CAA section
111(d). The term ‘‘designated facility’’
means ‘‘any existing facility . . . which
emits a designated pollutant and which
would be subject to a standard of
performance for that pollutant if the
existing facility were an affected
facility.’’ See 40 CFR 60.21a(b). If a State
fails to submit a plan or the EPA
determines that a State plan is not
satisfactory, the EPA has the authority
to establish a Federal CAA section
111(d) plan in such instances.
Under the Tribal Authority Rule
adopted by the EPA, Tribes may seek
authority to implement a plan under
CAA section 111(d) in a manner similar
to a State. See 40 CFR part 49, subpart
A. Tribes may, but are not required to,
seek approval for treatment in a manner
similar to a State for purposes of
developing a Tribal Implementation
Plan (TIP) implementing an emission
guideline. If a Tribe does not seek and
obtain the authority from the EPA to
establish a TIP, the EPA has the
authority to establish a Federal CAA
section 111(d) plan for designated
facilities that are located in areas of
Indian country. A Federal plan would
apply to all designated facilities located
in the areas of Indian country covered
by the Federal plan unless and until the
EPA approves a TIP applicable to those
facilities.
B. Where To Get a Copy of This
Document and Other Related
Information
In addition to being available in the
docket, an electronic copy of this action
is available on the internet at https://
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www.epa.gov/stationary-sources-airpollution/greenhouse-gas-standardsand-guidelines-fossil-fuel-fired-power.
Following publication in the Federal
Register, the EPA will post the Federal
Register version of the proposals and
key technical documents at this same
website.
Memoranda showing the edits that
would be necessary to incorporate the
changes to 40 CFR part 60, subpart
TTTT and UUUUa and new 40 CFR part
60, subparts TTTTa and UUUUb
proposed in these actions are available
in the docket (Docket ID No. EPA–HQ–
OAR–2023–0072). Following signature
by the EPA Administrator, the EPA also
will post a copy of the documents at
https://www.epa.gov/stationary-sourcesair-pollution/greenhouse-gas-standardsand-guidelines-fossil-fuel-fired-power.
C. Organization and Approach for
These Proposed Rules
This rulemaking includes several
proposed actions: (1) The EPA’s
proposed amendments to the Standards
of Performance for Greenhouse Gas
Emissions From New, Modified, and
Reconstructed Stationary Sources:
Electric Utility Generating Units (80 FR
64510; October 23, 2015) (2015 NSPS)
and (2) proposed requirements for GHG
emissions from new and reconstructed
fossil fuel-fired stationary combustion
turbine EGUs. These actions also (3)
propose to repeal the ACE Rule (84 FR
32523; July 8, 2019), (4) propose new
emission guidelines for states in
developing plans to reduce GHG
emissions from existing fossil fuel-fired
steam generating EGUs, which include
both coal-fired and oil- and natural gasfired steam generating EGUs, and (5)
propose new emission guidelines for
states in developing plans to reduce
GHG emissions from existing fossil fuelfired stationary combustion turbines.
The EPA proposes that each of these
actions function independently and are
therefore severable. The EPA invites
comment on the question of which
portions of these proposed rules, if any,
should be severable.
Section III of this preamble provides
updated information on the impacts of
climate change. In section IV, the EPA
provides a summary of recent
developments in emissions controls and
the electric power sector. Section V
presents a summary of the statutory
background and regulatory history. In
section VI, the EPA summarizes
stakeholder outreach efforts. In section
VII, the EPA describes the proposed
BSERs, standards of performance, and
associated requirements for new and
reconstructed fossil fuel-fired stationary
combustion turbine EGUs. In section
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VIII, the EPA presents proposed
amendments to requirements for new,
reconstructed, and modified fossil fuelfired steam generating units. In section
IX, the EPA provides a summary of the
ACE Rule and proposes its repeal. In
section X, the EPA presents the
proposed BSERs, degree of emission
limitation, and related requirements for
the proposed emission guidelines for
existing fossil fuel-fired steam
generating EGUs. In section XI, the EPA
presents the proposed BSERs, degree of
emission limitation, and related
requirements for the proposed emission
guidelines for existing natural gas-fired
combustion turbines. Section XII
presents the requirements for State plan
development. In section XIII, the EPA
describes the implications for these
proposals on other EPA programs and
rules. Section XIV describes the impacts
of these proposals. Finally, in section
XV, the EPA provides the statutory and
executive order reviews.
III. Climate Change and Its Impacts
Elevated concentrations of GHGs are
and have been warming the planet,
leading to changes in the Earth’s climate
including changes in the frequency and
intensity of heat waves, precipitation,
and extreme weather events; rising seas;
and retreating snow and ice. The
changes taking place in the atmosphere
as a result of the well-documented
buildup of GHGs due to human
activities are transforming the climate at
a pace and scale that threatens human
health, society, and the natural
environment. Human-induced GHGs,
largely derived from our reliance on
fossil fuels, are causing serious and lifethreatening environmental and health
impacts.
Extensive additional information on
climate change is available in the
scientific assessments and the EPA
documents that are briefly described in
this section, as well as in the technical
and scientific information supporting
them. One of those documents is the
EPA’s 2009 Endangerment and Cause or
Contribute Findings for GHGs Under
section 202(a) of the CAA (74 FR 66496;
December 15, 2009).7 In the 2009
Endangerment Findings, the
Administrator found under section
202(a) of the CAA that elevated
atmospheric concentrations of six key
well-mixed GHGs—carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur
hexafluoride (SF6)—‘‘may reasonably be
7 In describing these 2009 Findings in these
proposals, the EPA is neither reopening nor
revisiting them.
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anticipated to endanger the public
health and welfare of current and future
generations’’ (74 FR 66523; December
15, 2009), and the science and observed
changes have confirmed and
strengthened the understanding and
concerns regarding the climate risks
considered in the Finding. The 2009
Endangerment Findings, together with
the extensive scientific and technical
evidence in the supporting record,
documented that climate change caused
by human emissions of GHGs threatens
the public health of the U.S. population.
It explained that by raising average
temperatures, climate change increases
the likelihood of heat waves, which are
associated with increased deaths and
illnesses (74 FR 66497; December 15,
2009). While climate change also
increases the likelihood of reductions in
cold-related mortality, evidence
indicates that the increases in heat
mortality will be larger than the
decreases in cold mortality in the U.S.
(74 FR 66525; December 15, 2009). The
2009 Endangerment Findings further
explained that compared to a future
without climate change, climate change
is expected to increase tropospheric
ozone pollution over broad areas of the
U.S., including in the largest
metropolitan areas with the worst
tropospheric ozone problems, and
thereby increase the risk of adverse
effects on public health (74 FR 66525;
December 15, 2009). Climate change is
also expected to cause more intense
hurricanes and more frequent and
intense storms of other types and heavy
precipitation, with impacts on other
areas of public health, such as the
potential for increased deaths, injuries,
infectious and waterborne diseases, and
stress-related disorders (74 FR 66525;
December 15, 2009). Children, the
elderly, and the poor are among the
most vulnerable to these climate-related
health effects (74 FR 66498; December
15, 2009).
The 2009 Endangerment Findings also
documented, together with the
extensive scientific and technical
evidence in the supporting record, that
climate change touches nearly every
aspect of public welfare 8 in the U.S.
including changes in water supply and
quality due to increased frequency of
drought and extreme rainfall events;
8 The CAA states in section 302(h) that ‘‘[a]ll
language referring to effects on welfare includes,
but is not limited to, effects on soils, water, crops,
vegetation, manmade materials, animals, wildlife,
weather, visibility, and climate, damage to and
deterioration of property, and hazards to
transportation, as well as effects on economic
values and on personal comfort and well-being,
whether caused by transformation, conversion, or
combination with other air pollutants.’’ 42 U.S.C.
7602(h).
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33249
increased risk of storm surge and
flooding in coastal areas and land loss
due to inundation; increases in peak
electricity demand and risks to
electricity infrastructure; predominantly
negative consequences for biodiversity
and the provisioning of ecosystem goods
and services; and the potential for
significant agricultural disruptions and
crop failures (though offset to some
extent by carbon fertilization). These
impacts are also global and may
exacerbate problems outside the U.S.
that raise humanitarian, trade, and
national security issues for the U.S. (74
FR 66530; December 15, 2009).
In 2016, the Administrator similarly
issued Endangerment and Cause or
Contribute Findings for GHG emissions
from aircraft under section 231(a)(2)(A)
of the CAA (81 FR 54422; August 15,
2016).9 In the 2016 Endangerment
Findings, the Administrator found that
the body of scientific evidence amassed
in the record for the 2009 Endangerment
Findings compellingly supported a
similar endangerment finding under
CAA section 231(a)(2)(A) and also found
that the science assessments released
between the 2009 and the 2016
Findings, ‘‘strengthen and further
support the judgment that GHGs in the
atmosphere may reasonably be
anticipated to endanger the public
health and welfare of current and future
generations.’’ 81 FR 54424 (August 15,
2016).
Since the 2016 Endangerment
Findings, the climate has continued to
change, with new records being set for
several climate indicators such as global
average surface temperatures, GHG
concentrations, and sea level rise.
Moreover, heavy precipitation events
have increased in the Eastern U.S. while
agricultural and ecological drought has
increased in the Western U.S. along
with more intense and larger
wildfires.10 These and other trends are
examples of the risks discussed in the
2009 and 2016 Endangerment Findings
that have already been experienced.
Additionally, major scientific
assessments continue to demonstrate
advances in our understanding of the
climate system and the impacts that
GHGs have on public health and welfare
both for current and future generations.
These updated observations and
projections document the rapid rate of
current and future climate change both
9 In describing these 2016 Findings in these
proposals, the EPA is neither reopening nor
revisiting them.
10 See later in this section for specific examples.
An additional resource for indicators can be found
at https://www.epa.gov/climate-indicators.
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globally and in the U.S. These
assessments include:
• U.S. Global Change Research
Program’s (USGCRP) 2016 Climate and
Health Assessment 11 and 2017–2018
Fourth National Climate Assessment
(NCA4).12 13
• Intergovernmental Panel on Climate
Change (IPCC) 2018 Global Warming of
1.5 °C,14 2019 Climate Change and
Land,15 and the 2019 Ocean and
Cryosphere in a Changing
Climate 16 assessments, as well as the
2021 IPCC Sixth Assessment Report
(AR6).17 18
11 USGCRP, 2016: The Impacts of Climate Change
on Human Health in the United States: A Scientific
Assessment. Crimmins, A., J. Balbus, J.L. Gamble,
C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen, N. Fann,
M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M.
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska,
Eds. U.S. Global Change Research Program,
Washington, DC, 312 pp.
12 USGCRP, 2017: Climate Science Special
Report: Fourth National Climate Assessment,
Volume I [Wuebbles, D.J., D.W. Fahey, K.A.
Hibbard, D.J. Dokken, B.C. Stewart, and T.K.
Maycock (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 470 pp, doi:
10.7930/J0J964J6.
13 USGCRP, 2018: Impacts, Risks, and Adaptation
in the United States: Fourth National Climate
Assessment, Volume II [Reidmiller, D.R., C.W.
Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis,
T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global
Change Research Program, Washington, DC, USA,
1515 pp. doi: 10.7930/NCA4.2018.
14 IPCC, 2018: Global Warming of 1.5 °C. An IPCC
Special Report on the impacts of global warming of
1.5 °C above pre-industrial levels and related global
greenhouse gas emission pathways, in the context
of strengthening the global response to the threat of
climate change, sustainable development, and
efforts to eradicate poverty [Masson-Delmotte, V., P.
Zhai, H.-O. Portner, D. Roberts, J. Skea, P.R. Shukla,
A. Pirani, W. Moufouma-Okia, C. Pe´an, R. Pidcock,
S. Connors, J.B.R. Matthews, Y. Chen, X. Zhou, M.I.
Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)].
15 IPCC, 2019: Climate Change and Land: an IPCC
special report on climate change, desertification,
land degradation, sustainable land management,
food security, and greenhouse gas fluxes in
terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo
Buendia, V. Masson-Delmotte, H.-O. Portner, D.C.
Roberts, P. Zhai, R. Slade, S. Connors, R. van
Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M.
Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E.
Huntley, K. Kissick, M. Belkacemi, J. Malley (eds.)].
16 IPCC, 2019: IPCC Special Report on the Ocean
and Cryosphere in a Changing Climate [H.-O.
Po¨rtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai,
M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegr(´a, M. Nicolai, A. Okem, J. Petzold, B. Rama,
N.M. Weyer (eds.)].
17 IPCC, 2021: Summary for Policymakers. In:
Climate Change 2021: The Physical Science Basis.
Contribution of Working Group I to the Sixth
Assessment Report of the Intergovernmental Panel
on Climate Change [Masson-Delmotte, V., P. Zhai,
A. Pirani, S.L. Connors, C. Pe´an, S. Berger, N.
Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang,
K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K.
Maycock, T. Waterfield, O. Yelekc¸i, R. Yu and B.
Zhou (eds.)]. Cambridge University Press.
18 IPCC, 2022: Summary for Policymakers [H.-O.
Po¨rtner, D.C. Roberts, E.S. Poloczanska, K.
Mintenbeck, M. Tignor, A. Alegrı´a, M. Craig, S.
Langsdorf, S. Lo¨schke, V. Mo¨ller, A. Okem (eds.)].
In: Climate Change 2022: Impacts, Adaptation and
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• The National Academy of Sciences
(NAS) 2016 Attribution of Extreme
Weather Events in the Context of
Climate Change,19 2017 Valuing Climate
Damages: Updating Estimation of the
Social Cost of Carbon Dioxide,20 and
2019 Climate Change and Ecosystems 21
assessments.
• National Oceanic and Atmospheric
Administration’s (NOAA) annual State
of the Climate reports published by the
Bulletin of the American Meteorological
Society,22 most recently in August of
2022.
• EPA Climate Change and Social
Vulnerability in the United States: A
Focus on Six Impacts (2021).23
The most recent information
demonstrates that the climate is
continuing to change in response to the
human-induced buildup of GHGs in the
atmosphere. These recent assessments
show that atmospheric concentrations of
GHGs have risen to a level that has no
precedent in human history and that
they continue to climb, primarily as a
result of both historic and current
anthropogenic emissions, and that these
elevated concentrations endanger our
health by affecting our food and water
sources, the air we breathe, the weather
we experience, and our interactions
with the natural and built
environments. For example, the annual
global average atmospheric
concentrations of one of these GHGs,
CO2, measured at Mauna Loa in Hawaii
and at other sites around the world
reached 415 parts per million (ppm) in
2020 (nearly 50 percent higher than preindustrial levels) 24 and has continued
Vulnerability. Contribution of Working Group II to
the Sixth Assessment Report of the
Intergovernmental Panel on Climate Change [H.-O.
Po¨rtner, D.C. Roberts, M. Tignor, E.S. Poloczanska,
K. Mintenbeck, A. Alegrı´a, M. Craig, S. Langsdorf,
S. Lo¨schke, V. Mo¨ller, A. Okem, B. Rama (eds.)].
Cambridge University Press, Cambridge, United
Kingdom and New York, New York, USA, pp. 3–
33, doi:10.1017/9781009325844.001.
19 National Academies of Sciences, Engineering,
and Medicine. 2016. Attribution of Extreme
Weather Events in the Context of Climate Change.
Washington, DC: The National Academies Press.
https://dio.org/10.17226/21852.
20 National Academies of Sciences, Engineering,
and Medicine. 2017. Valuing Climate Damages:
Updating Estimation of the Social Cost of Carbon
Dioxide. Washington, DC: The National Academies
Press. https://doi.org/10.17226/24651.
21 National Academies of Sciences, Engineering,
and Medicine. 2019. Climate Change and
Ecosystems. Washington, DC: The National
Academies Press. https://doi.org/10.17226/25504.
22 Blunden, J. and T. Boyer, Eds., 2022: ‘‘State of
the Climate in 2021.’’ Bull. Amer. Meteor. Soc., 103
(8), Si–S465, https://doi.org/10.1175/
2022BAMSStateoftheClimate.1.
23 EPA. 2021. Climate Change and Social
Vulnerability in the United States: A Focus on Six
Impacts. U.S. Environmental Protection Agency,
EPA 430–R–21–003.
24 Blunden, J. and T. Boyer, Eds., 2022: ‘‘State of
the Climate in 2021.’’ Bull. Amer. Meteor. Soc., 103
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to rise at a rapid rate. Global average
temperature has increased by about 1.1
degrees Celsius (°C) (2.0 degrees
Fahrenheit (°F)) in the 2011–2020
decade relative to 1850–1900.25 The
years 2015–2021 were the warmest 7
years in the 1880–2020 record according
to six different global surface
temperature datasets.26 The IPCC
determined with medium confidence
that this past decade was warmer than
any multi-century period in at least the
past 100,000 years.27 Global average sea
level has risen by about 8 inches (about
21 centimeters (cm)) from 1901 to 2018,
with the rate from 2006 to 2018 (0.15
inches/year or 3.7 millimeters (mm)/
year) almost twice the rate over the 1971
to 2006 period and three times the rate
of the 1901 to 2018 period.28 The rate
of sea level rise during the 20th Century
was higher than in any other century in
at least the last 2,800 years.29 Higher
CO2 concentrations have led to
acidification of the surface ocean in
recent decades to an extent unusual in
the past 2 million years, with negative
impacts on marine organisms that use
calcium carbonate to build shells or
skeletons.30 Arctic sea ice extent
continues to decline in all months of the
year; the most rapid reductions occur in
September (very likely almost a 13
percent decrease per decade between
1979 and 2018) and are unprecedented
in at least 1,000 years.31 Humaninduced climate change has led to
heatwaves and heavy precipitation
becoming more frequent and more
intense, along with increases in
agricultural and ecological droughts 32
in many regions.33
The assessment literature
demonstrates that modest additional
amounts of warming may lead to a
climate different from anything humans
have ever experienced. The present-day
CO2 concentration of 415 ppm is already
higher than at any time in the last 2
million years.34 If concentrations exceed
450 ppm, they would likely be higher
(8), Si–S465, https://doi.org/10.1175/
2022BAMSStateoftheClimate.1.
25 IPCC, 2021.
26 Blunden, J. and T. Boyer, Eds., 2022.
27 IPCC, 2021.
28 IPCC, 2021.
29 USGCRP, 2018: Impacts, Risks, and Adaptation
in the United States: Fourth National Climate
Assessment, Volume II [Reidmiller, D.R., C.W.
Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis,
T.K. Maycock, and B.C. Stewart (eds.)]. U.S. Global
Change Research Program, Washington, DC, USA,
1515 pp. doi: 10.7930/NCA4.2018.
30 IPCC, 2021.
31 IPCC, 2021.
32 These are drought measures based on soil
moisture.
33 IPCC, 2021.
34 IPCC, 2021.
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than at any time in the past 23 million
years: 35 At the current rate of increase
of more than 2 ppm per year, this will
occur in about 15 years. While buildup
of GHGs is not the only factor that
controls climate, it is illustrative that 3
million years ago (the last time CO2
concentrations were this high)
Greenland was not yet completely
covered by ice and still supported
forests, while 23 million years ago (the
last time concentrations were above 450
ppm) the West Antarctic ice sheet was
not yet developed, indicating the
possibility that high GHG
concentrations could lead to a world
that looks very different from today and
from the conditions in which human
civilization has developed.36
If the Greenland and Antarctic ice
sheets were to melt substantially, for
example, sea levels would rise
dramatically, with potentially severe
consequences for coastal cities and
infrastructure. The IPCC estimated that
during the next 2,000 years, sea level
will rise by 7 to 10 feet even if warming
is limited to 1.5 °C (2.7 °F), from 7 to 20
feet if limited to 2 °C (3.6 °F), and by 60
to 70 feet if warming is allowed to reach
5 °C (9 °F) above preindustrial levels.37
For context, almost all of the city of
Miami is less than 25 feet above sea
level, and the NCA4 stated that 13
million Americans would be at risk of
migration due to 6 feet of sea level rise.
Moreover, the CO2 being absorbed by
the ocean has resulted in changes in
ocean chemistry due to acidification of
a magnitude not seen in 65 million
years,38 putting many marine species—
particularly calcifying species—at
risk.39
The NCA4 found that it is very likely
(greater than 90 percent likelihood) that
by mid-century, the Arctic Ocean will
be almost entirely free of sea ice by late
summer for the first time in about 2
million years.40 Coral reefs will be at
risk for almost complete (99 percent)
35 IPCC,
2013.
S.K., P.W. Thorne, J. Ahn, F.J. Dentener,
C.M. Domingues, S. Gerland, D. Gong, D.S.
Kaufman, H.C. Nnamchi, J. Quaas, J.A. Rivera, S.
Sathyendranath, S.L. Smith, B. Trewin, K. von
Schuckmann, and R.S. Vose, 2021: Changing State
of the Climate System. In Climate Change 2021: The
Physical Science Basis. Contribution of Working
Group I to the Sixth Assessment Report of the
Intergovernmental Panel on Climate Change
[Masson-Delmotte, V., P. Zhai, A. Pirani, S.L.
Connors, C. Pe´an, S. Berger, N. Caud, Y. Chen, L.
Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E.
Lonnoy, J.B.R. Matthews, T.K. Maycock, T.
Waterfield, O. Yelekc
¸i, R. Yu, and B. Zhou (eds.)].
Cambridge University Press, Cambridge, United
Kingdom and New York, New York, USA, pp. 287–
422, doi:10.1017/9781009157896.004.
37 IPCC, 2021.
38 IPCC, 2018.
39 IPCC, 2021.
40 USGCRP, 2018.
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losses with 1 °C (1.8 °F) of additional
warming from today (2 °C or 3.6 °F since
preindustrial). At this temperature,
between 8 and 18 percent of animal,
plant, and insect species could lose over
half of the geographic area with suitable
climate for their survival, and 7 to 10
percent of rangeland livestock would be
projected to be lost.41 The IPCC
similarly found that climate change has
caused substantial damages and
increasingly irreversible losses in
terrestrial, freshwater, and coastal and
open ocean marine ecosystems.42
Every additional increment of
temperature comes with consequences.
For example, the half degree of warming
from 1.5 to 2 °C (0.9 °F of warming from
2.7 °F to 3.6 °F) above preindustrial
temperatures is projected on a global
scale to expose 420 million more people
to frequent extreme heatwaves and 62
million more people to frequent
exceptional heatwaves (where
heatwaves are defined based on a heat
wave magnitude index which takes into
account duration and intensity—using
this index, the 2003 French heat wave
that led to almost 15,000 deaths would
be classified as an ‘‘extreme heatwave’’
and the 2010 Russian heatwave which
led to thousands of deaths and extensive
wildfires would be classified as
‘‘exceptional’’). This half degree
temperature increase has been projected
to lead to an increase in the frequency
of sea-ice-free Arctic summers from
once in a hundred years to once in a
decade. It could lead to 4 inches of
additional sea level rise by the end of
the century, exposing an additional 10
million people to risks of inundation, as
well as increasing the probability of
triggering instabilities in either the
Greenland or Antarctic ice sheets.
Between half a million and a million
additional square miles of permafrost is
projected to thaw over several centuries.
Risks to food security is projected to
increase from medium to high for
several lower income regions in the
Sahel, southern Africa, the
Mediterranean, central Europe, and the
Amazon. In addition to food security
issues, this temperature increase is
projected to have implications for
human health in terms of increasing
ozone concentrations, heatwaves, and
vector-borne diseases (for example,
expanding the range of the mosquitoes
which carry dengue fever, chikungunya,
yellow fever, and the Zika virus or the
ticks which carry lyme, babesiosis, or
Rocky Mountain Spotted Fever).43
Moreover, every additional increment in
41 IPCC,
2018.
2022.
43 IPCC, 2018.
42 IPCC,
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warming leads to larger changes in
extremes, including the potential for
events unprecedented in the
observational record. Every additional
degree is projected to intensify extreme
precipitation events by about 7 percent.
The peak winds of the most intense
tropical cyclones (hurricanes) are
projected to increase with warming. In
addition to a higher intensity, the IPCC
found that precipitation and frequency
of rapid intensification of these storms
has already increased, while the
movement speed has decreased, and
elevated sea levels have increased
coastal flooding, all of which make
these tropical cyclones more
damaging.44
The NCA4 also evaluated a number of
impacts specific to the U.S. Severe
drought and outbreaks of insects like the
mountain pine beetle have killed
hundreds of millions of trees in the
Western U.S. Wildfires have burned
more than 3.7 million acres in 14 of the
17 years between 2000 and 2016, and
Federal wildfire suppression costs were
about a billion dollars annually.45 The
National Interagency Fire Center has
documented U.S. wildfires since 1983,
and the 10 years with the largest acreage
burned have all occurred since 2004.46
Wildfire smoke degrades air quality
increasing health risks, and more
frequent and severe wildfires due to
climate change would further diminish
air quality, increase incidences of
respiratory illness, impair visibility, and
disrupt outdoor activities, sometimes
thousands of miles from the location of
the fire. Meanwhile, sea level rise has
amplified coastal flooding and erosion
impacts, leading to salt water intrusion
into coastal aquifers and groundwater,
flooding streets, increasing storm surge
damages, and threatening coastal
property and ecosystems, requiring
costly adaptive measures such as
installation of pump stations, beach
nourishment, property elevation, and
shoreline armoring. Tens of billions of
dollars of U.S. real estate could be
below sea level by 2050 under some
scenarios. Increased frequency and
duration of drought will reduce
agricultural productivity in some
regions, accelerate depletion of water
supplies for irrigation, and expand the
distribution and incidence of pests and
diseases for crops and livestock. The
NCA4 also recognized that climate
change can increase risks to national
44 IPCC,
2021.
2018.
46 NIFC (National Interagency Fire Center). 2022.
Total wildland fires and acres (1983–2020).
Accessed November 2022. https://www.nifc.gov/
sites/default/files/document-media/TotalFires.pdf.
45 USGCRP,
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security, both through direct impacts on
military infrastructure, but also by
affecting factors such as food and water
availability that can exacerbate conflict
outside U.S. borders. Droughts, floods,
storm surges, wildfires, and other
extreme events stress nations and
people through loss of life,
displacement of populations, and
impacts on livelihoods.47
Some GHGs also have impacts beyond
those mediated through climate change.
For example, elevated concentrations of
CO2 stimulate plant growth (which can
be positive in the case of beneficial
species, but negative in terms of weeds
and invasive species, and can also lead
to a reduction in plant
micronutrients) 48 and cause ocean
acidification. Nitrous oxide depletes the
levels of protective stratospheric
ozone.49 The tropospheric ozone
produced by the reaction of methane in
the atmosphere has harmful effects for
human health and plant growth in
addition to its climate effects.50
Ongoing EPA modeling efforts can
shed further light on the distribution of
climate change damages expected to
occur within the U.S. Based on methods
from over 30 peer-reviewed climate
change impact studies, the EPA’s
Framework for Evaluating Damages and
Impacts (FrEDI) model has developed
estimates of the relationship between
future temperature changes and
physical and economic climate-driven
damages occurring in specific U.S.
regions across 20 impact categories,
which span a large number of sectors of
the U.S. economy.51 Recent applications
of FrEDI have advanced the collective
47 USGCRP,
2018.
L., A. Crimmins, A. Auclair, S. DeGrasse,
J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Perez de
Leon, A. Showler, J. Thurston, and I. Walls, 2016:
Ch. 7: Food Safety, Nutrition, and Distribution. The
Impacts of Climate Change on Human Health in the
United States: A Scientific Assessment. U.S. Global
Change Research Program, Washington, DC, 189–
216, https://dx.doi.org/10.7930/J0ZP4417.
49 WMO (World Meteorological Organization),
Scientific Assessment of Ozone Depletion: 2018,
Global Ozone Research and Monitoring Project—
Report No. 58, 588 pp., Geneva, Switzerland, 2018.
50 Nolte, C.G., P.D. Dolwick, N. Fann, L.W.
Horowitz, V. Naik, R.W. Pinder, T.L. Spero, D.A.
Winner, and L.H. Ziska, 2018: Air Quality. In
Impacts, Risks, and Adaptation in the United States:
Fourth National Climate Assessment, Volume II
[Reidmiller, D.R., C.W. Avery, D.R. Easterling, K.E.
Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C.
Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 512–538. doi:
10.7930/NCA4. 2018. CH13.
51 EPA. (2021). Technical Documentation on the
Framework for Evaluating Damages and Impacts
(FrEDI). U.S. Environmental Protection Agency,
EPA 430–R–21–004, available at https://
www.epa.gov/cira/fredi. Documentation has been
subject to both a public review comment period and
an independent expert peer review, following EPA
peer-review guidelines.
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understanding about how future climate
change impacts in these 20 sectors are
expected to be substantial and
distributed unevenly across U.S.
regions.52 Using this framework, the
EPA estimates that under a global
emission scenario with no additional
mitigation, relative to a world with no
additional warming since the baseline
period (1986–2005), damages accruing
to these 20 sectors in the contiguous
U.S. occur mainly through increased
deaths due to increasing temperatures,
as well as climate-driven changes in air
quality, transportation impacts due to
coastal flooding resulting from sea level
rise, increased mortality from wildfire
emission exposure and response costs
for fire suppression, and reduced labor
hours worked in outdoor settings and
buildings without air conditioning. The
relative damages from long-term climate
driven changes in these sectors are also
projected vary from region to region: for
example, the Southeast is projected to
see some of the largest damages from sea
level rise, the West Coast will see higher
damages from wildfire smoke than other
parts of the country, and the Northern
Plains states are projected to see a
higher proportion of damages to rail and
road infrastructure. While the FrEDI
framework currently quantifies damages
for 20 sectors within the U.S., it is
important to note that it is still a
preliminary and partial assessment of
climate impacts relevant to U.S.
interests in a number of ways. For
example, FrEDI does not reflect
increased damages that occur due to
interactions between different sectors
impacted by climate change or all the
ways in which physical impacts of
climate change occuring abroad have
spillover effects in different regions of
the U.S. See the FrEDI Technical
Documentation 53 for more details.
52 (1) Sarofim, M.C., Martinich, J., Neumann, J.E.,
et al. (2021). A temperature binning approach for
multi-sector climate impact analysis. Climatic
Change 165. https://doi.org/10.1007/s10584-02103048-6, (2) Supplementary Material for the
Regulatory Impact Analysis for the Supplemental
Proposed Rulemaking, ‘‘Standards of Performance
for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and
Natural Gas Sector Climate Review,’’ Docket ID No.
EPA–HQ–OAR–2021–0317, September 2022, (3)
The Long-Term Strategy of the United States:
Pathways to Net-Zero Greenhouse Gas Emissions by
2050. Published by the U.S. Department of State
and the U.S. Executive Office of the President,
Washington DC. November 2021, (4) Climate Risk
Exposure: An Assessment of the Federal
Government’s Financial Risks to Climate Change,
White Paper, Office of Management and Budget,
April 2022.
53 EPA. (2021). Technical Documentation on the
Framework for Evaluating Damages and Impacts
(FrEDI). U.S. Environmental Protection Agency,
EPA 430–R–21–004, available at https://
www.epa.gov/cira/fredi.
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These scientific assessments, EPA
analyses, and documented observed
changes in the climate of the planet and
of the U.S. present clear support
regarding the current and future dangers
of climate change and the importance of
GHG emissions mitigation.
IV. Recent Developments in Emissions
Controls and the Electric Power Sector
A. Introduction
In this section, we discuss
background information about the
electric power sector and then discuss
several recent developments that are
relevant for many of the controls that
the EPA is proposing to determine
qualify as the BSER for the fossil fuelfired power plants that are the subject
of this proposed rulemaking. After
giving some general background, we
first discuss CCS and explain that its
cost has fallen significantly. Lower CCS
costs are central for the EPA’s proposals
that CCS is the BSER for certain existing
coal-fired EGUs and certain existing and
new natural gas-fired combustion
turbines. Second, we discuss natural gas
co-firing for coal-fired EGUs and explain
recent reductions in cost for this
approach as well as its widespread
availability and current and potential
deployment within this source category.
Third, we discuss hydrogen produced
through low-emitting manufacturing,
the availability of which is expected to
increase significantly and the cost of
which is expected to decline
significantly in the near future. This
increase in availability and decrease in
cost is central for the EPA’s proposal
that low-GHG hydrogen is the BSER for
certain existing and new natural gasfired combustion turbines. Finally, we
discuss key developments in the electric
power sector that underly the expected
operational methods for existing coalfired EGUs and new and existing natural
gas-fired combustion turbines. These
key developments, in turn, are relevant
for the regulatory design.
B. Background
1. Electric Power Sector
Electricity in the U.S. is generated by
a range of technologies, and while the
sector is rapidly evolving, the stationary
combustion turbines and steam
generating EGUs that are the subject of
these proposed regulations still provide
more than half of the electricity
generated in the U.S. These EGUs fill
many roles that are important to
maintaining a reliable supply of
electricity. For example, certain EGUs
generate base load power, which is the
portion of electricity loads that are
continually present and typically
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operate throughout all hours of the year.
Other EGUs provide complementary
generation to balance variable supply
and demand resources. ‘‘Peaking units’’
provide capacity during hours of the
highest daily, weekly, or seasonal net
demand. Some EGUs also play
important roles ensuring the reliability
of the electric grid, including facilitating
the regulation of frequency and voltage,
providing ‘‘black start’’ capability in the
event the grid must be repowered after
a widespread outage, and providing
reserve generating capacity 54 in the
event of unexpected changes in the
availability of other generators.
In general, the EGUs with the lowest
operating costs are dispatched first, and,
as a result, an inefficient EGU with high
fuel costs will typically only operate if
other lower-cost plants are unavailable
or insufficient to meet demand. Units
are also unavailable during both routine
and unanticipated outages, which
typically become more frequent as
power plants age. These factors result in
the mix of available generating capacity
types (e.g., the share of capacity of each
type of generating source) being
substantially different than the mix of
the share of total electricity produced by
each type of generating source in a given
season or year.
Generated electricity must be
transmitted over networks 55 of high
voltage lines to substations where power
is stepped down to a lower voltage for
local distribution. Within each of these
transmission networks, there are
multiple areas where the operation of
power plants is monitored and
controlled by regional organizations to
ensure that electricity generation and
load are kept in balance. In some areas,
the operation of the transmission system
is under the control of a single regional
54 Generation and capacity are commonly
reported statistics with key distinctions. Generation
is the production of electricity and is a measure of
an EGU’s actual output while capacity is a measure
of the maximum potential production of an EGU
under certain conditions. There are several methods
to calculate an EGU’s capacity, which are suited for
different applications of the statistic. Capacity is
typically measured in megawatts (MW) for
individual units or gigawatts (1 GW = 1,000 MW)
for multiple EGUs. Generation is often measured in
kilowatt-hours (kWh), megawatt-hours (MWh), or
gigawatt-hours (1 GWh = 1 million kWh).
55 The three network interconnections are the
Western Interconnection, comprising the western
parts of both the U.S. and Canada (approximately
the area to the west of the Rocky Mountains), the
Eastern Interconnection, comprising the eastern
parts of both the U.S. and Canada (except those
parts of Eastern Canada that are in the Quebec
Interconnection), and the Texas Interconnection
(which encompasses the portion of the Texas
electricity system commonly known as the Electric
Reliability Council of Texas (ERCOT)). See map of
all NERC interconnections at https://
www.nerc.com/AboutNERC/keyplayers/
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operator; 56 in others, individual
utilities 57 coordinate the operations of
their generation and transmission to
balance the system across their
respective service territories.
2. Types of EGUs
In 2021, approximately 61 percent of
net electricity was generated from the
combustion of fossil fuels with natural
gas providing 38 percent, coal providing
22 percent, and petroleum products
such as fuel oil providing an additional
1 percent.58 Fossil fuel-fired EGUs
include the steam generating units and
stationary combustion turbines that are
the subject of these proposed
regulations.
There are two forms of fossil fuel-fired
electric utility steam generating units:
utility boilers and those that use
gasification technology (i.e., integrated
gasification combined cycle (IGCC)
units). While coal is the most common
fuel for fossil fuel-fired utility boilers,
natural gas can also be used as a fuel in
these EGUs and many existing coal- and
oil-fired utility boilers have repowered
as natural gas-fired units. An IGCC unit
gasifies fuel—typically coal or
petroleum coke—to form a synthetic gas
(or syngas) composed of carbon
monoxide (CO) and hydrogen (H2),
which can be combusted in a combined
cycle system to generate power. The
heat created by these technologies
produces high-pressure steam that is
released to rotate turbines, which, in
turn, spin an electric generator.
Stationary combustion turbine EGUs
(most commonly natural gas-fired) use
one of two configurations: combined
cycle or simple cycle combustion
turbines. Combined cycle units have
two generating components (i.e., two
cycles) operating from a single source of
heat. Combined cycle units first
generate power from a combustion
turbine (i.e., the combustion cycle)
directly from the heat of burning natural
gas or other fuel. The second cycle
reuses the waste heat from the
combustion turbine engine, which is
routed to a heat recovery steam
generator (HRSG) that generates steam,
which is then used to produce
additional power using a steam turbine
(i.e., the steam cycle). Combining these
generation cycles increases the overall
56 For example, PJM Interconnection, LLC, New
York Independent System Operator (NYISO),
Midwest Independent System Operator (MISO),
California Independent System Operator (CAISO),
etc.
57 For example, Los Angeles Department of Power
and Water, Florida Power and Light, etc.
58 U.S. Energy Information Administration (EIA).
Electric Power Monthly, Table 1.1 and Form EIA–
860M, July 2022. https://www.eia.gov/electricity/
data/php.
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efficiency of the system. Combined
cycle units that fire mostly natural gas
are commonly referred to as natural gas
combined cycle (NGCC) units, and, with
greater efficiency, are utilized at higher
capacity factors to provide base load or
intermediate power. An EGU’s capacity
factor indicates a power plant’s
electricity output as a percentage of its
total generation capacity. Simple cycle
combustion turbines only use a
combustion turbine to produce
electricity (i.e., there is no heat recovery
or steam cycle). These less-efficient
combustion turbines are generally
utilized at non-base load capacity
factors and contribute to reliable
operations of the grid during periods of
peak demand or provide flexibility to
support increased generation from
variable energy sources.59
Other generating sources produce
electricity by harnessing kinetic energy
from flowing water, wind, or tides,
thermal energy from geothermal wells,
or solar energy primarily through
photovoltaic solar arrays. Spurred by a
combination of declining costs,
consumer preferences, and government
policies, the capacity of these renewable
technologies is growing, and when
considered with existing nuclear energy,
accounted for nearly 41 percent of the
overall net electricity supply in 2022.
Many projections show this share
growing over time. For example, the
EPA’s Power Sector Modeling Platform
v6 Using the Integrated Planning Model
post-IRA 2022 reference case (i.e., the
EPA’s projections of the power sector,
which includes representation of the
IRA absent further regulation) shows
zero-emitting sources reaching 76
percent of electricity generation by
2040. (See section IV.F of this preamble
and the accompanying RIA for
additional discussion of projections for
the power sector). These projections are
consistent with power company
announcements. For example, as the
Edison Electric Institute (EEI) stated in
pre-proposal public comments
59 Non-dispatchable renewable energy (electrical
output cannot be used at any given time to meet
fluctuating demand) is both variable and
intermittent and is often referred to as intermittent
renewable energy. The variability aspect results
from predictable changes in electric generation (e.g.,
solar not generating electricity at night) that often
occur on longer time periods. The intermittent
aspect of renewable energy results from
inconsistent generation due to unpredictable
external factors outside the control of the owner/
operator (e.g., imperfect local weather forecasts)
that often occur on shorter time periods. Since
renewable energy fluctuates over multiple time
periods, grid operators are required to adjust
forecast and real time operating procedures. As
more renewable energy is added to the electric grid
and generation forecasts improve, the intermittency
of renewable energy is reduced.
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Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed Rules
submitted to the regulatory docket:
‘‘Fifty EEI members have announced
forward-looking carbon reduction goals,
two-thirds of which include a net-zero
by 2050 or earlier equivalent goal, and
members are routinely increasing the
ambition or speed of their goals or
altogether transforming them into netzero goals . . . . EEI’s member
companies see a clear path to continued
emissions reductions over the next
decade using current technologies,
including nuclear power, natural gasbased generation, energy demand
efficiency, energy storage, and
deployment of new renewable energy—
especially wind and solar—as older
coal-based and less-efficient natural gasbased generating units retire.’’ 60
C. CCS
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One of the key GHG reduction
technologies upon which BSER
determinations are founded in this
proposal is CCS—a technology that can
capture and permanently store CO2 from
EGUs. CCS has three major components:
CO2 capture, transportation, and
sequestration/storage. Generally, the
capture processes most applicable to
combustion turbines and utility boilers
remove CO2 from the exhaust gas after
combustion. The exhaust gases from
most combustion processes are at
atmospheric pressure with relatively
low concentrations of CO2. Most postcombustion capture systems utilize
liquid solvents (most commonly aminebased) in a scrubber column to absorb
the CO2 from the flue gas.61 The CO2rich solvent is then regenerated by
heating the solvent to release the
captured CO2. The high purity CO2 is
then compressed and transported,
generally through pipelines, to a site for
geologic sequestration (i.e., the longterm containment of CO2 in subsurface
geologic formations).62 Process
improvements learned from earlier
deployments of CCS, the availability of
better solvents, and other advances have
resulted in a decrease in the cost of CCS
in recent years. The cost of CO2 capture,
excluding any tax credits, from coalfired power generation is projected to
fall by 50 percent by 2025 compared to
60 Edison Electric Institute (EEI). (November 18,
2022). Clean Air Act Section 111 Standards and the
Power Sector: Considerations and Options for
Setting Standards and Providing Compliance
Flexibility to Units and States. Pg. 5. Public
comments submitted to the EPA’s pre-proposal
rulemaking, Docket ID No. EPA–HQ–OAR–2022–
0723.
61 Post-combustion CO capture is most common,
2
but as discussed later in this preamble, there are
also pre-combustion CO2 capture options available
and applicable to the power sector.
62 40 CFR 261.4(h).
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2010.63 In addition, new policies such
as the IRA, enacted in 2022, support the
deployment of CCS technology and will
further reduce the cost of implementing
CCS by extending and increasing the tax
credit for CCS under Internal Revenue
Code section 45Q.
There are several examples of the
application of CCS at EGUs, some of
which are noted here with further detail
provided in section VII.F.3.b.iii(A) of
this preamble. These include
SaskPower’s Boundary Dam Unit 3, a
110–MW lignite-fired unit in
Saskatchewan, Canada, which has
achieved CO2 capture rates of 90 percent
using an amine-based post-combustion
capture system retrofitted to the existing
steam generating unit.64 Amine-based
carbon capture has also been
demonstrated at AES’s Warrior Run
(Cumberland, Maryland) and Shady
Point (Panama, Oklahoma) coal-fired
power plants.65
CCS has also been successfully
applied to an existing combined cycle
combustion turbine EGU at the
Bellingham Energy Center in south
central Massachusetts, and other
projects are in different stages of
deployment. The 40–MW slipstream
capture facility at the Bellingham
Energy Center operated from 1991 to
2005 and captured 85 to 95 percent of
the CO2 in the slipstream.66 In Scotland,
the proposed 900–MW Peterhead Power
Station combined cycle EGU with CCS
is in the planning stages of deployment
and will have the potential to capture 90
percent of its CO2 emissions.67
Moreover, an 1,800–MW combined
cycle EGU that will be constructed in
West Virginia and will utilize CCS has
been announced. The project is planned
to begin operation later this decade, and
63 Technology Readiness and Costs of CCS (2021).
Global CCS Institute. https://www.globalccs
institute.com/wp-content/uploads/2021/03/
Technology-Readiness-and-Costs-for-CCS-20211.pdf.
64 Giannaris, S., et al. Proceedings of the 15th
International Conference on Greenhouse Gas
Control Technologies (March 15–18, 2021).
SaskPower’s Boundary Dam Unit 3 Carbon Capture
Facility–The Journey to Achieving Reliability.
https://papers.ssrn.com/sol3/papers.cfm?abstract_
id=3820191.
65 Dooley, J.J., et al. (2009). ‘‘An Assessment of the
Commercial Availability of Carbon Dioxide Capture
and Storage Technologies as of June 2009.’’ U.S.
DOE, Pacific Northwest National Laboratory, under
Contract DE–AC05–76RL01830.
66 U.S. Department of Energy (DOE). Carbon
Capture Opportunities for Natural Gas Fired Power
Systems. https://www.energy.gov/fecm/articles/
carbon-capture-opportunities-natural-gas-firedpower-systems.
67 Buli, N. (2021, May 10). SSE, Equinor plan new
gas power plant with carbon capture in Scotland.
Reuters. https://www.reuters.com/business/
sustainable-business/sse-equinor-plan-new-gaspower-plant-with-carbon-capture-scotland-2021-0511/.
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its economic feasibility was partially
credited to the expanded IRC section
45Q tax credit for sequestered CO2
provided through the IRA.68
In developing these proposals, the
EPA reviewed the current state of CCS
technology and costs, including the use
of CCS with both steam generating units
and combustion turbines. This review is
reflected in the BSER discussions later
in this preamble and is further detailed
in the accompanying RIA and technical
support documents titled, GHG
Mitigation Measures for Steam
Generating Units and GHG Mitigation
Measures—Carbon Capture and Storage
for Combustion Turbines. The three
documents are included in the
rulemaking docket.
D. Natural Gas Co-Firing
For a coal-fired steam generating unit,
the substitution of natural gas for some
of the coal so that the unit fires a
combination of coal and natural gas is
known as ‘‘natural gas co-firing.’’ Most
existing coal-fired steam generating
units can be modified to co-fire natural
gas in any desired proportion with coal.
Generally, the modification of existing
boilers to enable or increase natural gas
firing typically involves the installation
of new gas burners and related boiler
modifications as well as the
construction of natural gas supply
pipelines. In recent years, the cost of
natural gas co-firing has declined
because the expected difference
between coal and gas prices has
decreased to about $1/MMBtu and
recent analyses support lower capital
costs for modifying existing boilers to
co-fire with natural gas, as discussed in
section X.D.2 of this preamble.
In developing these proposals, the
EPA reviewed in detail the current state
of natural gas co-firing technology and
costs. This review is reflected in the
BSER discussions later in this preamble
and is further detailed in the
accompanying RIA and GHG Mitigation
Measures for Steam Generating Units
TSD. Both documents are included in
the rulemaking docket.
E. Hydrogen Co-Firing
Industrial combustion turbines have
been burning byproduct fuels
containing large percentages of
hydrogen for decades, and recently,
utility combustion turbines in the power
sector have begun to co-fire hydrogen as
68 Competitive Power Ventures (2022). MultiBillion Dollar Combined Cycle Natural Gas Power
Station with Carbon Capture Announced in West
Virginia. Press Release. September 16, 2022. https://
www.cpv.com/2022/09/16/multi-billion-dollarcombinedcycle-natural-gas-power-station-withcarbon-capture-announced-in-west-virginia/.
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a fuel to generate electricity. Hydrogen
contains no carbon, and when
combusted in a turbine, produces zero
direct CO2 emissions. However, as
discussed in section IV.F.3 of this
preamble, the manufacture of hydrogen,
depending on the method of production,
can generate GHG emissions. As noted
previously, there has been a growing
interest in the use of hydrogen as a fuel
for combustion turbines to generate
electricity. Many models of new utility
combustion turbines have demonstrated
the ability to co-fire up to 30 percent
hydrogen and developers are working
toward models that will be ready to
combust 100 percent hydrogen by 2030.
Furthermore, several utilities are cofiring hydrogen in test burns; and some
have announced plans to move to
combusting 100 percent hydrogen in the
2035–2045 timeframe. Specifically, the
Los Angeles Department of Water and
Power’s (LADWP) Scattergood
Modernization project includes plans to
have a hydrogen-ready combustion
turbine in place when the 346–MW
combined cycle plant (potential for up
to 830 MW) begins initial operations in
2029. LADWP foresees the plant
running on 100 percent electrolytic
hydrogen by 2035.69 In addition,
LADWP also has an agreement in place
to purchase electricity from the
Intermountain Power Agency project
(IPA) in Utah. IPA is replacing an
existing 1.8–GW coal-fired EGU with an
840–MW combined cycle turbine that
developers expect to initially co-fire 30
percent electrolytic hydrogen in 2025
and 100 percent hydrogen by 2045.70 In
Florida, NextEra Energy has announced
plans to operate 16 GW of existing
natural gas-fired combustion turbines
with electrolytic hydrogen as part of the
utility’s Zero Carbon Blueprint to be
carbon-free by 2045.71 Duke Energy
Corporation, which operates 33 gas-fired
plants across the Midwest, the
Carolinas, and Florida, has outlined
plans for full hydrogen capabilities
throughout its future turbine fleet: ‘‘All
natural gas units built after 2030 are
assumed to be convertible to full
hydrogen capability. After 2040, only
peaking units that are fully hydrogen
capable are assumed to be built.’’ 72
69 https://clkrep.lacity.org/onlinedocs/2023/230039_rpt_DWP_02-03-2023.pdf.
70 https://www.forbes.com/sites/mitsubishi
heavyindustries/2021/07/30/eager-to-becomehydrogen-ready-power-plants-turn-to-dual-fuelturbines/?sh=38ddea053476.
71 https://www.nexteraenergy.com/content/dam/
nee/us/en/pdf/NextEraEnergyZero
CarbonBlueprint.pdf.
72 https://www.duke-energy.com/_/media/PDFs/
our-company/Climate-Report-2022.pdf.
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In addition to those three utility
announcements, several merchant
generators operating in wholesale
markets are also signaling their intent to
ramp up hydrogen co-firing levels after
initial 30 percent co-firing phases. The
Cricket Valley Energy Center (CVEC) in
New York is retrofitting its combined
cycle power plant starting in 2022 as a
first step toward the conversion to a 100
percent hydrogen fuel capable plant.
CVEC announcements did not have
specific dates for 100 percent
electrolytic hydrogen firing but
indicated in its announcement that New
York has mandated achieving a zeroemission electricity sector by 2040.73
The Long Ridge Energy Terminal in
Ohio, which is has successfully co-fired
a 5 percent hydrogen blend at its 485–
MW combined cycle plant, noted its
technology has the capability to
transition to 100 percent hydrogen over
time as its low-GHG fuel supply
becomes available.74 Constellation
Energy, which owns 23 natural gas-fired
or dual fuel generators (8.6 GW), is
exploring electrolytic hydrogen co-firing
across its fleet. It estimated costs for
blend levels in the range of 60–100
percent at approximately $100/kW for
retrofits and noted that equipment
manufacturers are planning 100 percent
hydrogen combustion-ready turbines
before 2030.75
In both the IIJA and the IRA, Congress
provided extensive support for the
development of hydrogen produced
through low-GHG methods. This
support includes investment in
infrastructure through the IIJA, and the
provision of tax credits in the IRA to
incentivize the manufacture of hydrogen
through low GHG-emitting methods.
These incentives are fueling interest in
co-firing hydrogen and creating
expectations that the availability of lowcost and low-GHG hydrogen will
increase in the coming years. These
projections are based on a combination
of economies of scale as low-GHG
production methods expand, the
increasing availability of low-cost
electricity—largely powered by
renewable energy sources and
potentially nuclear energy—and
learning by doing as more turbine
projects are developed.
73 https://www.cricketvalley.com/news/cricketvalley-energy-center-and-ge-sign-agreement-to-helpreduce-carbon-emissions-in-new-york-with-greenhydrogen-fueled-power-plant/.
74 GE-powered gas-fired plant in Ohio now
burning hydrogen (power-eng.com).
75 Constellation Energy Corporation’s Comments
on EPA Draft White Paper: Available and Emerging
Technologies for Reducing Greenhouse Gas
Emissions from Combustion Turbine Electric
Generating Units Docket ID No. EPA–HQ–OAR–
2022–0289–0022.
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In developing these proposals, the
EPA reviewed in detail the current state
of hydrogen co-firing technology and
costs. This review is reflected in the
BSER discussions later in this preamble
and is further detailed in the
accompanying RIA and technical
support document titled, Hydrogen in
Combustion Turbine Electric Generating
Units. Both documents are included in
the rulemaking docket.
F. Recent Changes in the Power Sector
1. Overview
The electric power sector is
experiencing a prolonged period of
transition and structural change. Since
the generation of electricity from coalfired power plants peaked nearly two
decades ago, the power sector has
changed at a rapid pace. Today, natural
gas-fired power plants provide the
largest share of net generation, coal-fired
power plants provide a significantly
smaller share than in the recent past,
renewable energy provides a steadily
increasing share, and as new
technologies enter the marketplace,
power producers continue to replace
aging assets with more efficient and
lower cost alternatives.
These developments have significant
implications for the types of controls
that the EPA proposes to determine
qualify as the BSER for different types
of fossil fuel-fired EGUs. For example,
many utilities and power plant
operators have announced plans to
voluntarily cease operating coal-fired
power plants in the near future, in some
cases after operating them at low levels
for a several-year period. Industry
stakeholders have requested that the
EPA structure this rule to avoid
imposing costly control obligations on
coal-fired power plants that have
announced plans to voluntarily cease
operations, and the EPA proposes to
accommodate those requests. In
addition, the EPA recognizes that
utilities and power plant operators are
building new natural gas-fired
combustion turbines with plans to
operate them at varying levels of
utilization, in coordination with other
existing and expected new energy
sources. These patterns of operation are
important for the type of controls that
the EPA is proposing as the BSER for
these turbines.
This section discusses the recent
trends in the power sector. It also
includes a summary of the provisions
and incentives included in recent
Federal legislation that will impact the
power sector as well as State actions
and commitments by power producers
to reduce GHG emissions. The section
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2. Broad Trends Within the Power
Sector
For more than a decade, the power
sector has experienced substantial
transition and structural change, both in
terms of the mix of generating capacity
and in the share of electricity generation
supplied by different types of EGUs.
These changes are the result of multiple
factors, including normal replacements
of older EGUs; changes in electricity
demand across the broader economy;
growth and regional changes in the U.S.
population; technological improvements
in electricity generation from both
existing and new EGUs; changes in the
prices and availability of different fuels;
State and Federal policy; the
preferences and purchasing behaviors of
end-use electricity consumers; and
substantial growth in electricity
generation from renewable sources.
One of the most important
developments of this transition has been
the evolving economics of the power
sector. Specifically, the existing fleet of
coal-fired EGUs continues to age and
become more costly to maintain and
operate. At the same time, the supply
and availability of natural gas has
increased significantly, and its price has
held relatively low. For the first time, in
April 2015, natural gas surpassed coal
in monthly net electricity generation
and since that time has maintained its
position as the primary fossil fuel for
base load energy generation, for peaking
applications, and for balancing
renewable generation.76 Additionally,
there has been increased generation
from investments in zero- and low-GHG
emission energy technologies spurred
by technological advancements,
declining costs, State and Federal
policies, and most recently, the IIJA and
the IRA. For example, the IIJA provides
investments and other policies to help
commercialize, demonstrate, and deploy
technologies such as small modular
nuclear reactors, long-duration energy
storage, regional clean hydrogen hubs,
carbon capture and storage and
associated infrastructure, advanced
geothermal systems, and advanced
distributed energy resources (DER) as
well as more traditional wind and solar
resources. The IRA provides numerous
tax and other incentives to directly spur
deployment of clean energy
technologies. Particularly relevant to
these proposals, the incentives in the
76 U.S. Energy Information Administration (EIA).
Monthly Energy Review and Short-Term Energy
Outlook, March 2016. https://www.eia.gov/
todayinenergy/detail.php?id=25392.
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IRA,77 which are discussed in detail
later in this section of the preamble,
support the expansion of technologies,
such as CCS and hydrogen technologies,
that reduce GHG emissions from fossilfired units.
The ongoing transition of the power
sector is illustrated by a comparison of
data between 2010 and 2021. In 2010,
approximately 70 percent of the
electricity provided to the U.S. grid was
produced through the combustion of
fossil fuels, primarily coal and natural
gas, with coal accounting for the largest
single share. By 2021, fossil fuel net
generation was approximately 60
percent, less than the share in 2010
despite electricity demand remaining
relatively flat over this same time
period. Moreover, the share of fossil
generation supplied by coal-fired EGUs
fell from 46 percent in 2010 to 23
percent in 2021 while the share
supplied by natural gas-fired EGUs rose
from 23 to 37 percent during the same
period. In absolute terms, coal-fired
generation declined by 51 percent while
natural gas-fired generation increased by
64 percent. This reflects both the
increase in natural gas capacity as well
as an increase in the utilization of new
and existing gas-fired EGUs. The
combination of wind and solar
generation also grew from 2 percent of
the electric power sector mix in 2010 to
12 percent in 2021.78
The broad trends throughout the
power sector can also be seen in the
number of commitments and announced
plans of many EGU owners and
operators across the industry to
decarbonize—spanning all types of
companies in all locations. Moreover,
State governments, which traditionally
regulate investment decisions regarding
electricity generation, have
implemented their own policies to
reduce GHG emissions from power
generation.
Additional analysis of the utility
power sector, including projections of
future power sector behavior and the
impacts of these proposed rules, is
discussed in more detail in section XV
of this preamble, in the accompanying
RIA, and in the Power Sector Trends
technical support document (TSD). The
latter two documents are available in
the rulemaking docket. Consistent with
77 U.S. Department of Energy (DOE). August 2022.
The Inflation Reduction Act Drives Significant
Emissions Reductions and Positions America to
Reach Our Climate Goals. https://www.energy.gov/
sites/default/files/2022-08/8.18%20Inflation
ReductionAct_Factsheet_Final.pdf.
78 U.S. Energy Information Administration (EIA).
Annual Energy Review, table 8.2b Electricity net
generation: electric power sector. https://
www.eia.gov/totalenergy/data/annual/.
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analyses done by other energy modelers,
the RIA and TSD demonstrate that the
sector trend of moving away from coalfired generation is likely to continue
and that non-emitting technologies may
eventually displace certain natural gasfired combustion turbines.
3. Trends in Coal-Fired Generation
Coal-fired steam generating units have
historically been the nation’s foremost
source of electricity, but coal-fired
generation has declined steadily since
its peak approximately 20 years ago.79
Construction of new coal-fired steam
generating units was at its highest
between 1967 and 1986, with
approximately 188 GW (or 9.4 GW per
year) of capacity added to the grid
during that 20-year period.80 The peak
annual capacity addition was 14 GW,
which was added in 1980. These coalfired steam generating units operated as
base load units for decades. However,
beginning in 2005, the U.S. power
sector—and especially the coal-fired
fleet—began experiencing a period of
transition that continues today. Many of
the older coal-fired steam generating
units built in the 1960s, 1970s, and
1980s have retired and/or have
experienced significant reductions in
net generation due to cost pressures and
other factors. Some of these coal-fired
steam generating units repowered with
combustion turbines and natural gas.81
And with no new coal-fired steam
generating units commencing
construction in more than a decade—
and with the EPA unaware of any plans
by any companies to construct a new
coal-fired EGU—much of the fleet that
remains is aging, expensive to operate
and maintain, and increasingly
uncompetitive relative to other sources
of generation in many parts of the
country.
Since 2010, the power sector’s total
installed capacity 82 has increased by
79 U.S. Energy Information Administration (EIA).
Today in Energy. Natural gas expected to surpass
coal in mix of fuel used for U.S. power generation
in 2016. March 2016. https://www.eia.gov/
todayinenergy/detail.php?id=25392.
80 U.S. Energy Information Administration (EIA).
Electric Generators Inventory, Form EIA–860M,
Inventory of Operating Generators and Inventory of
Retired Generators, March 2022. https://
www.eia.gov/electricity/data/eia860m/.
81 U.S. Energy Information Administration (EIA).
Today in Energy. More than 100 coal-fired plants
have been replaced or converted to natural gas
since 2011. August 2020. https://www.eia.gov/
todayinenergy/detail.php?id=44636.
82 This includes generating capacity at EGUs
primarily operated to supply electricity to the grid
and combined heat and power (CHP) facilities
classified as Independent Power Producers and
excludes generating capacity at commercial and
industrial facilities that does not operate primarily
as an EGU. Natural gas information reflects data for
all generating units using natural gas as the primary
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144 GW (14 percent), while coal-fired
steam generating unit capacity has
declined by 107 GW. This reduction in
coal-fired steam generating unit capacity
was offset by an increase in total
installed wind capacity of 93 GW,
natural gas capacity of 84 GW, and an
increase in utility-scale solar capacity of
60 GW during the same period.
Additionally, significant amounts of
DER solar (33 GW) were also added.
Two-thirds or more of these changes
were in the most recent 6 years of this
period. From 2015–2021, coal capacity
was reduced by 70 GW and this
reduction in capacity was offset by a net
increase of 60 GW of wind capacity, 52
GW of natural gas capacity, and 47 GW
of utility-scale solar capacity.
Additionally, 23 GW of DER solar were
also added from 2015 to 2021.
At the end of 2021, there were more
than 500 EGUs totaling 212 GW of coalfired capacity remaining in the U.S.
Although much of the fleet of coal-fired
steam generating units has historically
operated as base load, there can be
notable differences in design and
operation across various facilities. For
example, coal-fired steam generating
units smaller than 100 MW comprise 18
percent of the total number of coal-fired
units, but only 2 percent of total coalfired capacity.83 Moreover, average
annual capacity factors for coal-fired
steam generating units have declined
from 67 to 49 percent since 2010,84
indicating that a larger share of units are
operating in non-base load fashion.
Older power plants also tend to
become uneconomic over time as they
become more costly to maintain and
operate,85 especially when competing
for dispatch against newer and more
efficient generating technologies that
have lower operating costs. The average
coal-fired power plant that retired
between 2015 and 2021 was more than
50 years old, and 65 percent of the
remaining fleet of coal-fired steam
generating units will be 50 years old or
more within a decade.86 To further
illustrate this trend, the existing coalfired steam generating units older than
40 years represent 71 percent (154
GW) 87 of the total remaining capacity.
In fact, more than half (118 GW) of the
coal-fired steam generating units still
operating have already announced
retirement dates prior to 2040.88 As
discussed further in this section,
projections anticipate that this trend
will continue.
The reduction in coal-fired generation
by electric utilities is also evident in
data for annual U.S. coal production,
which reflects reductions in
international demand as well. In 2008,
annual coal production peaked at nearly
1,200 million short tons (MMst)
followed by sharp declines in 2015 and
2020.89 In 2015, less than 900 MMst
were produced, and in 2020, the total
dropped to 535 MMst, the lowest output
since 1965.
fossil heat source unless otherwise stated. This
includes combined cycle, simple cycle, steam, and
miscellaneous (<1 percent).
83 U.S. Environmental Protection Agency.
National Electric Energy Data System (NEEDS) v6.
October 2022. https://www.epa.gov/power-sectormodeling/national-electric-energy-data-systemneeds.
84 U.S. Energy Information Administration (EIA).
Electric Power Annual 2021, table 1.2.
85 U.S. Energy Information Administration (EIA).
U.S. coal plant retirements linked to plants with
higher operating costs. December 2019. https://
www.eia.gov/todayinenergy/detail.php?id=42155.
86 eGRID 2020 (January 2022 release from EPA
eGRID website). Represents data from generators
that came online between 1950 and 2020
(inclusive); a 71-year period. Full eGRID data
includes generators that came online as far back as
1915.
87 U.S. Energy Information Administration (EIA).
Electric Generators Inventory, Form-860M,
Inventory of Operating Generators and Inventory of
Retired Generators. August 2022. https://
www.eia.gov/electricity/data/eia860m/.
88 U.S. Environmental Protection Agency.
National Electric Energy Data System (NEEDS) v6.
October 2022. https://www.epa.gov/power-sectormodeling/national-electric-energy-data-systemneeds.
89 U.S. Energy Information Administration (EIA).
Annual Coal Report. Table ES–1. October 2022.
https://eia.gov/coal/annual/pdf/tableES1.pdf.
90 U.S. Energy Information Administration (EIA).
Natural Gas Explained. December 2022. https://
www.eia.gov/energyexplained/natural-gas/.
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4. Trends in Natural Gas-Fired
Generation
In the lower 48 states, most
combustion turbine EGUs burn natural
gas, and some have the capability to fire
distillate oil as backup for periods when
natural gas is not available, such as
when residential demand for natural gas
is high during the winter. Areas of the
country without access to natural gas
often use distillate oil or some other
locally available fuel. Combustion
turbines have the capability to burn
either gaseous or liquid fossil fuels,
including but not limited to kerosene,
naphtha, synthetic gas, biogases,
liquified natural gas (LNG), and
hydrogen.
Natural gas consists primarily of
methane, and after the raw gas is
extracted from the ground, it is
processed to remove impurities and to
separate the methane from other gases
and natural gas liquids to produce
pipeline quality gas.90 This gas is sent
to intermediate storage facilities prior to
being piped through transmission feeder
lines to a distribution network on its
path to storage facilities or end users.
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During the past 20 years, advances in
hydraulic fracturing (i.e., fracking) and
horizontal drilling techniques have
opened new regions of the U.S. to gas
exploration.
According to the U.S. Energy
Information Administration (EIA),
annual natural gas marketed production
in the U.S. remained consistent at
approximately 20 trillion cubic feet
(Tcf) from the 1970s to the early 2000s.
However, since 2005, annual natural gas
marketed production has steadily
increased and approached 35 Tcf in
2021, which is an average of
approximately 94.6 billion cubic feet
per day.91 Thirty-four states produce
natural gas with Texas (24.6 percent),
Pennsylvania (21.8 percent), Louisiana
(9.9 percent), West Virginia (7.4
percent), and Oklahoma (6.7 percent)
accounting for approximately 70 percent
of total production. Natural gas
production exceeded consumption in
the U.S. for the first time in 2017.
As the production of natural gas has
increased, the annual average price has
declined during the same period.92 In
2008, U.S. natural gas prices peaked at
$13.39 per million British thermal units
($/MMBtu) for residential customers. By
2020, the price was $10.45/MMBtu. The
decrease in average annual natural gas
prices can also been seen in city gate
prices (i.e., a point or measuring station
where natural gas is transferred from
long-distance pipelines to a local
distribution company), which peaked in
2008 at $8.85/MMBtu. By 2020, city gate
prices were $3.30/MMBtu. An
equivalent $/MMBtu basis is a common
way to compare natural gas and coal
fuel prices. For example, the price of
Henry Hub natural gas in July 2022 was
$7.39/MMBtu while the spot price of
Central Appalachian coal was $7.25/
MMBtu for the same month. However,
this method of fuel price comparison
based on equivalent energy content does
not reflect differences in energy
conversion efficiency (i.e., heat rate) and
other factors among different types of
generators. Because natural gas-fired
combustion turbines are more efficient
than coal-fired steam units, any fuel cost
comparison should include an
efficiency basis (dollar per megawatthour) to the equivalent energy content.
For illustrative purposes, an EIA
comparison based on this method
showed that the Henry Hub natural gas
91 U.S. Energy Information Administration (EIA).
Natural gas explained. Where our natural gas comes
from. https://www.eia.gov/energyexplained/naturalgas/where-our-natural-gas-comes-from.php.
92 U.S. Energy Information Administration (EIA).
Natural Gas Annual, September 2021. https://
www.eia.gov/energyexplained/natural-gas/
prices.php.
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price in July 2022 was $59.18/MWh and
the price for Central Appalachian coal
was $78.25/MWh for the same month.93
There has been significant expansion
of the natural gas-fired EGU fleet since
2000, coinciding with efficiency
improvements of combustion turbine
technologies, increased availability of
natural gas, increased demand for
flexible generation to support the
expanding capacity of renewable energy
resources, and declining costs for all
three elements. According to data from
EIA, annual capacity additions for
natural gas-fired EGUs peaked between
2000 and 2006, with more than 212 GW
added to the grid during this period. Of
this total, approximately 147 GW (70
percent) were combined cycle capacity
and 65 GW were simple cycle
capacity.94 From 2007 to 2021, more
than 125 GW of capacity were
constructed and approximately 78
percent of that total were combined
cycle EGUs. This figure represents an
average of almost 4.2 GW of new
combustion turbine generation capacity
per year. In 2021, the net summer
capacity of combustion turbine EGUs
totaled 413 GW, with 281 GW being
combined cycle generation and 132 GW
being simple cycle generation.
This trend away from coal to natural
gas is also reflected in comparisons of
annual capacity factors, sizes, and ages
of affected EGUs. For example, the
annual average capacity factors for
natural gas-fired units increased from 28
to 37 percent between 2010 and 2021.
And compared with the fleet of coalfired steam generating units, the natural
gas fleet is generally smaller and newer.
While 67 percent of the coal-fired steam
generating unit fleet capacity is over 500
MW per unit, 75 percent of the gas fleet
is between 50 and 500 MW per unit. In
terms of the age of the generating units,
nearly 50 percent of the natural gas
capacity has been in service less than 15
years.95
As explained in greater detail later in
this preamble and in the accompanying
RIA, future capacity projections for
natural gas-fired combustion turbines
differ from those highlighted in recent
93 U.S. Energy Information Administration (EIA).
Electric Monthly Update. September 23. 2022.
Report derived from Bloomberg Energy. EIA notes
that the competition between coal and natural gas
to produce electricity is complex, involving
delivered prices and emission costs, the terms of
fuel supply contracts, and the workings of fuel
markets.
94 U.S. Energy Information Administration (EIA).
Electric Generators Inventory, Form EIA–860M,
Inventory of Operating Generators and Inventory of
Retired Generators, July 2022. https://www.eia.gov/
electricity/data/eia860m/.
95 National Electric Energy Data System (NEEDS)
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historical trends. The largest source of
new generation is from renewable
energy and projections show that total
natural gas-fired combined cycle
capacity is likely to decline after 2030
in response to increased generation from
renewables, energy storage, and other
technologies, as discussed in section
IV.I. Approximately, 86 percent of
capacity additions in 2023 are expected
to be from non-emitting generation
resources including solar, wind,
nuclear, and energy storage.96 The IRA
is likely to accelerate this trend, which
is also expected to impact the operation
of certain combustion turbines. For
example, as the electric output from
additional non-emitting generating
sources fluctuates daily and seasonally,
flexible low and intermediate load
combustion turbines will be needed to
support these variable sources and
provide reliability to the grid. This
requires the ability to start and stop
quickly and change load more
frequently.
5. Trends in Renewable Generation
Renewable sources of electric
generation—especially solar and wind—
have expanded in the U.S. during the
past decade. This growth has coincided
with a reduction in the costs of the
technologies, supportive State and
Federal policies, and increased
consumer demand for low-GHG
electricity. In 2021, renewable energy
sources produced approximately 20
percent of the nation’s net generation,
led by wind (9.2 percent), hydroelectric
(6.3 percent), solar (2.8 percent), and
other sources such as geothermal and
biomass (1.7 percent).97
The costs of renewable energy sources
have fallen over time due to
technological advances, improvements
in performance, and increased demand
for clean energy. For example, the
unsubsidized average levelized cost of
wind energy from 1988 to 1999 was
$106/MWh and has since declined to
$32/MWh in 2021.98 The average
levelized cost of energy for utility-scale
solar photovoltaics has fallen from
$227/MWh in 2010 to $33/MWh in
96 U.S. Energy Information Administration (EIA).
Today in Energy. More than half of new U.S.
electric-generating capacity in 2023 will be solar.
February 2023. https://www.eia.gov/todayinenergy/
detail.php?id=55419.
97 U.S. Energy Information Administration (EIA).
Monthly Energy Review, table 7.2B Electricity Net
Generation: Electric Power Sector, May 2022.
https://www.eia.gov/totalenergy/data/monthly/.
98 U.S. Department of Energy (DOE), Land-Based
Wind Market Report: 2022 Edition, 2022. https://
www.energy.gov/eere/wind/articles/land-basedwind-market-report-2022-edition.
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2021.99 And the National Renewable
Energy Laboratory (NREL) has
documented cost decreases of 64, 69,
and 82 percent, respectively, for
residential-, commercial-, and utilityscale solar installations since 2010.100
Local, State, and Federal incentives and
tax credits have further reduced the cost
of renewable energy resources.
During the past 15 years, more than
122 GW of wind (primarily onshore)
and 61 GW of solar capacity have been
constructed, which represent a tripling
of wind capacity and a 20-fold increase
in solar capacity.101 Prior to 2007, no
more than 2.6 GW of new wind capacity
was built in any year, and the wind
capacity added from 2000 to 2006
averaged 1.2 GW per year. In 2007, the
nation added 5.3 GW of total wind
capacity and the annual average was 7.2
GW through 2019. Wind capacity
additions peaked in the past 2 years at
a total of nearly 29 GW. For solar, the
pattern of expansion is similar. For
example, from 2000 to 2006, a total of
11 MW of new solar capacity was
constructed, and from 2007 to 2011,
total capacity additions increased to 1.2
GW. However, from 2012 to 2019, more
than 36 GW of solar capacity was built
(an average of 4.5 GW per year). And in
2020 and 2021, new solar capacity
totaled of 24 GW. In terms of the net
operating share of summer capacity in
2021, wind produced 46 percent of all
renewable energy while solar generated
21 percent. The remaining electricity
generated from renewables included 28
percent from hydroelectric and 5
percent from other sources that include
geothermal systems, biogases/
biomethane from landfills, woody
materials and other biomass, and
municipal solid waste.
There are also emerging technologies
such as battery storage that have
demonstrated the ability to further
support the development and
integration of renewable energy to the
grid by balancing variable supply and
demand resources. At the end of 2021,
there were 331 large-scale battery
storage systems operating in the U.S.
with a combined capacity of 4.8 GW
99 Lawrence Berkeley National Laboratory
(LBNL), Utility-Scale Solar Technical Brief, 2022
Edition, September 2022. https://emp.lbl.gov/
utility-scale-solar.
100 https://www.nrel.gov/news/program/2021/
documenting-a-decade-of-cost-declines-for-pvsystems.html.
101 U.S. Energy Information Administration (EIA),
Electric Generators Inventory, Form-860M,
Inventory of Operating Generators and Inventory of
Retired Generators, July 2022. https://www.eia.gov/
electricity/data/eia860m/.
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(10.7 GWh).102 In terms of small-scale
battery storage, there were 781 MW of
reported capacity in 2021, mostly in
California.103 Energy storage costs
declined 72 percent between 2015 and
2019,104 and declining costs have led to
additional capacity being installed at
each facility, and this increases the
duration of each system when operating
at maximum output. With 20.8 GW of
grid storage already announced for
2023–2025, EIA expects that capacity
will more than triple from 7.8 GW in
late 2022 to approximately 30 GW by
the end of 2025.105
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6. Trends in Nuclear Generation
The U.S. power sector continues to
rely on nuclear sources of energy for a
consistent portion of net generation.
Since 1990, nuclear energy has provided
about 20 percent of the nation’s
electricity, and 92 reactors were
operating at 54 nuclear power plants in
28 states in 2022.106
It should be noted that despite the
consistent output from nuclear power
plants over time, the number of
operating reactors has recently declined.
The average retirement age for a nuclear
reactor is 44 years and the average age
of the remaining nuclear fleet is
currently 42 years, although age is only
one consideration for determining when
a nuclear plant may retire. For example,
nuclear generating units at Dominion
Generation’s Surry plant, Florida Power
& Light’s Turkey Point plant, and
Constellation Energy’s Peach Bottom
plant applied to the Nuclear Regulatory
Commission (NRC) for second 20-year
license renewals and subsequent
renewed licenses were granted for six
units, although four of the six units have
not had their license terms extended
beyond the periods of their first
renewed licenses and are undergoing
further environmental review.107 Others
102 U.S. Energy Information Administration (EIA).
Annual Electric Generator Report, 2021 Form EIA–
860. https://www.eia.gov/electricity/data/eia860/.
103 U.S. Energy Information Administration (EIA).
Annual Electric Power Industry Report, 2021 Form
EIA–861. https://www.eia.gov/electricity/data/
eia861/.
104 U.S. Energy Information Administration (EIA).
Annual Electric Generator Report, 2019 Form EIA–
860. https://www.eia.gov/analysis/studies/
electricity/batterystorage/.
105 U.S. Energy Information Administration (EIA).
Today in Energy. U.S. battery storage capacity will
increase significantly by 2025. December 2022.
https://www.eia.gov/todayinenergy/detail.
php?id=54939.
106 U.S. Energy Information Administration (EIA).
Electric Generators Inventory, Form-860M,
Inventory of Operating Generators and Inventory of
Retired Generators. August 2022. https://
www.eia.gov/electricity/data/eia860m/.
107 U.S. Nuclear Regulatory Commission (NRC).
Status of Subsequent License Renewal
Applications. April 2023. https://www.nrc.gov/
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who have applied to the NRC for a
second 20-year license renewal include
Dominion for its North Anna units 1
and 2; NextEra Energy for its Point
Beach units 1 and 2; Duke Energy
Carolinas for its Oconee units 1, 2, and
3; Florida Power & Light for its St. Lucie
units 1 and 2; and Northern States
Power Company for its Monticello unit
1. If granted, these additional licenses
would also extend the lifespans of these
units well past the 42-year average.
Recent State and Federal policies,
including the DOE’s $6 billion Civilian
Nuclear Credit program enacted by the
IIJA and the 45U tax credit (discussed
below), are intended to support the
continued operation of existing nuclear
power plants.
There is also interest in the next
generation of nuclear technologies.
Small modular nuclear reactors, which
can provide both firm dispatchable
power and load-following capabilities to
balance greater volumes of variable
renewable generation, could play a role
in future energy generation. The NRC
has issued a final rule certifying the first
small modular reactor design.108
Expectations with respect to output
from advanced nuclear generation vary,
from negligible on the low end to as
high as between 1,400 and 3,600
terawatt-hours per year by 2050.109
According to one survey by the Nuclear
Energy Institute, utilities are currently
considering building more than 90 GW
of small modular nuclear reactors by
2050.110
G. GHG Emissions From Fossil FuelFired EGUs
The principal GHGs that accumulate
in the Earth’s atmosphere above preindustrial levels because of human
activity are CO2, CH4, N2O, HFCs, PFCs,
and SF6. Of these, CO2 is the most
abundant, accounting for 80 percent of
all GHGs present in the atmosphere.
This abundance of CO2 is largely due to
the combustion of fossil fuels by the
transportation, electricity, and
industrial sectors.111
reactors/operating/licensing/renewal/subsequentlicense-renewal.html.
108 88 FR 3287 (January 19, 2023).
109 Stein, A., Messinger, J., Wang, S., Lloyd, J.,
McBride, J., Franovich, R. (July 6, 2022).
‘‘Advancing Nuclear Energy: Evaluating
Deployment, Investment, and Impact in America’s
Clean Energy Future.’’ Breakthrough Institute.
https://thebreakthrough.imgix.net/AdvancingNuclear-Energy_v3-compressed.pdf.
110 Derr, E. (July 29, 2022). Energy Studies and
Models Show Advanced Nuclear as the Backbone
of Our Carbon-Free Future. Nuclear Energy Institute
(NEI). https://www.nei.org/news/2022/studies-andmodels-show-demand-for-adv-nuclear.
111 U.S. Environmental Protection Agency (EPA).
Overview of greenhouse gas emissions. July 2021.
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The amount of CO2 emitted from
fossil fuel-fired EGUs depends on the
carbon content of the fuel and the size
and efficiency of the EGU. Different
fuels emit different amounts of CO2 in
relation to the energy they produce
when combusted. The amount of CO2
produced when a fuel is burned is a
function of the carbon content of the
fuel. The heat content, or the amount of
energy produced when a fuel is burned,
is mainly determined by the carbon and
hydrogen content of the fuel. For
example, in terms of pounds of CO2
emitted per million British thermal
units of energy produced, when
combusted, natural gas is the lowest
compared to other fossil fuels at 117 lb
CO2/MMBtu.112 113 The average for coal
is 216 lb CO2/MMBtu, but varies
between 206 to 229 lb CO2/MMBtu by
type (e.g., anthracite, lignite,
subbituminous, and bituminous).114 The
value for petroleum products such as
diesel fuel and heating oil is 161 lb CO2/
MMBtu.
The EPA prepares the official U.S.
Inventory of Greenhouse Gas Emissions
and Sinks 115 (the U.S. GHG Inventory)
to comply with commitments under the
United Nations Framework Convention
on Climate Change (UNFCCC). This
inventory, which includes recent trends,
is organized by industrial sectors. It
presents total U.S. anthropogenic
emissions and sinks 116 of GHGs,
including CO2 emissions, for the years
1990–2020.
According to the latest inventory, in
2021, total U.S. GHG emissions were
6,340 million metric tons of carbon
dioxide equivalent (MMT CO2e). The
transportation sector (28.5 percent) was
the largest contributor to total U.S. GHG
emissions, followed by the power sector
(25.0 percent) and industrial sources
https://www.epa.gov/ghgemissions/overviewgreenhouse-gases#carbon-dioxide.
112 Natural gas is primarily CH , which has a
4
higher hydrogen to carbon atomic ratio, relative to
other fuels, and thus, produces the least CO2 per
unit of heat released. In addition to a lower CO2
emission rate on a lb/MMBtu basis, natural gas is
generally converted to electricity more efficiently
than coal. According to EIA, the 2020 emissions
rate for coal and natural gas were 2.23 lb CO2/kWh
and 0.91 lb CO2/kWh, respectively. www.eia.gov/
tools/faqs/faq.php?id=74&t=11.
113 Values reflect the carbon content on a per unit
of energy produced on a higher heating value (HHV)
combustion basis and are not reflective of recovered
useful energy from any particular technology.
114 Energy Information Administration (EIA).
Carbon Dioxide Emissions Coefficients. https://
www.eia.gov/environment/emissions/co2_vol_
mass.php.
115 U.S. Environmental Protection Agency (EPA).
Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990–2021. https://cfpub.epa.gov/ghgdata.
116 Sinks are a physical unit or process that stores
GHGs, such as forests or underground or deep-sea
reservoirs of carbon dioxide.
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(23.5 percent). In terms of annual CO2
emissions, the power sector was
responsible for 30.6 percent (1,541
MMT CO2e) of the nation’s 2021 total.
CO2 emissions from the power sector
have declined by 36 percent since 2005
(when the power sector reached annual
emissions of 2,400 MMT CO2, its
historical peak to date).117 The
reduction in CO2 emissions can be
attributed to the power sector’s ongoing
trends away from carbon-intensive coalfired generation and toward more
natural gas-fired and renewable sources.
In 2005, CO2 emissions from coal-fired
EGUs alone measured 1,983 MMT.118
This total dropped to 1,351 MMT in
2015 and reached 974 MMT in 2019, the
first time since 1978 that coal-fired CO2
emissions were below 1,000 MMT. In
2020, emissions of CO2 from coal-fired
EGUs measured 788 MMT before
rebounding in 2021 to 909 MMT due to
increased demand. By contrast, CO2
emissions from natural gas-fired
generation have almost doubled since
2005, increasing from 319 MMT to 613
MMT in 2021, and CO2 emissions from
petroleum products (i.e., distillate fuel
oil, petroleum coke, and residual fuel
oil) declined from 98 MMT in 2005 to
18 MMT in 2021.
When the EPA finalized the Clean
Power Plan (CPP) in October 2015, the
Agency projected that, as a result of the
CPP, the power sector would reduce its
annual CO2 emissions to 1,632 MMT by
2030, or 32 percent below 2005 levels
(2,400 MMT).119 Instead, even in the
absence of Federal regulations for
existing EGUs, annual CO2 emissions
from sources covered by the CPP had
fallen to 1,540 MMT by the end of 2021,
a nearly 36 percent reduction below
2005 levels. The power sector achieved
a deeper level of reductions than
forecast under the CPP and
approximately a decade ahead of time.
By the end of 2015, several months after
the CPP was finalized, those sources
already had achieved CO2 emission
levels of 1,900 MMT, or approximately
21 percent below 2005 levels. However,
progress in emission reductions is not
uniform across all states and so Federal
policies play an essential role. As
discussed earlier in this section, the
power sector remains a leading emitter
of CO2 in the U.S., and, despite the
117 U.S. Environmental Protection Agency (EPA).
Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990–2020. https://cfpub.epa.gov/ghgdata/
inventoryexplorer/#electricitygeneration/
entiresector/allgas/category/all.
118 U.S. Energy Information Administration (EIA).
Monthly Energy Review, table 11.6. September
2022. https://www.eia.gov/totalenergy/data/
monthly/pdf/sec11.pdf.
119 80 FR 63662 (October 23, 2015).
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emission reductions since 2005, current
CO2 levels continue to endanger human
health and welfare. Further, as sources
in other sectors of the economy turn to
electrification to decarbonize, future
CO2 reductions from fossil fuel-fired
EGUs have the potential to take on
added significance and increased
benefits.
The Legislative, Market, and State Law
Context
Recent Legislation Impacting the Power
Sector
On November 15, 2021, President
Biden signed the IIJA 120 (also known as
the Bipartisan Infrastructure Law),
which allocated more than $65 billion
in funding via grant programs, contracts,
cooperative agreements, credit
allocations, and other mechanisms to
develop and upgrade infrastructure and
expand access to clean energy
technologies. Specific objectives of the
legislation are to improve the nation’s
electricity transmission capacity,
pipeline infrastructure, and increase the
availability of low-GHG fuels. Some of
the IIJA programs 121 that will impact
the utility power sector include: $16.5
billion to build and upgrade the nation’s
electric grid; $6 billion in financial
support for existing nuclear reactors that
are at risk of closing and being replaced
by high-emitting resources; and more
than $700 million for upgrades to the
existing hydroelectric fleet. The IIJA
established the Carbon Dioxide
Transportation Infrastructure Finance
and Innovation Program to provide
flexible Federal loans and grants for
building CO2 pipelines designed with
excess capacity, enabling integrated
carbon capture and geologic storage.
The IIJA also allocated $21.5 billion to
fund new programs to support the
development, demonstration, and
deployment of clean energy
technologies, such as $8 billion for the
development of regional clean hydrogen
hubs. Other clean energy technologies
with IIJA funding include carbon
capture, geologic sequestration, direct
air capture, grid-scale energy storage,
and advanced nuclear reactors. States,
Tribes, local communities, utilities, and
others are eligible to receive funding.
The IRA, which President Biden
signed on August 16, 2022,122 has the
potential for even greater impacts on the
electric power sector. With an estimated
120 https://www.congress.gov/bill/117th-congress/
house-bill/3684/text.
121 https://gfoaorg.cdn.prismic.io/gfoaorg/
0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDINGA-BETTER-AMERICA-V2.pdf.
122 https://www.congress.gov/bill/117th-congress/
house-bill/5376/text..
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$369 billion in Energy Security and
Climate Change programs over the next
10 years, covering grant funding and tax
incentives, the IRA provides significant
investments in non GHG-emitting
generation. For example, one of the
conditions set by Congress for the
expiration of the Clean Electricity
Production Tax Credits of the IRA,
found in section 13701, is a 75 percent
reduction in GHG emissions from the
power sector below 2022 levels. The
IRA also contains the Low Emission
Electricity Program (LEEP) with funding
provided to the EPA with the objective
to reduce GHG emissions from domestic
electricity generation and use through
promotion of incentives, tools to
facilitate action, and use of CAA
regulatory authority. In particular, CAA
section 135, added by IRA section
60107, requires the EPA to conduct an
assessment of the GHG emission
reductions expected to occur from
changes in domestic electricity
generation and use through fiscal year
2031 and, further, provides the EPA $18
million ‘‘to ensure that reductions in
[GHG] emissions are achieved through
use of the existing authorities of [the
Clean Air Act], incorporating the
assessment. . ..’’ CAA section 135(a)(6).
The IRA’s provisions also
demonstrate an intent to support
development and deployment of lowGHG emitting technologies in the power
sector through a broad array of
additional tax credits, loan guarantees,
and public investment programs. These
provisions are aimed at reducing
emissions of GHGs from new and
existing generating assets, with tax
credits for carbon capture, utilization,
and storage (CCUS) and clean hydrogen
production providing a pathway for the
use of coal and natural gas as part of a
low-GHG electricity grid. Finally, with
provisions such as the Methane
Emissions Reduction Program, Congress
demonstrated a focus on the importance
of actions to address methane emissions
from petroleum and natural gas systems.
To assist states and utilities in their
decarbonizing efforts, and most germane
to these proposed rulemakings, the IRA
increased the tax credit incentives for
capturing and storing CO2, including
from industrial sources, coal-fired steam
generating units, and natural gas-fired
stationary combustion turbines. The
increase in credit values, found in
section 13104 (which revises IRC
section 45Q), is 70 percent, equaling
$85/metric ton for CO2 captured and
securely stored in geologic formations
and $60/metric ton for CO2 captured
and utilized or securely stored
incidentally in conjunction with
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enhanced oil recovery (EOR).123 The
CCUS incentives include 12 years of
credits that can be claimed at the higher
credit value beginning in 2023 for
qualifying projects. These incentives
will significantly cut costs and are
expected to accelerate the adoption of
CCS in the utility power and other
industrial sectors. Specifically for the
power sector, the IRA requires that a
qualifying carbon capture facility have a
CO2 capture design capacity of not less
than 75 percent of the baseline CO2
production of the unit and that
construction must begin before January
1, 2033. Tax credits under 45Q can be
combined with other tax credits, in
some circumstances, and with Statelevel incentives, including California’s
low carbon fuel standard which is a
market-based program with fuel-specific
carbon intensity benchmarks.124 The
magnitude of this incentive is driving
investment and announcements,
evidenced by the increased number of
permit applications for geologic
sequestration.
The new provisions in section 13204
(IRC section 45V) codify production tax
credits for ‘clean hydrogen’ as defined
in the provision. The value of the
credits earned by a project is tiered (four
different tiers) and depends on the
estimated GHG emissions of the
hydrogen production process from wellto-gate. The credits range from $3/kg H2
for 0.0 to 0.45 kilograms of CO2equivalent emitted per kilogram of lowGHG hydrogen produced (kg CO2e/kg
H2) down to $0.6/kg H2 for 2.5 to 4.0 kg
CO2e/kg H2 (assuming wage and
apprenticeship requirements are met).
Projects with GHG emissions greater
than 4.0 kg CO2e/kg H2 are not eligible.
According to the DOE, current costs for
hydrogen produced from renewable
energy are approximately $5/kg H2.125
These production costs could decline by
2025 to between $2.5 and $2.7/kg H2
(not including the production tax
credits).126
The clean hydrogen production tax
credit is expected to incentivize the
production of low-GHG hydrogen and
123 26
U.S.C. 45Q.
CCS Institute. (2019). The LCFS and
CCS Protocol: An Overview for Policymakers and
Project Developers. Policy report. https://
www.globalccsinstitute.com/wp-content/uploads/
2019/05/LCFS-and-CCS-Protocol_digital_version2.pdf.
125 U.S. Department of Energy (DOE). Hydrogen
and Fuel Cell Technologies Office. Hydrogen Shot.
https://www.energy.gov/eere/fuelcells/hydrogenshot.
126 U.S. Department of Energy (DOE). Pathways to
Commercial Liftoff: Clean Hydrogen, March 2023.
https://www.energy.gov/articles/doe-releases-newreports-pathways-commercial-liftoff-accelerateclean-energy-technologies.
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ultimately exert downward pressure on
costs.127 Low-cost and widely available
low-GHG hydrogen has the potential to
become a material decarbonization lever
in the power sector as the use of lowGHG hydrogen in stationary combustion
turbines reduces direct GHG emissions
as hydrogen releases no CO2 when
combusted. The tiered eligibility
requirements for the clean hydrogen
production tax credit also incentivize
the lowest-GHG emissions production
processes.
Both IRC 45Q and 45V are eligible for
additional provisions that increase the
value and usability of the credits.
Certain tax-exempt entities, such as
electric co-ops, may use direct pay for
the full 12- or 10-year lifetime of the
credits to monetize the credits directly
as cash refunds rather than through tax
equity transactions. Tax-paying entities
may elect to have direct payment of 45Q
or 45V credits for five consecutive years.
Tax-paying entities may also elect to
transfer credits to unrelated taxpayers,
enabling direct monetization of the
credits again without relying on tax
equity transactions.
The production tax credit is not the
only provision in the IRA designed to
incentivize low-GHG hydrogen. Projects
may also access an investment tax credit
(ITC) under IRC section 48. For
example, manufacturers of clean
hydrogen production equipment, like
electrolyzers, may apply under IRC
section 48C (the Advanced
Manufacturing Tax Credit). And the
manufacturing facility for electrolyzers
could receive credits under section 48C
while the resulting hydrogen production
facility could then earn credits under
section 45V (this form of stacking is
allowed by statute). However, the same
project may not claim ITC credits under
section 48C while claiming PTC credits
under section 45V. Projects may not
generally combine credits from IRC
section 45V with credits in IRC section
45Q. Hydrogen production tax credits
became available in January 2023 for
eligible new projects. Entities that
commence construction between 2023
and 2032 can claim credits for the first
10 years of production.
The magnitude of this incentive—
combined with those in the IIJA such as
the $8 billion for regional hydrogen
hubs and $1.5 billion for electrolyzer
advancement—should accelerate the
production of low-GHG hydrogen for
127 Larsen, J., King, B., Kolus, H., Dasari, N.,
Hiltbrand, G., Herndon, W. (August 12, 2022). A
Turning Point for US Climate Progress: Assessing
the Climate and Clean Energy Provisions in the
Inflation Reduction Act. Rhodium Group. https://
rhg.com/research/climate-clean-energy-inflationreduction-act/.
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use in a broad range of applications
across many sectors, including the
utility power sector.128
Many of the IRA tax credit incentives
are directed toward low- and zeroemission electric generation. They are
designed to lower costs and market
barriers to bring new zero-emitting
generation and energy storage capacity
online, to retain existing zero-emitting
generators, and the energy efficiency tax
credits are designed to reduce electricity
demand. These financial tools have
been used historically and shown to be
a principal policy driver, buttressed by
State renewable and clean energy
standards, for incentivizing deployment
of low- and zero-emitting
generation.129 130
For example, the IRA expanded and
extended the existing section 13101
(IRC section 45) production tax credits
for new solar, wind, geothermal, and
other eligible zero- or low-GHG
emissions energy sources. The
production tax credit (PTC) provides
credits in a 10-year stream for each
MWh of clean energy produced. The
IRA indexed the PTC on inflation,
increasing the credit amount to $27.50/
MWh for facilities meeting certain wage
and apprenticeship requirements. For
context, the energy price in the nation’s
largest wholesale energy market, PJM,131
is typically between $20/MWh and $90/
MWh depending on timing, load, and
transmission congestion.
In parallel, the existing investment tax
credits in section 13101 (IRC section 48)
were also expanded and extended in the
IRA. Taxpayers must elect between the
ITC and the PTC for each applicable
project. The ITC enables taxpayers to
recoup up to 30 percent of project costs
for technologies such as solar,
geothermal, fiberoptic solar, fuel cells,
microturbines, small wind, offshore
wind, combined heat and power (CHP),
and waste energy recovery for
investments meeting certain wage and
apprenticeship requirements. There are
also a range of bonus credits available
128 U.S. Department of Energy (DOE). Pathways to
Commercial Liftoff: Clean Hydrogen, March 2023.
https://www.energy.gov/articles/doe-releases-newreports-pathways-commercial-liftoff-accelerateclean-energy-technologies.
129 Impacts of Federal Tax Credit Extensions on
Renewable Deployment and Power Sector
Emissions, National Renewable Energy Laboratory
(NREL), February 2016.
130 A Retrospective Assessment of Clean Energy
Investments in the Recovery Act, February 2016,
U.S. Executive Office of the President,
Memorandum.
131 PJM Interconnection LLC (PJM) is a regional
transmission organization (RTO) serving all or parts
of Delaware, Illinois, Indiana, Kentucky, Maryland,
Michigan, New Jersey, North Carolina, Ohio,
Pennsylvania, Tennessee, Virginia, West Virginia,
and the District of Columbia.
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if certain criteria are met, for example
for meeting domestic content and
energy communities’ requirements with
each earning an additional 10 percent
credit. The IRA expanded eligibility to
include storage technologies as well as
some non-storage technologies.
The IRA also tied the availability of
tax credits explicitly to reductions of
GHG emissions from the power sector.
Sections 13701 and 13702 enacted
technology-neutral production and
investment tax credits for projects
placed in service after 2025 that have
GHG emissions rates of zero or less.
These credits are available until the
phaseout is triggered when the power
sector’s GHG emissions fall below 25
percent of 2022 levels.
Following State practices, Congress
also included a zero-emission nuclear
power production credit in the IRA to
ensure existing in-service nuclear
generators are retained for their
contribution to base load zero-carbon
emitting electricity. When labor and
apprenticeship requirements are met,
the credit price is $15/MWh. The credit
amount declines when gross receipts of
services provided with electricity rise
above a specified level. The program
begins in 2024 with credit streams
available for nine years. This PTC is
complementary to the $6 billion for
nuclear advancements the IIJA
authorized and appropriated to the
DOE. New nuclear plants, including
small modular reactors, would be
eligible for either the technology-neutral
Clean Electricity Production or
Investment Credit (IRC section 45Y and
48E).
In the evaluation of these proposed
actions, many of the technologies that
receive investment under recent Federal
legislation are not directly considered,
as the EPA has not evaluated the new
generation technologies that entities
could employ as alternatives to fossil
fuel-fired EGUs in its assessment of the
BSER. As the discussion of that
assessment will make clear later in this
preamble, the EPA’s inquiry has focused
on ‘‘measures that improve the
pollution performance of individual
sources.’’ 132 However, these
overarching incentives and policies are
important context for this rulemaking.
The following section (section IV.E.2)
includes a review of integrated resource
plans (IRPs) filed by public utilities that
prioritize GHG reductions. IRPs
demonstrate how utilities plan to meet
future forecasted energy demand while
ensuring reliable and cost-effective
service. These IRPs demonstrate that
132 West Virginia v. EPA, 142 S. Ct. 2587, 2615
(2022).
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most power companies intend to meet
their GHG reduction targets by retiring
aging coal-fired steam generating EGUs
and replacing them with a combination
of renewable resources, energy storage,
other non-emitting technologies, and
natural gas-fired combustion turbines.
Many IRPs further demonstrate the
realization of power companies that to
meet their GHG reduction targets, their
natural gas-fired assets will need to
occupy a much smaller GHG footprint
through a combination of hydrogen,
CCS, and reduced utilization. The IRA
is designed to encourage this trend. For
example, in addition to the provisions
outlined above, including the 10 percent
bonus value applied in ‘energy
communities’ that include fossil-related
properties, the IRA created grant and
loan funding sources for hard-to-abate
energy assets. Section 22004 of the IRA
authorizes $9.7 billion in financing for
rural electric co-operatives and
providers to invest in cleaner
technologies to achieve GHG reductions
across rural electric systems while
buttressing resilience and reliability.
Additionally, section 50144 of the IRA,
known as the Energy Infrastructure
Reinvestment Financing provision,
provides $5 billion for backing $250
billion in low-cost loans for utilities to
repower, repurpose, or replace existing
infrastructure that has ceased
operations, or to enable operating
energy infrastructure to reduce air
pollution or GHG emissions. The
financing in this provision enables a
utility to repurpose an existing fossil
site, such as a retired coal-fired power
plant, or add CCS, renewable
generation, or hydrogen capability to an
operating coal- or natural gas-fired
power plant and retain community jobs
while reducing GHG emissions.
2. Commitments by Utilities To Reduce
GHG Emissions
The broad trends away from coal-fired
generation and toward lower-emitting
generation are reflected in the recent
actions and announced plans of many
utilities across the industry. As
highlighted later in this section, through
planning documents, IRPs, filings with
State and local public utility
commissions, and news releases, many
utilities have made public commitments
to voluntarily cease operating coal-fired
generation and move toward zero- and
low-GHG energy generation. Many
utilities and other power generators
have announced plans to increase their
renewable energy holdings and continue
reducing GHG emissions, regardless of
any potential Federal regulatory
requirements. For example, 50 power
producers that are members of the
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Edison Electric Institute have
announced CO2 reduction goals, twothirds of which include net-zero carbon
emissions by 2050.133 This trend is not
unique to the largest owner-operators of
coal-fired EGUs; smaller utilities, public
power cooperatives, and municipal
entities are also contributing to these
changes.
Some of the largest electric utilities
that have publicly announced near- and
long-term GHG reduction commitments,
many with emission reduction targets of
at least 80 percent (relative to 2005
levels unless otherwise noted), include:
• Xcel Energy: 80 percent reduction
in CO2 emissions by 2030 and 100
percent carbon-free by 2050. This
includes a commitment to close or
repower all remaining coal-fired EGUs
by 2030.134
• DTE Energy: 65 percent reduction
in CO2 emissions by 2028, 90 percent
reduction by 2040, and net-zero carbon
emissions by 2050.135
• Ameren Energy: 60 percent
reduction in CO2 by 2030, 85 percent
reduction by 2040, and net-zero carbon
emissions by 2045.136
• Consumers Energy: 60 percent
reduction in CO2 by 2025 and net-zero
carbon emissions by 2040. This includes
the retirement of all coal-fired units by
2025.137
• Southern Company: 50 percent
reduction in CO2 by 2030 (relative to
2007 levels) and net-zero carbon
emissions by 2050.138
• Duke Energy: 70 percent reduction
in CO2 by 2030 and net-zero carbon
133 See Comments of Edison Electric Institute to
EPA’s Pre-Proposal Docket on Greenhouse Gas
Regulations for Fossil Fuel-fired Power Plants,
Docket ID No. EPA–HQ–OAR–2022–0723,
November 18, 2022 (‘‘Fifty EEI members have
announced forward-looking carbon reduction goals,
two-third of which include a net-zero by 2050 or
earlier equivalent goal, and members are routinely
increasing the ambition or speed of their goals or
altogether transforming them into net-zero goals.’’).
134 Xcel Energy is based in Minnesota with
operations in Colorado, Michigan, New Mexico,
North Dakota, South Dakota, Texas, and Wisconsin.
2018 Integrated Resource Plan at https://
www.xcelenergy.com/staticfiles/xe-responsive/
Company/Rates%20&%20Regulations/
Resource%20Plans/2018-SPS-NM-IntegratedResource-Plan.pdf.
135 DTE Energy is based in Michigan. Our Bold
Goal for Michigan’s Clean Energy Future at https://
dtecleanenergy.com/.
136 Ameren is based in Illinois and Missouri. 2022
Integrated Resource Plan at https://
www.ameren.com/missouri/company/environmentand-sustainability/integrated-resource-plan.
137 Consumers Energy is based in Michigan.
Integrated Resource Plan at https://s26.q4cdn.com/
888045447/files/doc_presentations/2021/06/2021Integrated-Resource-Plan.pdf.
138 Southern Company is based in Georgia with
operations in Alabama and Mississippi. https://
www.southerncompany.com/sustainability/netzero-and-environmental-priorities/net-zerotransition.html.
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emissions by 2050. All coal-fired units
will retire by 2035.139
• Minnesota Power (Allete Inc.): 70
percent renewable energy by 2030, 80
percent reduction in CO2 and coal-free
by 2035, and 100 percent carbon-free by
2050.140
• First Energy: 30 percent reduction
in CO2 by 2030 (relative to 2019 levels)
and net-zero carbon emissions by
2050.141
• American Electric Power: 80
percent reduction in CO2 by 2030 and
net-zero carbon emissions by 2045.142
• Alliant Energy: 50 percent
reduction in CO2 by 2030 and net-zero
carbon emissions by 2050; will retire
final coal-fired EGU by 2040.143
• Tennessee Valley Authority: 70
percent reduction in CO2 by 2030, 80
percent reduction by 2035, and net-zero
carbon emissions by 2050.144
• NextEra Energy: 70 percent
reduction in CO2 by 2025, 82 percent
reduction by 2030, 87 percent reduction
by 2035, 94 percent reduction by 2040,
and carbon-free by 2045.145
The geographic footprint of zero or
net-zero carbon commitments made by
utilities, their parent companies, or in
response to a State clean energy
requirement, covers portions of 47 states
and includes 75 percent of U.S.
customer accounts.146 These statements
139 Duke Energy is based in North Carolina with
operations in South Carolina, Florida, Indiana,
Ohio, and Kentucky. NC IRP Fact Sheet at https://
p-scapi.duke-energy.com/-/media/pdfs/ourcompany/202296-nc-irp-fact-sheet.pdf.
140 Allete Energy is based in Minnesota with
operations in Wisconsin and North Dakota.
Integrated Resource Plan at: https://
www.edockets.state.mn.us/EFiling/edockets/
searchDocuments.do?method=show
Poup&documentId=%7b70795F77-0000-C41EA71C-FD089119967C%7d&documentTitle=20212170583-01.
141 First Energy is based in Ohio with operations
in Pennsylvania, West Virginia, and New Jersey.
https://www.firstenergycorp.com/content/dam/
environmental/files/climate-strategy.pdf.
142 American Electric Power (AEP) is based in
Ohio with operations in Arkansas, Indiana,
Kentucky, Louisiana, Michigan, Oklahoma,
Tennessee, Texas, Virginia, and West Virginia.
Clean Energy Future at https://www.aep.com/about/
ourstory/cleanenergy.
143 Alliant Energy has operations in Iowa and
Wisconsin. See Our Sustainable Energy Plan at
https://www.alliantenergy.com/cleanenergy/
ourenergyvision/poweringwhatsnext/sustainable
energyplan.
144 Tennessee Valley Authority (TVA) is based in
Tennessee with operations in Alabama, Georgia,
Kentucky, Mississippi, North Carolina, and
Virginia. See https://www.tva.com/newsroom/pressreleases/tva-charts-path-to-clean-energy-future.
145 NextEra Energy. See https://newsroom.nextera
energy.com/2022-06-14-NextEra-Energy-setsindustry-leading-Real-Zero-TM-goal-to-eliminatecarbon-emissions-from-its-operations,-leverage-lowcost-renewables-to-drive-energy-affordability-forcustomers.
146 Smart Electric Power Alliance Utility Carbon
Tracker. See https://sepapower.org/utility-
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are often made as part of long-term
planning processes with considerable
stakeholder involvement, including
regulators.
3. State Actions To Reduce Power
Sector GHG Emissions
States across the country have taken
the lead in efforts to reduce GHG
emissions from the power sector. These
actions include commitments that
require utilities to expand renewable
and clean energy production through
the adoption of renewable portfolio
standards (RPS) and clean energy
standards (CES), as well as other
measures tailored to decarbonize State
power systems enacted in specific
legislation.
Twenty-nine states and the District of
Columbia have enforceable RPS.147 RPS
require a percentage of electricity that
utilities sell to come from eligible
renewable sources like wind and solar
rather than from fossil fuel-based
sources like coal and natural gas. Fifteen
states have RPS targets that are at or
well above 50 percent. Eight of these
states—California, Illinois,
Massachusetts, Maryland, Minnesota,
New Jersey, Nevada, and Oregon—have
targets ranging from 50 percent to just
below 70 percent. Four states—Maine,
New Mexico, New York, and Vermont—
have RPS targets greater than or equal to
70 percent but below 100 percent, and
three states—Hawaii, Rhode Island, and
Virginia plus the District of Columbia—
have 100 percent RPS requirements.
Most of these ambitious targets fall
during the next decade. Ten states and
the District of Columbia have final
targets that mature between 2025 and
2033, while the remaining five states
impose peak requirements between
2040 and 2050. Resources that are
eligible under an RPS vary by State and
are determined by the State’s existing
energy production and possibility for
renewable energy development. For
example, Colorado’s RPS includes a
range of resources such as solar, wind,
emissions-neutral coal mine methane
and other sources as qualifying
renewable energy sources. Hawaii’s
includes, but is not limited to, solar,
wind, and energy produced from falling
water, ocean water, waves, and water
currents. RPS in some other states
include landfill gas, animal wastes,
CHP, and energy efficiency.148
transformation-challenge/utility-carbon-reductiontracker/. Accessed January 12, 2023.
147 DSIRE, Renewable Portfolio Standards and
Clean Energy Standards (2022). https://ncsolarcenprod.s3.amazonaws.com/wp-content/uploads/2022/
11/RPS-CES-Nov2022.pdf.
148 NCSL (2021). State Renewable Portfolio
Standards and Goals. https://www.ncsl.org/
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States are also shifting their
generating fleets away from fossil fuel
generating resources through the
adoption of CES. A CES requires a
percentage of retail electricity to come
from sources that are defined as clean.
Unlike an RPS, which defines eligible
generation in terms of the renewable
attributes of its energy source, CES
eligibility is based on the GHG emission
attributes of the generation itself,
typically with a zero or net-zero carbon
emissions requirement. Twenty-one
states have adopted some form of clean
energy requirement or goal with 17 of
those states setting 100 percent targets.
In nearly all cases, the CES applies in
addition to the State’s other RPS
requirements. Seven states, including
California, Colorado, Minnesota, New
York, Washington, Oregon, and Arizona,
have a zero or net-zero carbon emissions
requirement with most target dates
falling in 2040, 2045, or 2050. Two
states—New Mexico and
Massachusetts—have 80 percent clean
energy requirements that must be met in
2045 and 2050, respectively. Ten
additional states, including Connecticut,
New Jersey, Nevada, Wisconsin, Illinois,
Maine, North Carolina, Nebraska,
Louisiana, and Michigan, have 100
percent clean energy goals with target
dates falling in either 2040 or 2050. Like
an RPS, CES resource eligibility can
vary from State to State. One key
difference between an RPS and a CES is
the extent to which a CES can allow for
resources like nuclear and CCS-enabled
coal and natural gas, which are not
renewable but have low or zero direct
GHG emission attributes that make them
CES eligible.
In addition, states across the U.S.
have announced specific legislation
aimed at reducing GHG emissions. In
California, Senate Bill 32, passed in
2016, was a landmark legislation that
requires California to reduce its
economy-wide GHG emissions to 1990
levels by 2020, 40 percent below 1990
levels by 2030, and 80 percent below
1990 levels by 2050. Senate Bill 100,
passed in 2018, requires California to
procure 60 percent of all electricity from
renewable sources by 2030 and plan for
100 percent from carbon-free sources by
2045. Senate Bills 605 and 1383, passed
in 2016, require a reduction in
emissions of short-lived climate
pollutants like methane by 40 to 50
percent below 2013 levels by 2030.149
Achieving California’s established goal
research/energy/renewable-portfoliostandards.aspx.
149 Berkeley Law. California Climate Policy
Dashboard. https://www.law.berkeley.edu/research/
clee/research/climate/climate-policy-dashboard.
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of carbon-free electricity by 2045
requires emissions to be balanced by
carbon sequestration, capture, or other
technologies. Senate Bill 905, passed in
2022, requires the California Air
Resources Board to establish programs
for permitting CCS projects.150 Senate
Bill 905, also passed in 2022, prevents
the use of captured CO2 for enhanced oil
recovery within California.
In New York, The Climate Leadership
and Community Protection Act, passed
in 2019, sets several climate targets. The
most important goals include an 85
percent reduction in GHG emissions by
2050, 100 percent zero-emission
electricity by 2040, and 70 percent
renewable energy by 2030. Other targets
include 9,000 MW of offshore wind by
2035, 3,000 MW of energy storage by
2030, and 6,000 MW of solar by 2025.151
Washington State’s Climate
Commitment Act sets a target of
reducing GHG emissions by 95 percent
by 2050. The State is required to reduce
emissions to 1990 levels by 2020, 45
percent below 1990 levels by 2030, 70
percent below 1990 levels by 2040, and
95 percent below 1990 levels by 2050.
This also includes achieving net-zero
emissions by 2050.152
In addition to the prevalence of State
RPS and CES programs outlined above,
several states developed regulatory
programs to retain nuclear power plants
to preserve the significant amount of
zero-emission output the plants provide,
especially as many nuclear plants face
downward economic pressures resulting
from ultra-low natural gas spot prices
combined with increasing NGCC
capacity. Between 2016 and 2021, New
York, New Jersey, Connecticut, and
Illinois took action to retain their
nuclear power stations by providing
State-level financial incentives.
Retention of nuclear power plants is
another strategy that some states have
used to ensure an increasing market
share for zero-emission electricity
generation. As discussed earlier, the IRA
included a zero-emission nuclear power
production credit in section 13105, also
referred to as IRC section 45U.153
In the past two years, State actions
have generally increased their
decarbonization ambitions. For
example, legislation in Illinois and
North Carolina requires a transition
away from GHG-emitting generation.
Illinois’ Climate and Equitable Jobs Act,
which became law on September 25,
2021, requires all private coal-fired or
oil-fired power plants to reach zero
carbon emissions by 2030, municipal
coal-fired plants to reach zero carbon
emissions by 2045, and natural gas-fired
plants to reach zero carbon emissions by
2045.154 On October 13, 2021, North
Carolina passed House Bill 951 that
required the North Carolina Utilities
Commission to ‘‘take all reasonable
steps to achieve a seventy percent (70%)
reduction in emissions of carbon
dioxide (CO2) emitted in the State from
electric generating facilities owned or
operated by electric public utilities from
2005 levels by the year 2030 and carbon
neutrality by the year 2050.’’ 155
150 Berkeley Law. California Climate Policy
Dashboard. https://www.law.berkeley.edu/research/
clee/research/climate/climate-policy-dashboard.
151 New York State. Our Progress. https://
climate.ny.gov/Our-Progress.
152 Department of Ecology Washington State.
Greenhouse Gases. https://ecology.wa.gov/AirClimate/Climate-change/Tracking-greenhousegases.
153 https://uscode.house.gov/
view.xhtml?req=(title:26%20section:45U%20
edition:prelim).
154 State of Illinois General Assembly. Public Act
102–0662: Climate and Equitable Jobs Act. 2021.
https://www.ilga.gov/legislation/publicacts/102/
PDF/102-0662.pdf.
155 General Assembly of North Carolina, House
Bill 951 (2021). https://www.ncleg.gov/Sessions/
2021/Bills/House/PDF/H951v5.pdf.
156 U.S. Environmental Protection Agency. PostIRA 2022 Reference Case EPA’s Power Sector
Modeling Platform v6 Using IPM. April 2023.
https://www.epa.gov/power-sector-modeling/postira-2022-reference-case.
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1. Projections of Power Sector Trends
Projections for the U.S. power
sector—based on the landscape of
market forces in addition to the known
actions of Congress, utilities, and
states—have indicated that the ongoing
transition will continue for specific fuel
types and EGUs. The EPA’s Power
Sector Modeling Platform v6 Using the
Integrated Planning Model post-IRA
2022 reference case (i.e., the EPA’s
projections of the power sector, which
includes representation of the IRA
absent further regulation), provides
projections out to 2050 on future
outcomes of the electric power sector.
For more information on the details of
this modeling, see the model
documentation.156
Since the passage of the IRA in
August 2022, the EPA has engaged with
many external partners, including other
governmental entities, academia, nongovernmental organizations (NGOs), and
industry, to understand the impacts that
the IRA will have on power sector GHG
emissions. In addition to engaging in
several workgroups, the EPA has
contributed to two separate journal
articles that include multi-model
comparisons of IRA impacts across
several state-of-the-art models of the
U.S. energy system and electricity
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sector 157 158 and participated in public
events exploring modeling assumptions
for the IRA.159 The EPA plans to
continue collaborating with
stakeholders, conducting external
engagements, and using information
gathered to refine modeling of the IRA.
As such, the EPA is soliciting comment
on power sector modeling of the IRA,
including the assumptions and potential
impacts, including assumptions about
growth in electric demand, rates at
which renewable generation can be
built, and cost and performance
assumptions about all relevant
technologies, including carbon capture,
renewables, energy storage and other
generation technologies.
While much of the discussion below
focuses on the EPA’s post-IRA 2022
reference case, many other analyses
show similar trends,160 and these trends
are consistent with utility IRPs and
public GHG reduction commitments, as
well as State actions, both of which
were described in the previous sections.
1. Projections for Coal-Fired Generation
In the post-IRA 2022 reference case,
coal-fired steam EGU capacity is
projected to fall from 210 GW in
2021 161 to 44 GW in 2035, of which 11
GW includes retrofit CCS. Generation
from coal-fired steam generating units is
projected to also fall from 898 thousand
GWh in 2021 162 to 120 thousand GWh
by 2035. This change in generation
reflects the anticipated continued
decline in projected coal-fired steam
generating unit capacity as well as a
steady decline in annual operation of
those EGUs that remain online, with
capacity factors falling from
approximately 41 percent in 2021 to 15
percent in 2035. By 2050, coal-fired
steam generating unit capacity is
projected to diminish further, with only
10 GW, or less than 5 percent of 2021
157 Bistline, et al. (2023). ‘‘Emissions and Energy
System Impacts of the Inflation Reduction Act of
2022,’’ Under Review.
158 Bistline, et al. (2023). ‘‘Power Sector Impacts
of the Inflation Reduction Act of 2022,’’ In
Preparation.
159 Resource for the Future (2023). ‘‘Future
Generation: Exploring the New Baseline for
Electricity in the Presence of the Inflation
Reduction Act.’’ https://www.rff.org/events/rff-live/
future-generation-exploring-the-new-baseline-forelectricity-in-the-presence-of-the-inflationreduction-act/.
160 A wide variety of modeling teams have
assessed baselines with IRA. The baseline estimated
here is generally in line with these other estimates.
Bistline, et al. (2023). ‘‘Power Sector Impacts of the
Inflation Reduction Act of 2022,’’ In Preparation.
161 U.S. Energy Information Administration (EIA),
Electric Power Annual, table 4.3. November 2022.
https://www.eia.gov/electricity/annual/.
162 U.S. Energy Information Administration (EIA),
Electric Power Annual, table 3.1.A. November 2022.
https://www.eia.gov/electricity/annual/.
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capacity (and approximately 3 percent
of the 2010 capacity), still in operation
across the continental U.S. These
projections are driven by the eroding
economic opportunities for coal-fired
steam generating units to operate, the
continued aging of the fleet of coal-fired
steam generating units, and the
continued availability and expansion of
low-cost alternatives, like natural gas,
renewable technologies, and energy
storage.
In 2020, there was a total of 1,439
million metric tons of CO2 from the
power sector with coal-fired sources
contributing to over half of those
emissions. In the post-IRA 2022
reference case, power sector related CO2
emission are projected to fall to 608
million metric tons by 2035, of which 8
percent is projected to come from coalfired sources in 2035.
2. Projections for Natural Gas-Fired
Generation
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As described in the post-IRA 2022
reference case, natural gas-fired capacity
is expected to continue to buildout
during the next decade with 61 GW of
new capacity projected to come online
by 2035 and 309 GW of new capacity by
2050. By 2035, the new natural gas
capacity is comprised of 24 GW of
simple cycle combustion turbines and
37 GW of combined cycle combustion
turbines. By 2050, most of the
incremental new capacity is projected to
come just from simple cycle combustion
turbines. This also represents a higher
rate of new simple cycle combustion
turbine builds compared to the
reference periods (i.e., 2000–2006 and
2007–2021) discussed previously in this
section.
It should be noted that despite this
increase in capacity, both overall
generation and emissions from the
natural gas-fired capacity are projected
to decline. Generation from natural gas
units is projected to fall from 1,579
thousand GWh in 2021 163 to 1,402
thousand GWh by 2035. Power sector
related CO2 emissions from natural gasfired EGUs were 615 million metric tons
in 2021.164 By 2035, emission levels are
projected to reach 527 million metric
tons, 93 percent of which comes from
NGCC sources.
163 U.S. Energy Information Administration (EIA),
Electric Power Annual, table 3.1.A. November 2022.
https://www.eia.gov/electricity/annual/.
164 U.S. Environmental Protection Agency,
Inventory of U.S. Greenhouse Gas Emission Sources
and Sinks. February 2023. https://www.epa.gov/
system/files/documents/2023-02/US-GHGInventory-2023-Main-Text.pdf.
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The decline in generation and
emissions is driven by a projected
decline in NGCC capacity factors. In
model projections, NGCC units have a
capacity factor early in the projection
period of 64 percent, but by 2035,
capacity factor projections fall to 50
percent as many of these units switch
from base load operation to more
intermediate load operation to support
the integration of variable renewable
energy resources. Natural gas simple
cycle combustion turbine capacity
factors also fall, although since they are
used primarily as a peaking resource
and their capacity factors are already
below 10 percent annually, their impact
on generation and emissions changes
are less notable.
Some of the reasons for this continued
growth in natural gas-fired capacity
include anticipated sustained lower fuel
costs and the greater efficiency and
flexibility offered by combustion
turbines. Simple cycle combustion
turbines operate at lower efficiencies
but offer fast startup times to meet
peaking load demands. In addition,
combustion turbines, along with energy
storage technologies, support the
expansion of renewable electricity by
meeting demand during peak periods
and providing flexibility around the
variability of renewable generation and
electricity demand. In the longer term,
as renewables and battery storage grow,
they are anticipated to outcompete the
need for natural gas-fired generation and
the overall utilization of natural gasfired capacity is expected to decline.
3. Projections for Renewable Generation
The EIA’s Short-Term Energy Outlook
(STEO) suggests that the U.S. will
continue its expansion of wind and
solar renewable capacity with most of
the growth in electricity capacity
additions in the next 2 years to come
from renewable energy sources.165 The
EIA projects utility-scale solar capacity
to grow by approximately 29 GW in
2023 and by 35 GW in 2024 wind
generating capacity to grow by 7 GW in
2023 and by 7.5 GW in 2024. These
increases in new renewable capacity
will continue to reduce the demand for
fossil fuel-fired generation.
In the post-IRA 2022 reference case
projections, shows that this short-term
trend in renewable capacity is expected
to continue. Non-hydroelectric utilityscale renewable capacity is projected to
increase from 209 GW in 2021 to 668
165 U.S. Energy Information Administration (EIA).
Short-Term Energy Outlook, March 2023. https://
www.eia.gov/outlooks/steo/.
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GW by 2035 and then to 1,293 GW by
2050. This capacity growth is comprised
mostly of wind and solar. The post-IRA
2022 reference case shows projections of
399 GW of wind capacity by 2035 and
748 GW by 2050. Utility-scale solar
capacity has a similar trajectory with
263 GW by 2035 and 539 GW by 2050
and small-scale or distributed solar
capacity (e.g., rooftop solar) similarly
increases from 33 GW in 2021 to 198
GW in 2050.166 In total, nonhydroelectric utility-scale renewable
generation is projected to produce 45
percent of electricity generation by 2035
in the post-IRA 2022 reference case.
4. Projections for Energy Storage
According to EIA, the capacity of
battery energy storage is expected to
increase by 10 times between 2019 and
2023, of which 6 GW of battery storage
capacity is planned to be co-located
with solar generation.167 The benefit of
paring energy storage systems with solar
capacity deployment is that the batteries
can recharge throughout the middle of
the day when surplus energy is
available. Then this stored energy can
be discharged during peak hours,
supporting grid reliability and
potentially displacing higher emitting
generation. This also reduces
curtailment of renewable energy when
generation exceeds demand.
The build out of energy storage is
projected to continue in the long-term,
enabling the integration of renewable
technologies with lower emission
consequences. The post-IRA 2022
reference case shows projections of 97
GW of energy storage to be available on
the grid by 2035 and 152 GW by 2050.
5. Projections for Nuclear Energy
The post-IRA 2022 reference case
shows a steady decline in nuclear
generating capacity, dropping from 96
GW in 2021 to 84 GW or by 12 percent
by 2035. In the short-term, capacity
reductions are expected to be delayed in
part due to programs passed as part of
the IIJA and IRA. These acts, along with
several State programs, support the
continued use of existing nuclear
facilities by providing payments that
166 U.S. Energy Information Administration (EIA),
Electric Power Annual, table 4.3. November 2022.
https://www.eia.gov/electricity/annual/.
167 U.S. Energy Information Administration (EIA).
Preliminary Monthly Electric Generator Inventory,
December 2020 Form EIA–860M. https://
www.eia.gov/analysis/studies/electricity/
batterstorage/.
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will likely keep reactors in affected
regions profitable for the next 5–10
years.168 169 After 2035, the EPA projects
nuclear capacity retirements to occur as
EGUs begin to age out of operation, and
by 2050, the nuclear fleet is projected to
reduce by more than half, to 45 GW.
However, breakthrough technologies
like small modular reactors, if
successful, could result in higher levels
of nuclear capacity than discussed here.
For example, output from advanced
nuclear generation could range from
negligible to as high as 3,600 terawatthours per year by 2050.170
V. Statutory Background and
Regulatory History for CAA Section 111
A. Statutory Authority To Regulate
GHGs From EGUs Under CAA Section
111
The EPA’s authority for and
obligation to issue these proposed rules
is CAA section 111, which establishes
mechanisms for controlling emissions of
air pollutants from new and existing
stationary sources. CAA section
111(b)(1)(A) requires the EPA
Administrator to promulgate a list of
categories of stationary sources that the
Administrator, in his or her judgment,
finds ‘‘causes, or contributes
significantly to, air pollution which may
reasonably be anticipated to endanger
public health or welfare.’’ The EPA has
the authority to define the scope of the
source categories, determine the
pollutants for which standards should
be developed, and distinguish among
classes, types, and sizes within
categories in establishing the standards.
lotter on DSK11XQN23PROD with PROPOSALS2
1. Regulation of Emissions From New
Sources
Once the EPA lists a source category,
the EPA must, under CAA section
111(b)(1)(B), establish ‘‘standards of
performance’’ for emissions of air
pollutants from new sources (including
modified and reconstructed sources) in
the source category. Under CAA section
111(a)(2), a ‘‘new source’’ is defined as
‘‘any stationary source, the construction
or modification of which is commenced
168 ‘‘Constellation Making Major Investments in
Two Illinois Nuclear Plants to Increase Clean
Energy Output.’’ Constellation Energy Corporation.
February 21, 2023. https://www.constellation
energy.com/newsroom/2023/Constellation-MakingMajor-Investment-in-Two-Illinois-Nuclear-Plants-toIncrease-Clean-Energy-Output.html.
169 Singer, S. (February 22, 2023). PSEG to
consider nuclear plant investments, capitalizing on
the IRA’s production tax credits, CEO says. Utility
Dive. https://www.utilitydive.com/news/pseg-iranuclear-production-tax-credits/643221/.
170 ‘‘Advancing Nuclear Energy Evaluating
Deployment, Investment, and Impact in America’s
Clean Energy Future’’ Breakthrough Institute, July
6, 2022.
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after the publication of regulations (or,
if earlier, proposed regulations)
prescribing a standard of performance
under this section, which will be
applicable to such source.’’ Under CAA
section 111(a)(3), a ‘‘stationary source’’
is defined as ‘‘any building, structure,
facility, or installation which emits or
may emit any air pollutant.’’ Under
CAA section 111(a)(4), ‘‘modification’’
means any physical change in, or
change in the method of operation of, a
stationary source which increases the
amount of any air pollutant emitted by
such source or which results in the
emission of any air pollutant not
previously emitted. While this provision
treats modified sources as new sources,
EPA regulations also treat a source that
undergoes ‘‘reconstruction’’ as a new
source. Under the provisions in 40 CFR
60.15, ‘‘reconstruction’’ means the
replacement of components of an
existing facility such that: (1) The fixed
capital cost of the new components
exceeds 50 percent of the fixed capital
cost that would be required to construct
a comparable entirely new facility; and
(2) it is technologically and
economically feasible to meet the
applicable standards. Pursuant to CAA
section 111(b)(1)(B), the standards of
performance or revisions thereof shall
become effective upon promulgation.
The standards of performance for new
sources are referred to as new source
performance standards, or NSPS. The
NSPS are national requirements that
apply directly to the sources subject to
them.
In setting or revising a performance
standard, CAA section 111(a)(1)
provides that performance standards are
to reflect ‘‘the degree of emission
limitation achievable through the
application of the best system of
emission reduction which (taking into
account the cost of achieving such
reduction and any nonair quality health
and environmental impact and energy
requirements) the Administrator
determines has been adequately
demonstrated.’’ The term ‘‘standard of
performance’’ in CAA 111(a)(1) makes
clear that the EPA is to determine both
the ‘‘best system of emission reduction
. . . adequately demonstrated’’ (BSER)
for the regulated sources in the source
category and the ‘‘degree of emission
limitation achievable through the
application of the [BSER].’’ West
Virginia v. EPA, 142 S. Ct. 2587, 2601
(2022). To determine the BSER, the EPA
first identifies the ‘‘system[s] of
emission reduction’’ that are
‘‘adequately demonstrated,’’ and then
determines the ‘‘best’’ of those systems,
‘‘taking into account’’ factors including
‘‘cost,’’ ‘‘nonair quality health and
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environmental impact,’’ and ‘‘energy
requirements.’’ The EPA then derives
from that system an ‘‘achievable’’
‘‘degree of emission limitation.’’ The
EPA must then, under CAA section
111(b)(1)(B), promulgate ‘‘standard[s]
for emissions’’—the NSPS—that reflect
that level of stringency.
2. Regulation of Emissions From
Existing Sources
When the EPA establishes a standard
for emissions of an air pollutant from
new sources within a category, it must
also, under CAA section 111(d), regulate
emissions of that pollutant from existing
sources within the same category,
unless the pollutant is regulated under
the National Ambient Air Quality
Standards (NAAQS) program, under
CAA sections 108–110, or the National
Emission Standards for Hazardous Air
Pollutants (NESHAP) program, under
CAA section 112. See CAA section
111(d)(1)(A)(i) and (ii); West Virginia,
142 S. Ct. at 2601.
CAA section 111(d) establishes a
framework of ‘‘cooperative federalism
for the regulation of existing sources.’’
American Lung Ass’n, 985 F.3d at 931.
CAA sections 111(d)(1)(A)–(B) require
‘‘[t]he Administrator . . . to prescribe
regulations’’ that require ‘‘[e]ach state
. . . to submit to [EPA] a plan . . .
which establishes standards of
performance for any existing stationary
source for’’ the air pollutant at issue,
and which ‘‘provides for the
implementation and enforcement of
such standards of performance.’’ CAA
section 111(a)(6) defines an ‘‘existing
source’’ as ‘‘any stationary source other
than a new source.’’
To meet these requirements, the EPA
promulgates ‘‘emission guidelines’’ that
identify the BSER and the degree of
emission limitation achievable through
the application of the BSER. Each State
must then establish standards of
performance for its sources that reflect
that level of stringency. However, the
states need not compel regulated
sources to adopt the particular
components of the BSER itself. The
EPA’s emission guidelines must also
permit a State, ‘‘in applying a standard
of performance to any particular
source,’’ to ‘‘take into consideration,
among other factors, the remaining
useful life of the existing source to
which such standard applies.’’ 42 U.S.C.
7411(d)(1). Once a State receives the
EPA’s approval of its plan, the
provisions in the plan become federally
enforceable against the source, in the
same manner as the provisions of an
approved State Implementation Plan
(SIP) under the Act. If a State elects not
to submit a plan or submits a plan that
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the EPA does not find ‘‘satisfactory,’’ the
EPA must promulgate a plan that
establishes Federal standards of
performance for the State’s existing
sources. CAA section 111(d)(2)(A).
3. EPA Review of Requirements
CAA section 111(b)(1)(B) requires the
EPA to ‘‘at least every 8 years, review
and, if appropriate, revise’’ new source
performance standards. However, the
Administrator need not review any such
standard if the ‘‘Administrator
determines that such review is not
appropriate in light of readily available
information on the efficacy’’ of the
standard. Id. When conducting a review
of an NSPS, the EPA has the discretion
and authority to add emission limits for
pollutants or emission sources not
currently regulated for that source
category. CAA section 111 does not by
its terms require the EPA to review
emission guidelines for existing sources,
but the EPA retains the authority to do
so. See 81 FR 59276, 59277 (August 29,
2016) (explaining legal authority to
review emission guidelines for
municipal solid waste landfills).
lotter on DSK11XQN23PROD with PROPOSALS2
B. History of EPA Regulation of
Greenhouse Gases From Electricity
Generating Units Under CAA Section
111 and Caselaw
The EPA has listed more than 60
stationary source categories under CAA
section 111(b)(1)(A). See 40 CFR part 60,
subparts Cb–OOOO. In 1971, the EPA
listed fossil fuel-fired EGUs (which
includes natural gas, petroleum, and
coal) that use steam-generating boilers
in a category under CAA section
111(b)(1)(A). See 36 FR 5931 (March 31,
1971) (listing ‘‘fossil fuel-fired steam
generators of more than 250 million Btu
per hour heat input’’). In 1977, the EPA
listed fossil fuel-fired combustion
turbines, which can be used in EGUs, in
a category under CAA section
111(b)(1)(A). See 42 FR 53657 (October
3, 1977) (listing ‘‘stationary gas
turbines’’).
In 2015, the EPA promulgated two
rules that addressed CO2 emissions from
fossil fuel-fired EGUs. The first
promulgated standards of performance
for new fossil fuel-fired EGUs.
‘‘Standards of Performance for
Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary
Sources: Electric Utility Generating
Units; Final Rule,’’ (80 FR 64510;
October 23, 2015) (2015 NSPS). The
second promulgated emission
guidelines for existing sources. ‘‘Carbon
Pollution Emission Guidelines for
Existing Stationary Sources: Electric
Utility Generating Units; Final Rule,’’
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(80 FR 64662; October 23, 2015) (Clean
Power Plan, or CPP).
1. 2015 NSPS
In 2015, the EPA promulgated an
NSPS to limit emissions of GHGs,
manifested as CO2, from newly
constructed, modified, and
reconstructed fossil fuel-fired electric
utility steam generating units, i.e.,
utility boilers and IGCC EGUs, and
newly constructed and reconstructed
stationary combustion turbine EGUs.
These final standards are codified in 40
CFR part 60, subpart TTTT.
In promulgating the NSPS for newly
constructed fossil fuel-fired steam
generating units, the EPA determined
the BSER to be a new, highly efficient,
supercritical pulverized coal (SCPC)
EGU that implements post-combustion
partial CCS technology. The EPA
concluded that CCS was adequately
demonstrated (including being
technically feasible) and widely
available and could be implemented at
reasonable cost. The EPA identified
natural gas co-firing and IGCC
technology (either with natural gas cofiring or implementing partial CCS) as
alternative methods of compliance.
The 2015 NSPS included standards of
performance for steam generating units
that undergo a ‘‘reconstruction’’ as well
as units that implement ‘‘large
modifications,’’ (i.e., modifications
resulting in an increase in hourly CO2
emissions of more than 10 percent). The
2015 NSPS did not establish standards
of performance for steam generating
units that undertake ‘‘small
modifications’’ (i.e., modifications
resulting in an increase in hourly CO2
emissions of less than or equal to 10
percent), due to the limited information
available to inform the analysis of a
BSER and corresponding standard of
performance.
The 2015 NSPS also finalized
standards of performance for newly
constructed and reconstructed
stationary combustion turbine EGUs.
For newly constructed and
reconstructed base load natural gas-fired
stationary combustion turbines, the EPA
finalized a standard based on efficient
NGCC technology as the BSER. For
newly constructed and reconstructed
non-base load natural gas-fired
stationary combustion turbines and for
both base load and non-base load multifuel-fired stationary combustion
turbines, the EPA finalized a heat inputbased standard based on the use of
lower emitting fuels (referred to as clean
fuels in the 2015 NSPS). The EPA did
not promulgate final standards of
performance for modified stationary
combustion turbines due to lack of
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information. These standards remain in
effect today.
The EPA received six petitions for
reconsideration of the 2015 NSPS. On
May 6, 2016 (81 FR 27442), the EPA
denied five of the petitions on the basis
they did not satisfy the statutory
conditions for reconsideration under
CAA section 307(d)(7)(B), and deferred
action on one petition that raised the
issue of the treatment of biomass.
Multiple parties also filed petitions
for judicial review of the 2015 NSPS in
the D.C. Circuit. These cases have been
briefed and, on the EPA’s motion, are
being held in abeyance while the
Agency reviews the rule and considers
whether to propose revisions to it.
In the 2015 NSPS, the EPA noted that
it was authorized to regulate GHGs from
the fossil fuel-fired EGU source
categories because it had listed those
source categories under CAA section
111(b)(1)(A). The EPA added that CAA
section 111 did not require it to make
a determination that GHGs from EGUs
contribute significantly to dangerous air
pollution (a pollutant-specific
significant contribution finding), but in
the alternative, the EPA did make that
finding. It explained that ‘‘[greenhouse
gas] air pollution may reasonably be
anticipated to endanger public health or
welfare,’’ 80 FR 64530 (October 23,
2015) and emphasized that power plants
are ‘‘by far the largest emitters’’ of
greenhouse gases among stationary
sources in the U.S. Id. at 64522. In
American Lung Ass’n v. EPA, 985 F.3d
977 (D.C. Cir. 2021), the court held that
even if the EPA were required to
determine that CO2 from fossil fuel-fired
EGUs contributes significantly to
dangerous air pollution—and the court
emphasized that it was not deciding that
the EPA was required to make such a
pollutant-specific determination—the
determination in the alternative that the
EPA made in the 2015 NSPS was not
arbitrary and capricious and,
accordingly, the EPA had a sufficient
basis to regulate greenhouse gases from
EGUs under CAA section 111(d) in the
ACE Rule. The EPA is not reopening or
soliciting comment on any of those
determinations in the 2015 NSPS
concerning its rational basis to regulate
GHG emissions from EGUs or its
alternative finding that GHG emissions
from EGUs contribute significantly to
dangerous air pollution.
2. 2018 Proposal To Revise the 2015
NSPS
In 2018, the EPA proposed to revise
the NSPS for new, modified, and
reconstructed fossil fuel-fired steam
generating units and IGCC units.
‘‘Review of Standards of Performance
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for Greenhouse Gas Emissions From
New, Modified, and Reconstructed
Stationary Sources: Electric Utility
Generating Units; Proposed Rule,’’ (83
FR 65424; December 20, 2018) (2018
NSPS Proposal). The EPA proposed to
revise the NSPS for newly constructed
units, based on a revised BSER of a
highly efficient SCPC, without partial
CCS. The EPA also proposed to revise
the NSPS for modified and
reconstructed units. The EPA has not
taken further action on this proposed
rule.171
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3. Clean Power Plan
With the promulgation of the 2015
NSPS, the EPA also incurred a statutory
obligation under CAA section 111(d) to
issue emission guidelines for GHG
emissions from existing fossil fuel-fired
steam generating EGUs and stationary
combustion turbine EGUs, which the
EPA initially fulfilled with the
promulgation of the CPP. See 80 FR
64662 (October 23, 2015). The EPA first
determined that the BSER included
three types of measures: (1) Improving
heat rate (i.e., the amount of fuel that
must be burned to generate a unit of
electricity) at coal-fired steam plants; (2)
substituting increased generation from
lower-emitting NGCC plants for
generation from higher-emitting steam
plants (which are primarily coal-fired);
and (3) substituting increased
generation from new renewable energy
sources for generation from fossil fuelfired steam plants and combustion
turbines. See 80 FR 64667 (October 23,
2015). The latter two measures are
known as ‘‘generation shifting’’ because
they involve shifting electricity
generation from higher-emitting sources
to lower-emitting ones. See 80 FR
64728–29 (October 23, 2015).
The EPA based this BSER
determination on a technical record that
evaluated generation-shifting, including
its cost-effectiveness, against the
relevant statutory criteria for BSER and
on a legal interpretation that the term
‘‘system’’ in CAA section 111(a)(1) is
171 In the 2018 NSPS Proposal, the EPA solicited
comment on whether it is required to make a
determination that GHGs from a source category
contribute significantly to dangerous air pollution
as a predicate to promulgating a NSPS for GHG
emissions from that source category for the first
time. 83 FR 65432 (December 20, 2018). The EPA
subsequently issued a final rule that provided that
it would not regulate GHGs under CAA section 111
from a source category unless the GHGs from the
category exceed 3 percent of total U.S. GHG
emissions, on grounds that GHGs emitted in a lesser
amount do not contribute significantly to dangerous
air pollution. 86 FR 2652 (January, 13 2021).
Shortly afterwards, the D.C. Circuit granted an
unopposed motion by the EPA for voluntary vacatur
and remand of the final rule. California v. EPA, No.
21–1035, doc. 1893155 (D.C. Cir. April 5, 2021).
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sufficiently broad to encompass shifting
of generation from higher-emitting to
lower-emitting sources. See 80 FR 64720
(October 23, 2015). The EPA then
determined the ‘‘degree of emission
limitation achievable through the
application of the [BSER],’’ CAA section
111(a)(1), expressed as emission
performance rates. See 80 FR 64667
(October 23, 2015). The EPA explained
that a State would ‘‘have to ensure,
through its plan, that the emission
standards it establishes for its sources
individually, in the aggregate, or in
combination with other measures
undertaken by the [S]tate, represent the
equivalent of’’ those performance rates
(80 FR 64667; October 23, 2015).
Neither states nor sources were required
to apply the specific measures identified
in the BSER (80 FR 64667; October 23,
2015), and states could include trading
or averaging programs in their State
plans for compliance. See 80 FR 64840
(October 23, 2015).
Numerous states and private parties
petitioned for review of the CPP before
the D.C. Circuit. On February 9, 2016,
the U.S. Supreme Court stayed the rule
pending review, West Virginia v. EPA,
577 U.S. 1126 (2016), and the D.C.
Circuit held the litigation in abeyance,
and ultimately dismissed it, as the EPA
reassessed its position. American Lung
Ass’n, 985 F.3d at 937.
4. The CPP Repeal and ACE Rule
In 2019, the EPA repealed the CPP
and replaced it with the ACE Rule. In
contrast to its interpretation of CAA
section 111 in the CPP, in the ACE Rule
the EPA determined that the statutory
‘‘text and reasonable inferences from it’’
make ‘‘clear’’ that a ‘‘system’’ of
emission reduction under CAA section
111(a)(1) ‘‘is limited to measures that
can be applied to and at the level of the
individual source,’’ (84 FR 32529; July
8, 2019); that is, the system must be
limited to control measures that could
be applied at and to each source to
reduce emissions at each source. See 84
FR 32523–24 (July 8, 2019). Specifically,
the ACE Rule argued that the
requirements in CAA sections 111(d)(1),
(a)(3), and (a)(6), that each State
establish a standard of performance
‘‘for’’ ‘‘any existing source,’’ defined, in
general, as any ‘‘building . . . [or]
facility,’’ and the requirement in CAA
section 111(a)(1) that the degree of
emission limitation must be
‘‘achievable’’ through the ‘‘application’’
of the BSER, by their terms, impose this
limitation. The EPA concluded that
generation shifting is not such a control
measure. See 84 FR 32546 (July 8, 2019).
Based on its view that the CPP was a
‘‘major rule,’’ the EPA further
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determined that, absent ‘‘a clear
statement from Congress,’’ the term
‘‘‘system of emission reduction’’’ should
not be read to encompass ‘‘generationshifting measures.’’ See 84 FR 32529
(July 8, 2019). The EPA acknowledged,
however, that ‘‘[m]arket-based forces
ha[d] already led to significant
generation shifting in the power sector,’’
(84 FR 32532; July 8, 2019), and that
there was ‘‘likely to be no difference
between a world where the CPP is
implemented and one where it is not.’’
See 84 FR 32561 (July 8, 2019); the
Regulatory Impact Analysis for the
Repeal of the Clean Power Plan, and the
Emission Guidelines for Greenhouse
Gas Emissions from Existing Electric
Utility Generating Units, 2–1 to 2–5.172
In addition, the EPA promulgated in
the ACE Rule a new set of emission
guidelines for existing coal-fired steamgenerating EGUs. See 84 FR 32532 (July
8, 2019). In light of ‘‘the legal
interpretation adopted in the repeal of
the CPP,’’ (84 FR 32532; July 8, 2019)—
which ‘‘limit[ed] ‘standards of
performance’ to systems that can be
applied at and to a stationary source,’’
(84 FR 32534; July 8, 2019)—the EPA
found the BSER to be heat rate
improvements alone. See 84 FR 32535
(July 8, 2019). The EPA listed various
technologies that could improve heat
rate (84 FR 32536; July 8, 2019), and
identified the ‘‘degree of emission
limitation achievable’’ by ‘‘providing
ranges of expected [emission]
reductions associated with each of the
technologies.’’ See 84 FR 32537–38 (July
8, 2019).
The EPA also stated that, under the
ACE Rule, compliance measures that the
State plans could authorize the sources
to implement ‘‘should correspond with
the approach used to set the standard in
the first place,’’ (84 FR 32556; July 8,
2019), and therefore must ‘‘apply at and
to an individual source and reduce
emissions from that source.’’ See 84 FR
32555–56 (July 8, 2019). The EPA
concluded that various measures
besides generation shifting—including
averaging (i.e., allowing multiple
sources to average their emissions to
meet an emission-reduction goal), and
trading (i.e., allowing sources to
exchange emission credits or
allowances)—did not meet that
requirement. The EPA therefore barred
states from using such measures in their
plans. See 84 FR 32556 (July 8, 2019).
172 https://www.epa.gov/sites/default/files/201906/documents/utilities_ria_final_cpp_repeal_
and_ace_2019-06.pdf.
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5. D.C. Circuit Decision in American
Lung Association v. EPA Concerning the
CPP Repeal and ACE Rule
Numerous states and private parties
petitioned for review of the CPP Repeal
and ACE Rule. In 2021, the D.C. Circuit
vacated the ACE Rule, including the
CPP Repeal. American Lung Ass’n v.
EPA, 985 F.3d 914 (D.C. Cir. 2021). The
court held, among other things, that
CAA section 111(d) does not limit the
EPA, in determining the BSER, to
measures applied at and to an
individual source. The court noted that
‘‘the sole ground on which the EPA
defends its abandonment of the [CPP] in
favor of the ACE Rule is that the text of
[CAA section 111] is clear and
unambiguous in constraining the EPA to
use only improvements at and to
existing sources in its [BSER].’’ 985 F.3d
at 944. The court found ‘‘nothing in the
text, structure, history, or purpose of
[CAA section 111] that compels the
reading the EPA adopted.’’ 985 F.3d at
957. The court explained that contrary
to the ACE Rule, the above-noted
requirements in CAA section 111 that
each State must establish a standard of
performance ‘‘for’’ any existing
‘‘building . . . [or] facility,’’ mean that
the State must establish standards
applicable to each regulated stationary
source; and the requirements that the
degree of emission limitation must be
achievable through the ‘‘application’’ of
the BSER could be read to mean that the
sources must be able to apply the
system to reduce emissions across the
source category. None of these
requirements, the court further
explained, can be read to mandate that
the BSER is limited to some measure
that each source can apply to its own
facility to reduce its own emissions in
a specified amount. 985 F.3d at 944–51.
The court likewise rejected the view
that the CPP’s use of generation-shifting
implicated a ‘‘major question’’ requiring
unambiguous authorization by
Congress. 985 F.3d at 958–68.
Having rejected the CPP Repeal Rule’s
view, also reflected in the ACE Rule,
that CAA section 111 unambiguously
requires that the BSER be ‘‘one that can
be applied to and at the individual
source,’’ the court also ‘‘reject[ed] the
ACE Rule’s exclusion from [CAA
section 111(d)] of compliance
measures’’ that do not meet that
requirement. 985 F.3d at 957. Thus, the
court held that CAA section 111 does
not preclude states from allowing
trading or averaging. The court
explained that the ACE Rule’s premise
for its view that compliance measures
are limited to measures applied at and
to an individual source is that BSER
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measures are so limited, but the court
further stated that this premise was
invalid. The court added that in any
event, CAA section 111(d) says nothing
about the type of compliance measures
states may adopt, regardless of what the
EPA identifies as the BSER. Id. at 957–
58.
The D.C. Circuit concluded that,
because the EPA had relied on an
‘‘erroneous legal premise,’’ both the CPP
Repeal Rule and the ACE Rule should
be vacated. 985 F.3d at 995. The court
did not decide, however, ‘‘whether the
approach of the ACE Rule is a
permissible reading of the statute as a
matter of agency discretion,’’ 985 F.3d at
944, and instead ‘‘remanded to the EPA
so that the Agency may ‘consider the
question afresh,’ ’’ 985 F.3d at 995
(citations omitted). The court also
rejected the arguments that the EPA
cannot regulate CO2 emissions from
coal-fired power plants under CAA
section 111(d) at all because it had
already regulated mercury emissions
from coal-fired power plants under CAA
section 112. 985 F.3d at 988. In
addition, the court held that that the
2015 NSPS included a valid
determination that greenhouse gases
from the EGU source category
contributed significantly to dangerous
air pollution, which provided a
sufficient basis for a CAA section 111(d)
rule regulating greenhouse gases from
existing fossil fuel-fired EGUs. Id. at
977.
Because the D.C. Circuit vacated the
ACE Rule on the grounds noted above,
it did not address the numerous other
challenges to the ACE Rule, including
the arguments by Petitioners that the
heat rate improvement BSER was
inadequate because of the limited
amount of reductions it achieved and
because the ACE Rule failed to include
an appropriately specific degree of
emission limitation.
Upon a motion from the EPA, the D.C.
Circuit agreed to stay its mandate with
respect to vacatur of the CPP Repeal,
American Lung Assn v. EPA, No. 19–
1140, Order (February 22, 2021), so that
the CPP remained repealed. In its
motion, the EPA explained that the CPP
should remain repealed because the
deadline for states to submit their plans
under the CPP had long since passed. In
addition, and most importantly, because
of ongoing changes in electricity
generation—in particular, retirements of
coal-fired electricity generation—the
emissions reductions that the CPP was
projected to achieve had already been
achieved by 2021. American Lung Assn
v. EPA, No. 19–1140, Respondents’
Motion for a Partial Stay of Issuance of
the Mandate (February 12, 2021).
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Therefore, following the D.C. Circuit’s
decision, no EPA rule under CAA
section 111 to reduce GHGs from
existing fossil fuel-fired EGUs remained
in place.
6. U.S. Supreme Court Decision in West
Virginia v. EPA Concerning the CPP
In 2022, the U.S. Supreme Court
reversed the D.C. Circuit’s vacatur of the
ACE Rule’s embedded repeal of the CPP.
West Virginia v. EPA, 142 S. Ct. 2587
(2022). The Supreme Court made clear
that CAA section 111 authorizes the
EPA to determine the BSER and the
degree of emission limitation that State
plans must achieve. Id. at 2601–02.
However, the Supreme Court
invalidated the CPP’s generationshifting BSER under the major questions
doctrine. The Court characterized the
generation-shifting BSER as
‘‘restructuring the Nation’s overall mix
of electricity generation,’’ and stated
that the EPA’s claim that CAA section
111 authorized it to promulgate
generation shifting as the BSER was
‘‘not only unprecedented; it also
effected a fundamental revision of the
statute, changing it from one sort of
scheme of regulation into an entirely
different kind.’’ Id. at 2612 (internal
quotation marks, brackets, and citation
omitted). The Court explained that the
EPA, in prior rules under CAA section
111, had set emissions limits based on
‘‘measures that would reduce pollution
by causing the regulated source to
operate more cleanly.’’ Id. at 2610. The
Court noted with approval those ‘‘more
traditional air pollution control
measures,’’ and gave as examples ‘‘fuelswitching’’ and ‘‘add-on controls,’’
which, the Court observed, the EPA had
considered in the CPP. Id. at 2611
(internal quotations marks and citation
omitted). In contrast, the Court
continued, generation-shifting was
‘‘unprecedented’’ because ‘‘[r]ather than
focus on improving the performance of
individual sources, it would improve
the overall power system by lowering
the carbon intensity of power
generation. And it would do that by
forcing a shift throughout the power
grid from one type of energy source to
another.’’ Id. at 2611–12 (internal
quotation marks, emphasis, and citation
omitted). The Court also emphasized
that the adoption of generation shifting
was based on a ‘‘very different kind of
policy judgment [than prior CAA
section 111 rules]: that it would be ‘best’
if coal made up a much smaller share of
national electricity generation.’’ Id. at
2612. The Court recognized that a rule
based on traditional measures ‘‘may end
up causing an incidental loss of coal’s
market share,’’ but emphasized that the
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CPP was ‘‘obvious[ly] differen[t]’’
because, with its generation-shifting
BSER, it ‘‘simply announc[ed] what the
market share of coal, natural gas, wind,
and solar must be, and then require[ed]
plants to reduce operations or subsidize
their competitors to get there.’’ Id. at
2613 n. 4. Beyond highlighting the
novelty of generation shifting, the Court
also emphasized ‘‘the magnitude and
consequence’’ of the CPP. Id. at 2616. It
noted ‘‘the magnitude of this
unprecedented power over American
industry,’’ id. at 2612 (internal
quotation marks and citation omitted),
and added that the EPA’s adoption of
generation shifting ‘‘represent[ed] a
transformative expansion in its
regulatory authority.’’ Id. at 2610
(internal quotation marks and citation
omitted). The Court also viewed the CPP
as promulgating ‘‘a program that . . .
Congress had considered and rejected
multiple times.’’ Id. at 2614 (internal
quotation marks and citation omitted).
The Court explained that ‘‘[a]t bottom,
the [CPP] essentially adopted a cap-andtrade scheme, or set of state cap-andtrade schemes, for carbon,’’ and that
Congress ‘‘has consistently rejected
proposals to amend the Clean Air Act to
create such a program.’’ Id.
For these and related reasons, the
Court viewed the CPP as raising a major
question, and therefore, under the major
questions doctrine, required ‘‘clear
congressional authorization’’ as a basis.
Id. (internal quotation marks and
citation omitted). The EPA had
defended generation shifting as
qualifying as a ‘‘system of emission
reduction’’ under CAA section 111(a)(1),
but the Court found that the term
‘‘system’’ is ‘‘a vague statutory grant
[that] is not close to the sort of clear
authorization required’’ under the
doctrine, id., and, on that basis,
invalidated the CPP.
The Court declined to address the
D.C. Circuit’s conclusion that the text of
CAA section 111 did not limit the type
of ‘‘system’’ the EPA could consider as
the BSER to measures applied at and to
an individual source. See id. at 2615
(‘‘We have no occasion to decide
whether the statutory phrase ‘system of
emission reduction’ refers exclusively to
measures that improve the pollution
performance of individual sources, such
that all other actions are ineligible to
qualify as the BSER.’’ (emphasis in
original)). Nor did the Court address the
scope of the States’ compliance
flexibilities.
C. Detailed Discussion of CAA Section
111 Requirements
This section discusses in more detail
the key requirements of CAA section
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111 for both new and existing sources
that are relevant for these rulemakings.
Approach to the Source Category and
Subcategorizing
CAA section 111 requires the EPA
first to list stationary source categories
that cause or contribute to air pollution
which may reasonably be anticipated to
endanger public health or welfare and
then to regulate new sources within
each such source category. CAA section
111(b)(2) grants the EPA discretion
whether to ‘‘distinguish among classes,
types, and sizes within categories of
new sources for the purpose of
establishing [new source] standards,’’
which we refer to as ‘‘subcategorizing.’’
The D.C. Circuit has stated that whether
and how to subcategorize is a decision
for which the EPA is entitled to a ‘‘high
degree of deference’’ because it entails
‘‘scientific judgement.’’ Lignite Energy
Council v. EPA, 198 F3d 930, 933 (D.C.
Cir. 1999); see Sierra Cub, v. Costle, 657
F.2d 298, 318–19 (D.C. Cir. 1981).
Although CAA section 111(d)(1) does
not by its terms address
subcategorization, the EPA interprets it
to authorize the Agency to exercise
discretion as to whether and, if so, how
to subcategorize, for the following
reasons. CAA section 111(d)(1) provides
a broad grant of authority to the EPA,
directing it to ‘‘prescribe regulations
which shall establish a procedure . . .
under which each State shall submit to
the Administrator a plan [with
standards of performance for existing
sources.]’’ The EPA promulgates
emission guidelines under this
provision directing the States to regulate
existing sources. The Supreme Court
has recognized the breadth of authority
that CAA section 111(d) grants the EPA:
Although the States set the actual rules
governing existing power plants, EPA itself
still retains the primary regulatory role in
Section 111(d). The Agency, not the States,
decides the amount of pollution reduction
that must ultimately be achieved. It does so
by again determining, as when setting the
new source rules, ‘‘the best system of
emission reduction . . . that has been
adequately demonstrated for [existing
covered] facilities.’’
West Virginia, 142 S. Ct. at 2601–02
(citations omitted). That this broad
authority under CAA section 111(d)
includes subcategorization follows from
the fact that these provisions authorize
the EPA to determine the BSER.
Subcategorizing is a mechanism for
determining different controls to be the
BSER for different sets of sources. This
is clear from CAA section 111(b)(2)
itself, which authorizes the EPA to
subcategorize new sources ‘‘for the
purpose of establishing . . . standards.’’
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In addition, the EPA’s implementing
regulations under CAA section 111(d),
promulgated in 1975, 40 FR 53340
(November 17, 1975), provide that the
Administrator will specify different
emission guidelines or compliance
times or both ‘‘for different sizes, types,
and classes of designated facilities when
costs of control, physical limitations,
geographical location, or [based on]
similar factors.’’ 173 In promulgating this
provision, the EPA made clear the
purpose of subcategorization is to tailor
the BSER for different sets of sources:
EPA’s emission guidelines will reflect
subcategorization within source categories
where appropriate, taking into account
differences in sizes and types of facilities and
similar considerations, including differences
in control costs that may be involved for
sources located in different parts of the
country. Thus, EPA’s emission guidelines
will in effect be tailored to what is reasonably
achievable by particular classes of existing
sources. . . .
Id. at 53343.
The EPA’s authority to ‘‘distinguish
among classes, types, and sizes within
categories,’’ as provided under CAA
section 111(b)(2), generally allows the
Agency to place types of sources into
subcategories when they have
characteristics that are relevant to the
controls they can apply to reduce their
emissions. This is consistent with the
commonly understood meaning of the
term ‘‘type’’ in CAA section 111(b)(2):
‘‘a particular kind, class, or group,’’ or
‘‘qualities common to a number of
individuals that distinguish them as an
identifiable class.’’ See https://
www.merriam-webster.com/dictionary/
type. That is, subcategorization is
appropriate for a set of sources that have
qualities in common that are relevant
for determining what controls are
appropriate for those sources. And
where the qualities in common are not
relevant for determining what controls
are appropriate, subcategorization is not
appropriate. This view is consistent
with the D.C. Circuit’s interpretation of
CAA section 112(d)(1), which is a
subcategorization provision that is
substantially similar to CAA section
111(b)(2). In NRDC v. EPA, 489 F.3d
1364, 1375–76 (D.C. Cir. 2007), the court
upheld the EPA’s decision under CAA
section 112(d)(1) not to subcategorize
sources subject to control requirements
under CAA section 112(d)(3), known as
the maximum achievable control
technology (MACT) floor, on the basis of
173 40 CFR 60.22(b)(5), 60.22a(b)(5). Because the
definition of subcategories depends on
characteristics relevant to the BSER, and because
those characteristics can differ as between new and
existing sources, the EPA may establish different
subcategories as between new and existing sources.
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costs. That was because the EPA is not
authorized to consider costs in setting
the MACT floor.174
The EPA has developed subcategories
in numerous rulemakings under CAA
section 111 since it began promulgating
them in the 1970s. These rulemakings
have included subcategories on the
basis of the size of the sources, see 40
CFR 60.40b(b)(1)–(2) (subcategorizing
certain coal-fired steam generating units
on the basis of heat input capacity); the
types of fuel combusted, see Sierra Cub,
v. EPA, 657 F.2d 298, 318–19 (D.C. Cir.
1981) (upholding a rulemaking that
established different NSPS ‘‘for utility
plants that burn coal of varying sulfur
content’’), 2015 NSPS, 80 FR 64510,
64602 (table 15) (October 23, 2015)
(subdividing new combustion turbines
on the basis of type of fuel combusted);
the types of equipment used to produce
products, see 81 FR 35824 (June 3, 2016)
(promulgating separate NSPS for many
types of oil and gas sources, such as
centrifugal compressors, pneumatic
controllers, and well sites); types of
manufacturing processes used to
produce product, see 42 FR 12022
(March 1, 1977) (announcing
availability of final guideline document
for control of atmospheric fluoride
emissions from existing phosphate
fertilizer plants) and ‘‘Final Guideline
Document: Control of Fluoride
Emissions From Existing Phosphate
Fertilizer Plants, EPA–450/2–77–005 1–
7 to 1–9, including table 1–2 (applying
different control requirements for
different manufacturing operations for
phosphate fertilizer); levels of
utilization of the sources, see 2015
NSPS, 80 FR 64510, 64602 (table 15)
(October 23, 2015) (dividing new
natural gas-fired combustion turbines
into the subcategories of base load and
non-base load); the activity level of the
sources, see 81 FR 59276, 59278–79
(August 29, 2016) (dividing municipal
solid waste landfills into the
subcategories of active and closed
landfills); and geographic location of the
sources, see 71 FR 38482 (July 6, 2006)
(SO2 NSPS for stationary combustion
turbines subcategories turbines on the
basis of whether they are located in, for
example, a continental area, a
noncontinental area, the part of Alaska
north of the Arctic Circle, and the rest
of Alaska), see also Sierra Club v. Costle,
657 F.2d 298, 330 (D.C. Cir. 1981)
(stating that the EPA could create
different subcategories for new sources
in the Eastern and Western U.S. for
174 See Chem. Mfrs. Ass’n v. NRDC, 470 U.S. 116,
131 (1985) (Court interprets similar
subcategorization provision under the Clean Water
Act to grant the EPA broad discretion).
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requirements that depend on waterintensive controls). As these references
indicate, the EPA has subcategorized
many times in rulemaking under CAA
sections 111(b) and 111(d) and based on
a wide variety of physical, locational,
and operational characteristics. It
should also be noted that in some
instances, the EPA has declined to
subcategorize. Lignite Energy Council,
198 F.3d at 933 (upholding EPA
decision not to subcategorize utility
boilers for purposes of NOX NSPS on
grounds that the decision was not
arbitrary and capricious).
Regardless of whether the EPA
subcategorizes within a source category
for purposes of determining the BSER
and the emission performance level for
the emission guideline, a State retains
certain flexibility in assigning standards
of performance to its affected EGUs. The
statutory framework for CAA section
111(d) emission guidelines, and the
flexibilities available to States within
that framework, are discussed below.
D.C. Circuit Order To Reinstate the ACE
Rule
On October 27, 2022, the D.C. Circuit
responded to the U.S. Supreme Court’s
reversal by recalling its mandate for the
vacatur of the ACE Rule. American Lung
Ass’n v. EPA, No. 19–1140, Order
(October 27, 2022). Accordingly, at that
time, the ACE Rule came back into
effect. The court also revised its
judgment to deny petitions for review
challenging the CPP Repeal Rule,
consistent with the West Virginia
decision, so that the CPP remains
repealed. The court took further action
denying several of the petitions for
review unaffected by the Supreme
Court’s decision in West Virginia, which
means that certain parts of its 2021
decision in American Lung Ass’n
remain valid. These parts include the
holding that the EPA’s prior regulation
of mercury emissions from coal-fired
electric power plants under CAA
section 112 does not preclude the
Agency from regulating CO2 from coalfired electric power plants under CAA
section 111, and the holding, discussed
above, that the 2015 NSPS included a
valid significant contribution
determination and therefore provided a
sufficient basis for a CAA section 111(d)
rule regulating greenhouse gases from
existing fossil fuel-fired EGUs. The
court’s holding to invalidate
amendments to the implementing
regulations applicable to emission
guidelines under CAA section 111(d)
that extended the preexisting schedules
for State and Federal actions and
sources’ compliance, also remains valid.
Based on the EPA’s stated intention to
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replace the ACE Rule, the court stayed
further proceedings with respect to the
ACE Rule, including the various
challenges that its BSER was flawed
because it did not achieve sufficient
emission reductions and failed to
specify an appropriately specific degree
of emission limitation.
3. Key Elements of Determining a
Standard of Performance
Congress first included the definition
of ‘‘standard of performance’’ when
enacting CAA section 111 in the 1970
Clean Air Act Amendments (CAAA),
amended it in the 1977 CAAA, and then
amended it again in the 1990 CAAA to
largely restore the definition as it read
in the 1970 CAAA. The current text of
CAA section 111(a)(1) reads: ‘‘The term
‘standard of performance’ means a
standard for emission of air pollutants
which reflects the degree of emission
limitation achievable through the
application of the best system of
emission reduction which (taking into
account the cost of achieving such
reduction and any non-air quality health
and environmental impact and energy
requirements) the Administrator
determines has been adequately
demonstrated.’’ The D.C. Circuit has
reviewed CAA section 111 rulemakings
on numerous occasions since 1973,175
and has developed a body of caselaw
that interprets the term ‘‘standard of
performance,’’ as discussed throughout
this preamble.
The basis for standards of
performance, whether promulgated by
the EPA under CAA section 111(b) or
established by the States under CAA
section 111(d), is that the EPA
determines the ‘‘degree of emission
limitation’’ that is ‘‘achievable’’ by the
sources by application of a ‘‘system of
emission reduction’’ that the EPA
determines is ‘‘adequately
demonstrated,’’ ‘‘taking into account’’
the factors of ‘‘cost . . . nonair quality
health and environmental impact and
energy requirements,’’ and that the EPA
determines to be the ‘‘best.’’ The D.C.
Circuit has stated that in determining
the ‘‘best’’ system, the EPA must also
take into account ‘‘the amount of air
175 Portland Cement Ass’n v. Ruckelshaus, 486
F.2d 375 (D.C. Cir. 1973); Essex Chemical Corp. v.
Ruckelshaus, 486 F.2d 427 (D.C. Cir. 1973); Sierra
Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981); Lignite
Energy Council v. EPA, 198 F.3d 930 (D.C. Cir.
1999); Portland Cement Ass’n v. EPA, 665 F.3d 177
(D.C. Cir. 2011); American Lung Ass’n v. EPA, 985
F.3d 914 (D.C. Cir. 2021), rev’d in part, West
Virginia v. EPA, 142 S. Ct. 2587 (2022). See also
Delaware v. EPA, No. 13–1093 (D.C. Cir. May 1,
2015).
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pollution’’ 176 reduced and the role of
‘‘technological innovation.’’ 177 The
determination of the ‘‘best’’ system
entails weighing the various factors
against each other, and the D.C. Circuit
has emphasized that the EPA has
discretion in weighing the factors.178 179
The EPA’s overall approach to
determining the BSER and degree of
emission limitation achievable, which
incorporates the various elements, is as
follows: The EPA identifies ‘‘system[s]
of emission reduction’’ that have been
‘‘adequately demonstrated’’ for a
particular source category and
determines the ‘‘best’’ of these systems
after evaluating the amount of
reductions, costs, any nonair health and
environmental impacts, and energy
requirements. As discussed below, for
each of numerous subcategories, the
EPA followed this approach to propose
the BSER on the basis that the identified
costs are reasonable and that the
proposed BSER is rational in light of the
statutory factors and other impacts,
including the amount of emission
reductions, that the EPA examined in its
BSER analysis, consistent with
governing precedent.
After determining the BSER, the EPA
determines an achievable emission limit
based on application of the BSER.180 For
a CAA section 111(b) rule, we determine
the standard of performance that reflects
the achievable emission limit. For a
CAA section 111(d) rule, the States have
the obligation of establishing standards
of performance for the affected sources
that reflect the degree of emission
limitation that the EPA has determined.
As discussed below, the EPA proposed
these determinations in association with
176 See Sierra Club v. Costle, 657 F.2d 298, 326
(D.C. Cir. 1981).
177 See Sierra Club v. Costle, 657 F.2d at 347.
178 See Lignite Energy Council, 198 F.3d at 933.
179 Although CAA section 111(a)(1) may be read
to state that the factors enumerated in the
parenthetical are part of the ‘‘adequately
demonstrated’’ determination, the D.C. Circuit’s
case law may be read to treat them as part of the
‘‘best’’ determination. See Sierra Club v. Costle, 657
F.2d at 330 (recognizing that CAA section 111 gives
the EPA authority ‘‘when determining the best
technological system to weigh cost, energy, and
environmental impacts’’). Nevertheless, it does not
appear that those two approaches would lead to
different outcomes. See, e.g., Lignite Energy
Council, 198 F.3d at 933 (rejecting challenge to the
EPA’s cost assessment of the ‘‘best demonstrated
system’’). Regardless of whether the factors are part
of the ‘‘adequately demonstrated’’ determination or
the ‘‘best’’ determination, our analysis and outcome
would be the same.
180 See, e.g., Oil and Natural Gas Sector: New
Source Performance Standards and National
Emission Standards for Hazardous Air pollutants
Reviews (77 FR 49490, 49494; August 16, 2012)
(describing the three-step analysis in setting a
standard of performance).
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each of the proposed BSER
determinations.
The remainder of this subsection
discusses each element in our general
analytical approach.
a. System of Emission Reduction
The CAA does not define the phrase
‘‘system of emission reduction.’’ In West
Virginia v. EPA, the Supreme Court
recognized that historically, the EPA
had looked to ‘‘measures that improve
the pollution performance of individual
sources and followed a ‘‘technologybased approach’’ in identifying systems
of emission reduction. In particular, the
Court identified ‘‘the sort of ‘systems of
emission reduction’ [the EPA] had
always before selected,’’ which included
‘‘ ‘efficiency improvements, fuelswitching,’ and ‘add-on controls’.’’ 142
S. Ct. at 2611 (quoting the Clean Power
Plan).181 Section 111 itself recognizes
that such systems may include off-site
activities that may reduce a source’s
pollution contribution, identifying
‘‘precombustion cleaning or treatment of
fuels’’ as a ‘‘system’’ of ‘‘emission
reduction.’’ 42 U.S.C. 7411(a)(7)(B). A
‘‘system of emission reduction’’ thus, at
a minimum, includes measures that an
individual source applies that improve
the emissions performance of that
source. Measures are fairly
characterized as improving the
pollution performance of a source where
they reduce the individual source’s
overall contribution to pollution.
In West Virginia, the Supreme Court
did not define the term ‘‘system of
emissions reduction,’’ and so did not
rule on whether ‘‘system of emission
reduction’’ is limited to those measures
that the EPA has historically relied
upon. It did go on to apply the major
questions doctrine to hold that the term
‘‘system’’ does not provide the requisite
clear authorization to support the Clean
Power Plan’s BSER, which the Court
described as ‘‘carbon emissions caps
based on a generation shifting
approach.’’ Id. at 2614. While the Court
did not define the outer bounds of the
meaning of ‘‘system,’’ systems of
emissions reduction like fuel switching,
add-on controls, and efficiency
improvements fall comfortably within
181 As noted in section V.B.4 of this preamble, the
ACE Rule adopted the interpretation that CAA
section 111(a)(1), by its plain language, limits
‘‘system of emission reduction’’ to those control
measures that could be applied at and to each
source to reduce emissions at each source. 84 FR
32523–24 (July 8, 2019). The EPA has proposed to
reject that interpretation as too narrow. See
‘‘Implementing Regulations under 40 CFR part 60
Subpart Ba Adoption and Submittal of State Plans
for Designated Facilities: Proposed Rule,’’ 87 FR
79176, 79208 (December 23, 2022).
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the scope of prior practice as recognized
by the Supreme Court.
b. ‘‘Adequately Demonstrated’’
Under CAA section 111(a)(1), an
essential, although not sufficient,
condition for a ‘‘system of emission
reduction’’ to serve as the basis for an
‘‘achievable’’ emission limitation, is that
the Administrator must determine that
the system is ‘‘adequately
demonstrated.’’ This means, according
to the D.C. Circuit, that the system is
‘‘one which has been shown to be
reasonably reliable, reasonably efficient,
and which can reasonably be expected
to serve the interests of pollution
control without becoming exorbitantly
costly in an economic or environmental
way.’’ 182 It does not mean that the
system ‘‘must be in actual routine use
somewhere.’’ 183 Rather, the court has
said, ‘‘[t]he Administrator may make a
projection based on existing technology,
though that projection is subject to the
restraints of reasonableness and cannot
be based on ‘crystal ball’ inquiry.’’ 184
Similarly, the EPA may ‘‘hold the
industry to a standard of improved
design and operational advances, so
long as there is substantial evidence that
such improvements are feasible.’’ 185
Ultimately, the analysis ‘‘is partially
dependent on ‘lead time,’ ’’ that is, ‘‘the
time in which the technology will have
to be available.’’ 186 The caselaw is clear
that the EPA may treat a set of control
measures as ‘‘adequately demonstrated’’
regardless of whether the measures are
in widespread commercial use. For
example, the D.C. Circuit upheld the
EPA’s determination that selective
catalytic reduction (SCR) was
adequately demonstrated to reduce NOX
emissions from coal-fired industrial
boilers, even though it was a ‘‘new
technology.’’ The court explained that
‘‘section 111 ‘looks toward what may
fairly be projected for the regulated
future, rather than the state of the art at
present.’ ’’ Lignite Energy Council, 198
F.3d at 934 (citing Portland Cement
Ass’n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973)). The Court added that
the EPA may determine that control
measures are ‘‘adequately
demonstrated’’ through a ‘‘reasonable
182 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d
427, 433 (D.C. Cir. 1973), cert. denied, 416 U.S. 969
(1974).
183 Portland Cement Ass’n v. Ruckelshaus, 486
F.2d 375, 391 (D.C. Cir. 1973) (citations omitted)
(discussing the Senate and House bills and reports
from which the language in CAA section 111 grew).
184 Ibid.
185 Sierra Club v. Costle, 657 F.2d 298, 364 (D.C.
Cir. 1981).
186 Portland Cement Ass’n v. Ruckelshaus, 486
F.2d 375, 391 (D.C. Cir. 1973) (citations omitted).
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extrapolation of [the control measures’]
performance in other industries.’’ Id.
The D.C. Circuit’s view that the EPA
may determine a ‘‘system of emission
reduction’’ to be ‘‘adequately
demonstrated’’ if the EPA reasonably
projects that it will be available by a
future date certain, is well-grounded in
the purposes of CAA section 111 to
reduce dangerous air pollutants. This
view recognizes that pollution control
systems may be complex and may
require a predictable amount of time for
sources across the source category to be
able to design, acquire, install, and
begin to operate them. In some
instances, the control technology may
be available, but the installation may be
a multi-year process. For example, an
existing coal-fired steam generating unit
may require several years to plan,
design, and install a Flue Gas
Desulfurization (FGD) wet scrubber for
the control of sulfur dioxide (SO2)
emissions. Under these circumstances,
common sense dictates that the EPA
may promulgate a rulemaking that
imposes a standard on the sources, but
establishes the date for compliance as a
date-certain in the future, consistent
with the period of time the source needs
to install and start operating the control
equipment. In other circumstances, a
system of emission reduction may be
well-recognized as effective in
controlling pollutants emitted by a large
source category, but manufacturers may
require a predictable amount of time to
manufacture enough control equipment
to cover the source category. In still
other circumstances, the infrastructure
needed to support the system so that it
will cover sources across the category—
whether physical infrastructure such as
pipelines or human infrastructure such
as skilled labor to install the
equipment—may require a predictable
amount of time to build out or develop
in sufficient quantity to achieve such
coverage. In all of these circumstances,
adopting requirements under CAA
section 111 at the time that the EPA is
able to reasonably project the future
deployment of the system of emission
reduction, and establishing the date of
compliance as a date-certain in the
future, serves the statutory purposes of
protecting against dangerous air
pollution by ensuring that sources take
action to control their emissions as soon
as practicable. It should also be noted
that because pollution control
invariably entails additional cost, in
some cases, the EPA’s promulgation of
regulatory requirements may be an
essential trigger for the sometimes
lengthy process of implementing
pollution controls. In these cases,
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delaying the promulgation of the
regulatory requirements until the
pollution controls can be immediately
deployed would be futile.
c. Costs
Under CAA section 111(a)(1), in
determining whether a particular
emission control is the ‘‘best system of
emission reduction . . . adequately
demonstrated,’’ the EPA is required to
take into account ‘‘the cost of achieving
[the emission] reduction.’’ By its terms,
this provision makes clear that the cost
that the EPA must take into account is
the cost to the affected source of the
system of emission reduction. Although
the Clean Air Act does not describe how
the EPA is to account for costs, the D.C.
Circuit has formulated the cost standard
in various ways.187 It has stated that the
EPA may not adopt a standard the cost
of which would be ‘‘exorbitant,’’ 188
‘‘greater than the industry could bear
and survive,’’ 189 ‘‘excessive,’’ 190 or
‘‘unreasonable.’’ 191 These formulations
appear to be synonymous, and for
convenience, in these rulemakings, we
are treating them as synonymous with
reasonableness as well, so that a control
technology may be considered the ‘‘best
system of emission reduction . . .
adequately demonstrated’’ if its costs are
reasonable, but cannot be considered
the best system if its costs are
unreasonable.192
The D.C. Circuit has repeatedly
upheld the EPA’s consideration of cost
in reviewing standards of performance.
In several cases, the court upheld
standards that entailed significant costs,
consistent with Congress’s view that
‘‘the costs of applying best practicable
control technology be considered by the
187 79
FR 1430, 1464 (January 8, 2014).
Energy Council, 198 F.3d at 933.
189 Portland Cement Ass’n v. EPA, 513 F.2d 506,
508 (D.C. Cir. 1975).
190 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C.
Cir. 1981).
191 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C.
Cir. 1981).
192 These cost formulations are consistent with
the legislative history of CAA section 111. The 1977
House Committee Report noted:
In the [1970] Congress [sic: Congress’s] view, it
was only right that the costs of applying best
practicable control technology be considered by the
owner of a large new source of pollution as a
normal and proper expense of doing business.
1977 House Committee Report at 184. Similarly,
the 1970 Senate Committee Report stated:
The implicit consideration of economic factors in
determining whether technology is ‘‘available’’
should not affect the usefulness of this section. The
overriding purpose of this section would be to
prevent new air pollution problems, and toward
that end, maximum feasible control of new sources
at the time of their construction is seen by the
committee as the most effective and, in the long
run, the least expensive approach.
S. Comm. Rep. No. 91–1196 at 16.
188 Lignite
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33273
owner of a large new source of pollution
as a normal and proper expense of doing
business.’’ 193 See Essex Chemical Corp.
v. Ruckelshaus, 486 F.2d 427, 440 (D.C.
Cir. 1973); 194 Portland Cement Ass’n v.
Ruckelshaus, 486 F.2d 375, 387–88
(D.C. Cir. 1973); Sierra Club v. Costle,
657 F.2d 298, 313 (D.C. Cir. 1981)
(upholding NSPS imposing controls on
SO2 emissions from coal-fired power
plants when the ‘‘cost of the new
controls . . . is substantial. EPA
estimates that utilities will have to
spend tens of billions of dollars by 1995
on pollution control under the new
NSPS.’’).
In its CAA section 111 rulemakings,
the EPA has frequently used a costeffectiveness metric, which determines
the cost in dollars for each ton or other
quantity of the regulated air pollutant
removed through the system of emission
reduction. See, e.g., 81 FR 35824 (June
3, 2016) (NSPS for GHG and VOC
emissions for the oil and natural gas
source category); 71 FR 9866, 9870
(February 27, 2006) (NSPS for NOX,
SO2, and PM emissions from fossil fuelfired electric utility steam generating
units); 61 FR 9905, 9910 (March 12,
1996) (NSPS and emissions guidelines
for nonmethane organic compounds and
landfill gas from new and existing
municipal solid waste landfills); 50 FR
40158 (October 1, 1985) (NSPS for SO2
emissions from sweetening and sulfur
recovery units in natural gas processing
plants). This metric allows the EPA to
compare the amount a regulation would
require sources to pay to reduce a
particular pollutant across regulations
and industries. In rules for the electric
power sector, a metric that determines
the dollar increase in the cost of a
megawatt hour of electricity generated
by the affected sources due to the
emission controls, shows the cost of
controls relative to the output of
electricity. See section VII.F.3.b.iii(B)(5)
of this preamble, which discusses $/
MWh costs of the March 15, 2023 Good
Neighbor Plan for the 2015 Ozone
NAAQS and the Cross-State Air
Pollution Rule (CSAPR) 76 FR 48208
(August 8, 2011). This metric facilitates
comparing costs across regulations and
pollutants. In this proposal, as
explained herein, the EPA looks at both
of these metrics to assess the cost
reasonableness of the proposed
requirements.
193 1977
House Committee Report at 184.
costs for these standards were described
in the rulemakings. See 36 FR 24876 (December 23,
1971), 37 FR 5767, 5769 (March 21, 1972).
194 The
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d. Non-Air Quality Health and
Environmental Impact and Energy
Requirements
Under CAA section 111(a)(1), the EPA
is required to take into account ‘‘any
nonair quality health and environmental
impact and energy requirements’’ in
determining the BSER. Non-air quality
health and environmental impacts may
include the impacts of the disposal of
byproducts of the air pollution controls,
or requirements of the air pollution
control equipment for water. Portland
Cement Ass’n v. Ruckelshaus, 465 F.2d
375, 387–88 (D.C. Cir. 1973), cert.
denied, 417 U.S. 921 (1974). Energy
requirements may include the impact, if
any, of the air pollution controls on the
source’s own energy needs.
e. Sector or Nationwide Component of
Factors in Determining the BSER
Another component of the D.C.
Circuit’s interpretations of CAA section
111 is that the EPA may consider the
various factors it is required to consider
on a national or regional level and over
time, and not only on a plant-specific
level at the time of the rulemaking.195
The D.C. Circuit based this
interpretation—which it made in the
1981 Sierra Club v. Costle case
regarding the NSPS for new power
plants—on a review of the legislative
history, stating,
[T]he Reports from both Houses on the
Senate and House bills illustrate very clearly
that Congress itself was using a long-term
lens with a broad focus on future costs,
environmental and energy effects of different
technological systems when it discussed
section 111.196
The court has upheld EPA rules that
the EPA ‘‘justified . . . in terms of the
policies of the Act,’’ including balancing
long-term national and regional impacts.
For example, the court upheld a
standard of performance for SO2
emissions from new coal-fired power
plants on grounds that it—
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reflects a balance in environmental,
economic, and energy consideration by being
sufficiently stringent to bring about
substantial reductions in SO2 emissions (3
million tons in 1995) yet does so at
reasonable costs without significant energy
penalties. . . .197
The EPA interprets this caselaw to
authorize it to assess the impacts of the
controls it is considering as the BSER,
including their costs and implications
for the energy system, on a sector-wide,
195 See 79 FR 1430, 1465 (January 8, 2014) (citing
Sierra Club v. Costle, 657 F.2d at 351).
196 Sierra Club v. Costle, 657 F.2d at 331 (citations
omitted) (citing legislative history).
197 Sierra Club v. Costle, 657 F.2d at 327–28
(quoting 44 FR 33583–33584; June 11, 1979).
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regional, or national basis, as
appropriate. For example, the EPA may
assess whether controls it is considering
would create risks to the reliability of
the electricity system in a particular
area or nationwide and, if they would,
to reject those controls as the BSER.
f. ‘‘Best’’
In determining which adequately
demonstrated system of emission
reduction is the ‘‘best,’’ the D.C. Circuit
has made clear that the EPA has broad
discretion. Specifically, in Sierra Club v.
Costle, 657 F.2d 298 (D.C. Cir. 1981), the
court explained that ‘‘section 111(a)
explicitly instructs the EPA to balance
multiple concerns when promulgating a
NSPS,’’ 198 and emphasized that ‘‘[t]he
text gives the EPA broad discretion to
weigh different factors in setting the
standard,’’ including the amount of
emission reductions, the cost of the
controls, and the non-air quality
environmental impacts and energy
requirements.199 In Lignite Energy
Council v. EPA, 198 F.3d 930 (D.C. Cir.
1999), the court reiterated:
Because section 111 does not set forth the
weight that should be assigned to each of
these factors, we have granted the agency a
great degree of discretion in balancing
them. . .–. EPA’s choice [of the ‘best
system’] will be sustained unless the
environmental or economic costs of using the
technology are exorbitant. . . . EPA [has]
considerable discretion under section 111.200
See AEP v. Connecticut, 564 U.S. 410,
427 (2011) (under CAA section 111,
‘‘The appropriate amount of regulation
in any particular greenhouse gasproducing sector cannot be prescribed
in a vacuum: . . . informed assessment
of competing interests is required.
Along with the environmental benefit
potentially achievable, our Nation’s
energy needs and the possibility of
economic disruption must weigh in the
balance. The Clean Air Act entrusts
such complex balancing to the EPA in
198 Sierra
Club v. Costle, 657 F.2d at 319.
Club v. Costle, 657 F.2d at 321; see also
New York v. Reilly, 969 F.2d at 1150 (because
Congress did not assign the specific weight the
Administrator should assign to the statutory
elements, ‘‘the Administrator is free to exercise
[her] discretion’’ in promulgating an NSPS).
200 Lignite Energy Council, 198 F.3d at 933
(paragraphing revised for convenience). See New
York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992)
(‘‘Because Congress did not assign the specific
weight the Administrator should accord each of
these factors, the Administrator is free to exercise
his discretion in this area.’’); see also NRDC v. EPA,
25 F.3d 1063, 1071 (D.C. Cir. 1994) (The EPA did
not err in its final balancing because ‘‘neither RCRA
nor EPA’s regulations purports to assign any
particular weight to the factors listed in subsection
(a)(3). That being the case, the Administrator was
free to emphasize or deemphasize particular factors,
constrained only by the requirements of reasoned
agency decisionmaking.’’).
199 Sierra
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the first instance, in combination with
State regulators. Each ‘‘standard of
performance’’ the EPA sets must ‘‘tak[e]
into account the cost of achieving
[emissions] reduction and any nonair
quality health and environmental
impact and energy requirements.’’
(paragraphing revised; citations
omitted)).
Moreover, the D.C. Circuit has also
read ‘‘best’’ to authorize the EPA to
consider factors in addition to the ones
enumerated in CAA section 111(a)(1),
that further the purpose of the statute.
In Portland Cement Ass’n v.
Ruckelshaus, 486 F.2d 375 (D.C. Cir.
1973), the D.C. Circuit held that under
CAA section 111(a)(1) as it read prior to
the enactment of the 1977 CAA
Amendments that added a requirement
that the EPA take account of non-air
quality environmental impacts, the EPA
must consider ‘‘counter-productive
environmental effects’’ in determining
the BSER. Id. at 385. The court
elaborated: ‘‘The standard of the ‘best
system’ is comprehensive, and we
cannot imagine that Congress intended
that ‘best’ could apply to a system
which did more damage to water than
it prevented to air.’’ Id., n.42. In Sierra
Club v. Costle, 657 F.2d 298, 326, 346–
47 (D.C. Cir. 1981), the court added that
the EPA must consider the amount of
emission reductions and technology
advancement in determining BSER.
The court’s view that ‘‘best’’ includes
additional factors that further the
purpose of CAA section 111 is a
reasonable interpretation of that term in
its statutory context. The purpose of
CAA section 111 is to reduce emissions
of air pollutants that endanger public
health or welfare. CAA section
111(b)(1)(A). The court reasonably
surmised that the EPA’s determination
of whether a system of emission
reduction that reduced certain air
pollutants is ‘‘best’’ should be informed
by impacts that the system may have on
other pollutants that affect public or
welfare. Portland Cement Ass’n, 486
F.2d at 385. The Supreme Court
confirmed the D.C. Circuit’s approach in
Michigan v. EPA 576 U.S. 743 (2015),
explaining that administrative agencies
must engage in ‘‘reasoned
decisionmaking’’ that, in the case of
pollution control, cannot be based on
technologies that ‘‘do even more damage
to human health’’ than the emissions
they eliminate. Id. at 751–52. After
Portland Cement Ass’n, Congress
revised CAA section 111(a)(1) to make
explicit that in determining whether a
system of emission reduction is the
‘‘best,’’ the EPA should account for nonair quality health and environmental
impacts. By the same token, the EPA
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takes the position that in determining
whether a system of emission reduction
is the ‘‘best,’’ the EPA may account for
the impacts of the system on air
pollutants other than the ones that are
the subject of the CAA section 111
regulation.201 We discuss immediately
below other factors that the D.C. Circuit
has held the EPA should account for in
determining what system is the ‘‘best.’’
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g. Amount of Emissions Reductions
Consideration of the amount of
emissions from the category of sources
or the amount of emission reductions
achieved as factors the EPA must
consider in determining the ‘‘best
system of emission reduction’’ is
implicit in the plain language of CAA
section 111(a)(1)—the EPA must choose
the best system of emission reduction.
Indeed, consistent with this plain
language and the purpose of CAA
section 111, the D.C. Circuit has stated
that the EPA must consider the quantity
of emissions at issue. See Sierra Club v.
Costle, 657 F.2d 298, 326 (D.C. Cir.
1981) (‘‘we can think of no sensible
interpretation of the statutory words
‘‘best . . . system’’ which would not
incorporate the amount of air pollution
as a relevant factor to be weighed when
determining the optimal standard for
controlling . . . emissions’’).202 The fact
that the purpose of a ‘‘system of
emission reduction’’ is to reduce
emissions, and that the term itself
explicitly incorporates the concept of
reducing emissions, supports the court’s
view that in determining whether a
‘‘system of emission reduction’’ is the
‘‘best,’’ the EPA must consider the
amount of emission reductions that the
system would yield. Even if the EPA
201 See generally ‘‘Standards of Performance for
New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and
Natural Gas Sector Climate Review—Supplemental
Notice of Proposed Rulemaking,’’ 87 FR 74702,
74765 (December 6, 2022) (proposing the BSER for
reducing methane and VOC emissions from natural
gas-driven controllers in the oil and natural gas
sector on the basis of, among other things, impacts
on emissions of criteria pollutants). In this
preamble, for convenience, the EPA generally
discusses the effects of controls on non-GHG air
pollutants along with the effects of controls on nonair quality health and environmental impacts.
202 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir.
1981) was governed by the 1977 CAAA version of
the definition of ‘‘standard of performance,’’ which
revised the phrase ‘‘best system of emission
reduction’’ to read, ‘‘best technological system of
continuous emission reduction.’’ As noted above,
the 1990 CAAA deleted ‘‘technological’’ and
‘‘continuous’’ and thereby returned the phrase to
how it read under the 1970 CAAA. The court’s
interpretation of the 1977 CAAA phrase in Sierra
Club v. Costle to require consideration of the
amount of air emissions focused on the term ‘‘best’’,
and the terms ‘‘technological’’ and ‘‘continuous’’
were irrelevant to its analysis. It thus remains valid
for the 1990 CAAA phrase ‘‘best system of emission
reduction.’’
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were not required to consider the
amount of emission reductions, the EPA
has the discretion to do so, on grounds
that either the term ‘‘system of emission
reduction’’ or the term ‘‘best’’ may
reasonably be read to allow that
discretion.
33275
Congress’s emphasis on technological
innovation.
i. Achievability of the Degree of
Emission Limitation
For new sources, CAA section
111(b)(1)(B) and (a)(1) provides that the
EPA must establish ‘‘standards of
h. Expanded Use and Development of
performance,’’ which are standards for
Technology
emissions that reflect the degree of
The D.C. Circuit has long held that
emission limitation that is ‘‘achievable’’
Congress intended for CAA section 111
through the application of the BSER.
to create incentives for new technology
According to the D.C. Circuit, a standard
and therefore that the EPA is required
of performance is ‘‘achievable’’ if a
to consider technological innovation as
technology can reasonably be projected
one of the factors in determining the
to be available to an individual source
‘‘best system of emission reduction.’’
at the time it is constructed that will
See Sierra Club v. Costle, 657 F.2d at
allow it to meet the standard.208
346–47. The court has grounded its
Moreover, according to the court, ‘‘[a]n
reading in the statutory text of CAA
achievable standard is one which is
111(a)(1), defining the term ‘‘standard of within the realm of the adequately
performance’’.203 In addition, the court’s demonstrated system’s efficiency and
interpretation finds support in the
which, while not at a level that is purely
legislative history.204 The legislative
theoretical or experimental, need not
history identifies three different ways
necessarily be routinely achieved within
that Congress designed CAA section 111 the industry prior to its adoption.’’ 209
to authorize standards of performance
To be achievable, a standard ‘‘must be
that promote technological
capable of being met under most
improvement: (1) The development of
adverse conditions which can
technology that may be treated as the
reasonably be expected to recur and
‘‘best system of emission reduction . . . which are not or cannot be taken into
adequately demonstrated;’’ under CAA
account in determining the ‘costs’ of
section 111(a)(1); 205 (2) the expanded
compliance.’’ 210 To show a standard is
use of the best demonstrated
achievable, the EPA must ‘‘(1) identify
technology; 206 and (3) the development variable conditions that might
of emerging technology.207 Even if the
contribute to the amount of expected
EPA were not required to consider
emissions, and (2) establish that the test
technological innovation as part of its
data relied on by the agency are
determination of the BSER, it would be
representative of potential industryreasonable for the EPA to consider it
wide performance, given the range of
because technological innovation may
variables that affect the achievability of
be considered an element of the term
the standard.’’ 211
‘‘best,’’ particularly in light of
Although the D.C. Circuit established
these standards for achievability in
203 Sierra Club v. Costle, 657 F.2d at 346 (‘‘Our
cases concerning CAA section 111(b)
interpretation of section 111(a) is that the mandated
new source standards of performance,
balancing of cost, energy, and nonair quality health
generally comparable standards for
and environmental factors embraces consideration
achievability should apply under CAA
of technological innovation as part of that balance.
The statutory factors which EPA must weigh are
section 111(d), although the BSER may
broadly defined and include within their ambit
differ as between new and existing
subfactors such as technological innovation.’’).
sources due to, for example, higher costs
204 See S. Rep. No. 91–1196 at 16 (1970)
(‘‘Standards of performance should provide an
incentive for industries to work toward constant
improvement in techniques for preventing and
controlling emissions from stationary sources’’); S.
Rep. No. 95–127 at 17 (1977) (cited in Sierra Club
v. Costle, 657 F.2d at 346 n. 174) (‘‘The section 111
Standards of Performance . . . sought to assure the
use of available technology and to stimulate the
development of new technology’’).
205 Portland Cement Ass’n v. Ruckelshaus, 486
F.2d 375, 391 (D.C. Cir. 1973) (the best system of
emission reduction must ‘‘look[ ] toward what may
fairly be projected for the regulated future, rather
than the state of the art at present’’).
206 1970 Senate Committee Report No. 91–1196 at
15 (‘‘The maximum use of available means of
preventing and controlling air pollution is essential
to the elimination of new pollution problems’’).
207 Sierra Club v. Costle, 657 F.2d at 351
(upholding a standard of performance designed to
promote the use of an emerging technology).
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208 Sierra Club v. Costle, 657 F.2d 298, 364, n. 276
(D.C. Cir. 1981).
209 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d
427, 433–34 (D.C. Cir. 1973), cert. denied, 416 U.S.
969 (1974).
210 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433,
n.46 (D.C. Cir. 1980).
211 Sierra Club v. Costle, 657 F.2d 298, 377 (D.C.
Cir. 1981) (citing Nat’l Lime Ass’n v. EPA, 627 F.2d
416 (D.C. Cir. 1980). In considering the
representativeness of the source tested, the EPA
may consider such variables as the ‘‘ ‘feedstock,
operation, size and age’ of the source.’’ Nat’l Lime
Ass’n v. EPA, 627 F.2d 416, 433 (D.C. Cir. 1980).
Moreover, it may be sufficient to ‘‘generalize from
a sample of one when one is the only available
sample, or when that one is shown to be
representative of the regulated industry along
relevant parameters.’’ Nat’l Lime Ass’n v. EPA, 627
F.2d 416, 434, n.52 (D.C. Cir. 1980).
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of retrofit. 40 FR 53340 (November 17,
1975). For existing sources, CAA section
111(d)(1) requires the EPA to establish
requirements for State plans that, in
turn, must include ‘‘standards of
performance.’’ As the Supreme Court
has recognized, this provision requires
the EPA to promulgate emission
guidelines that determine the BSER for
a source category and then identify the
degree of emission limitation achievable
by application of the BSER. See West
Virginia v. EPA, 142 S. Ct. 2587, 2601–
02 (2022).212
The EPA has promulgated emission
guidelines on the basis that the existing
sources can achieve the degree of
emission limitation described therein,
even though under the RULOF
provision of CAA section 111(d)(1), the
State retains discretion to apply
standards of performance to individual
sources that are more or less stringent,
which indicates that Congress
recognized that the EPA may
promulgate emission guidelines that are
consistent with CAA section 111(d)
even though certain individual sources
may not be able to achieve the degree
of emission limitation identified therein
by applying the controls that the EPA
determined to be the BSER. Note further
that this requirement that the emission
limitation be ‘‘achievable’’ based on the
‘‘best system of emission reduction . . .
adequately demonstrated’’ indicates that
the technology or other measures that
the EPA identifies as the BSER must be
technically feasible.
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4. EPA Promulgation of Emission
Guidelines for States To Establish
Standards of Performance
CAA section 111(d)(1) directs the EPA
to promulgate regulations establishing a
CAA section 110-like procedure under
which States submit State plans that
establish ‘‘standards of performance’’ for
emissions of certain air pollutants from
sources which, if they were new
sources, would be regulated under CAA
section 111(b), and that implement and
enforce those standards of performance.
The term ‘‘standard of performance’’ is
defined under CAA section 111(a)(1),
quoted above. Thus, CAA sections
111(a)(1) and (d)(1) collectively require
the EPA to determine the BSER for the
existing sources and, based on the
BSER, to establish emission guidelines
that identify the minimum amount of
emission limitation that a State, in its
State plan, must impose on its existing
sources through standards of
performance. Consistent with these
CAA requirements, the EPA’s
regulations require that the EPA’s
guidelines reflect—
the degree of emission limitation achievable
through the application of the best system of
emission reduction which (taking into
account the cost of such reduction and any
non-air quality health and environmental
impact and energy requirements) the
Administrator has determined has been
adequately demonstrated from designated
facilities.213
Following the EPA’s promulgation of
emission guidelines, each State must
determine the standards of performance
for its existing sources, which the EPA’s
regulations call ‘‘designated
facilities.’’ 214 While the EPA specifies
in emission guidelines the degree of
emission limitation achievable through
application of the best system of
emission reduction, which it may
express as a presumptive standard of
performance, a State retains discretion
in applying such a presumptive
standard of performance to any
particular designated facility. CAA
section 111(d)(1) requires the EPA’s
regulations to ‘‘permit the State in
applying a standard of performance to
any particular source . . . to take into
consideration, among other factors, the
remaining useful life the . . . source
. . . .’’ Consistent with this statutory
direction, the EPA’s regulations provide
requirements for States that wish to
apply standards of performance that
deviate from an emission guideline. In
December 2022, the EPA proposed to
clarify these requirements, including the
three circumstances under which States
can invoke a particular source’s
remaining useful life and other factors
(RULOF), to apply a less stringent
standard of performance. These
proposed clarifications provided:
The State may apply a standard of
performance to a particular source that is less
stringent than otherwise required by an
applicable emission guideline, taking into
consideration remaining useful life and other
factors, provided that the State demonstrates
with respect to each such facility (or class of
such facilities) that it cannot reasonably
apply the best system of emission reduction
to achieve the degree of emission limitation
determined by the EPA, based on:
(1) Unreasonable cost of control resulting
from plant age, location, or basic process
design;
(2) Physical impossibility or technical
infeasibility of installing necessary control
equipment; or
(3) Other circumstances specific to the
facilities (or class of facilities) that are
fundamentally different from the information
considered in the determination of the best
system of emission reduction in the emission
guidelines.
213 40
212 40
CFR 60.21(e), 60.21a(e).
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CFR 60.21a(b), 60.24a(b).
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87 FR 79176 (December 23, 2022),
Docket ID No. EPA–HQ–OAR–2021–
0527–0002 (proposed 40 CFR
60.24a(e)).215 In addition, under CAA
sections 111(d) and 116, the State is
authorized to establish a standard of
performance for any particular source
that is more stringent than the
presumptive standards contained in the
EPA’s emission guidelines.216 Thus, for
any particular source, a State may apply
a standard of performance that is either
more stringent or less stringent than the
presumptive standards of performance
in the emission guidelines. The State
must include the standards of
performance in their State plans and
submit the plans to the EPA for
review.217 Under CAA section
111(d)(2)(A), the EPA approves State
plans that are determined to be
‘‘satisfactory.’’
IV. Stakeholder Engagement
Prior to proposing these actions, the
EPA conducted outreach to a broad
range of stakeholders. The EPA also
opened a non-regulatory pre-proposal
docket to solicit public input on the
Agency’s efforts to reduce GHG
emissions from new and existing
EGUs.218 For additional details on
stakeholder engagement, see the
memorandum in the docket titled
Stakeholder Outreach.
The EPA conducted two rounds of
outreach to gather input for these
proposals. In the first round of outreach,
in early 2022, the EPA sought input in
a variety of formats and settings from
States, Tribal nations, and a broad range
215 The EPA intends to finalize the December
2022 proposed revisions to the CAA section 111
implementation regulations in 40 CFR part 60,
subpart Ba, including any changes made in
response to public comments, prior to promulgating
these emission guidelines. Thus, 40 CFR part 60,
subpart Ba, as revised, would apply to these
emission guidelines.
216 40 CFR 60.24a(f). The EPA’s December 2022
proposed revisions to 40 CFR part 60, subpart Ba
reflect its current interpretation that the EPA has
the authority to review and approve plans that
include standards of performance that are more
stringent than the presumptive standards in the
EPA’s emission guidelines, thus making those more
stringent requirements federally enforceable. 87 FR
79204 (December 23, 2022), Docket ID No. EPA–
HQ–OAR–2021–0527–0002 (proposed 40 CFR
60.24a(m), (n)). In addition, CAA section 116
authorizes the state to set standards of performance
for all of its sources that, together, are more
stringent than the EPA’s emission guidelines.
217 40 CFR 60.23a. In January 2021, the D.C.
Circuit Court of Appeals vacated the three-year
deadline for state plan submissions of a final
emission guideline in 40 CFR 60.23a(a)(1). The
EPA’s December 2022 proposed revisions to subpart
Ba would revise 60.23a to, inter alia, provide for a
fifteen-month submission deadline. 87 FR 79182
(December 23, 2022), Docket ID No. EPA–HQ–
OAR–2021–0527–0002 (proposed 40 CFR
60.23a(a)).
218 Docket ID No. EPA–HQ–OAR–2022–0723.
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of stakeholders on the state of the power
sector and how the Agency’s regulatory
actions affect those trends. This
outreach included State energy and
environmental regulators; Tribal air
regulators; power companies and trade
associations representing investorowned utilities, rural electric
cooperatives, and municipal power
agencies; environmental justice and
community organizations; and labor,
environmental, and public health
organizations. A second round of
outreach took place in August and
September 2022, and focused on seeking
input specific to this rulemaking. The
EPA asked to hear perspectives,
priorities, and feedback around five
guiding questions, and encouraged
public input to the nonregulatory docket
(Docket ID No. EPA–HQ–OAR–2022–
0723) on these questions as well.
The EPA also regularly interacts with
other Federal agencies and departments
whose activities intersect with the
power sector, and in the course of
developing these proposed rules the
Agency conducted multiple discussions
with these agencies to benefit from their
expertise and to explore the potential
interaction of these proposed rules with
their independent missions and
initiatives. Among other things, these
discussions focused on the impacts of
proposed investments in energy
technology by the Department of Energy
and Department of Treasury on the
technical and economic analyses
underlying this proposal. In addition,
the EPA evaluated structures in these
proposals to address reliability
considerations with the Department of
Energy.
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VII. Proposed Requirements for New
and Reconstructed Stationary
Combustion Turbine EGUs and
Rationale for Proposed Requirements
A. Overview
This section discusses and proposes
requirements for stationary combustion
turbine EGUs that commence
construction or reconstruction after the
date of publication of this proposed
action. The EPA is proposing that those
requirements will be codified in 40 CFR
part 60, subpart TTTTa. The EPA
explains in section VII.B the two basic
turbine technologies in use in the power
sector and covered by 40 CFR part 60,
subpart TTTT, simple cycle turbines
and combined cycle turbines. It further
explains how these technologies are
used in the three subcategories of low
load turbines, intermediate load
turbines, and base load turbines. Section
VII.C provides an overview of how
stationary combustion turbines have
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been previously regulated and how the
EPA recently took comment on a
proposed white paper on GHG
mitigation options for stationary
combustion turbines. Section VII.D
discusses the EPA’s decision to revisit
the standards for turbines as part of the
statutorily required 8-year review.
Section VII.E discusses changes that the
EPA is proposing in both applicability
and subcategories in the new proposed
40 CFR part 60, subpart TTTTa as
compared to those codified in 40 CFR
part 60, subpart TTTT. Most notably, for
natural gas-fired combustion turbines,
the EPA is proposing three
subcategories, a low load subcategory,
an intermediate load subcategory, and a
base load subcategory.
Section VII.F discusses the EPA’s
determination of the BSER for each of
the subcategories of turbines. For low
load combustion turbines, the EPA
continues to believe that use of lower
emitting fuels is the appropriate BSER.
For intermediate load turbines, the EPA
believes that both highly efficient
generation and co-firing low-GHG
hydrogen are appropriate components of
the BSER, and that there will be enough
low-GHG hydrogen at a reasonable price
to supply the combustion turbines that
would need to use it in 2032. For this
reason, the EPA is proposing a twocomponent BSER for intermediate load
combustion turbines, and a two-phase
standard of performance. The first
component of the BSER would be highly
efficient generation (based on the
performance of a highly efficient simple
cycle turbine), with a corresponding
first-phase standard of performance. The
second component of the BSER is cofiring 30 percent (by volume) low-GHG
hydrogen, along with continued use of
highly efficient generation, with a
corresponding second-phase standard of
performance. The EPA is also soliciting
comment on whether intermediate load
combustion turbines should be subject
to a more stringent third-phase standard
based on higher levels of low-GHG
hydrogen co-firing by 2038.
Additionally, the EPA is soliciting
comment on whether the electric sales
threshold used to define intermediate
and base load units should be reduced
further.
For base load turbines, the EPA
likewise believes that the BSER includes
multiple components that correspond to
a multi-phase standard of performance.
This is appropriate based on
consideration of the manufacturing and
installation capabilities within the
larger EGU category and other
industries, and considerations of
projected operation of combustion
turbines in the future. For base load
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turbines, the EPA is proposing two
BSER pathways with corresponding
standards of performance that new and
reconstructed stationary combustion
turbines may take—one BSER pathway
is based on the use of 90 percent CCS
and a separate BSER pathway is based
on co-firing low-GHG hydrogen. The
EPA proposes that the first component
of the BSER for both pathways is highly
efficient generation (based on the
performance of a highly efficient
combined cycle unit) and the second
component of the BSER is based on the
use of either 90 percent CCS in 2035 or
co-firing 30 percent (by volume) lowGHG hydrogen in 2032, along with
continued use of highly efficient
generation for both pathways. For base
load turbines that are subject to a
second phase standard of performance
based on a highly efficient combined
cycle unit co-firing 30 percent (by
volume) low-GHG hydrogen, the EPA
proposes that those units also meet a
third phase component of the BSER
based on the co-firing of 96 percent (by
volume) low-GHG hydrogen by 2038.
These two BSER pathways both offer
significant opportunities to reduce GHG
emissions even though they may be
available on slightly different
timescales. The EPA seeks comment
specifically on the percentages of
hydrogen co-firing and CO2 capture, the
dates that meet the statutory BSER
criteria for each pathway, whether the
Agency should finalize both pathways
as separate subcategories with separate
standards of performance, or whether it
should finalize one pathway with the
option of meeting the standard of
performance using either system of
emission reduction—e.g., a single
standard of 90 lb CO2/MWh-gross based
on the application of CCS with 90
percent capture, which could also be
met by co-firing 96 percent low-GHG
hydrogen.
For both intermediate load and base
load turbines, the standards of
performance corresponding to both
components of the BSER would apply to
all new and reconstructed sources that
commence construction or
reconstruction after the publication date
of this proposal. The EPA occasionally
refers to these standards of performance
as the phase-1, phase-2, or phase-3
standards.
B. Combustion Turbine Technology
For purposes of 40 CFR part 60,
subparts TTTT and TTTTa, stationary
combustion turbines include both
simple cycle and combined cycle EGUs.
Simple cycle turbines operate in the
Brayton thermodynamic cycle and
include three primary components: a
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multistage compressor, a combustion
chamber (i.e., combustor), and a turbine.
The compressor is used to supply large
volumes of high-pressure air to the
combustion chamber. The combustion
chamber converts fuel to heat and
expands the now heated, compressed air
to create shaft work. The shaft work
drives an electric generator to produce
electricity. Combustion turbines that
recover their high-temperature
exhaust—instead of venting it directly
to the atmosphere—are combined cycle
EGUs and can obtain additional useful
electric output. A combined cycle EGU
includes a heat recovery steam generator
(HRSG) operating in the Rankine
thermodynamic cycle. The HRSG
receives the high-temperature exhaust
and converts the heat to mechanical
energy by producing steam that is then
fed into a steam turbine that, in turn,
drives a second electric generator. As
the thermal efficiency of a stationary
combustion turbine EGU is increased,
less fuel is burned to produce the same
amount of electricity, with a
corresponding decrease in fuel costs and
lower emissions of CO2 and, generally,
of other air pollutants. The greater the
output of electric energy for a given
amount of fuel energy input, the higher
the efficiency of the electric generation
process.
Combustion turbines serve various
roles in the power sector. Some
combustion turbines operate at low
annual capacity factors and are available
to provide temporary power during
periods of high load demand. These
turbines are often referred to as
‘‘peaking units.’’ Some combustion
turbines operate at intermediate annual
capacity factors and are often referred to
as cycling or load-following units. Other
combustion turbines operate at high
annual capacity factors to serve base
load demand and are often referred to as
base load units. In this proposal, the
EPA refers to these types of combustion
turbines as low load, intermediate load,
and base load, respectively.
Low load combustion turbines
provide reserve capacity, support grid
reliability, and generally provide power
during periods of peak electric demand.
As such, the units may operate at or
near their full capacity, but only for
short periods, as needed. Because these
units only operate occasionally, capital
expenses are a major factor in the
overall cost of electricity, and often, the
lowest capital cost (and generally less
efficient) simple cycle EGUs are
intended for use only during periods of
peak electric demand. Due to their low
efficiency, these units require more fuel
per MWh of electricity produced and
their operating costs tend to be higher.
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Because of the higher operating costs,
they are generally some of the last units
in the dispatch order. Important
characteristics for low load combustion
turbines include their low capital costs,
their ability to start and quickly ramp to
full load, and their ability to operate at
partial loads while maintaining
acceptable emission rates and
efficiencies. The ability to start and
quickly attain full load is important to
maximize revenue during periods of
peak electric prices and to meet sudden
shifts in demand. In contrast, under
steady-state conditions, more efficient
combined cycle EGUs are dispatched
ahead of low load turbines and often
operate at higher capacity factors.
Highly efficient simple cycle turbines
and fast-start combined cycle turbines
both offer different advantages and
disadvantages when operating at
intermediate loads. One of the roles of
these intermediate or load-following
EGUs is to provide dispatchable backup
power to support variable renewable
generating sources. A developer’s
decision of whether to build a simple
cycle combustion turbine or a combined
cycle combustion turbine to serve
intermediate load demand would be
based on several factors related to the
intended operation of the unit. These
factors include how frequently the unit
is expected to cycle between starts and
stops, the predominant load level at
which the unit is expected to operate,
and whether this level of operation is
expected to remain consistent or is
expected to vary over the lifetime of the
unit. While the owner/operator of an
individual combustion turbine controls
whether and how that unit will operate
over time, they do not necessarily
control the precise timing of dispatch
for the unit in any given day or hour.
Such short-term dispatch decisions are
often made by regional grid operators
that determine, on a moment-to-moment
basis, which available individual units
should operate to balance supply and
demand and other requirements in an
optimal manner, based on operating
costs, price bids, and/or operational
characteristics. However, operating
permits for simple cycle turbines often
contain restrictions on the annual hours
of operation that owners/operators
incorporate into longer term operating
plans and short-term dispatch decisions.
Intermediate load combustion
turbines vary their generation,
especially during transition periods
between low and high electric demand.
Both high-efficiency simple cycle
combustion turbines and fast-start
combined cycle combustion turbines
can fill this cycling role. While the
ability to start and quickly ramp is
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important, efficiency is also an
important characteristic. These
combustion turbines generally have
higher capital costs than low load
combustion turbines but are generally
less expensive to operate.
Base load combustion turbines are
designed to operate for extended
periods at high loads with infrequent
starts and stops. Quick start capability
and low capital costs are less important
than low operating costs. Highefficiency combined cycle combustion
turbines typically fill the role of base
load combustion turbines.
The increase in generation from
variable renewable energy sources
during the past decade has impacted the
way in which firm dispatchable
generating resources operate.219 For
example, the electric output from wind
and solar generating sources fluctuates
daily and seasonally due to increases
and decreases in the wind speed or solar
intensity. Due to this variable nature of
wind and solar, firm dispatchable
electric generating units are used to
ensure the reliability of the electric grid.
This requires technologies such as
dispatchable power plants to start and
stop and change load more frequently
than was previously needed. Important
characteristics of combustion turbines
that provide firm backup capacity are
the ability to start and stop quickly and
the ability to quickly change loads.
Natural gas-fired combustion turbines
are much more flexible than coal-fired
utility boilers in this regard and have
played an important role in ensuring
electric supply and demand are in
balance during the past decade.
As discussed in section IV.F.2 of this
preamble and in the accompanying RIA,
the post-IRA 2022 reference case
projects that natural gas-fired
combustion turbines will continue to
play an important role in meeting
electricity demand. However, that role
is projected to evolve as additional
renewable and non-renewable low-GHG
generation and energy storage
technologies are added to the grid.
Energy storage technologies can store
energy during periods when generation
from renewable resources is high
relative to demand and provide
electricity to the grid during other
periods. This could reduce the need for
fossil fuel-fired firm dispatchable power
plants to start and stop as frequently.
Consequently, in the future, natural gas219 Dispatchable EGUs can be turned on and off
and adjust the amount of power supplied to the
electric grid based on the demand for electricity.
Variable (sometimes referred to as intermittent)
EGUs supply electricity based on external factors
that are not controlled by the owner/operator of the
EGU.
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fired stationary combustion turbine
EGUs may run at more stable operation
and, thus, more efficiently (i.e., at higher
duty cycles and for longer periods of
operation per start). The EPA is
soliciting comment on whether this a
likely scenario.
C. Overview of Regulation of Stationary
Combustion Turbines for GHGs
As explained earlier in this preamble,
the EPA originally regulated stationary
combustion turbine EGUs for emissions
of GHGs in 2015 under 40 CFR part 60,
subpart TTTT. In 40 CFR part 60,
subpart TTTT, the EPA created three
subcategories, two for natural gas-fired
combustion turbines and one for multifuel-fired combustion turbines. For
natural gas-fired turbines, the EPA
created a subcategory for base load
turbines and a separate subcategory for
non-base load turbines. Base load
turbines were defined as combustion
turbines with electric sales greater than
a site-specific electric sales threshold
that is based on the design efficiency of
the combustion turbine. Non-base load
turbines were defined as combustion
turbines with a capacity factor less than
or equal to the site-specific electric sales
threshold. For base load turbines, the
EPA set a standard of 1,000 lb CO2/
MWh-gross based on efficient combined
cycle turbine technology and for nonbase load and multi-fuel-fired turbines,
the EPA set a standard based on the use
of lower emitting fuels that varied from
120 lb CO2/MMBtu to 160 lb CO2/
MMBtu depending upon whether the
turbine burned primarily natural gas or
other lower emitting fuels.
On April 21, 2022, the EPA issued an
informational draft white paper, titled
Available and Emerging Technologies
for Reducing Greenhouse Gas Emissions
from Combustion Turbine Electric
Generating Units.220 The draft
document included discussion of the
basic types of available stationary
combustion turbines as well as factors
that influence GHG emission rates from
these sources. The technology
discussion in the draft white paper
included information on an array of new
and existing control technologies and
potential reduction measures for GHG
emissions. These reduction measures
included: the GHG reduction potential
of various efficiency improvements;
technologies capable of firing or cofiring alternative fuels such as
hydrogen; the ongoing advancement of
CCS projects with NGCC units; and the
co-location of technologies that do not
220 https://www.epa.gov/stationary-sources-air-
pollution/white-paper-available-and-emergingtechnologies-reducing.
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emit onsite GHG emissions with EGUs,
such as onsite renewables or shortduration energy storage.
The EPA provided an opportunity for
the public to comment on this white
paper to inform its approach to this
proposed rulemaking. More than 30
groups or individuals provided public
comments on the topics and
technologies discussed in the draft
white paper. Commenters included
representatives from utilities,
technology providers, trade
associations, States, regulatory agencies,
NGOs, and public health advocates. The
information provided in the public
comments was beneficial in enabling
the EPA to review the current NSPS for
new stationary combustion turbines and
to develop the proposed revisions
described in this preamble.
D. Eight-Year Review of NSPS
CAA section 111(b)(1)(B) requires the
Administrator to ‘‘at least every 8 years,
review and, if appropriate, revise [the
NSPS] . . .’’ The provision further
provides that ‘‘the Administrator need
not review any such standard if the
Administrator determines that such
review is not appropriate in light of
readily available information on the
efficacy of such [NSPS].’’
The EPA promulgated the NSPS for
GHG emissions for stationary
combustion turbines in 2015.
Announcements and modeling
projections show companies are
building new fossil fuel-fired
combustion turbines and plan to
continue building additional capacity.
Because the emissions from this
capacity have the potential to be large
and these units are likely to have long
lives (25 years or more), the EPA
believes it is important to consider
options to reduce emissions from these
new units. In addition, the EPA is aware
of developments concerning the types of
control measures that may be available
to reduce GHG emissions from new
stationary combustion turbines.
Accordingly, the EPA is proceeding to
review and is proposing updated NSPS
for newly constructed and reconstructed
fossil fuel-fired stationary combustion
turbines.
E. Applicability Requirements and
Subcategorization
This section describes the proposed
amendments to the specific
applicability criteria for non-fossil fuelfired EGUs, industrial EGUs, CHP EGUs,
and combustion turbines EGUs not
connected to a natural gas pipeline. The
EPA is also proposing certain changes to
the applicability requirements for
stationary combustion turbines affected
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by this proposal as compared to those
for sources affected by the 2015 NSPS.
The proposed changes are described
below and include the elimination of
the multi-fuel-fired subcategory, further
binning non-base load combustion
turbines into low and intermediate load
subcategories, and lowering the electric
sales threshold for base load combustion
turbines.
1. Applicability Requirements
In general, the EPA refers to fossil
fuel-fired EGUs that would be subject to
a CAA section 111 NSPS as ‘‘affected’’
EGUs or units. An EGU is any fossil
fuel-fired electric utility steam
generating unit (i.e., a utility boiler or
IGCC unit) or stationary combustion
turbine (in either simple cycle or
combined cycle configuration). To be
considered an affected EGU under the
current NSPS at 40 CFR part 60, subpart
TTTT, the unit must meet the following
applicability criteria: The unit must: (1)
Be capable of combusting more than 250
million British thermal units per hour
(MMBtu/h) (260 gigajoules per hour (GJ/
h)) of heat input of fossil fuel (either
alone or in combination with any other
fuel); and (2) serve a generator capable
of supplying more than 25 MW net to
a utility distribution system (i.e., for sale
to the grid).221 However, 40 CFR part 60,
subpart TTTT includes applicability
exemptions for certain EGUs, including:
(1) Non-fossil fuel-fired units subject to
a federally enforceable permit that
limits the use of fossil fuels to 10
percent or less of their heat input
capacity on an annual basis; (2) CHP
units that are subject to a federally
enforceable permit limiting annual net
electric sales to no more than either the
unit’s design efficiency multiplied by its
potential electric output, or 219,000
megawatt-hours (MWh), whichever is
greater; (3) stationary combustion
turbines that are not physically capable
of combusting natural gas (e.g., those
that are not connected to a natural gas
pipeline); (4) utility boilers and IGCC
units that have always been subject to
a federally enforceable permit limiting
annual net electric sales to one-third or
less of their potential electric output
(e.g., limiting hours of operation to less
than 2,920 hours annually) or limiting
annual electric sales to 219,000 MWh or
less; (5) municipal waste combustors
that are subject to 40 CFR part 60,
subpart Eb; (6) commercial or industrial
solid waste incineration units subject to
40 CFR part 60, subpart CCCC; and (7)
221 The EPA refers to the capability to combust
250 MMBtu/h of fossil fuel as the ‘‘base load rating
criterion.’’ Note that 250 MMBtu/h is equivalent to
73 MW or 260 GJ/h heat input.
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certain projects under development, as
discussed below.
a. Revisions to 40 CFR Part 60, Subpart
TTTT
The EPA is proposing to amend 40
CFR 60.5508 and 60.5509 to reflect that
40 CFR part 60, subpart TTTT will
remain applicable to steam generating
EGUs and IGCC units constructed after
January 8, 2014 or reconstructed after
June 18, 2014. The EPA is also
proposing that stationary combustion
turbines that commenced construction
after January 8, 2014 or reconstruction
after June 18, 2014 and before May 23,
2023 that meet the relevant applicability
criteria would be subject to 40 CFR part
60, subpart TTTT. Upon promulgation
of 40 CFR part 60, subpart TTTTa,
stationary combustion turbines that
commence construction or
reconstruction after May 23, 2023 and
meet the relevant applicability criteria
will be subject to 40 CFR part 60,
subpart TTTTa.
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b. Revisions to 40 CFR Part 60, Subpart
TTTT That Would Also Be Included in
40 CFR Part 60, Subpart TTTTa
The EPA is proposing that 40 CFR
part 60, subpart TTTT and 40 CFR part
60, subpart TTTTa use similar
regulatory text except where specifically
stated. This section describes proposed
amendments that would be included in
both subparts.
i. Applicability to Non-Fossil Fuel-Fired
EGUs
The current non-fossil applicability
exemption in 40 CFR part 60, subpart
TTTT is based strictly on the
combustion of non-fossil fuels (e.g.,
biomass). To be considered a non-fossil
fuel-fired EGU, the EGU must both (1)
Be capable of combusting more than 50
percent non-fossil fuel and (2) be subject
to a federally enforceable permit
condition limiting the annual capacity
factor for all fossil fuels combined of 10
percent (0.10) or less. The current
language does not take heat input from
non-combustion sources (e.g., solar
thermal) into account. Certain solar
thermal installations have natural gas
backup burners larger than 250 MMBtu/
h. As currently written, these solar
thermal installations would not be
eligible to be considered non-fossil units
because they are not capable of deriving
more than 50 percent of their heat input
from the combustion of non-fossil fuels.
Therefore, solar thermal installations
that include backup burners could meet
the applicability criteria of 40 CFR part
60, subpart TTTT even if the burners are
limited to an annual capacity factor of
10 percent or less. These EGUs would
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readily comply with the standard of
performance, but the reporting and
recordkeeping would increase costs for
these EGUs.
The EPA is proposing several
amendments to align the applicability
criteria with the original intent to cover
only fossil fuel-fired EGUs. This would
ensure that solar thermal EGUs with
natural gas backup burners, like other
types of non-fossil fuel-fired units in
which most of their energy is derived
from non-fossil fuel sources, are not
subject to the requirements of 40 CFR
part 60, subparts TTTT or TTTTa.
Amending the applicability language to
include heat input derived from noncombustion sources would allow these
facilities to avoid the requirements of 40
CFR part 60, subparts TTTT or TTTTa
by limiting the use of the natural gas
burners to less than 10 percent of the
capacity factor of the backup burners.
Specifically, the EPA is proposing to
amend the definition of non-fossil fuelfired EGUs from EGUs capable of
‘‘combusting 50 percent or more nonfossil fuel’’ to EGUs capable of ‘‘deriving
50 percent or more of the heat input
from non-fossil fuel at the base load
rating.’’ (emphasis added). The
definition of base load rating would also
be amended to include the heat input
from non-combustion sources (e.g., solar
thermal).
The proposed amended non-fossil
fuel applicability language changing
‘‘combusting’’ to ‘‘deriving’’ will ensure
that 40 CFR part 60, subparts TTTT and
TTTTa cover the fossil fuel-fired EGUs,
properly understood, that the original
rule was intended to cover, while
minimizing unnecessary costs to EGUs
fueled primarily by steam generated
without combustion (e.g., through the
use of solar thermal). The corresponding
change in the base load rating to include
the heat input from non-combustion
sources is necessary to determine the
relative heat input from fossil fuel and
non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
In simple terms, the current
applicability provisions in 40 CFR part
60, subpart TTTT require that an EGU
be capable of combusting more than 250
MMBtu/h of fossil fuel and be capable
of selling 25 MW to a utility distribution
system to be subject to 40 CFR part 60,
subpart TTTT. These applicability
provisions exclude industrial EGUs.
However, the definition of an EGU also
includes ‘‘integrated equipment that
provides electricity or useful thermal
output.’’ This language facilitates the
integration of non-emitting generation
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and avoids energy inputs from nonaffected facilities being used in the
emission calculation without also
considering the emissions of those
facilities (e.g., an auxiliary boiler
providing steam to a primary boiler).
This language could result in certain
large processes being included as part of
the EGU and meeting the applicability
criteria. For example, the hightemperature exhaust from an industrial
process (e.g., calcining kilns, dryer,
metals processing, or carbon black
production facilities) that consumes
fossil fuel could be sent to a HRSG to
produce electricity. If the industrial
process is more than 250 MMBtu/h heat
input and the electric sales exceed the
applicability criteria, then the unit
could be subject to 40 CFR part 60,
subparts TTTT or TTTTa. This is
potentially problematic for multiple
reasons. First, it is difficult to determine
the useful output of the EGU (i.e.,
HRSG) since part of the useful output is
included in the industrial process. In
addition, the fossil fuel that is
combusted might have a relatively high
CO2 emissions rate on a lb/MMBtu
basis, making it potentially problematic
to meet the standard of performance
using efficient generation. This could
result in the owner/operator reducing
the electric output of the industrial
facility to avoid the applicability
criteria. Finally, the compliance costs
associated with 40 CFR part 60, subparts
TTTT or TTTTa could discourage the
development of environmentally
beneficial projects.
To avoid these outcomes, the EPA is
proposing to amend the applicability
provision that exempts EGUs where
greater than 50 percent of the heat input
is derived from an industrial process
that does not produce any electrical or
mechanical output or useful thermal
output that is used outside the affected
EGU.222 Reducing the output or not
developing industrial electric generating
projects where the majority of the heat
input is derived from the industrial
process itself would not necessarily
result in reductions in GHG emissions
from the industrial facility. However,
the electricity that would have been
produced from the industrial project
could still be needed. Therefore,
projects of this type provide significant
environmental benefit with little if any
additional emissions. Including these
types of projects would result in
regulatory burden without any
222 Auxiliary equipment such as boilers or
combustion turbines that provide heat or electricity
to the primary EGU (including to any control
equipment) would still be considered integrated
equipment and included as part of the affected
facility.
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associated environmental benefit and
could discourage project development,
leading to potential overall increases in
GHG emissions.
(B) Industrial EGUs Electric Sales
Threshold Permit Requirement
The current electric sales applicability
exemption in 40 CFR part 60, subpart
TTTT for non-CHP steam generating
units includes the provision that EGUs
have ‘‘always been subject to a federally
enforceable permit limiting annual net
electric sales to one-third or less of their
potential electric output (e.g., limiting
hours of operation to less than 2,920
hours annually) or limiting annual
electric sales to 219,000 MWh or less’’
(emphasis added). The justification for
this restriction includes that the 40 CFR
part 60, subpart Da applicability
language includes ‘‘constructed for the
purpose of . . .’’ and the Agency
concluded that the intent was defined
by permit conditions (80 FR 64544;
October 23, 2015). This applicability
criterion is important for determining
applicability with both the new source
CAA section 111(b) requirements and if
existing steam generating units are
subject to the existing source CAA
section 111(d) requirements. For steam
generating units that commenced
construction after September 18, 1978,
the applicability of 40 CFR part 60,
subpart Da, would be relatively clear by
what criteria pollutant NSPS is
applicable to the facility. However, for
steam generating units that commenced
construction prior to September 18,
1978, or where the owner/operator
determined that criteria pollutant NSPS
applicability was not critical to the
project (e.g., emission controls were
sufficient to comply with either the EGU
or industrial boiler criteria pollutant
NSPS), owners/operators might not have
requested an electric sales permit
restriction be included in the operating
permit. Under the current applicability
language, some onsite EGUs could be
covered by the existing source CAA
section 111(d) requirements even if they
have never sold electricity to the grid.
To avoid covering these industrial
EGUs, the EPA is proposing to amend
the electric sales exemption in 40 CFR
part 60, subparts TTTT and TTTTa to
read, ‘‘annual net-electric sales have
never exceeded one-third of its potential
electric output or 219,000 MWh,
whichever is greater, and is’’ (the
‘‘always been’’ would be deleted)
subject to a federally enforceable permit
limiting annual net electric sales to onethird or less of their potential electric
output (e.g., limiting hours of operation
to less than 2,920 hours annually) or
limiting annual electric sales to 219,000
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MWh or less’’ (emphasis added). EGUs
that reduce current generation would
continue to be covered as long as they
sold more than one-third of their
potential electric output at some time in
the past. The proposed revisions would
simply make it possible for an owner/
operator of an existing industrial EGU to
provide evidence to the Administrator
that the facility has never sold
electricity in excess of the electricity
sales threshold and to modify their
permit to limit sales in the future.
Without the amendment, owners/
operators of any non-CHP industrial
EGU capable of selling 25 MW would be
subject to the existing source CAA
section 111(d) requirements even if they
have never sold any electricity.
Therefore, the EPA is proposing the
exemption to eliminate the requirement
that existing industrial EGUs must have
always been subject to a permit
restriction limiting net electric sales.
iii. Determination of the Design
Efficiency
The design efficiency (i.e., the
efficiency of converting thermal energy
to useful energy output) of a combustion
turbine is used to determine the electric
sales applicability threshold and is
relevant to both new and existing
EGUs.223 The sales criteria are based in
part on the individual EGU design
efficiency. Three methods for
determining the design efficiency are
currently provided in 40 CFR part 60,
subpart TTTT.224 Since the 2015 NSPS
was finalized, the EPA has become
aware that owners/operators of certain
existing EGUs do not have records of the
original design efficiency. These units
are not able to readily determine
whether they meet the applicability
criteria and are therefore subject to the
CAA section 111(d) requirements for
existing sources in the same way that
111(b) sources would be able to
determine if the facility meets the
applicability criteria. Many of these
EGUs are CHP units and it is likely they
do not meet the applicability criteria.
However, the language in the 2015
NSPS would require them to conduct
additional testing to demonstrate this.
The requirement would result in burden
to the regulated community without any
environmental benefit. The electricity
223 While the EPA could specifically allow
different methods to determine the design
efficiency in the 111(d) existing source emission
guidelines, the Agency is proposing to align the
criteria for regulatory clarity.
224 40 CFR part 60, subpart TTTT currently lists
ASME PTC 22 Gas Turbines, ASME PTC 46 Overall
Plant Performance, and ISO 2314 Gas turbines
acceptance tests as approved methods to determine
the design efficiency.
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33281
generating market has changed, in some
cases dramatically, during the lifetime
of existing EGUs, especially concerning
ownership. As a result of acquisitions
and mergers, original EGU design
efficiency documentation as well as
performance guarantee results that
affirmed the design efficiency, may no
longer exist. Moreover, such
documentation and results may not be
relevant for current EGU efficiencies, as
changes to original EGU configurations,
upon which the original design
efficiencies were based, render those
original design efficiencies moot,
meaning that there would be little
reason to maintain former design
efficiency documentation since it would
not comport with the efficiency
associated with current EGU
configurations. As the three specified
methods would rely on documentation
from the original EGU configuration
performance guarantee testing, and
results from that documentation may no
longer exist or be relevant, it is
appropriate to allow other means to
demonstrate EGU design efficiency. To
reduce compliance burden, the EPA is
proposing in 40 CFR part 60, subparts
TTTT and TTTTa to allow alternative
methods as approved by the
Administrator on a case-by-case basis.
Owners/operators of EGUs would
petition the Administrator in writing to
use an alternate method to determine
the design efficiency. The
Administrator’s discretion is
intentionally left broad and could
extend to other American Society of
Mechanical Engineers (ASME) or
International Organization for
Standardization (ISO) methods as well
as to operating data to demonstrate the
design efficiency of the EGU. The EPA
is also proposing to change the
applicability of paragraph 60.8(b) in
table 3 of 40 CFR part 60, subpart TTTT
from ‘‘no’’ to ‘‘yes’’ and that the
applicability of paragraph 60.8(b) in
table 3 of 40 CFR part 60, subpart
TTTTa is ‘‘yes.’’ This would allow the
Administrator to approve alternatives to
the test methods specified in 40 CFR
part 60, subparts TTTT and TTTTa.
c. Applicability for 40 CFR Part 60,
Subpart TTTTa
This section describes proposed
amendments that would only be
incorporated into 40 CFR part 60,
subpart TTTTa and would differ from
the requirements in 40 CFR part 60,
subpart TTTT.
i. Proposed Applicability
Section 111 of the CAA defines a new
or modified source for purposes of a
given NSPS as any stationary source
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that commences construction or
modification after the publication of the
proposed regulation. Thus, any
standards of performance the Agency
finalizes as part of this rulemaking will
apply to EGUs that commence
construction or reconstruction after the
date of this proposal. EGUs that
commenced construction after the date
of the proposal for the 2015 NSPS and
by the date of this proposal will remain
subject to the standards of performance
promulgated in the 2015 NSPS. A
modification is any physical change in,
or change in the method of operation of,
an existing source that increases the
amount of any air pollutant emitted to
which a standard applies.225 The NSPS
General Provisions (40 CFR part 60,
subpart A) provide that an existing
source is considered a new source if it
undertakes a reconstruction.226
The EPA is proposing the same
applicability requirements in 40 CFR
part 60, subpart TTTTa as the
applicability requirements in 40 CFR
part 60, subpart TTTT. The stationary
combustion turbine must meet the
following applicability criteria: The
stationary combustion turbine must: (1)
Be capable of combusting more than 250
million British thermal units per hour
(MMBtu/h) (260 gigajoules per hour
(GJ/h)) of heat input of fossil fuel (either
alone or in combination with any other
fuel); and (2) serve a generator capable
of supplying more than 25 MW net to
a utility distribution system (i.e., for sale
to the grid).227 In addition, the EPA is
proposing in 40 CFR part 60, subpart
TTTTa to include applicability
exemptions for stationary combustion
turbines that are: (1) Capable of deriving
50 percent or more of the heat input
from non-fossil fuel at the base load
rating and subject to a federally
enforceable permit condition limiting
the annual capacity factor for all fossil
fuels combined of 10 percent (0.10) or
less; (2) combined heat and power units
subject to a federally enforceable permit
condition limiting annual net-electric
sales to no more than 219,000 MWh or
the product of the design efficiency and
the potential electric output, whichever
is greater; (3) serving a generator along
with other steam generating unit(s),
IGCC, or stationary combustion
turbine(s) where the effective generation
capacity is 25 MW or less; (4) municipal
waste combustors that are subject to 40
CFR part 60, subpart Eb; (5) commercial
225 40
CFR 60.2.
CFR 60.15(a).
227 The EPA refers to the capability to combust
250 MMBtu/h of fossil fuel as the ‘‘base load rating
criterion.’’ Note that 250 MMBtu/h is equivalent to
73 MW or 260 GJ/h heat input.
226 40
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or industrial solid waste incineration
units subject to 40 CFR part 60, subpart
CCCC; and (6) deriving greater than 50
percent of heat input from an industrial
process that does not produce any
electrical or mechanical output that is
used outside the affected stationary
combustion turbine.
The EPA is proposing to apply the
same requirements to combustion
turbines in non-continental areas (i.e.,
Hawaii, the Virgin Islands, Guam,
American Samoa, the Commonwealth of
Puerto Rico, and the Northern Mariana
Islands) and non-contiguous areas (noncontinental areas and Alaska) as the
EPA is proposing for comparable units
in the contiguous 48 States. However,
new units in non-continental and noncontiguous areas may operate on small,
isolated electric grids, may operate
differently from units in the contiguous
48 States, and may have limited access
to certain components of the proposed
BSER due to their uniquely isolated
geography or infrastructure. Therefore,
the EPA is soliciting comment on
whether combustion turbines in noncontinental and non-contiguous areas
should be subject to different
requirements.
ii. Applicability to CHP Units
For 40 CFR part 60, subpart TTTT,
owner/operators of CHP units calculate
net electric sales and net energy output
using an approach that includes ‘‘at
least 20.0 percent of the total gross or
net energy output consists of electric or
direct mechanical output.’’ It is unlikely
that a CHP unit with a relatively low
electric output (i.e., less than 20.0
percent) would meet the applicability
criteria. However, if a CHP unit with
less than 20.0 percent of the total output
consisting of electricity were to meet the
applicability criteria, the net electric
sales and net energy output would be
calculated the same as for a traditional
non-CHP EGU. Even so, it is not clear
that these CHP units would have less
environmental benefit per unit of
electricity produced than more
traditional CHP units. For 40 CFR part
60, subpart TTTTa, the EPA is
proposing to eliminate the restriction
that CHP units produce at least 20.0
percent electrical or mechanical output
to qualify for the CHP-specific method
for calculating net electric sales and net
energy output.
In the 2015 NSPS, the EPA did not
issue standards of performance for
certain types of sources—including
industrial CHP units and CHPs that are
subject to a federally enforceable permit
limiting annual net electric sales to no
more than the unit’s design efficiency
multiplied by its potential electric
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output, or 219,000 MWh or less,
whichever is greater. For CHP units, the
approach in 40 CFR part 60, subpart
TTTT for determining net electric sales
for applicability purposes allows the
owner/operator to subtract the
purchased power of the thermal host
facility. The intent of the approach is to
determine applicability similarly for
third-party developers and CHP units
owned by the thermal host facility.228
However, as written in 40 CFR part 60,
subpart TTTT, each third-party CHP
unit would subtract the entire electricity
use of the thermal host facility when
determining its net electric sales. It is
clearly not the intent of the provision to
allow multiple third-party developers
that serve the same thermal host to all
subtract the purchased power of the
thermal host facility when determining
net electric sales. This would result in
counting the purchased power multiple
times. In addition, it is not the intent of
the provision to allow a CHP developer
to provide a trivial amount of useful
thermal output to multiple thermal
hosts and then subtract all the thermal
hosts’ purchased power when
determining net electric sales for
applicability purposes. The proposed
approach in 40 CFR part 60, subpart
TTTTa would set a limit to the amount
of thermal host purchased power that a
third-party CHP developer can subtract
for electric sales when determining net
electric sales equivalent to the
percentage of useful thermal output
provided to the host facility by the
specific CHP unit. This approach would
eliminate both circumvention of the
intended applicability by sales of trivial
amounts of useful thermal output and
double counting of thermal hostpurchased power.
Finally, to avoid potential double
counting of electric sales, the EPA is
proposing that for CHP units
determining net electric sales,
purchased power of the host facility
would be determined based on the
percentage of thermal power provided
to the host facility by the specific CHP
facility.
iii. Non-Natural Gas Stationary
Combustion Turbines
There is currently an exemption in 40
CFR part 60, subpart TTTT for
228 For contractual reasons, many developers of
CHP units sell all the generated electricity to the
electricity distribution grid even though in actuality
a significant portion of the generated electricity is
used onsite. Owners/operators of both the CHP unit
and thermal host can subtract the site purchased
power when determining net electric sales. Third
party developers that do not own the thermal host
can also subtract the purchased power of the
thermal host when determining net electric sales for
applicability purposes.
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stationary combustion turbines that are
not physically capable of combusting
natural gas (e.g., those that are not
connected to a natural gas pipeline).
While combustion turbines not
connected to a natural gas pipeline meet
the general applicability of 40 CFR part
60, subpart TTTT, these units are not
subject to any of the requirements. The
EPA is proposing requirements for new
and reconstructed combustion turbines
that are not capable of combusting
natural gas. As described in the
standards of performance section, the
Agency is proposing that owners/
operators of combustion turbines
burning fuels with a higher heat input
emission rate than natural gas would
adjust the natural gas-fired emissions
rate by the ratio of the heat input-based
emission rates. The overall result is that
new stationary combustion turbines
combusting fuels with higher GHG
emissions rates than natural gas on a lb
CO2/MMBtu basis would have to
maintain the same efficiency compared
to a natural gas-fired combustion
turbine and comply with a standard of
performance based on the identified
BSER. Therefore, the EPA is not
including in 40 CFR part 60, subpart
TTTTa, the exemption for stationary
combustion turbines that are not
physically capable of combusting
natural gas.
F. Determination of the Best System of
Emission Reduction (BSER) for New and
Reconstructed Stationary Combustion
Turbines
In this section, the EPA describes the
technologies it is proposing to
determine are the BSER for each of the
subcategories of new and reconstructed
combustion turbines that commence
construction after the date of this
proposal, and explains its basis for
proposing those controls, and not
others, as the BSER. The controls that
the EPA is evaluating include
combusting non-hydrogen lower
emitting fuels (e.g., natural gas and
distillate oil), using highly efficient
generation, using CCS, and co-firing
with low-GHG hydrogen.
For the low-load subcategory, the EPA
is proposing the use of lower emitting
fuels as the BSER. For the intermediate
load subcategory, the EPA is proposing
an approach under which the BSER is
made up of two components that each
represent a different set of controls, and
that form the basis of standards of
performance that apply in multiple
phases. That is, affected facilities—
which are facilities that commence
construction or reconstruction after the
date of this proposed rulemaking—must
meet the first phase of the standard of
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performance, which is based on the
application of the first component of the
BSER, highly efficient generation, by the
date the rule is finalized; and then meet
the second and more stringent phase of
the standard of performance, which is
based on co-firing 30 percent (by
volume) low-GHG hydrogen by 2032.
The EPA is also soliciting comment on
whether the intermediate load
subcategory should apply a third
component of BSER, which is co-firing
96 percent (by volume) low-GHG
hydrogen by 2038. In addition, the EPA
is also soliciting comment on whether
the low load subcategory should apply
the second component of BSER, which
is co-firing 30 percent (by volume) lowGHG hydrogen by 2032. These latter
components of BSER would also
include the continued application of
highly efficient generation.
For the base load subcategory, the
EPA is also proposing a multicomponent BSER and an associated
multi-phase standard of performance.
The first component of the BSER, as
with intermediate load combustion
turbines, is highly efficient generation.
New base load combustion turbines
would be required to meet a phase one
standard of performance based on the
application of the first component of the
BSER upon initial startup of the source.
Subsequently, EPA is proposing two
technology pathways as potential BSER
for base load combustion turbines, with
corresponding standards of
performance. The first technology
pathway is based on 90 percent CCS,
which base load combustion turbines
may install and begin to operate to meet
the standard of performance by 2035.
The second technology pathway is
based on co-firing low-GHG hydrogen,
which EPA proposes base load
combustion turbines may undertake in
two steps—by co-firing 30 percent (by
volume) low-GHG hydrogen to meet the
second phase of the standard of
performance by 2032 and, then by cofiring 96 percent (by volume) low-GHG
hydrogen to meet the third phase of the
standard of performance by 2038.
Throughout, base load turbines, like
intermediate load turbines, would
remain subject to the BSER of highly
efficient generation.
This approach reflects the EPA’s view
that the BSER for the intermediate load
and base load subcategories should
reflect the deeper reductions in GHG
emissions that can be achieved by
implementing CCS and co-firing lowGHG hydrogen but recognizes that
building the infrastructure required to
support widespread use of CCS and
low-GHG hydrogen in the power sector
will take place on a multi-year time
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33283
scale. Accordingly, newly constructed
or reconstructed facilities must be aware
of their need to ramp toward more
stringent phases of the standards, which
reflect application of the more stringent
controls in the BSER, either through use
of co-firing a lower level of low-GHG
hydrogen by 2032 and a higher level of
low-GHG hydrogen by 2038 or through
use of CCS by 2035. The EPA is also
soliciting comment on the potential for
an earlier compliance date for the
second phase, for instance, 2030 for
units co-firing 30 percent hydrogen by
volume and 2032 for units installing
CCS.
For the base load subcategory, the
EPA is proposing both potential BSER
pathways because it believes there may
be more than one viable BSER pathway
for base load combustion turbines to
significantly reduce their CO2 emissions
and believes there is value in receiving
comment on, and potentially finalizing,
both BSER pathways to enable project
developers to elect how they will reduce
their CO2 emissions on timeframes that
make sense for each BSER pathway. The
EPA recognizes that standards of
performance are technology neutral and
that if the EPA finalizes a standard
based on application of CCS, units
could meet that standard using co-firing
of low-GHG hydrogen. The EPA solicits
comment on whether co-firing of lowGHG hydrogen should be considered a
compliance pathway for sources to meet
a single standard of performance based
on application of CCS rather than a
separate BSER pathway. The EPA
believes that there will be earlier
opportunities for units to begin co-firing
lower amounts of low-GHG hydrogen
than to install and begin operating 90
percent CCS systems. However, it will
likely take a longer timeframe for those
units to then ramp up to co-firing
significant quantities of low-GHG
hydrogen. Therefore, in this proposal,
the EPA presents these pathways as
separate subcategories, while soliciting
comment on the option of finalizing a
single standard of performance based on
application of CCS.
Specifically, with respect to the first
phase of the standards of performance,
for both the intermediate load and base
load subcategories, the EPA is proposing
that the BSER is highly efficient
generating technology—combined cycle
technology for the base load
subcategories and simple cycle
technology for the intermediate load
subcategory—as well as operating and
maintaining it efficiently. The EPA
sometimes refers to highly efficient
generating technology in combination
with the best operating and
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maintenance practices as highly
efficient generation.
The affected sources must meet
standards based on this efficient
generating technology upon the effective
date of the final rule. With respect to the
second phase of the standards of
performance, for base load combustion
turbines adopting the CCS pathway, the
BSER includes the use of 90 percent
CCS. These sources would be required
to meet standards of performance by
2035 that reflect application of both
components of the BSER—highly
efficient generation and CCS—and thus
are more stringent. For base load
combustion turbines adopting the lowGHG hydrogen co-firing pathway and
for intermediate load combustion
turbines, the BSER includes co-firing 30
percent by volume (12 percent by heat
input) low-GHG hydrogen. These
sources would be required to meet
second phase standards of performance
by 2032 that reflect the application of
both components of the BSER—in this
case, highly efficient generation and cofiring 30 percent (by volume) low-GHG
hydrogen—and that are, again, more
stringent. Finally, for base load
combustion turbines adopting the lowGHG hydrogen co-firing pathway, the
BSER also includes a third component—
co-firing 96 percent (by volume) lowGHG hydrogen. These sources would be
required to meet a third phase standard
of performance equivalent to that for the
affected sources applying CCS as a
second component of the BSER. These
sources would be required to meet that
equivalent standard of performance
reflecting the application of highly
efficient generation and co-firing high
levels of low-GHG hydrogen. Table 1
summarizes the proposed BSER for
combustion turbine EGUs that
commence construction or
reconstruction after publication of this
proposal. The EPA is also proposing
standards of performance based on
those BSER for each subcategory, as
discussed in section VII.G.
TABLE 1—PROPOSED BSER FOR COMBUSTION TURBINE EGUS
Subcategory
Fuel
1st Component
BSER
2nd Component
BSER
Low Load * .........................
Intermediate Load .............
All Fuels ............................
All Fuels ............................
Lower emitting fuels ..........
Highly Efficient Generation
N/A
N/A
Base Load .........................
Sources adopting the CCS
pathway.
Sources adopting the lowGHG hydrogen co-firing
pathway.
Highly Efficient Generation
N/A ....................................
30 percent (by volume)
Low-GHG Hydrogen Cofiring by 2032.
90 percent CCS by 2035 ..
30 percent (by volume)
Low-GHG Hydrogen Cofiring by 2032.
96 percent (by volume)
Low-GHG Hydrogen Cofiring by 2038
...........................................
3rd Component
BSER
N/A
* The low load subcategory has a single-component BSER consisting of fuels that emit lower GHG emissions.
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1. BSER for Low Load Subcategory
This section describes the proposed
BSER for the low load (i.e., peaking)
subcategory, which is the use of lower
emitting fuels. For this proposed rule,
the Agency proposes to determine that
the use of lower emitting fuels, which
the EPA determined to be the BSER for
the non-base load subcategory in the
2015 NSPS, is the BSER for this low
load subcategory in the standards of
performance proposed in this action. As
explained above, the EPA is proposing
to narrow the definition of the low load
subcategory by lowering the electric
sales threshold (as compared to the
electric sales threshold for non-base
load combustion turbines in the 2015
NSPS), so that turbines with higher
electric sales would be placed in the
proposed intermediate load subcategory
and therefore be subject to a more
stringent standards based on the more
stringent component of the BSER.
Unlike the proposals for intermediate
and base load combustion turbines, the
proposed low load subcategory includes
only a single-phase BSER component.
a. Background: The Non-Base Load
Subcategory in the 2015 NSPS
The 2015 NSPS defined non-base load
natural gas-fired EGUs as stationary
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combustion turbines that (1) Burn more
than 90 percent natural gas and (2) have
net electric sales equal to or less than
their design efficiency (not to exceed 50
percent) multiplied by their potential
electric output (80 FR 64601; October
23, 2015). These are calculated on 12operating-month and 3-year rolling
average bases. The EPA also determined
in the 2015 NSPS that the BSER for
newly constructed and reconstructed
non-base load natural gas-fired
stationary combustion turbines is the
use of lower emitting fuels. Id. at 64515.
These lower emitting fuels are primarily
natural gas with a small allowance for
distillate oil (i.e., Nos. 1 and 2 fuel oils),
which have been widely used in
stationary combustion turbine EGUs for
decades.
The EPA also determined in the 2015
NSPS that the standard of performance
for sources in this subcategory is a heat
input-based standard of 120 lb CO2/
MMBtu. The EPA established this cleanfuels BSER for this subcategory because
of the variability in the operation in
non-base load combustion turbines and
the challenges involved in determining
a uniform output-based standard that all
new and reconstructed non-base load
units could achieve.
Specifically, in the 2015 NSPS, the
EPA recognized that a BSER for the non-
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base load subcategory based on the use
of lower emitting fuels results in limited
GHG reductions, but further recognized
that an output-based standard of
performance could not reasonably be
applied to the subcategory. The EPA
explained that a combustion turbine
operating at a low capacity factor could
operate with multiple starts and stops,
and that its emission rate would be
highly dependent on how it was
operated and not its design efficiency.
Moreover, combustion turbines with
low annual capacity factors typically
operated differently from each other,
and therefore had different emission
rates. The EPA recognized that, as a
result, it would not be possible to
determine a standard of performance
that could reasonably apply to all
combustion turbines in the subcategory.
For that reason, the EPA further
recognized, efficient design 229 and
operation would not qualify as the
BSER; rather, the BSER should be lower
229 Important characteristics for minimizing
emissions from low load combustion turbines
include the ability to operate efficiently while
operating at part load conditions and the ability to
rapidly achieve maximum efficiency to minimize
periods of operation at lower efficiencies. These
characteristics do not necessarily always align with
higher design efficiencies that are determined under
steady state full load conditions.
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emitting fuels and the associated
standard of performance should be
based on heat input. Since the 2015
NSPS, all newly constructed simple
cycle turbines have been non-base load
units and thus have become subject to
this standard of performance.
b. Proposed BSER
Consistent with the rationale of the
2015 NSPS, the EPA proposes that the
use of fuels with an emissions rate of
less than 160 lb CO2/MMBtu (i.e., lower
emitting fuels) meets the BSER
requirements for the low load
subcategory. Use of these fuels is
technically feasible for combustion
turbines. Natural gas comprises the
majority of the heat input for simple
cycle turbines and is the lowest cost
fossil fuel. In the 2015 NSPS, the EPA
determined that natural gas comprised
96 percent of the heat input for simple
cycle turbines. See 80 FR 64616
(October 23, 2015). Therefore, a BSER
based on the use of natural gas and/or
distillate oil would have minimal, if
any, costs to regulated entities. The use
of lower emitting fuels would not have
any significant adverse energy
requirements or non-air quality or
environmental impacts, as the EPA
determined in the 2015 NSPS. Id. at
64616. In addition, the use of fuels
meeting this criterion would result in
some emission reductions by limiting
the use of fuels with higher carbon
content, such as residual oil, as the EPA
also explained in the 2015 NSPS. Id.
Although the use of fuels meeting this
criterion would not advance technology,
in light of the other reasons described
here, the EPA proposes that the use of
natural gas, Nos. 1 and 2 fuel oils, and
other fuels 230 currently specified in 40
CFR part 60, subpart TTTT, qualify as
the BSER for new and reconstructed
combustion turbine EGUs in the low
load subcategory. The EPA is also
proposing to add low-GHG hydrogen to
the list of fuels meeting the uniform
fuels criteria in 40 CFR part 60, subpart
TTTTa. The addition of low-GHG
hydrogen (and fuels derived from
hydrogen) to 40 CFR part 60, subpart
TTTTa would simplify the
recordkeeping and reporting
requirements for low load combustion
turbines that elect to burn low-GHG
hydrogen. As described in section VII.F,
a component of the BSER for certain
subcategories in subpart TTTTa is based
on the use of low-GHG hydrogen. An
230 The BSER for multi-fuel-fired combustion
turbines subject to 40 CFR part 60, subpart TTTT
is also the use of fuels with an emissions rate of
160 lb CO2/MMBtu or less. The use of these fuels
would demonstrate compliance with the low load
subcategory.
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owner/operator of a subpart TTTTa
affected combustion turbine that
combusts hydrogen for compliance
purposes not meeting the definition of
low-GHG hydrogen would be in
violation of the subpart TTTTa
requirements.
For the reasons discussed in the 2015
NSPS and noted above, the EPA is not
proposing that efficient design and
operation qualify as the BSER for the
low load subcategory. The EPA is not
proposing high-efficiency simple cycle
or combined cycle turbine design and
operation as the BSER for the low load
subcategory because they are not
necessarily cost reasonable and would
not necessarily result in emission
reductions. High efficiency combustion
turbines have higher initial costs
compared to lower efficiency
combustion turbines. The cost of
combustion turbine engines is
dependent upon many factors, but the
EPA estimates that the capital cost of a
high-efficiency simple cycle turbine is 5
percent more than that of a comparable
lower efficiency simple cycle turbine.
Assuming all other costs are the same
and that the high-efficiency simple
cycle turbine uses 6 percent less fuel, it
would not necessarily be cost
reasonable to use a high-efficiency
simple cycle turbine until the
combustion turbine is operated at a 12operating-month capacity factor of
approximately 20 percent. At lower
capacity factors, the CO2 abatement
costs on both a $/ton and $/MW basis
increase rapidly.231 Further, the
emission rate of a low load combustion
turbine is highly dependent upon the
way the combustion turbine is operated.
If the combustion turbine is frequently
operated at part load conditions with
frequent starts and stops, a combustion
turbine with a high design efficiency,
which is determined at full load steady
state conditions, would not necessarily
emit at a lower GHG rate than a
combustion turbine with a lower design
efficiency.
The EPA solicits comment on
whether, and the extent to which, highefficiency designs also operate more
efficiently at part loads and can start
more quickly and reach the desired load
more rapidly than combustion turbines
with less efficient design efficiencies. If
high-efficiency simple cycle turbines do
operate at higher part-load efficiencies
and are able to reach the intended
operating load more quickly, the use of
highly efficient simple cycle turbines for
low load applications would result in
lower GHG reductions. In addition, the
EPA solicits comment on the cost
premium of high-efficiency simple cycle
turbines. If the use of highly efficient
simple cycle turbines results in GHG
reductions at reasonable cost, their use
could qualify as the BSER for low load
combustion turbines. The EPA is
soliciting comment on whether the
BSER for new low load combustion
turbines should be the use of high
efficiency simple cycle technology.
However, since the method of operation
has a substantial impact on the
emissions rate, it may not be feasible for
to prescribe or enforce a single
numerical standard of performance for
affected sources strictly based on design
efficiency. Accordingly, the EPA solicits
comment on whether it would be
appropriate to promulgate such a
requirement as a design standard
pursuant to CAA section 111(h).
Pursuant to such a design standard,
compliance would be demonstrated (i)
initially, through an emissions test and
(ii) subsequently, based on the use of
lower emitting fuels. The initial full
load performance test for natural gasfired low load combustion turbines the
EPA is considering is 1,150 lb CO2/
MWh-gross or 1,100 lb CO2/MWhgross.232 Combustion turbine
manufacturers conduct testing on their
products and the initial performance
test is equivalent to a design efficiency
of approximately 35 and 36 percent,
respectively. According to Gas Turbine
World 2021, approximately threefourths of simple cycle combustion
turbines have design efficiencies of 35
percent or higher and half of simple
cycle combustion turbines have design
efficiencies of 36 percent or higher. The
EPA is soliciting comment on if the
initial performance test for low load
combustion turbines could be
conducted by the manufacturer
certifying the design GHG emissions
rate or if the owner or operator should
be required to conduct separate testing
to verify the emissions rate. The EPA
notes that even if the Agency
determines that a manufacturer design
efficiency-based emissions requirement
is appropriate for new low load
combustion turbines, owners/operators
would also have the option to either
comply with the intermediate load
standard of performance on a
continuous basis or conduct an initial
performance test as an alternative to
purchasing a combustion turbine that
231 The cost effectiveness calculation is highly
dependent upon assumptions concerning the
increase in capital costs, the decrease in heat rate,
and the price of natural gas.
232 The initial full load compliance test would be
a 3-hour performance test and the measured
emissions rate would be corrected to ISO
conditions.
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achieves the specified design efficiency.
For example, owners/operators could
elect to cofire low-GHG hydrogen or
install integrated renewable generation
as an alternative to purchasing a
combustion turbine that meets the
specified design efficiency.
The EPA expects that units in the low
load subcategory will be simple cycle
turbines. The capital cost of a combined
cycle EGU is approximately 250 percent
that of a comparable sized simple cycle
EGU and would not be recovered by
reduced fuel costs if operated as low
load units. Furthermore, low load
combustion turbines start and stop so
frequently that there might not be
sufficient periods of continuous
operation for the HRSG to begin
generating steam to operate the steam
turbine enough to significantly lower
the emissions rate of the EGU.
The EPA is not proposing the use of
CCS or hydrogen co-firing as the BSER
(or as a component of the BSER) for low
load combustion turbines.233 As
described in the section discussing the
second component of BSER for the
intermediate load subcategory, the EPA
is not proposing that CCS is the BSER
for simple cycle combustion turbines
based on the Agency’s assessment that
CCS may not be cost-effective for such
combustion turbines when operated at
intermediate load. This rationale applies
with even greater force for low load
combustion turbines. In addition,
currently available post-combustion
amine-based carbon capture systems
require that the exhaust from a
combustion turbine be cooled prior to
entering the carbon capture equipment.
The most energy efficient way to do this
is to use a HSRG, which is an integral
component of a combined cycle turbine
system but is not incorporated in a
simple cycle unit. For these reasons, the
Agency is not proposing that CCS
qualifies as the BSER for this
subcategory of sources.
The EPA is not proposing low-GHG
hydrogen co-firing as the BSER for low
load combustion turbines because not
all new combustion turbines can
necessarily co-fire higher percentages of
hydrogen, there are potential
infrastructure issues specific to low load
combustion turbines, and at the
relatively infrequent levels of utilization
that characterize the low load
subcategory, a low-GHG hydrogen cofiring BSER would not necessarily result
in cost-effective GHG reductions for all
233 The EPA will not finalize the use of CCS or
hydrogen co-firing as the BSER (or as a component
of the BSER) for low load combustion turbines
unless it first issues a subsequent notice of
proposed rulemaking further evaluating such
measures for that subcategory.
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low load combustion turbines. As
discussed later in this section, the
announced hydrogen co-firing
combustion turbine projects appear to
be intermediate and base load
combustion turbines. Manufacturers
may focus initial research and
development for hydrogen co-firing on
combustion turbines that operate at
higher capacity factors and that can
achieve higher levels of overall GHG
reductions. The EPA is soliciting
comment on whether this development
could limit the availability of low load
combustion turbines that are capable of
burning higher percentages of hydrogen.
The EPA is also soliciting comment on
technologies to reduce potential costs
and technical challenges for the
transport and storage of hydrogen for
owners/operators of low load
combustion turbines. In particular, the
EPA is soliciting comment on
approaches that could be used for
owners/operators of low load
combustion turbines located in high
demand centers (e.g., dense urban
areas). To the extent these factors are
not significant, the EPA is soliciting
comment, with the intention of
determining whether it would be
appropriate to consider such a
requirement in a future rulemaking, on
whether the EPA should add a second
component of the BSER for low load
combustion turbines, based on hydrogen
co-firing that would begin in 2032. The
hydrogen co-firing requirement would
be a separate requirement in addition to
the proposed lower emitting fuels
requirement. Based on simple cycle
turbines that recently commenced
operation, the average 12-operatingmonth capacity factor of low load
combustion turbines would be less than
8 percent. If hydrogen co-firing were to
qualify as the BSER, based on historical
trends for construction of new simple
cycle turbines and the operation of
those turbines in 2021, a BSER based on
30 percent low-GHG hydrogen co-firing
by volume for low load combustion
turbines would result in annual
reductions of 49,000 tons of CO2.
2. BSER for Base Load and Intermediate
Load Subcategories—First Component
This section describes the first
component of the EPA’s proposed BSER
for newly constructed and reconstructed
combustion turbines in the base load
and intermediate load subcategories. For
combustion turbines in the intermediate
load subcategory, this first component
of the BSER is the use of high-efficiency
simple cycle turbine technology in
combination with the best operating and
maintenance practices. For combustion
turbines in the base load subcategory,
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the first component of the BSER is the
use of high-efficiency combined cycle
technology in combination with the best
operating and maintenance practices.
a. Lower Emitting Fuels
The EPA is not proposing lower
emitting fuels as the BSER for
intermediate load or base load EGUs
because, as described earlier in this
section, it would achieve few GHG
emission reductions compared to highly
efficient generation.
b. Highly Efficient Generation
The use of highly efficient generating
technology in combination with the best
operating and maintenance practices
has been demonstrated by multiple
facilities for decades. Notably, over
time, as technologies have improved,
what is considered highly efficient has
changed as well. Highly efficient
generating technology is available and
offered by multiple vendors for both
simple cycle and combined cycle
combustion turbines. Both types of
turbines can also employ best operating
and maintenance practices, which
include routine operating and
maintenance practices that minimize
fuel use.
For simple cycle combustion turbines,
manufacturers continue to improve the
efficiency by increasing firing
temperature, increasing pressure ratios,
using intercooling on the air
compressor, and adopting other
measures. These improved designs
allow for improved operating
efficiencies and reduced emission rates.
Design efficiencies of simple cycle
combustion turbines range from 33 to 40
percent. Best operating practices for
simple cycle combustion turbines
include proper maintenance of the
combustion turbine flow path
components and the use of inlet air
cooling to reduce efficiency losses
during periods of high ambient
temperatures.
For combined cycle turbines, highefficiency technology uses a highly
efficient combustion turbine engine
matched with a high-efficiency HRSG.
The most efficient combined cycle EGUs
use HRSG with three different steam
pressures and incorporate a steam
reheat cycle to maximize the efficiency
of the Rankine cycle. It is not
necessarily practical for owner/
operators of combined cycle facilities
using a turbine engine with an exhaust
temperature below 593 °C or a steam
turbine engine smaller than 60 MW to
incorporate a steam reheat cycle.
Smaller combustion turbine engines,
less than those rated at approximately
2,000 MMBtu/h, tend to have lower
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exhaust temperatures and are paired
with steam turbines of 60 MW or less.
These smaller combined cycle units are
limited to using triple-pressure steam
without a reheat cycle. This reduces the
overall efficiency of the combined cycle
unit by approximately 2 percent.
Therefore, the EPA is proposing less
stringent standards of performance for
smaller combined cycle EGUs with base
load ratings of less than 2,000 MMBtu/
h relative to those for larger combined
cycle combustion turbine EGUs. High
efficiency also includes, but is not
limited to, the use of the most efficient
steam turbine and minimizing energy
losses using insulation and blowdown
heat recovery. Best operating and
maintenance practices include, but are
not limited to, minimizing steam leaks,
minimizing air infiltration, and cleaning
and maintaining heat transfer surfaces.
New technologies are available for
new simple and combined cycle EGUs
that could reduce emissions beyond
what is currently being achieved by the
best performing EGUs. For example,
pressure gain combustion in the turbine
engine would increase the efficiency of
both simple and combined cycle EGUs.
For combined cycle EGUs, the HRSG
could be designed to utilize
supercritical steam conditions or to
utilize supercritical CO2 as the working
fluid instead of water; useful thermal
output could be recovered from a
compressor intercooler and boiler
blowdown; and fuel preheating could be
implemented. For additional
information on these and other
technologies that could reduce the
emissions rate of new combustion
turbines, see the Efficient Generation at
Combustion Turbine Electric Generating
Units TSD, which is available in the
rulemaking docket. The EPA is
soliciting comment on whether these
technologies should be incorporated
into a standard of performance based on
an efficient generation BSER. To the
extent commenters support the
inclusion of emission reductions from
the use of these technologies, the EPA
requests that cost information and
potential emission reductions be
included.
i. Adequately Demonstrated
The EPA proposes that highly
efficient simple cycle and combined
cycle designs are adequately
demonstrated because highly efficient
simple cycle EGUs and highly efficient
combined cycle EGUs have been
demonstrated by multiple facilities for
decades, the efficiency improvements of
the most efficient designs are
incremental in nature and do not change
in any significant way how the
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combustion turbine is operated or
maintained, and the levels of efficiency
that the EPA is proposing have been
achieved by many recently constructed
turbines. Approximately 14 percent of
simple cycle and combined cycle
combustion turbines that have
commenced operation since 2015 have
maintained emission rates below the
proposed standards, demonstrating that
the efficient generation technology
described in this BSER is commercially
available and that the standards of
performance the EPA is proposing are
achievable.
ii. Costs
In general, advanced generation
technologies enhance operational
efficiency compared to lower efficiency
designs. Such technologies present little
incremental capital cost compared to
other types of technologies that may be
considered for new and reconstructed
sources. In addition, more efficient
designs have lower fuel costs that offset
at least a portion of the increase in
capital costs.
For the intermediate load subcategory,
the EPA proposes that the costs of highefficiency simple cycle combustion
turbines are reasonable. As described in
the subcategory section, the cost of
combustion turbine engines is
dependent upon many factors, but the
EPA estimates that that the capital cost
of a high-efficiency simple cycle turbine
is 5 percent more than a comparable
lower efficiency simple cycle turbine.
Assuming all other costs are the same
and that the high-efficiency simple
cycle turbine uses 6 percent less fuel,
high-efficiency simple cycle combustion
turbines have a lower LCOE compared
to standard efficiency simple cycle
combustion turbines at a 12-operatingmonth capacity factor of approximately
20 percent. Therefore, a BSER based on
the use of high-efficiency simple cycle
combustion turbines for intermediate
load combustion turbines would have
minimal, if any, overall compliance
costs since the capital costs would be
recovered through reduced fuel costs.
The EPA considered but is not
proposing combined cycle unit design
for combustion turbines in the
intermediate subcategory because the
capital cost of a combined cycle EGU is
approximately 250 percent that of a
comparable-sized simple cycle EGU and
because the amount of GHG reductions
that could be achieved by operating
combined cycle EGUs as intermediate
load EGUs is unclear. Furthermore,
intermediate load combustion turbines
start and stop so frequently that there
might not be sufficient periods of
continuous operation where the HRSG
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would have sufficient time to generate
steam to operate the steam turbine
enough to significantly lower the
emissions rate of the EGU.
For the base load subcategory, the
EPA proposes that the cost of highefficiency combined cycle EGUs is
reasonable. While the capital costs of a
higher efficiency combined cycle EGUs
are 1.9 percent higher than standard
efficiency combined cycle EGUs, fuel
use is 2.6 percent lower.234 The
reduction in fuel costs fully offset the
capital costs at capacity factors of 40
percent or greater over the expected 30year life of the facility. Therefore, a
BSER based on the use of highefficiency combined cycle combustion
turbines for base load combustion
turbines would have minimal, if any,
overall compliance costs since the
capital costs would be recovered
through reduced fuel costs over the
expected 30-year life of the facility. For
additional information on costs, see the
Efficient Generation at Combustion
Turbine Electric Generating Units TSD,
which is available in the rulemaking
docket.
iii. Non-Air Quality Health and
Environmental Impact and Energy
Requirements
Use of highly efficient simple cycle
and combined cycle generation reduces
all non-air quality health and
environmental impacts and energy
requirements as compared to use of less
efficient generation. Even when
operating at the same input-based
emissions rate, the more efficient a unit
is, the less fuel is required to produce
the same level of output; and, as a
result, emissions are reduced for all
pollutants. The use of highly efficient
simple cycle turbines, compared to the
use of less efficient simple cycle
turbines, reduces all pollutants.
Similarly, the use of high-efficiency
combined combustion turbines,
compared to the use of less efficient
combine cycle turbines, reduces all
pollutants. By the same token, because
improved efficiency allows for more
electricity generation from the same
amount of fuel, it will not have any
adverse effects on energy requirements.
Designating highly efficient
generation as part of the BSER for new
and reconstructed base load and
intermediate load combustion turbines
will not have significant impacts on the
234 Cost And Performance Baseline for Fossil
Energy Plants Volume 1: Bituminous Coal and
Natural Gas to Electricity, Rev. 4A (October 2022),
https://netl.doe.gov/projects/files/
CostAndPerformanceBaselineForFossilEnergyPlants
Volume1BituminousCoalAnd
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nationwide supply of electricity,
electricity prices, or the structure of the
electric power sector. On a nationwide
basis, the additional costs of the use of
highly efficient generation will be small
because the technology does not add
significant costs and at least some of
those costs are offset by reduced fuel
costs. In addition, at least some of these
new combustion turbines would be
expected to incorporate highly efficient
generation technology in any event.
iv. Extent of Reductions in CO2
Emissions
The EPA estimated the potential
emission reductions associated with a
standard that reflects the application of
highly efficient generation as BSER for
the intermediate load and base load
subcategories. As discussed in section
VII.G, the EPA determined that the
standards of performance reflecting this
BSER are 1,150 lb CO2/MWh-gross for
intermediate load and 770 lb CO2/MWhgross for large base load combustion
turbines.
Between 2015 and 2021, an average of
16 simple cycle turbines commenced
operation per year. Of these, the EPA
estimates that an average of six operated
at greater than a 20 percent capacity
factor on a 12-operating-month basis
and thus would be considered
intermediate load combustion turbines.
For recent intermediate load simple
cycle turbines, the EPA determined that
the weighted average maximum 12operating-month emissions rate 235 is
1,250 lb CO2/MWh-gross. This is 8.3
percent higher than the proposed
intermediate load standard of 1,150 lb
CO2/MWh-gross. Therefore, the EPA
estimates that the proposed standard of
performance based on the application of
the proposed BSER for intermediate
load combustion turbines would reduce
the GHG emissions from those sources
by 8.3 percent annually. Based on
historical trends for construction of new
simple cycle turbines and the operation
of those turbines in 2021, the proposed
standards for intermediate load
combustion turbines would result in
annual reductions of 44,000 tons of CO2
as well as 13 tons of NOX. For the base
load subcategory, the weighted average
maximum 12-operating-month
emissions rate of large (base load ratings
of 2,000 MMBtu/h or more) NGCC
combustion turbines that commenced
operation since 2015 has been 810 lb
CO2/MWh-gross. This is 5 percent
235 The EPA is defining the achievable emissions
rate as either the maximum 12-operating-month or
the 99th percent confidence 12-operating-month
emissions rate. The weighted average maximum
emissions rate is the heat input weighted overall
average of the maximum emission rates.
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higher than the proposed standard of
770 lb CO2/MWh-gross for large base
load combustion turbines. The only
small, combined cycle combustion
turbine (base load rating of 593 MMBtu/
h) reporting emissions that commenced
operation since 2015 has had a reported
annual emissions rate of 870 lb CO2/
MWh-gross, which is slightly lower than
the proposed standard of 875 lb CO2/
MWh-gross for a small base load
combustion turbine with a base load
rating of 593 MMBtu/h. Therefore, the
EPA estimates that the proposed
standards would require owners/
operators to construct and maintain
highly efficient combined cycle
combustion turbines that would result
in reductions in emissions of
approximately 5 percent for new large
stationary combustion EGUs and
maintaining best performing emission
rates for new small stationary
combustion EGUs. Using historical
trends for new combined cycle turbines
and the operation of those combustion
turbines in 2021, the proposed
standards for base load combustion
turbines would result in annual
reductions of 940,000 tons of CO2 as
well as 75 tons of NOX.
v. Promotion of the Development and
Implementation of Technology
The EPA also considered the potential
impact of selecting highly efficient
generation technology as the BSER in
promoting the development and
implementation of improved control
technology. This technology is more
efficient than the average new
generation technology and determining
it to be a component of the BSER will
advance its penetration throughout the
industry. Accordingly, consideration of
this factor supports the EPA’s proposal
to determine this technology to be the
first component of the BSER.
c. Low-GHG Hydrogen and CCS
For reasons discussed in sections
VII.F.3.b.v (CCS) and VII.F.3.c.vi (lowGHG hydrogen), the EPA is not
proposing either CCS or co-firing lowGHG hydrogen as the first component of
the BSER for intermediate load or base
load EGUs.
d. Proposed BSER
The EPA proposes that highly
efficient generating technology in
combination with the best operating and
maintenance practices is the first
component BSER for base load and
intermediate load combustion turbines
and the phase 1 standards of
performance are based on the
application of that technology.
Specifically, the use of highly efficient
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simple cycle technology in combination
with the best operating and
maintenance practices is the first
component of the BSER for intermediate
load combustion turbines. The use of
highly efficient combined cycle
technology in combination with best
operating and maintenance practices is
the first component of the BSER for base
load combustion turbines.
Highly efficient generation qualifies
as a component of the BSER because it
is adequately demonstrated, it can be
implemented at reasonable cost, it
achieves emission reductions, and it
does not have significant adverse nonair quality health or environmental
impacts or significant adverse energy
requirements. The fact that it promotes
greater use of advanced technology
provides additional support; however,
the EPA would consider highly efficient
generation to be a component of the
BSER for base load and intermediate
load combustion turbines even without
taking this factor into account.
3. BSER for Base Load and Intermediate
Load Subcategories—Second and Third
Components
This section describes the proposed
second (and in some cases third)
component of the BSER for base load
and intermediate load combustion
turbines, which would be reflected in
the second phase (and in some cases
third phase) standards of performance.
The proposed second component of the
BSER for base load combustion turbines
that are adopting the CCS pathway is
the use of 90 percent CCS; and the
corresponding standard of performance
would apply beginning in 2035. The
second component of the BSER for base
load combustion turbines that are
adopting the low-GHG hydrogen cofiring pathway and for intermediate load
combustion turbines is co-firing 30
percent (by volume) low-GHG hydrogen
and the corresponding standard of
performance would apply beginning in
2032. The third component of the BSER
would apply only to base load
combustion turbines that are subject to
a second phase standard that is based on
co-firing 30 percent (by volume) lowGHG hydrogen. For those sources, the
third component of the BSER is co-firing
96 percent (by volume) low-GHG
hydrogen and the corresponding
standard of performance would apply
beginning in 2038. The EPA is also
soliciting comment on whether
intermediate load combustion turbines
should be subject to a more stringent
third phase standard based on 96
percent low-GHG hydrogen co-firing by
2038. A BSER based on 96 percent cofiring would result in a standard of
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performance of 140 lb CO2/MWh-gross
for a natural gas-fired intermediate load
combustion turbine.
a. Authority To Promulgate a Multi-Part
BSER and Standard of Performance
The EPA’s proposed approach of
promulgating standards of performance
that apply in multiple phases, based on
determining the BSER to be a set of
controls with multiple components, is
consistent with CAA section 111(b).
That provision authorizes the EPA to
promulgate ‘‘standards of performance,’’
CAA section 111(b)(1)(B), defined, in
the singular, as ‘‘a standard for
emissions of air pollutants which
reflects the degree of emission
limitation achievable through the
application of the [BSER].’’ CAA section
111(a)(1). CAA section 111(b)(1)(B)
further provides, ‘‘[s]tandards of
performance . . . shall become effective
upon promulgation.’’ In this
rulemaking, the EPA is proposing to
determine that the BSER is a set of
controls that, depending on the
subcategory, include either highly
efficient generation plus use of CCS or
highly efficient generation plus co-firing
low-GHG hydrogen. The EPA is further
proposing that affected sources can
apply the first component of the BSER—
highly efficient generation—by the
effective date of the final rule and can
apply both the first and second
components of the BSER—highly
efficient generation in combination with
co-firing 30 percent (by volume) lowGHG hydrogen and highly efficient
generation in combination with 90
percent CCS—in 2032 and 2035,
respectively. The EPA is also proposing
that certain sources can apply the third
component of the BSER—co-firing 96
percent (by volume) low-GHG
hydrogen—by 2038.
Accordingly, the EPA is proposing
standards of performance that reflect the
application of this multi-component
BSER and that take the form of
standards of performance that affected
sources must comply with in either two
or three phases. Affected sources must
comply with the first phase standards
that are based on the application of the
first component of the BSER upon
initial startup of the facility. The second
phase standards are based on the
application of both the first and second
components of the BSER by 2032 (for
those sources utilizing co-firing lowGHG hydrogen) and by 2035 (for those
sources utilizing CCS). The third phase
standards are only applicable to those
sources that are subject to a second
phase standard of performance based on
the highly efficient generation in
combination with co-firing 30 percent
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(by volume) low-GHG hydrogen. The
third phase standards for those sources
are based on the application of the first
component of the BSER and on the third
component, which is co-firing 96
percent (by volume) low-GHG hydrogen
by 2038. In this manner, this multiphase standard of performance
‘‘become[s] effective upon
promulgation.’’ CAA section
111(b)(1)(B). That is, upon
promulgation, affected sources become
subject to a standard of performance
that limits their emissions immediately,
which is the first phase of the standard
of performance, and they also become
subject to more stringent standards
beginning in 2032 or later, which are the
second and in some cases third phase of
the standard of performance.
D.C. Circuit caselaw supports the
proposition that CAA section 111
authorizes the EPA to determine that
controls qualify as the BSER—including
meeting the ‘‘adequately demonstrated’’
criterion—even if the controls require
some amount of ‘‘lead time,’’ which the
court has defined as ‘‘the time in which
the technology will have to be
available.’’ 236 The caselaw’s
interpretation of ‘‘adequately
demonstrated’’ to accommodate lead
time accords with common sense and
the practical experience of certain types
of controls, discussed below. Consistent
with this caselaw, the phased
implementation of the standards of
performance in this rule ensures that
facilities have sufficient lead time for
planning and implementation of the use
of CCS or low GHG-hydrogen-based
controls necessary to comply with the
second phase of the standards, and
thereby ensures that the standards are
achievable. Indeed, interpreting CAA
section 111 to preclude phased
implementation of standards of
performance would be tantamount to
interpreting the provision to preclude
standards based on lead time, which
would be contrary to the D.C. Circuit
caselaw and common sense.
The EPA has promulgated several
prior rulemakings under CAA section
111(b) that have similarly provided the
regulated sector with lead time to
accommodate the availability of
technology, which also serve as
precedent for the two-phase
implementation approach proposed in
this rule. See 81 FR 59332 (August 29,
2016) (establishing standards for
municipal solid waste landfills with 30month compliance timeframe for
installation of control device, with
interim milestones); 80 FR 13672, 13676
236 Portland Cement Ass’n v. Ruckelshaus, 486
F.2d 375, 391 (D.C. Cir. 1973) (citations omitted).
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(March 16, 2015) (establishing stepped
compliance approach to wood heaters
standards to permit manufacturers lead
time to develop, test, field evaluate and
certify current technologies to meet Step
2 emission limits); 78 FR 58416, 58420
(September 23, 2013) (establishing
multi-phased compliance deadlines for
revised storage vessel standards to
permit sufficient time for production of
necessary supply of control devices and
for trained personnel to perform
installation); 77 FR 56422, 56450
(September 12, 2012) (establishing
standards for petroleum refineries, with
3-year compliance timeframe for
installation of control devices); 71 FR
39154, 39158 (July 11, 2006)
(establishing standards for stationary
compression ignition internal
combustion engines, with 2 to 3-year
compliance timeframe and up to 6 years
for certain emergency fire pump
engines); 70 FR 28606, 28617 (March 18,
2005) (establishing two-phase caps for
mercury standards of performance from
new and existing coal-fired electric
utility steam generating units based on
timeframe when additional control
technologies were projected to be
adequately demonstrated).237 Cf. 80 FR
64662, 64743 (October 23, 2015)
(establishing interim compliance period
to phase in final power sector GHG
standards to allow time for planning
and investment necessary for
implementation activities).238 In each
action, the standards and compliance
timelines were effective upon the final
rule, with affected facilities required to
comply consistent with the phased
compliance deadline specified in each
action.
It should be noted that the multiphased implementation of the standards
of performance that the EPA is
proposing in this rule, like the delayed
or multi-phased standards in prior rules
just described, is distinct from the
promulgation of revised standards of
performance under the 8-year review
provision of CAA section 111(b)(1)(B).
As discussed in section VII.F, the EPA
has determined that the proposed
BSER—highly efficient generation and
use of CCS or highly efficient generation
and co-firing low-GHG hydrogen—meet
all of the statutory criteria and are
adequately demonstrated for the
compliance timeframes being proposed.
Thus, the second and third phases of the
standard of performance, if finalized,
would apply to affected facilities that
commence construction after the date of
237 Cf. New Jersey v. EPA, 517 F.3d 574, 583–584
(D.C. Cir. 2008) (vacating rule on other grounds).
238 Cf. West Virginia v. EPA, 142 S. Ct. 2587
(2022) (vacating rule on other grounds).
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this proposal. In contrast, when the EPA
later reviews and (if appropriate) revises
a standard of performance under the 8year review provision, then affected
sources that commence construction
after the date of that proposal of the
revised standard of performance would
be subject to that standard, but not
sources that commenced construction
earlier.
Similarly, the multi-phased
implementation of the standard of
performance that the EPA is proposing
in this rule is also distinct from the
promulgation of emission guidelines for
existing sources under CAA section
111(d). Emission guidelines only apply
to existing sources, which are defined in
CAA section 111(a)(6) as ‘‘any stationary
source other than a new source.’’
Because new sources are defined
relative to the proposal of standards
pursuant to CAA section 111(b)(1)(B),
standards of performance adopted
pursuant to emission guidelines will
only apply to sources constructed before
the date of these proposed standards of
performance for new sources.
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b. BSER for Base Load Subcategory of
Combustion Turbines Adopting the CCS
Pathway—Second Component
This section describes the second
component of the BSER for the base
load subcategory of combustion turbines
that are adopting the CCS pathway. This
subcategory is expected to include
highly efficient combined cycle
combustion turbines that primarily
combust fossil fuels, and therefore have
higher levels of CO2 in the exhaust.
The EPA is proposing the use of CCS
as the second component of the BSER
for these combustion turbines. A
detailed discussion of CCS follows. It
should be noted that the EPA is also
proposing use of CCS as the BSER for
existing long-term coal-fired steam
generating units (i.e., coal-fired utility
boilers), as discussed in section X.D of
this preamble, as well as for large and
frequently operated existing stationary
combustion turbines. Many aspects of
CCS are common to new combined
cycle combustion turbines, existing
long-term steam generating units, and
existing stationary combustion turbines,
and the following discussion details
those common aspects and
considerations.
i. Lower Emitting Fuels
The EPA is not proposing lower
emitting fuels as the second component
of the BSER for base load combustion
turbines because it would achieve few
emission reductions, compared to
highly efficient generation in
combination with the use of CCS.
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ii. Highly Efficient Generation
For the reasons described above, the
EPA is proposing that highly efficient
generation technology in combination
with best operating and maintenance
practices continues to be a component
of the BSER that is reflected in the
second phase of the standards of
performance for base load combustion
turbine EGUs that are adopting the CCS
pathway. Highly efficient generation
reduces fuel use and the amount of CO2
that must be captured by a CCS system.
Since less flue gas needs to be treated,
physically smaller carbon capture
equipment may be used—potentially
reducing capital, fixed, and operating
costs.
iii. CCS
In this section of the preamble, the
EPA provides a description of the
components of CCS and evaluates it
against the criteria to qualify as the
BSER. CCS has three major components:
CO2 capture, transportation, and
sequestration/storage. Post-combustion
capture processes remove CO2 from the
exhaust gas of a combustion system,
such as a combustion turbine or a utility
boiler. This technology is referred to as
‘‘post-combustion capture’’ because CO2
is a product of the combustion of the
primary fuel and the capture takes place
after the combustion of that fuel. The
exhaust gases from most combustion
processes are at atmospheric pressure
and are moved through the flue gas duct
system by fans. The concentration of
CO2 in most fossil fuel combustion flue
gas streams is somewhat dilute. Most
post-combustion capture systems utilize
liquid solvents—most commonly aminebased solvents—that separate the CO2
from the flue gas in CO2 scrubber
systems using chemical absorption (or
chemisorption). In a chemisorptionbased separation process, the flue gas is
processed through the CO2 scrubber and
the CO2 is absorbed by the liquid
solvent. The CO2-rich solvent is then
regenerated by heating the solvent to
release the captured CO2.
Another technology, oxy-combustion,
uses a purified oxygen stream from an
air separation unit (often diluted with
recycled CO2 to control the flame
temperature) to combust the fuel and
produce a higher concentration of CO2
in the flue gas, as opposed to
combustion with oxygen in air which
contains 80 percent nitrogen. The high
purity CO2 is then compressed and
transported, generally through
pipelines, to a site for geologic
sequestration (i.e., the long-term
containment of CO2 in subsurface
geologic formations). These
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sequestration sites are widely available
across the nation, and the EPA has
developed a comprehensive regulatory
structure to oversee geological
sequestration projects and assure their
safety and effectiveness. See 80 FR
64549 (October 23, 2015).
(A) Adequately Demonstrated
For new base load combustion
turbines, the EPA proposes that CCS
with a 90 percent capture rate,
beginning in 2035, meets the BSER
criteria. This amount of CCS is feasible
and has been adequately demonstrated.
The use of CCS at this level can be
implemented at reasonable cost because
it allows affected sources to maximize
the benefits of the IRC section 45Q tax
credit, and sources can maintain it over
time by capturing a higher percentage at
certain times in order to offset a lower
capture rate at other times due to, for
example, the need to undertake
maintenance or due to unplanned
capture system outages. Higher capture
rates may be possible—the 2022 NETL
Baseline report evaluated capture rates
at 90 and 95 percent with marginal
differences in cost. The Agency is
soliciting comment on the range of the
capture rate of CO2 at the stack from 90
to 95 percent or greater. The EPA also
notes that the operating availability (the
fraction of time CCS equipment is
operational relative to the operation of
the combustion turbine) may be less
than 100 percent and is therefore
soliciting comment on a range in
emission reduction from 75 to 90
percent, as further discussed in section
VII.G.2 of this preamble.
The EPA previously determined
‘‘partial CCS’’ to be a component of the
BSER (in combination with the use of a
highly efficient supercritical utility
boiler) for new coal-fired steam
generating units as part of the 2015
NSPS (80 FR 64538; October 23,
2015).239 As described in that action,
reiterated in this section of the
preamble, and detailed further in
accompanying TSDs available in the
docket for this rulemaking, numerous
projects demonstrate the feasibility and
effectiveness of CCS technology.
In the 2015 NSPS, the EPA considered
coal-fired industrial projects that had
installed at least some components of
CCS technology. In doing so, the EPA
recognized that some of those projects
had received assistance in the form of
grants, loan guarantees, and Federal tax
credits for investment in ‘‘clean coal
technology,’’ under provisions of the
239 In the present action, the EPA is not reopening any aspect of the CCS determinations in
the 2015 NSPS.
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Energy Policy Act of 2005 (‘‘EPAct05’’).
See 80 FR 64541–42 (October 23, 2015).
(The EPA refers to projects that received
assistance under that legislation as
‘‘EPAct05-assisted projects.’’) The EPA
further recognized that the EPAct05
included provisions that constrained
how the EPA could rely on EPAct05assisted projects in determining whether
technology is adequately demonstrated
for the purposes of CAA section 111.240
The EPA went on to provide a legal
interpretation of those constraints.
Under that legal interpretation, ‘‘these
provisions [in the EPAct05] . . .
preclude the EPA from relying solely on
the experience of facilities that received
[EPAct05] assistance, but [do] not . . .
preclude the EPA from relying on the
experience of such facilities in
conjunction with other information.’’ 241
Id. at 64541–42. In the present action,
the EPA is applying the same legal
interpretation and is not reopening it for
comment.
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(1) CO2 Capture Technology
The EPA is proposing that the CO2
capture component of CCS has been
adequately demonstrated and is
technically feasible based on the
demonstration of the technology at
existing coal-fired steam generating
units and industrial sources in addition
to combustion turbines. While the EPA
would propose that the CO2 capture
component of CCS is adequately
demonstrated on those bases alone, this
determination is further corroborated by
EPAct05-assisted projects.
240 The relevant EPAct05 provisions include the
following: Section 402(i) of the EPAct05, codified
at 42 U.S.C. 15962(a), provides as follows:
‘‘No technology, or level of emission reduction,
solely by reason of the use of the technology, or the
achievement of the emission reduction, by 1 or
more facilities receiving assistance under this Act,
shall be considered to be adequately demonstrated
[ ] for purposes of section 111 of the Clean Air Act
. . . .’’
IRC section 48A(g), as added by EPAct05 1307(b),
provides as follows:
‘‘No use of technology (or level of emission
reduction solely by reason of the use of the
technology), and no achievement of any emission
reduction by the demonstration of any technology
or performance level, by or at one or more facilities
with respect to which a credit is allowed under this
section, shall be considered to indicate that the
technology or performance level is adequately
demonstrated [ ] for purposes of section 111 of the
Clean Air Act . . . .’’
Section 421(a) states:
‘‘No technology, or level of emission reduction,
shall be treated as adequately demonstrated for
purpose [sic] of section 7411 of this title, . . . solely
by reason of the use of such technology, or the
achievement of such emission reduction, by one or
more facilities receiving assistance under section
13572(a)(1) of this title.’’
241 In the 2015 NSPS, the EPA adopted several
other legal interpretations of these EPAct05
provisions as well, which it is not reopening in this
rule. See 80 FR 64541 (October 23, 2015).
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Various technologies may be used to
capture CO2, the details of which are
described in the GHG Mitigation
Measures for Steam Generating Units
TSD, which is available in the
rulemaking docket.242 For postcombustion capture, these technologies
include solvent-based methods (e.g.,
amines, chilled ammonia), solid
sorbent-based methods, membrane
filtration, pressure-swing adsorption,
and cryogenic methods.243 Lastly, as
noted above, oxy-combustion uses a
purified oxygen stream from an air
separation unit (often diluted with
recycled CO2 to control the flame
temperature) to combust the fuel and
produce a higher concentration of CO2
in the flue gas, as opposed to
combustion with oxygen in air which
contains 80 percent nitrogen. The CO2
can then be separated by the
aforementioned CO2 capture methods.
Of the available capture technologies,
solvent-based processes have been the
most widely demonstrated at
commercial scale for post-combustion
capture and are applicable to use with
either combustion turbines or steam
generating units.
Solvent-based capture processes
usually use an amine (e.g.,
monoethanolamine, MEA). Carbon
capture occurs by reactive absorption of
the CO2 from the flue gas into the amine
solution in an absorption column. The
amine reacts with the CO2 but will also
react with potential contaminants in the
flue gas, including SO2. After
absorption, the CO2-rich amine solution
passes to the solvent regeneration
column, while the treated gas passes
through a water 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 CO2. The released CO2 is then
compressed and transported offsite,
usually by pipeline. The amine solution
from the regenerating column is cooled
and sent back to the absorption column,
and any spent solvent is replenished
with new solvent.
242 Technologies to capture CO are also
2
discussed in the GHG Mitigation Measures—Carbon
Capture and Storage for Combustion Turbines TSD.
243 For pre-combustion capture (as is applicable
to an IGCC unit), syngas produced by gasification
passes through a water-gas shift catalyst to produce
a gas stream with a higher concentration of
hydrogen and CO2. The higher CO2 concentration
relative to conventional combustion flue gas
reduces the demands (power, heating, and cooling)
of the subsequent CO2 capture process (e.g., solid
sorbent-based or solvent-based capture), the treated
hydrogen can then be combusted in the unit.
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(2) Capture Demonstrations at CoalFired Steam Generating Units and
Industrial Processes
The function, design, and operation of
post-combustion CO2 capture
equipment is similar, although not
identical, for both steam generating
units and combustion turbines. As a
result, application of CO2 capture at
existing coal-fired steam generating
units helps demonstrate the adequacy of
the CO2 capture component of CCS.
SaskPower’s Boundary Dam Unit 3, a
110 MW lignite-fired unit in
Saskatchewan, Canada, has
demonstrated CO2 capture rates of 90
percent using an amine-based postcombustion capture system retrofitted to
the existing steam generating unit. The
capture plant, which began operation in
2014, was the first full-scale CO2
capture system retrofit on an existing
coal-fired power plant. It uses the
amine-based Shell CANSOLV process,
with integrated heat and power from the
steam generating unit.244 While
successfully demonstrating the
commercial-scale feasibility of 90
percent capture rates, the plant has also
provided valuable lessons learned for
the next generation of capture plants. A
feasibility study for SaskPower’s Shand
Power Station indicated achievable
capture rates of 97 percent, even at
lower loads.245
For all industrial processes,
operational availability (the percent of
time a unit operates relative to its
planned operation) is usually less than
100 percent due to unplanned
maintenance and other factors. As a
first-of-a-kind commercial-scale project,
Boundary Dam Unit 3 experienced some
additional challenges with availability
during its initial years of operation, due
to the fouling of heat exchangers and
issues with its CO2 compressor.246
However, identifying and correcting
those problems has improved the
operational availability of the capture
system. The facility has reported greater
than 90 percent capture system
244 Giannaris, S., et al. Proceedings of the 15th
International Conference on Greenhouse Gas
Control Technologies (March 15–18, 2021).
SaskPower’s Boundary Dam Unit 3 Carbon Capture
Facility—The Journey to Achieving Reliability.
https://papers.ssrn.com/sol3/papers.cfm?abstract_
id=3820191.
245 International CCS Knowledge Centre. The
Shand CCS Feasibility Study Public Report. https://
ccsknowledge.com/pub/Publications/Shand_CCS_
Feasibility_Study_Public_Report_Nov2018_(202105-12).pdf.
246 S&P Global Market Intelligence (January 6,
2022). Only still-operating carbon capture project
battled technical issues in 2021. https://
www.spglobal.com/marketintelligence/en/newsinsights/latest-news-headlines/only-still-operatingcarbon-capture-project-battled-technical-issues-in2021-68302671.
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availability in the second and third
quarters of 2022.247 Currently, newly
constructed and retrofit CO2 capture
systems are anticipated to have
operational availability of around 90
percent, on the same order of that is
expected at coal-fired steam generating
units. The EPA is soliciting comment on
information relevant to the expected
operational availability of new and
retrofit CO2 capture systems.
Several other projects have
successfully demonstrated the capture
component of CCS at electricity
generating plants and other industrial
facilities, some of which were
previously noted in the discussion in
the 2015 NSPS (80 FR 64548–54;
October 23, 2015). Amine-based carbon
capture has been demonstrated at AES’s
Warrior Run (Cumberland, Maryland)
and Shady Point (Panama, Oklahoma)
coal-fired power plants, with the
captured CO2 being sold for use in the
food processing industry.248 At the 180–
MW Warrior Run plant, approximately
10 percent of the plant’s CO2 emissions
(about 110,000 metric tons of CO2 per
year) has been captured since 2000 and
sold to the food and beverage industry.
AES’s 320–MW coal-fired Shady Point
plant captured CO2 from an
approximate 5 percent slipstream (about
66,000 metric tons of CO2 per year) from
2001 through around 2019.249 These
facilities, which have operated for
multiple years, clearly show the
technical feasibility of post-combustion
carbon capture.
The capture component of CCS has
also been demonstrated at other
industrial processes. Since 1978, the
Searles Valley Minerals soda ash plant
in Trona, California, has used an aminebased system to capture approximately
270,000 metric tons of CO2 per year
from the flue gas of a coal-fired
industrial power plant that generates
steam and power for onsite use. The
captured CO2 is used for the carbonation
of brine in the process of producing
soda ash.250
The Quest CO2 capture facility in
Alberta, Canada, uses amine-based CO2
247 SaskPower (October 18, 2022). BD3 Status
Update: Q3 2022. https://www.saskpower.com/
about-us/our-company/blog/2022/bd3-statusupdate-q3-2022.
248 Dooley, J.J., et al. (2009). ‘‘An Assessment of
the Commercial Availability of Carbon Dioxide
Capture and Storage Technologies as of June 2009.’’
U.S. DOE, Pacific Northwest National Laboratory,
under Contract DE–AC05–76RL01830.
249 Shady Point Plant (River Valley) was sold to
Oklahoma Gas and Electric in 2019. https://
www.oklahoman.com/story/business/columns/
2019/05/23/oklahoma-gas-and-electric-acquiresaes-shady-point-after-federal-approval/
60454346007/.
250 IEA (2009), World Energy Outlook 2009,
OECD/IEA, Paris.
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capture retrofitted to three existing
steam methane reformers at the Scotford
Upgrader facility (operated by Shell
Canada Energy) to capture and sequester
approximately 80 percent of the CO2 in
the produced syngas.251 The Quest
facility has been operating since 2015
and captures approximately 1 million
metric tons of CO2 per year.
(3) Capture Demonstrations at
Combustion Turbines
While most demonstrations of CCS
have been for applications other than
combustion turbines, CCS has been
successfully applied to an existing
combined cycle EGU and several other
projects are in development, as
discussed immediately below. Currently
available post-combustion amine-based
carbon capture systems require that the
flue gas be cooled prior to entering the
carbon capture equipment. This holds
true for the exhaust from a combustion
turbine. The most energy efficient way
to do this is to use a HSRG—which, as
explained above, is an integral
component of a combined cycle turbine
system—to generate additional useful
output. Because simple cycle
combustion turbines do not incorporate
a HRSG, the Agency is not considering
the use of CCS as a potential component
of the BSER for them.
(a) CCS on Combined Cycle EGUs
Examples of the use of CCS on
combined cycle EGUs include the
Bellingham Energy Center in south
central Massachusetts and the proposed
Peterhead Power Station in Scotland.
The Bellingham plant used Fluor’s
Econamine FG PlusSM capture system
and demonstrated the commercial
viability of carbon capture on a
combined cycle combustion turbine
EGU using first-generation technology.
The 40-MW slipstream capture facility
operated from 1991 to 2005 and
captured 85 to 95 percent of the CO2 in
the slipstream for use in the food
industry.252 In Scotland, the proposed
900-MW Peterhead Power Station
combined cycle EGU with CCS is in the
planning stages of development. It is
anticipated that the power plant will be
operational by the end of the 2020s and
will have the potential to capture 90
percent of the CO2 emitting from the
combined cycle facility and sequester
251 Quest Carbon Capture and Storage Project
Annual Summary Report, Alberta Department of
Energy: 2021. https://open.alberta.ca/publications/
quest-carbon-capture-and-storage-project-annualreport-2021.
252 U.S. Department of Energy (DOE). Carbon
Capture Opportunities for Natural Gas Fired Power
Systems. https://www.energy.gov/fecm/articles/
carbon-capture-opportunities-natural-gas-firedpower-systems.
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up to 1.5 million metric tons of CO2
annually. A storage site being developed
62 miles off the Scottish North Sea coast
might serve as a destination for the
captured CO2.253 Moreover, an 1,800MW NGCC EGU that will be constructed
in West Virginia and will utilize CCS
has been announced. The project is
planned to begin operation later this
decade, and its feasibility was partially
credited to the expanded IRC section
45Q tax credit for sequestered CO2
provided through the IRA.254
(b) Net Power Cycle
In addition, there are several planned
projects using the NET Power Cycle.255
The NET Power Cycle is a proprietary
process for producing electricity that
combusts a fuel with purified oxygen
and uses supercritical CO2 as the
working fluid instead of water/steam.
This cycle is designed to achieve
thermal efficiencies of up to 59
percent.256 Potential advantages of this
cycle are that it emits no NOX and
produces a stream of high-purity CO2 257
that can be delivered by pipeline to a
storage or sequestration site without
extensive processing. A 50-MW
(thermal) test facility in La Porte, Texas
was completed in 2018 and was
synchronized to the grid in 2021. There
are several announced commercial
projects proposing to use the NET
Power Cycle. These include the 280MW Broadwing Clean Energy Complex
in Illinois, and several international
projects.
(4) EPAct05-Assisted CO2 Capture
Projects
While the EPA is proposing that the
capture component of CCS is adequately
demonstrated based solely on the other
demonstrations of CO2 capture
discussed in this preamble, adequate
demonstration of CO2 capture
technology is further corroborated by
253 Buli, N. (2021, May 10). SSE, Equinor plan
new gas power plant with carbon capture in
Scotland. Reuters. https://www.reuters.com/
business/sustainable-business/sse-equinor-plannew-gas-power-plant-with-carbon-capture-scotland2021-05-11/.
254 Competitive Power Ventures (2022). MultiBillion Dollar Combined Cycle Natural Gas Power
Station with Carbon Capture Announced in West
Virginia. Press Release. September 16, 2022. https://
www.cpv.com/2022/09/16/multi-billion-dollarcombinedcycle-natural-gas-power-station-withcarbon-capture-announced-in-west-virginia/.
255 https://netpower.com/technology/. The Net
Power Cycle was formerly referred to as the AllamFetvedt cycle.
256 Yellen, D. (2020, May 25). Allam Cycle carbon
capture gas plants: 11 percent more efficient, all
CO2 captured. Energy Post. https://energypost.eu/
allam-cycle-carbon-capture-gas-plants-11-moreefficient-all-co2-captured/.
257 This allows for capture of over 97 percent of
the CO2 emissions. www.netpower.com.
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CO2 capture projects assisted by grants,
loan guarantees, and Federal tax credits
for ‘‘clean coal technology’’ authorized
by the EPAct05. 80 FR 64541–42
(October 23, 2015).
(a) EPAct05-Assisted CO2 Capture
Projects at Coal-Fired Steam Generating
Units
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Petra Nova is a 240 MW-equivalent
capture facility that is the first at-scale
application of carbon capture at a coalfired power plant in the U.S. The system
is located at the W.A. Parish Generating
Station in Thompsons, Texas, and began
operation in 2017, successfully
capturing and sequestering CO2 for
several years. Although the system was
put into reserve shutdown (i.e., idled) in
May 2020, citing the poor economics of
utilizing captured CO2 for enhanced oil
recovery (EOR) at that time, there are
reports of plans to restart the capture
system.258 A final report from National
Energy Technology (NETL) details the
success of the project and what was
learned from this first-of-a-kind
demonstration at scale.259 The project
used Mitsubishi Heavy Industry’s
proprietary KM–CDR Process®, a
process that is similar to an amine-based
solvent process but that uses a
proprietary solvent and is optimized for
CO2 capture from a coal-fired
generator’s flue gas. During its
operation, the project successfully
captured 92.4 percent of the CO2 from
the slip stream of flue gas processed
with 99.08 percent of the captured CO2
sequestered by EOR. Plant Barry in
Mobile, Alabama, began using the KM–
CDR Process® in 2011 for a fully
integrated 25-MW CCS project with a
capture rate of 90 percent.260 The CCS
project at Plant Barry captured
approximately 165,000 tons of CO2
annually, which is then transported via
pipeline and sequestered underground
in geologic formations. See 80 FR 64552
(October 23, 2015).
258 ‘‘The World’s Largest Carbon Capture Plant
Gets a Second Chance in Texas’’ Bloomberg News,
February 8, 2023. https://www.bloomberg.com/
news/articles/2023-02-08/the-world-s-largestcarbon-capture-plant-gets-a-second-chance-intexas?leadSource=uverify%20wall.
259 W.A. Parish Post-Combustion CO Capture
2
and Sequestration Demonstration Project, Final
Scientific/Technical Report (March 2020). https://
www.osti.gov/servlets/purl/1608572.
260 U.S. Department of Energy (DOE). National
Energy Technology Laboratory (NETL). https://
www.netl.doe.gov/node/1741.
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(b) EPAct05-Assisted CO2 Capture
Projects at Stationary Combustion
Turbines
There are several EPAct05-assisted
projects related to NGCC units
including: 261 262 263 264 265
• General Electric (GE) (Bucks,
Alabama) was awarded $5,771,670 to
retrofit an NGCC facility with CCS
technology to capture 95 percent of CO2
and is targeting commercial deployment
by 2030.
• Wood Environmental &
Infrastructure Solutions (Blue Bell,
Pennsylvania) was awarded $4,000,000
to complete an engineering design study
for CO2 capture at the Shell Chemicals
Complex. The aim is to reduce CO2
emissions by 95 percent using postcombustion technology to capture CO2
from several plants, including an onsite
natural gas CHP plant.
• General Electric Company, GE
Research (Niskayuna, New York) was
awarded $1,499,992 to develop a design
to capture 95 percent of CO2 from NGCC
flue gas with the potential to reduce
electricity costs by at least 15 percent.
• SRI International (Menlo Park,
California) was awarded $1,499,759 to
design, build, and test a technology that
can capture at least 95 percent of CO2
while demonstrating a 20 percent cost
reduction compared to existing NGCC
carbon capture.
• CORMETECH, Inc. (Charlotte,
North Carolina) was awarded
$2,500,000 to further develop, optimize,
and test a new, lower cost technology to
capture CO2 from NGCC flue gas and
improve scalability to large NGCC
plants.
261 General Electric (GE) (2022). U.S. Department
of Energy Awards $5.7 Million for GE-Led Carbon
Capture Technology Integration Project Targeting to
Achieve 95% Reduction of Carbon Emissions. Press
Release. February 15, 2022. https://www.ge.com/
news/press-releases/us-department-of-energyawards-57-million-for-ge-led-carbon-capturetechnology.
262 Larson, A. (2022). GE-Led Carbon Capture
Project at Southern Company Site Gets DOE
Funding. Power. https://www.powermag.com/geled-carbon-capture-project-at-southern-companysite-gets-doe-funding/.
263 U.S. Department of Energy (DOE) (2021). DOE
Invests $45 Million to Decarbonize the Natural Gas
Power and Industrial Sectors Using Carbon Capture
and Storage. October 6, 2021. https://
www.energy.gov/articles/doe-invests-45-milliondecarbonize-natural-gas-power-and-industrialsectors-using-carbon.
264 DOE (2022). Additional Selections for Funding
Opportunity Announcement 2515. Office of Fossil
Energy and Carbon Management. https://
www.energy.gov/fecm/additional-selectionsfunding-opportunity-announcement-2515.
265 DOE (2019). FOA 2058: Front-End Engineering
Design (FEED) Studies for Carbon Capture Systems
on Coal and Natural Gas Power Plants. Office of
Fossil Energy and Carbon Management. https://
www.energy.gov/fecm/foa-2058-front-endengineering-design-feed-studies-carbon-capturesystems-coal-and-natural-gas.
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33293
• TDA Research, Inc. (Wheat Ridge,
Colorado) was awarded $2,500,000 to
build and test a post-combustion
capture process to improve the
performance of NGCC flue gas CO2
capture.
• GE Gas Power (Schenectady, New
York) was awarded $5,771,670 to
perform an engineering design study to
incorporate a 95 percent CO2 capture
solution for an existing NGCC site while
providing lower costs and scalability to
other sites.
• Electric Power Research Institute
(EPRI) (Palo Alto, California) was
awarded $5,842,517 to complete a study
to retrofit a 700-Mwe NGCC with a
carbon capture system to capture 95
percent of CO2.
• Gas Technology Institute (Des
Plaines, Illinois) was awarded
$1,000,000 to develop membrane
technology capable of capturing more
than 97 percent of NGCC CO2 flue gas
and demonstrate upwards of 40 percent
reduction in costs.
• RTI International (Research
Triangle Park, North Carolina) was
awarded $1,000,000 to test a novel nonaqueous solvent technology aimed at
demonstrating 97 percent capture
efficiency from simulated NGCC flue
gas.
• Tampa Electric Company (Tampa,
Florida) was awarded $5,588,173 to
conduct a study retrofitting Polk Power
Station with post-combustion CO2
capture technology aiming to achieve a
95 percent capture rate.
There are also several announced NET
Power Cycle based CO2 capture projects
that are EPAct05-assisted. These include
the 280–MW Coyote Clean Power
Project on the Southern Ute Indian
Reservation in Colorado and a 300–MW
project located near Occidental’s
Permian Basin operations close to
Odessa, Texas. Commercial operation of
the facility near Odessa, Texas is
expected in 2026.
(5) CO2 Transport
(a) Demonstration of CO2 Transport
The majority of CO2 transported in the
U.S. is transported through pipelines.
Pipeline transport of CO2 has been
occurring for nearly 60 years, and over
this time, the design, construction, and
operational requirements for CO2
pipelines have been demonstrated.266
Moreover, the U.S. CO2 pipeline
network has steadily expanded, and
appears primed to continue to do so.
The Pipeline and Hazardous Materials
266 For additional information on CO
2
transportation infrastructure project timelines, costs
and other details, please see the GHG Mitigation
Measures for Steam Generating Units TSD.
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Safety Administration (PHMSA)
reported that 5,339 miles of CO2
pipelines were in operation in 2021, a
13 percent increase in CO2 pipeline
miles since 2011.267 Moreover, several
major projects have recently been
announced to expand the CO2 pipeline
network across the U.S. For example,
the Midwest Carbon Express has
proposed to add more than 2,000 miles
of dedicated CO2 pipeline in Iowa,
Nebraska, North Dakota, South Dakota,
and Minnesota. The Midwest Carbon
Express is projected to begin operations
in 2024.268 Another example is the
Heartland Greenway project, which has
proposed to add more than 1,300 miles
of dedicated CO2 pipeline in Iowa,
Nebraska, South Dakota, Minnesota, and
Illinois. The Heartland Greenway
project is projected to start its initial
system commissioning in the second
quarter of 2025.269 The proximity to
existing or planned CO2 pipelines and
geologic sequestration sites can be a
factor to consider in the construction of
stationary combustion turbines, and
pipeline expansion, when needed, has
been proven to be feasible.270 271 The
IIJA also included substantial support
for CO2 transportation infrastructure.
(b) Security of CO2 Transport
lotter on DSK11XQN23PROD with PROPOSALS2
The safety of existing and new CO2
pipelines that transport CO2 in a
supercritical state is exclusively
regulated by PHMSA. These regulations
include standards related to pipeline
design, construction, and testing,
operations and maintenance, operator
reporting requirements, operator
qualifications, corrosion control and
pipeline integrity management, incident
reporting and response, and public
awareness and communications.
PHMSA has regulatory authority to
267 U.S. Department of Transportation, Pipeline
and Hazardous Material Safety Administration,
‘‘Hazardous Annual Liquid Data.’’ 2021. https://
www.phmsa.dot.gov/data-and-statistics/pipeline/
gas-distribution-gas-gathering-gas-transmissionhazardous-liquids.
268 Beach, Jeff. ‘‘World’s Largest Carbon Capture
Pipeline Aims to Connect 31 Ethanol Plants, Cut
across Upper Midwest.’’ Agweek, December 6,
2021. https://www.agweek.com/business/worldslargest-carbon-capture-pipeline-aims-to-connect-31ethanol-plants-cut-across-upper-midwest.
269 Navigator CO ‘‘NavCO Fact Sheet.’’ 2022.
2,
2
https://d3o151.p3cdn1.secureserver.net/wpcontent/uploads/2022/08/HG-Fact-SheetvFINAL.pdf.
270 For additional information regarding planned
or announced pipelines please see section 4.6.1.2 of
the GHG Mitigation Measures for Steam Generating
Units TSD.
271 U.S. Department of Transportation, Pipeline
and Hazardous Material Safety Administration,
‘‘Hazardous Annual Liquid Data.’’ 2021. https://
www.phmsa.dot.gov/data-and-statistics/pipeline/
gas-distribution-gas-gathering-gas-transmissionhazardous-liquids.
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conduct inspections of supercritical CO2
pipeline operations and issue notices to
operators in the event of operator
noncompliance with regulatory
requirements.272 Furthermore, PHMSA
initiated a rulemaking in 2022 to
develop and implement new measures
to strengthen its safety oversight of
supercritical CO2 pipelines following
investigation into a CO2 pipeline failure
in Satartia, Mississippi in 2020.273
Following that incident, PHMSA also
issued a Notice of Probable Violation,
Proposed Civil Penalty, and Proposed
Compliance Order (Notice) to the
operator related to probable violations
of Federal pipeline safety regulations.
The Notice was ultimately resolved
through a Consent Agreement between
PHMSA and the operator that includes
the assessment of civil penalties and
identifies actions for the operator to take
to address the alleged violations and
risk conditions.274 PHMSA has further
issued an updated nationwide advisory
bulletin to all pipeline operators, and
solicited research proposals to
strengthen CO2 pipeline safety.275
Additionally, certain States have
authority delegated from the U.S.
Department of Transportation to
conduct safety inspections and enforce
State and Federal pipeline safety
regulations for intrastate CO2
pipelines.276 277 These CO2 pipeline
controls, in addition to the PHMSA
standards, ensure that captured CO2 will
be securely conveyed to a sequestration
site.
States are also directly involved in
siting proposed CO2 pipeline projects.
CO2 pipeline siting authorities,
landowner rights, and eminent domain
laws reside with the States and vary
from State to State. Pipeline developers
may secure rights-of-way for proposed
projects through voluntary agreements
with landowners; pipeline developers
272 See
generally 49 CFR 190–199.
‘‘PHMSA Announces New Safety
Measures to Protect Americans From Carbon
Dioxide Pipeline Failures After Satartia, MS Leak.’’
2022. https://www.phmsa.dot.gov/news/phmsaannounces-new-safety-measures-protect-americanscarbon-dioxide-pipeline-failures.
274 Consent Order, Denbury Gulf Coast Pipelines,
LLC, CPF No. 4–2022–017–NOPV (U.S. Dep’t of
Transp. Mar. 24, 2023). https://
primis.phmsa.dot.gov/comm/reports/enforce/
CaseDetail_cpf_
42022017NOPV.html?nocache=7208.
275 Ibid.
276 New Mexico Public Regulation Commission.
2023. Transportation Pipeline Safety. New Mexico
Public Regulation Commission, Bureau of Pipeline
Safety. https://www.nm-prc.org/transportation/
pipeline-safety.
277 Texas Railroad Commission. 2023. Oversight &
Safety Division. Texas Railroad Commission.
https://www.rrc.texas.gov/about-us/organizationand-activities/rrc-divisions/oversight-safetydivision.
273 PHMSA,
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may also secure rights-of-way through
eminent domain authority, which
typically accompanies siting permits
from State utility regulators with
jurisdiction over CO2 pipeline siting.278
Transportation of CO2 via pipeline is
the most viable and cost-effective
method at the scale needed for
sequestration of captured EGU CO2
emissions. However, CO2 can also be
liquified and transported via vessel (e.g.,
ship), highway (e.g., cargo tank, portable
tank), ship, or rail (e.g., tank cars) when
pipelines are not available. Liquefied
natural gas and liquefied petroleum
gases are already routinely transported
via ship at a large scale, and the
properties of liquified CO2 are not
significantly different.279 In fact, the
food and beverage as well as specialty
gas industries already have experience
transporting CO2 by rail.280 Highway
road tankers and rail transportation can
provide for the transport of smaller
quantities of CO2 and can be used in
tandem with other modes of
transportation to move CO2 captured
from an EGU.281
(6) Geologic Sequestration of CO2
(a) Security of Sequestration
Geologic sequestration (or storage),
which is the long-term containment of
a CO2 stream in subsurface geologic
formations, is well proven and broadly
available in many locations across the
U.S. Independent analyses of the
potential availability of geologic
sequestration capacity in the United
States have been conducted by DOE,
and the U.S. Geological Survey (USGS)
has also undertaken a comprehensive
assessment of geologic sequestration
resources in the U.S.282 283 Geologic
sequestration is based on a
demonstrated understanding of the
trapping processes that retain CO2 in the
subsurface; most importantly, geologic
sequestration occurs securely when the
CO2 is trapped under a low permeability
278 Congressional Research Service. 2022. Carbon
Dioxide Pipelines: Safety Issues, June 3, 2022.
https://crsreports.congress.gov/product/pdf/IN/
IN11944.
279 Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture
and Storage.
280 EU CCUS Projects Network. (2019). Briefing
on Carbon Dioxide Specifications for Transport.
https://www.ccusnetwork.eu/sites/default/files/
TG3_Briefing-CO2-Specifications-for-Transport.pdf.
281 Ibid.
282 U.S. DOE NETL, Carbon Storage Atlas, Fifth
Edition, September 2015. https://www.netl.doe.gov/
research/coal/carbon-storage/atlasv.
283 U.S. Geological Survey Geologic Carbon
Dioxide Storage Resources Assessment Team, 2013,
National assessment of geologic carbon dioxide
storage resources—Summary: U.S. Geological
Survey Factsheet 2013–3020. https://pubs.usgs.gov/
fs/2013/3020/.
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seal. There have been numerous efforts
demonstrating successful geologic
sequestration projects in the U.S. and
overseas, and the U.S. has developed a
detailed set of regulatory requirements
to ensure the security of sequestered
CO2.
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(i) Demonstration of Geologic
Sequestration
Existing project and regulatory
experience, along with other
information, indicate that geologic
sequestration is a viable long-term CO2
sequestration option. The effectiveness
of long-term trapping of CO2 has been
demonstrated by natural analogues in a
range of geologic settings where CO2 has
remained trapped for millions of
years.284 For example, CO2 has been
trapped for more than 65 million years
in the Jackson Dome, located near
Jackson, Mississippi.285 Other examples
of natural CO2 sources include the
Bravo Dome and the McElmo Dome in
New Mexico and Colorado,
respectively.286 These naturally
occurring sequestration sites
demonstrate the feasibility of containing
the large volumes of CO2 that may be
captured from fossil fuel-fired EGUs, as
these sites have held volumes of CO2
that are much larger than the volume of
CO2 expected to be captured from a
fossil fuel-fired EGU over the course of
its useful life. In 2010, the DOE
estimated CO2 reserves of 594 million
metric tons at Jackson Dome, 424
million metric tons at Bravo Dome, and
530 million metric tons at McElmo
Dome.287 Between 2000 and 2020, the
Department of Energy-sponsored
research totaling $1 billion to prove
carbon storage technologies and enable
large-scale deployment. Research
conducted through the Department of
Energy’s Regional Carbon Sequestration
Partnerships has demonstrated geologic
sequestration through a series of field
research projects that increased in scale
over time, injecting more than 11
million tons of CO2 with no indications
of negative impacts to either human
284 Holloway, S., et al. Natural Emissions of CO
2
from the Geosphere and their Bearing on the
Geological Storage of Carbon Dioxide. 2007. Energy
32: 1194–1201.
285 Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture
and Storage.
286 See K.J. Sathaye, M.A. Hesse, M. Cassidy, D.F.
Stockli, ‘‘Constraints on the magnitude and rate of
CO2 dissolution at Bravo Dome natural gas field.’’
Proceedings of the National Academy of Sciences
111, 15332–15337. 2014. and Kinder Morgan.
‘‘Carbon Dioxide (CO2) Operations; CO2 Supply.’’
https://www.kindermorgan.com/Operations/CO2/
Index.
287 DiPietro, P., et al. 2012. ‘‘A Note on Sources
of CO2 Supply for Enhanced-Oil Recovery
Operations.’’ SPE Economics & Management.
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health or the environment.288 Building
on this experience, the Department of
Energy launched the Carbon Storage
Assurance Facility Enterprise
(CarbonSAFE) Initiative in 2016 to
demonstrate how knowledge from the
Regional Carbon Sequestration
Partnerships can be applied to
commercial-scale safe storage. This
initiative is furthering the development
and refinement of technologies and
techniques critical to the
characterization of potential
sequestration sites greater than 50
million tons.289
Numerous additional saline facilities
are under development across the
United States. The Great Plains Synfuel
Plant currently captures 2 million
metric tons of CO2 per year, which is
used for enhanced oil recovery (EOR); a
planned addition of saline sequestration
for this facility is expected to increase
the amount captured and sequestered
(through both geologic sequestration
and EOR) to 3.5 million metric tons of
CO2 per year.290 The EPA is currently
reviewing Underground Injection
Control (UIC) Class VI geologic
sequestration well permit applications
for proposed sequestration sites in at
least seven States.291 292
Geologic sequestration has been
proven to be successful and safe in
projects internationally. The oldest
international facility has geologically
sequestered CO2 for over twenty years.
In Norway, facilities conduct offshore
sequestration under the Norwegian
continental shelf.293 In addition, the
Sleipner CO2 Storage facility in the
288 Safe Geologic Storage of Captured Carbon
Dioxide—DOE’s Carbon Storage R&D Program: Two
Decades in Review,’’ National Energy Technology
Laboratory, Pittsburgh, April 13, 2020. https://
www.netl.doe.gov/sites/default/files/
Safe%20Geologic%20Storage%20
of%20Captured%20Carbon%20Dioxide_
April%2015%202020_FINAL.pdf.
289 https://netl.doe.gov/carbon-management/
carbon-storage/carbonsafe.
290 Basin Electric Power Cooperative. ‘‘Great
Plains Synfuels Plant Potential to Be Largest CoalBased Carbon Capture and Storage Project to Use
Geologic Storage,’’ September 9, 2021. https://
www.basinelectric.com/News-Center/news-releases/
Great-Plains-Synfuels-Plant-potential-to-be-largestcoal-based-carbon-capture-and-storage-project-touse-geologic-storage.
291 UIC regulations for Class VI wells facilitate the
injection of CO2 for geologic sequestration while
protecting human health and the environment by
ensuring the protection of underground sources of
drinking water. The major components to be
included in UIC Class VI permits are detailed
further in section VII.F.3.b.iii.
292 U.S. EPA Class VI Underground Injection
Control (UIC) Class VI Wells Permitted by EPA as
of January 12, 2023. https://www.epa.gov/uic/classvi-wells-permitted-epa.
293 Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture
and Storage.
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North Sea, which began operations in
1996, injects around 1 million metric
tons of CO2 per year from natural gas
processing.294 The Snohvit CO2 Storage
facility in the Barents Sea, which began
operations in 2008, injects around 0.7
million metric tons of CO2 per year from
natural gas processing. The SaskPower
carbon capture and storage facility at
Boundary Dam Power Station in
Saskatchewan, Canada had, as of mid2022, captured 4.6 million tons of CO2
since it began operating in 2014.295
Other international sequestration
facilities in operation include Glacier
Gas Plant MCCS (Canada),296 Quest
(Canada), and Qatar LNG CCS (Qatar).
(ii) EPAct05-Assisted Geologic
Sequestration Projects
While the EPA is proposing that the
sequestration component of CCS is
adequately demonstrated based solely
on the other demonstrations of geologic
sequestration discussed in this
preamble, adequate demonstration of
geologic sequestration is further
corroborated by geologic sequestration
currently operational and planned
projects assisted by grants, loan
guarantees, and Federal tax credits for
‘‘clean coal technology’’ authorized by
the EPAct05. 80 FR 64541–42 (October
23, 2015).
Two saline sequestration facilities are
currently in operation in the U.S. and
several are under development.297 The
Illinois Industrial Carbon Capture and
Storage Project began injecting CO2 from
ethanol production into the Mount
Simon Sandstone in April 2017. The
project has the potential to store up to
5.5 million metric tons of CO2,298 and,
according to the facility’s report to the
EPA’s GHGRP, as of 2021, 2.5 million
metric tons of CO2 had been injected
294 Zapantis, Alex, Noora Al Amer, Ian
Havercroft, Ruth Ivory-Moore, Matt Steyn,
Xiaoliang Yang, Ruth Gebremedhin, et al. ‘‘Global
Status of CCS 2022.’’ Global CCS Institute, 2022.
https://status22.globalccsinstitute.com/2022-statusreport/introduction/.
295 Boundary Dam Carbon Capture Project.
https://www.saskpower.com/Our-Power-Future/
Infrastructure-Projects/Carbon-Capture-andStorage/Boundary-Dam-Carbon-Capture-Project.
296 Zapantis, Alex, Noora Al Amer, Ian
Havercroft, Ruth Ivory-Moore, Matt Steyn,
Xiaoliang Yang, Ruth Gebremedhin, et al. ‘‘Global
Status of CCS 2022.’’ Global CCS Institute, 2022.
https://status22.globalccsinstitute.com.
297 Zapantis, Alex, Noora Al Amer, Ian
Havercroft, Ruth Ivory-Moore, Matt Steyn,
Xiaoliang Yang, Ruth Gebremedhin, et al. ‘‘Global
Status of CCS 2022.’’ Global CCS Institute, 2022.
https://status22.globalccsinstitute.com/.
298 Archer Daniels Midland, Monitoring,
Reporting, and Verification Plan CCS#2, 2017.
https://www.epa.gov/sites/default/files/2017-01/
documents/adm_mrv_plan.pdf.
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into the saline reservoir.299 The Red
Trail Energy CCS facility in North
Dakota, which is the first saline
sequestration facility in the U.S. to
operate under a State-led regulatory
authority for carbon storage, began
injecting CO2 from ethanol production
in 2022.300 This project is expected to
inject a total of 3.7 million tons of CO2
over its lifetime.301
There are additional planned geologic
sequestration facilities across the United
States.302 Project Tundra, a saline
sequestration project planned at the
lignite-fired Milton R. Young Station in
North Dakota is projected to capture 4
million metric tons of CO2 annually.303
Finally, in Wyoming, Class VI permit
applications have been filed for a
proposed saline sequestration facility
located in Southwestern Wyoming. At
full capacity, the facility will
permanently store up to 5 million
metric tons of CO2 annually from
industrial facilities in the Nugget saline
sandstone reservoir.304
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(iii) Security of Geologic Sequestration
Regulatory oversight of geologic
sequestration is built upon an
understanding of the proven
mechanisms by which CO2 is retained
in geologic formations. These
mechanisms include (1) Structural and
stratigraphic trapping (generally
trapping below a low permeability
confining layer); (2) residual CO2
trapping (retention as an immobile
phase trapped in the pore spaces of the
geologic formation); (3) solubility
trapping (dissolution in the in situ
formation fluids); (4) mineral trapping
(reaction with the minerals in the
geologic formation and confining layer
299 EPA Greenhouse Gas Reporting Program. Data
reported as of August 12, 2022.
300 Zapantis, Alex, Noora Al Amer, Ian
Havercroft, Ruth Ivory-Moore, Matt Steyn,
Xiaoliang Yang, Ruth Gebremedhin, et al. ‘‘Global
Status of CCS 2022.’’ Global CCS Institute, 2022.
https://status22.globalccsinstitute.com.
301 North Dakota Industrial Commission, NDIC
Case No. 28848—Draft Permit Fact Sheet and
Storage Facility Permit Application.’’ https://
www.dmr.nd.gov/oilgas/GeoStorageofCO2.asp. This
injection well is permitted by North Dakota.
302 In addition, Denbury Resources injected CO
2
into a depleted oil and gas reservoir at a rate greater
than 1.2 million tons/year as part of a DOE
Southeast Regional Carbon Sequestration
Partnership study. The Texas Bureau of Economic
Geology tested a wide range of surface and
subsurface monitoring tools and approaches to
document sequestration efficiency and
sequestration permanence at the Cranfield oilfield
in Mississippi. Texas Bureau of Economic Geology,
‘‘Cranfield Log.’’ https://www.beg.utexas.edu/gccc/
research/cranfield.
303 Project Tundra. ‘‘Project Tundra.’’ https://
www.projecttundrand.com/.
304 Wyoming DEQ Class VI Permit Applications.
https://deq.wyoming.gov/water-quality/
groundwater/uic/class-vi/.
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to produce carbonate minerals); and (5)
preferential adsorption trapping
(adsorption onto organic matter in coal
and shale).
Based on the understanding
developed from natural analogs and
existing projects, the security of
sequestered CO2 is expected to increase
over time after injection ceases.305 This
is due to trapping mechanisms that
reduce CO2 mobility over time, e.g.,
physical CO2 trapping by a lowpermeability geologic seal or chemical
trapping by conversion or adsorption.306
In addition, site characterization, site
operations, and monitoring strategies as
required through the Underground
Injection Control (UIC) Program and the
GHGRP, discussed below, work in
combination to ensure security and
transparency.
The UIC Program, the GHGRP and
other regulatory requirements comprise
a detailed regulatory framework for
facilitating geologic sequestration in the
U.S., according to a 2021 report from the
Council on Environmental Quality
(CEQ). This framework is already in
place and capable of reviewing and
permitting CCS activities.307
This regulatory framework includes
the UIC Class VI well regulations,
promulgated under the authority of the
Safe Drinking Water Act (SDWA); and
the GHGRP, promulgated under the
authority of the CAA. The requirements
of the UIC and GHGRP programs work
together to ensure that sequestered CO2
will remain securely stored
underground. The UIC regulations
facilitate the injection of CO2 for
geologic sequestration while protecting
human health and the environment by
ensuring the protection of underground
sources of drinking water (USDW).
These regulations are built upon nearly
a half-century of Federal experience
regulating underground injection wells,
and many additional years of State UIC
program expertise. The IIJA established
a program to assist States and Tribal
regulatory authorities interested in Class
VI primacy.308 As the EPA considers
305 ‘‘Report of the Interagency Task Force on
Carbon Capture and Storage.’’ 2010. https://
www.osti.gov/servlets/purl/985209.
306 See, e.g., Intergovernmental Panel on Climate
Change. (2005). Special Report on Carbon Dioxide
Capture and Storage.
307 CEQ. ‘‘Council on Environmental Quality
Report to Congress on Carbon Capture, Utilization,
and Sequestration.’’ 2021. https://
www.whitehouse.gov/wp-content/uploads/2021/06/
CEQ-CCUS-Permitting-Report.pdf.
308 On April 27, 2023, the EPA Administrator
signed a proposed rule to approve the State of
Louisiana’s request to have primacy for UIC Class
VI wells within the state. Louisiana is the third state
to request primacy for UIC Class VI wells. https://
www.epa.gov/uic/primary-enforcement-authorityunderground-injection-control-program-0.
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Class VI primacy applications, it has
indicated that it will require approaches
that balance the use of geologic
sequestration with mitigation of impacts
on vulnerable communities. States and
Tribes applying for Class VI primacy are
asked to support communities by
implementing an inclusive public
participation process, considering
environmental justice impacts on
communities, enforcing Class VI
regulatory protections and incorporating
other mitigation measures.309
To complement the UIC regulations,
the EPA included in the GHGRP air-side
monitoring and reporting requirements
for CO2 capture, underground injection,
and geologic sequestration. These
requirements are included in 40 CFR
part 98, subpart RR, also referred to as
‘‘GHGRP subpart RR.’’
The GHGRP subpart RR requirements
provide the monitoring mechanisms to
identify, quantify, and address potential
leakage. The EPA designed them to
complement and build on UIC
monitoring and testing requirements.
Although the regulations for the UIC
program are designed to ensure
protection of USDWs from
endangerment, the practical effect of
these GHGRP subpart RR requirements
is that they also prevent releases of CO2
to the atmosphere.310
Major components to be included in
UIC Class VI permits are site
characterization, area of review,311
corrective action,312 well construction
and operation, testing and monitoring,
financial responsibility, post-injection
site care, well plugging, emergency and
remedial response, and site closure.
Reporting under GHGRP subpart RR is
required for, but not limited to, all
facilities that have received a UIC Class
VI permit for injection of CO2.313
GHGRP subpart RR requires facilities
309 EPA. Letter from the EPA Administrator
Michael S. Regan to U.S. State Governors. December
9, 2022. https://www.epa.gov/system/files/
documents/2022-12/
AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
310 In 2022, EPA proposed a new GHGRP subpart,
‘‘Geologic Sequestration of Carbon Dioxide with
Enhanced Oil Recovery (EOR) Using ISO 27916’’ (or
GHGRP subpart VV). For more information on
proposed GHGRP subpart VV, see section VII.K.2 of
this preamble.
311 Per 40 CFR 146.84(a), the area of review is the
region surrounding the geologic sequestration
project where USDWs may be endangered by the
injection activity. The area of review is delineated
using computational modeling that accounts for the
physical and chemical properties of all phases of
the injected carbon dioxide stream and is based on
available site characterization, monitoring, and
operational data.
312 UIC permitting authorities may require
corrective action for existing wells within the area
of review to ensure protection of underground
sources of drinking water.
313 40 CFR 98.440.
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meeting the source category definition
(40 CFR 98.440) for any well or group
of wells to report basic information on
the mass of CO2 received for injection;
develop and implement an EPAapproved monitoring, reporting, and
verification (MRV) plan; report the mass
of CO2 sequestered using a mass balance
approach; and report annual monitoring
activities.314 315 316 317 Although deep
subsurface monitoring is required for
UIC Class VI wells at 40 CFR 146.90 and
is the primary means of determining if
there are any leaks to a USDW, and is
generally effective in doing so, the
surface air and soil gas monitoring
employed under a GHGRP subpart RR
MRV Plan can be utilized in addition to
subsurface monitoring required under
40 CFR 146.90, if required by the UIC
Program Director under 40 CFR
146.90(h), to further ensure protection
of USDWs.318 The MRV plan includes
five major components: a delineation of
monitoring areas based on the CO2
plume location; an identification and
evaluation of the potential surface
leakage pathways and an assessment of
the likelihood, magnitude, and timing,
of surface leakage of CO2 through these
pathways; a strategy for detecting and
quantifying any surface leakage of CO2
in the event leakage occurs; an approach
for establishing the expected baselines
for monitoring CO2 surface leakage; and,
a summary of considerations made to
calculate site-specific variables for the
mass balance equation.319
Geologic sequestration efforts on
Federal lands as well as those efforts
that are directly supported with Federal
funds may need to comply with other
regulations, depending on the nature of
the project.320
(b) Broad Availability of Sequestration
Geologic sequestration potential for
CO2 is widespread and available
throughout the U.S. Nearly every State
in the U.S. has or is in close proximity
to formations with geologic
sequestration potential, including areas
offshore. These areas include deep
saline formation, unmineable coal
seams, and oil and gas reservoirs.
Moreover, the amount of storage
capacity can readily accommodate the
amount of CO2 for which sequestration
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314 40
CFR 98.446.
CFR 98.448.
316 40 CFR 98.446(f)(9) and (10).
317 40 CFR 98.446(f)(12).
318 See 75 FR 77263 (December 10, 2010).
319 40 CFR 98.448(a).
320 CEQ. ‘‘Council on Environmental Quality
Report to Congress on Carbon Capture, Utilization,
and Sequestration.’’ 2021. https://
www.whitehouse.gov/wp-content/uploads/2021/06/
CEQ-CCUS-Permitting-Report.pdf.
315 40
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could be required under this proposed
rule.
The DOE and the United States
Geological Survey (USGS) have
independently conducted preliminary
analyses of the availability and potential
CO2 sequestration resources in the U.S.
The DOE estimates are compiled in the
DOE’s National Carbon Sequestration
Database and Geographic Information
System (NATCARB) using volumetric
models and are published in its Carbon
Utilization and Sequestration Atlas
(NETL Atlas).321 The DOE estimates that
areas of the U.S. with appropriate
geology have a sequestration potential of
at least 2,400 billion to over 21,000
billion metric tons of CO2 in deep saline
formations, unmineable coal seams, and
oil and gas reservoirs.322 The USGS
assessment estimates a mean of 3,000
billion metric tons of subsurface CO2
sequestration potential across the
U.S.323
With respect to deep saline
formations, the DOE estimates a
sequestration potential of at least 2,200
billion metric tons of CO2 in these
formations in the U.S. At least 37 States
have geologic characteristics that are
amenable to deep saline sequestration,
and an additional 6 States are within
100 kilometers of potentially amenable
deep saline formations in either onshore
or offshore locations.324 325
Unmineable coal seams offer another
potential option for geologic
sequestration of CO2. Enhanced coalbed
methane recovery is the process of
injecting and storing CO2 in unmineable
coal seams to enhance methane
recovery. These operations take
advantage of the preferential chemical
affinity of coal for CO2 relative to the
methane that is naturally found on the
surfaces of coal. When CO2 is injected,
it is adsorbed to the coal surface and
releases methane that can then be
captured and produced. This process
effectively ‘‘locks’’ the CO2 to the coal,
321 U.S. DOE NETL, Carbon Storage Atlas, Fifth
Edition, September 2015. https://www.netl.doe.gov/
research/coal/carbon-storage/atlasv.
322 Ibid.
323 U.S. Geological Survey Geologic Carbon
Dioxide Storage Resources Assessment Team,
National assessment of geologic carbon dioxide
storage resources—Summary: U.S. Geological
Survey Factsheet 2013–3020. 2013. https://
pubs.usgs.gov/fs/2013/3020/.
324 Alaska has deep saline formation storage
capacity, geology amenable to EOR operations, and
potential geologic sequestration capacity in
unmineable coal seams.
325 The U.S. DOE NETL Carbon Storage Atlas,
Fifth Edition did not assess deep saline formation
potential for Alaska, Connecticut, Hawaii, Maine,
Massachusetts, Nevada, New Hampshire, Rhode
Island, and Vermont. We are assuming for purposes
of our analysis here that they do not have storage
potential in this type of formation.
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33297
where it remains stored. States with the
potential for sequestration in
unmineable coal seams include Iowa
and Missouri, which have little to no
saline sequestration potential and have
existing coal-fired EGUs. Unmineable
coal seams have a sequestration
potential of at least 54 billion metric
tons of CO2, or 2 percent of total
potential in the U.S., and are located in
22 States.326
The potential for CO2 sequestration in
unmineable coal seams has been
demonstrated in small-scale
demonstration projects, including the
Allison Unit pilot project in New
Mexico, which injected a total of
270,000 tons of CO2 over a six-year
period (1995–2001). Further, DOE
Regional Carbon Sequestration
Partnership projects have injected CO2
volumes in unmineable coal seams
ranging from 90 tons to 16,700 tons, and
completed site characterization,
injection, and post-injection monitoring
for sites.327 328 DOE has judged
unmineable coal seams worthy of
inclusion in the NETL Atlas.329
Although the large-scale injection of
CO2 in coal seams can lead to swelling
of coal, the literature also suggests that
there are available technologies and
techniques to compensate for the
resulting reduction in injectivity.330
Further, the reduced injectivity can be
anticipated and accommodated in sizing
and characterizing prospective
sequestration sites.
There is sufficient technical basis and
scientific evidence that depleted oil and
gas reservoirs represent another option
for geologic storage. The reservoir
characteristics of older fields are well
known as a result of exploration and
many years of hydrocarbon production
and, in many areas, infrastructure
326 U.S. DOE NETL, Carbon Storage Atlas, Fifth
Edition, September 2015. https://www.netl.doe.gov/
research/coal/carbon-storage/atlasv.
327 M. Godec et al., ‘‘CO -ECBM: A Review of its
2
Status and Global Potential,’’ Energy Procedia 63:
5858–5869 (2014). https://doi.org/10.1016/
j.egypro.2014.11.619.
328 N. Ripepi et al., ‘‘Central Appalachian Basin
Unconventional (Coal/Organic Shale) Reservoir
Small Scale CO2 Injection,’’ US DOE/NETL Annual
Carbon Storage and Oil and Natural Gas
Technologies Review Meeting (2017). https://
www.netl.doe.gov/sites/default/files/eventproceedings/2017/carbon-storage-oil-and-naturalgas/thur/Nino-Ripepi-VirginiaTech.DOE
Meeting.CoalShaleUpdate.8.3.2017.pdf.
329 U.S. DOE NETL, Carbon Storage Atlas, Fifth
Edition, September 2015. https://www.netl.doe.gov/
research/coal/carbon-storage/atlasv.
330 Xiachun Li & Zhi-Ming Fang, ‘‘Current Status
and Technical Challenges of CO2 Storage in Coal
Seams and Enhanced Coalbed Methane Recovery:
An Overview,’’ International Journal of Coal
Science & Technology, 93, 99 (2014) (suggesting
existing technologies that can be used to address
injectivity reduction in unmineable coal seams).
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already exists for CO2 transportation
and storage.331 Other types of geologic
formations such as organic rich shale
and basalt may also have the ability to
store CO2, and DOE is continuing to
evaluate their potential sequestration
capacity and efficacy.332
The EPA performed a geographic
availability analysis in which the
Agency examined areas of the country
with sequestration potential in deep
saline formations, unmineable coal
seams, and oil and gas reservoirs;
information on existing and probable,
planned or under study CO2 pipelines;
and areas within a 100-kilometer (km)
(62-mile) area of locations with
sequestration potential. The distance of
100 km is consistent with the
assumptions underlying the NETL cost
estimates for transporting CO2 by
pipeline.333 Overall, the EPA found that
there are 43 States containing areas
within 100 km from currently assessed
onshore or offshore storage resources in
deep saline formations, unmineable coal
seams, and depleted oil and gas
reservoirs. There are additional areas
that have not yet been assessed and may
provide additional infrastructure
capability.334
As described in the 2015 NSPS,
electricity demand in States that may
not have geologic sequestration sites
may be served by new generation,
including new base load combustion
turbines, built in nearby areas with
geologic sequestration, and this
electricity can be delivered through
331 Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture
and Storage.
332 Goodman, A., et al. ‘‘Methodology for
Assessing CO2 Storage Potential of Organic-Rich
Shale Formations.’’ Energy Procedia, 12th
International Conference on Greenhouse Gas
Control Technologies, GHGT–12, 63 (2014): 5178–
84. https://doi.org/10.1016/j.egypro.2014.11.548.
NETL DOE. ‘‘Big Sky Carbon Sequestration
Partnership.’’ https://netl.doe.gov/coal/carbonstorage/atlas/bscsp. Schaef, T., and McGrail, P.
‘‘Sequestration of CO2 in Basalt Formations.’’
Pacific Northwest National Laboratory, NETL, DOE,
2013. https://www.netl.doe.gov/sites/default/files/
event-proceedings/2013/carbon%20storage/8-00Schaef-58159-Task-1-082213.pdf.
333 Although a 100 km pipeline is used in this
analysis, this does not represent a technical
limitation, but rather a standardization used for
NETL cost estimates. As noted in the GHG
Mitigation Measures for Steam Generating Units
TSD, large pipelines connect CO2 sources in south
central Colorado, northeast New Mexico, and
Mississippi to Texas, Oklahoma, New Mexico,
Utah, and Louisiana. Additionally, as noted in
section VII.F.3.b.iii.(5) of this preamble, CO2 can by
transported via other modes such as ship, road
tanker, or rail tank cars.
334 GHG Mitigation Measures for Steam
Generating Units TSD, chapter 4.6.2. As discussed
in the TSD, geologic sequestration potential has not
yet been assessed for Connecticut, Hawaii, Nevada,
New Hampshire, Rhode Island, and Vermont, and
may provide additional infrastructure capability.
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transmission lines.335 This approach has
long been used in the electricity sector
because siting an EGU away from a load
center and transmitting the generation
long distances to the load area can be
less expensive and easier to permit than
siting the EGU near the load area.
In many of the areas without
reasonable access to geologic
sequestration, utilities, electric
cooperatives, and municipalities have a
history of joint ownership of electricity
generation outside the region or
contracting with electricity generation
in outside areas to meet demand. Some
of the areas are in Regional
Transmission Organizations (RTOs),336
which engage in planning as well as
balancing supply and demand in real
time throughout the RTO’s territory.
Accordingly, generating resources in
one part of the RTO can serve load in
other parts of the RTO, as well as load
outside of the RTO. For example, the
Prairie State Generating Plant, a 1,600MW coal-fired EGU in Illinois that is
currently considering retrofitting with
CCS, serves load in eight different States
from the Midwest to the midAtlantic.337 The Intermountain Power
Project, a coal-fired plant located in
Delta, Utah, that is converting to burn
hydrogen and natural gas, serves
customers in both Utah and
California.338
costing analysis see the GHG Mitigation
Measures for Steam Generating Units
TSD, which is available in the
rulemaking docket.
(B) Costs
The EPA has evaluated the costs of
CCS for new combined cycle units,
including the cost of installing and
operating CO2 capture equipment as
well as the costs of transport and
storage. The EPA has also compared the
costs of CCS for new combined cycle
units to other control costs, in part
derived from other rulemakings that the
EPA has determined to be cost
reasonable, and the costs are
comparable. Based on these analyses,
the EPA is proposing that the costs of
CCS for new combined cycle units are
reasonable. Certain elements of the
transport and storage costs are similar
for new combustion turbines and
existing steam generating units. In this
section, the EPA outlines these costs
and identifies the considerations
specific to new combustion turbines.
These costs are significantly reduced by
the IRC section 45Q tax credit. For
additional details on the EPA’s CCS
(1) Capture Costs
According to the NETL Fossil Energy
Baseline Report (October 2022 revision),
before accounting for the IRC section
45Q tax credit for sequestered CO2,
using a 90 percent capture amine-based
post-combustion CO2 capture system
increases the capital costs of a new
combined cycle EGU by 115 percent on
a $/kW basis, increases the heat rate by
13 percent, increases incremental
operating costs by 35 percent, and
derates the unit (i.e., decreases the
capacity available to generate useful
output) by 11 percent.339 For a base load
combustion turbine, carbon capture
increases the LCOE by 61 percent (an
increase of 27 $/MWh) and has an
estimated cost of $81/ton ($89/metric
ton) of onsite CO2 reduction.340 The
NETL costs are based on the use of a
second generation amine-based capture
system without exhaust gas
recirculation (EGR) and does not take
into account further cost reductions that
can be expected to occur as postcombustion capture systems are more
widely deployed.
The flue gas from NGCC EGUs differs
from that of a coal-fired EGUs in several
ways that impact the cost of CO2
capture. These include that the CO2
concentration is approximately onethird, the volumetric flow rate on a per
MW basis is larger, and the oxygen
concentration is approximately 3 times
that of a coal-fired EGU. The higher
amount of excess oxygen has the
potential to reduce the efficiency of
amine-based solvents that are
susceptible to oxidation. Other
important factors include that the lower
concentrations of CO2 reduce the
efficiency of the capture process and
that the larger volumetric flow rates
require a larger CO2 absorber, which
increases the capital cost of the capture
process. Exhaust gas recirculation
(EGR), also referred to as flue gas
recirculation (FGR), is a process that
addresses all of these issues. EGR
diverts some of the combustion turbine
exhaust gas back into the inlet stream
for the combustion turbine. Doing so
increases the CO2 concentration and
decreases the O2 concentration in the
335 This was described as ‘‘coal-by-wire’’ in the
2015 NSPS.
336 In this discussion, the term RTO indicates
both ISOs and RTOs.
337 https://prairiestateenergycampus.com/about/
ownership/.
338 https://www.ipautah.com/participantsservices-area/.
339 CCS reduced the net output of the NETL F
class combined cycle EGU from 726 MW to 645
MW.
340 These calculations use a service life of 30
years, an interest rate of 7.0 percent, a natural gas
price of $3.69/MMBtu, and a capacity factor of 65
percent. These costs do not include CO2 transport,
storage, or monitoring costs.
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exhaust stream and decreases the flow
rate, producing more favorable
conditions for CCS. One study found
that EGR can decrease the capital costs
of a combined cycle EGU with CCS by
6.4 percent, decrease the heat rate by 2.5
percent, decrease the LCOE by 3.4
percent, and decrease the overall CO2
capture costs by 11 percent relative to
a combined cycle EGU without EGR.341
Furthermore, the EPA expects that the
costs of capture systems will also
decrease over the rest of this decade and
continue to decrease afterwards. As part
of the plan to reduce the costs of CO2
capture, the DOE is funding multiple
projects to advance CCS technology.342
It should be noted that these projects are
EPAct05-assisted. The EPA proposes
that the rest of the information it has is
sufficient to support a determination
that the costs of capture systems are
reasonable, and that CCS is adequately
demonstrated. These EPAct05-assisted
projects provide additional confirmation
for this proposal because they will
contribute to improvements in the costs
of CCS. These include projects falling
under carbon capture research and
development, engineering-scale testing
of carbon capture technologies, and
engineering design studies for carbon
capture systems. The projects will aim
to capture CO2 from various point
sources, including NGCC units, cement
manufacturing plants, and iron and steel
plants. The general aim is to reach 95
percent or greater capture of CO2, to
lower the costs of the technologies, and
to prove feasible scalability at the
industrial scale for these new
technologies. Some projects are
designed solely to develop new carbon
capture technologies, while others are
designed to apply existing technologies
at the industrial scale. For a list of
notable projects, see section
VII.F.3.b.iii(A)(4)(b) of this preamble.
Although current post-combustion
CO2 capture projects have primarily
been based on amine capture systems,
there are multiple alternate capture
technologies in development—many of
which are funded through industry
research programs—that could have
341 Energy Procedia. (2014). Impact of exhaust gas
recirculation on combustion turbines. Energy and
economic analysis of the CO2 capture from flue gas
of combined cycle power plants. https://
www.sciencedirect.com/science/article/pii/
S1876610214001234.
342 The DOE has also previously funded FEED
studies for NGCC facilities. These include FEED
studies at existing NGCC facilities at Panda Energy
Fund in Texas, Elk Hills Power Plant in Kern
County, California, Deer Park Energy Center in
Texas, Delta Energy Center in Pittsburg, California,
and utilization of a Piperazine Advanced Stripper
(PZAS) process for CO2 capture conducted by The
University of Texas at Austin.
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reductions in capital, operating, and
auxiliary power requirements and could
reduce the cost of capture significantly
or improve performance. More
specifically, post combustion carbon
capture systems generally fall into one
of several categories: solvents, sorbents,
membranes, cryogenic, and molten
carbonate fuel cells 343 systems. It is
expected that as CCS infrastructure
increases, technologies from each of
these categories will become more
economically competitive. For example,
advancements in solvents, that are
potentially direct substitutes for current
amine-solvents, will reduce auxiliary
energy requirements and reduce both
operating and capital costs, and thereby,
increasing the economic
competitiveness of CCS.344 Planned
large-scale projects, pilot plants, and
research initiatives will also decrease
the capital and operating costs of future
CCS technologies.
In general, CCS costs have been
declining as carbon capture technology
advances.345 While the cost of capture
has been largely dependent on the
concentration of CO2 in the gas stream,
advancements in varying individual
CCS technologies tend to drive down
the cost of capture for other CCS
technologies. The increase in CCS
investment is already driving down the
costs of near-future CCS technologies.
The Global CCS Institute has tracked
publicly available information on
previously studied, executed, and
proposed CO2 capture projects.346 The
cost of CO2 capture from low-to-medium
partial pressure sources such as coalfired power generation has been
trending downward over the past
decade, and is projected to fall by 50
percent by 2025 compared to 2010. This
is driven by the familiar learningprocesses that accompany the
deployment of any industrial
technology. Studies of the cost of
capture and compression of CO2 from
343 Molten carbonate fuel cells are configured for
emissions capture through a process where the flue
gas from an EGU is routed through the molten
carbonate fuel cell that concentrates the CO2 as a
side reaction during the electric generation process
in the fuel cell. FuelCell Energy, Inc. (2018).
SureSource Capture. https://www.fuelcellenergy
.com/recovery-2/suresource-capture/.
344 DOE. Carbon Capture, Transport, & Storage.
Supply Chain Deep Dive Assessment. February 24,
2022. https://www.energy.gov/sites/default/files/
2022-02/Carbon%20Capture%20
Supply%20Chain%20Report%20-%20Final.pdf.
345 International Energy Agency (IEA) (2020).
CCUS in Clean Energy Transitions–A new era for
CCUS. https://www.iea.org/reports/ccus-in-cleanenergy-transitions/a-new-era-for-ccus.
346 Technology Readiness and Costs of CCS
(2021). Global CCS Institute. https://
www.globalccsinstitute.com/wp-content/uploads/
2021/03/Technology-Readiness-and-Costs-for-CCS2021-1.pdf.
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power stations completed ten years ago
averaged around $95/metric ton ($2020).
Comparable studies completed in 2018/
2019 estimated capture and
compression costs could fall to
approximately $50/metric ton CO2 by
2025. Current target pricing for
announced projects at coal-fired steam
generating units is approximately $40/
metric ton on average, compared to
Boundary Dam whose actual costs were
reported to be $105/metric ton, noting
that these estimates do not include the
impact of the 45Q tax credit as
enhanced by the IRA. Additionally, IEA
suggests this trend will continue in the
future as technology advancements
‘‘spill over’’ into other projects to reduce
costs.347 Policies in the IIJA and IRA are
further increasing investment in CCS
technology that can accelerate the pace
of innovation and deployment.
(2) CO2 Transport and Sequestration
Costs
NETL’s ‘‘Quality Guidelines for
Energy System Studies; Carbon Dioxide
Transport and Sequestration Costs in
NETL Studies’’ provides an estimation
of transport costs based on the CO2
Transport Cost Model.348 The CO2
Transport Cost Model estimates costs for
a single point-to-point pipeline.
Estimated costs reflect pipeline capital
costs, related capital expenditures, and
operations and maintenance costs.
NETL’s Quality Guidelines also
provide an estimate of sequestration
costs. These costs reflect the cost of site
screening and evaluation, permitting
and construction costs, the cost of
injection wells, the cost of injection
equipment, operation and maintenance
costs, pore volume acquisition expense,
and long-term liability protection.
Permitting and construction costs also
reflect the regulatory requirements of
the UIC Class VI program and GHGRP
subpart RR for geologic sequestration of
CO2 in deep saline formations. NETL
calculates these sequestration costs on
the basis of generic plant locations in
the Midwest, Texas, North Dakota, and
Montana, as described in the NETL
energy system studies that utilize the
coal found in Illinois, East Texas,
Williston, and Powder River basins.349
347 International Energy Agency (IEA) (2020).
CCUS in Clean Energy Transitions–CCUS
technology innovation. https://www.iea.org/reports/
ccus-in-clean-energy-transitions/a-new-era-for-ccus.
348 Grant, T., et al. ‘‘Quality Guidelines for Energy
System Studies; Carbon Dioxide Transport and
Storage Costs in NETL Studies.’’ National Energy
Technology Laboratory. 2019. https://
www.netl.doe.gov/energy-analysis/details?id=3743.
349 National Energy Technology Laboratory
(NETL), ‘‘FE/NETL CO2 Saline Storage Cost Model
(2017),’’ U.S. Department of Energy, DOE/NETL–
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There are two primary cost drivers for
a CO2 sequestration project: the rate of
injection of the CO2 into the reservoir
and the areal extent of the CO2 plume
in the reservoir. The rate of injection
depends, in part, on the thickness of the
reservoir and its permeability. Thick,
permeable reservoirs provide for better
injection and fewer injection wells. The
areal extent of the CO2 plume depends
on the sequestration capacity of the
reservoir. Thick, porous reservoirs with
a good sequestration coefficient will
present a small areal extent for the CO2
plume and have lower testing and
monitoring costs. NETL’s Quality
Guidelines model costs for a given
cumulative storage potential.350
In addition, provisions in the IIJA and
IRA are expected to significantly
increase the CO2 pipeline infrastructure
and development of sequestration sites,
which, in turn, are expected to result in
further cost reductions for the
application of CCS at a new combined
cycle EGUs. The IIJA establishes a new
Carbon Dioxide Transportation
Infrastructure Finance and Innovation
program to provide direct loans, loan
guarantees, and grants to CO2
infrastructure projects, such as
pipelines, rail transport, ships and
barges.351 The IIJA also establishes a
new Regional Direct Air Capture Hubs
program which includes funds to
support four large-scale, regional direct
air capture hubs and more broadly
support projects that could be
developed into a regional or interregional network to facilitate
sequestration or utilization.352 DOE is
additionally implementing IIJA section
40305 (Carbon Storage Validation and
Testing) through its CarbonSAFE
initiative, which aims to further
development of geographically
widespread, commercial-scale, safe
storage.353 The IRA increases and
extends the IRC section 45Q tax credit,
discussed next.
2018–1871, 30 September 2017. https://
netl.doe.gov/energy-analysis/details?id=2403.
350 Details on CO transportation and
2
sequestration costs can be found in the GHG
Mitigation Measures for Steam Generating Units
TSD.
351 Department of Energy. ‘‘Biden-Harris
Administration Announces $2 Billion from
Bipartisan Infrastructure Law to Finance Carbon
Dioxide Transportation Infrastructure.’’ (2022).
https://www.energy.gov/articles/biden-harrisadministration-announces-2-billion-bipartisaninfrastructure-law-finance.
352 Department of Energy. ‘‘Regional Direct Air
Capture Hubs.’’ (2022). https://www.energy.gov/
oced/regional-direct-air-capture-hubs.
353 For more information, see the NETL
announcement. https://www.netl.doe.gov/node/
12405.
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(3) IRC Section 45Q Tax Credit
In determining the cost of CCS, the
EPA is taking into account the tax credit
provided under IRC section 45Q, as
revised by the IRA. The tax credit is
available at $85/metric ton ($77/ton)
and offsets a significant portion of the
capture, transport, and sequestration
costs noted above.
It is reasonable to take the tax credit
into account because it reduces the cost
of the controls to the source, which has
a significant effect on the actual cost of
installing and operating CCS. In
addition, all sources that install CCS to
meet the requirements of these
proposals are eligible for the tax credit.
The legislative history of the IRA makes
clear that Congress was well aware that
the EPA may promulgate rulemaking
under CAA section 111 based on CCS
and explicitly stated that the EPA
should consider the tax credit to reduce
the costs of CCUS (i.e., CCS). Rep. Frank
Pallone, the chair of the House Energy
& Commerce Committee, included a
statement in the Congressional Record
when the House adopted the IRA in
which he explained: ‘‘The tax credit[ ]
for CCUS . . . included in this Act may
also figure into CAA Section 111 GHG
regulations for new and existing
industrial sources[.] . . . Congress
anticipates that EPA may consider
CCUS . . . as [a] candidate[ ] for BSER
for electric generating plants . . . .
Further, Congress anticipates that EPA
may consider the impact of the CCUS
. . . tax credit[ ] in lowering the costs of
[that] measure[ ].’’ 168 Cong. Rec. E879
(August 26, 2022) (statement of Rep.
Frank Pallone).
In the 2015 NSPS, in which the EPA
determined partial CCS to be the BSER
for GHGs from new coal-fired steam
generating EGUs, the EPA recognized
that the IRC section 45Q tax credit or
other tax incentives could factor into the
cost of the controls to the sources.
Specifically, the EPA calculated the cost
of partial CCS on the basis of cost
calculations from NETL, which
included ‘‘a range of assumptions
including the projected capital costs, the
cost of financing the project, the fixed
and variable O&M costs, the projected
fuel costs, and incorporation of any
incentives such as tax credits or
favorable financing that may be
available to the project developer.’’ 80
FR 64570 (October 23, 2015).354
Similarly, in the 2015 NSPS, the EPA
also recognized that revenues from
354 In fact, because of limits on the availability of
the IRC section 45Q tax credit at the time of the
2015 NSPS, the EPA did not factor it into the cost
calculation for partial CCS. 80 FR 64558–64
(October 23, 2015).
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utilizing captured CO2 for EOR would
reduce the cost of CCS to the sources,
although the EPA did not account for
potential EOR revenues for purposes of
determining the BSER. Id. at 64563–64.
In other rules, the EPA has considered
revenues from sale of the by-products of
emission controls to affect the costs of
the emission controls. For example, in
the 2016 Oil and Gas Methane Rule, the
EPA determined that certain control
requirements would reduce natural gas
leaks and therefore result in the
collection of recovered natural gas that
could be sold; and the EPA further
determined that revenues from the sale
of the recovered natural gas reduces the
cost of controls. See 81 FR 35824 (June
3, 2016). In a 2011 action concerning a
regional haze SIP, the EPA recognized
that a NOX control would alter the
chemical composition of fly ash that the
source had previously sold, so that it
could no longer be sold; and as a result,
the EPA further determined that the cost
of the NOX control should include the
foregone revenues from the fly ash sales.
76 FR 58570, 58603 (September 21,
2011). In the 2016 emission guidelines
for landfill gas from municipal solid
waste landfills, the EPA reduced the
costs of controls by accounting for
revenue from the sale of electricity
produced from the landfill gas collected
through the controls. 81 FR 59276,
19679 (August 29, 2016).
The amount of the IRC section 45Q
tax credit that the EPA is taking into
account is $85/metric ton for CO2 that
is captured and geologically stored. This
amount is available to the affected
source as long as it meets the prevailing
wage and apprenticeship requirements
of IRC section 45Q(h)(3)–(4). The
legislative history to the IRA specifically
stated that when the EPA considers CCS
as the BSER for GHG emissions from
industrial sources in CAA section 111
rulemaking, the EPA should determine
the cost of CCS by assuming that the
sources would meet those prevailing
wage and apprenticeship requirements.
168 Cong. Rec. E879 (August 26, 2022)
(statement of Rep. Frank Pallone). If
prevailing wage and apprenticeship
requirements are not met, the value of
the IRC section 45Q tax credit falls to
$17/metric ton. The substantially higher
credit available provides a considerable
incentive to meeting the prevailing wage
and apprenticeship requirements.
Therefore, the EPA assumes that
investors maximize the value of the IRC
section 45Q tax credit at $85/metric ton
by meeting those requirements.
(4) Total Costs of CCS
In a typical NSPS analysis, the EPA
amortizes costs over the expected life of
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the affected facility and assumes
constant revenue and expenses over that
period of time. This analysis is different
because the IRC section 45Q tax credits
for the sequestration of CO2 are only
available for combustion turbines that
commence construction by the end of
2032 and are available for 12 years. The
construction timeframe is within the
NSPS review cycle, and the EPA has
determined that it is appropriate to
include the credits as part of the CCS
costing analysis. Since the duration of
the tax credit is less than the expected
life of a new base load combustion
turbine, the EPA conducted the costing
analysis assuming a 30-year useful life
and a separate analysis assuming the
capital costs are amortized over a 12year period. For the 30-year analysis,
the EPA used a discount rate of 3.8
percent for the 45Q tax credits to get an
effective 30-year value of $41/ton.
Even considering that the IRC section
45Q tax credits are currently available
for only 12 years and would, therefore,
only offset costs for a portion of a new
NGCC turbine’s expected operating life,
the current overall CO2 abatement costs
of CCS of a 90 percent capture aminebased post combustion capture system,
accounting for the tax credit, are $44/
ton ($49/metric ton) and the increase in
the LCOE is $15/MWh.355 These costs
assume a stable 30-year operating life,
transport, storage, and monitoring costs
of $10/metric ton, and do not include
any revenues from sale of the CO2
following the 12-year period when the
IRC section 45Q tax credit is available.
An alternate costing approach is to
assume all capital costs are amortized
during the 12-year period when tax
credits are available. These tax credits
are a significant source of revenue and
would lower the incremental generating
costs of the unit. Therefore, under the
12-year costing approach the EPA
increased the assumed annual capacity
factor from 65 to 75 percent. The 12year CO2 abatement costs are $19/ton
($21/metric ton) and the increase in the
LCOE is $6/MWh. These costs are for a
combined cycle unit with a base load
rating of 4,600 MMBtu/h with an output
of approximately 700 MW.356 These
costs could be higher for small units and
lower for larger units. For additional
details on the CCS costing analysis see
355 The EPA used 3.76 percent discount factor to
levelized the 45Q tax credits to an annual value of
$45.4/metric ton. These calculations use a service
life of 30 years, an interest rate of 7.0 percent, a
natural gas price of $3.69/MMBtu, a capacity factor
of 65 percent, and a transport, storage, and
monitoring cost of $10/metric ton.
356 The output of the model combined cycle EGU
without CCS is 726 MW. The auxiliary load of CCS
reduces the net out to 645 MW.
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the GHG Mitigation Measures—Carbon
Capture and Storage for Combustion
Turbines TSD, which is available in the
rulemaking docket. The EPA is
soliciting comment on whether the CCS
transport, storage, and monitoring costs
are appropriate for determining the
BSER costs for combustion turbines.
(5) Comparison to Other Costs of
Controls
In assessing cost reasonableness for
the BSER determination for this rule,
the EPA compares the costs of GHG
control measures to control costs that
the EPA has previously determined to
be reasonable. This includes
comparison to the costs of controls at
EGUs for other air pollutants, such as
SO2 and NOX, and costs of controls for
GHGs in other industries. The costs
presented in this section of the
preamble are in 2019 dollars.357
At different times, many coal-fired
steam generating units have been
required to install and operate flue gas
desulfurization (FGD) equipment—that
is, wet or dry scrubbers—to reduce their
SO2 emissions or SCR to reduce their
NOX emissions. The EPA compares
these control costs across technologies—
steam generating units and combustion
turbines—because these costs are
indicative of what is reasonable for the
power sector in general. The fact that
EPA required these controls in prior
rules, and that many EGUs subsequently
installed and operated these controls,
provide evidence that these costs are
reasonable, and as a result, the cost of
these controls provides a benchmark to
assess the reasonableness of the costs of
the controls in this preamble. In the
2011 Cross-State Air Pollution Rule
(CSAPR) (76 FR 48208; August 8, 2011),
the EPA estimated the annualized costs
to install and operate wet FGD retrofits
on existing coal-fired steam generating
units. Using those same cost equations
and assumptions (i.e., a 63 percent
annual capacity factor—the average
value in 2011) for retrofitting wet FGD
on a representative 700 to 300 MW coalfired steam generating unit results in
annualized costs of $14.80 to $18.50/
MWh of generation, respectively.358 In
the March 15, 2023 Good Neighbor Plan
for the 2015 Ozone NAAQs (2023 GNP),
357 The EPA used the NETL Baseline Report costs
directly for the combustion turbine model plant
BSER analysis. Even though these costs are in 2018
dollars, the adjustment to 2019 dollars (1.018 using
the U.S. GDP Implicit Price Deflator) is well within
the uncertainty range of the report and the minor
adjustment would not impact the EPA’s BSER
determination.
358 For additional details, see https://
www.epa.gov/power-sector-modeling/
documentation-integrated-planning-model-ipmbase-case-v410.
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the EPA estimated the annualized costs
to install and operate SCR retrofits on
existing coal-fired steam generating
units. Using those same cost equations
and assumptions (including a 56
percent annual capacity factor—a
representative value in that rulemaking)
to retrofit SCR on a representative 700
to 300 MW coal-fired steam generating
unit results in annualized costs of
$10.60 to $11.80/MWh of generation,
respectively.359 Finally, using current
cost equations and assumptions
(including a 50 percent annual capacity
factor, and otherwise consistent with
the 2023 GNP) for retrofitting wet FGD
on a representative 700 to 300 MW coalfired steam generating unit results in
annualized costs of $23.20 to $29.00/
MWh of generation, respectively.360
Finally, the EPA compares costs to the
costs for GHG controls in rulemakings
for other industries. In the 2016 NSPS
regulating GHGs for the Crude Oil and
Natural Gas source category, the EPA
found the costs of reducing methane
emissions of $2,447/ton to be reasonable
(80 FR 56627; September 18, 2015).361
Converted to a ton of CO2e reduced
basis, those costs are expressed as $98/
ton of CO2e reduced.362
The costs for CCS applied to a
representative new base load stationary
combustion turbine EGU are generally
lower than the above-described costs,
which supports the EPA’s view that the
CCS costs are reasonable. The CCS costs
range from $6 to $15/MWh of generation
or $19 to $44/ton of CO2 reduced
(depending on the amortization period).
(C) Non-Air Quality Health and
Environmental Impact and Energy
Requirements
In this section of the preamble, the
EPA explains that it does not expect the
use of CCS for new combined cycle
combustion turbines to have
unreasonable adverse consequences
related to non-air quality health and
environmental impact and energy
requirements to combined cycle
combustion turbines. The EPA first
discusses energy requirements, and then
considers non-GHG emissions impacts
359 For additional details, see https://
www.epa.gov/system/files/documents/2023–01/
Updated%20Summer%202021%20Reference%20
Case%20Incremental%20Documentation%20
for%20the%202015%20Ozone%20NAAQS%20
Actions_0.pdf.
360 Ibid.
361 The EPA finalized the 2016 NSPS GHGs for
the Crude Oil and Natural Gas source category at
81 FR 35824 (June 3, 2016). The EPA included cost
information in the proposed rulemaking, at 80 FR
56627 (September 18, 2015).
362 Based on the 100-year global warming
potential for methane of 25 used in the GHGRP (40
CFR 98 Subpart A, Table A–1).
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and water use impacts, resulting from
the capture, transport, and sequestration
of CO2.
With respect to energy requirements,
including a 90 percent or greater carbon
capture system in the design of a new
NGCC will increase the parasitic/
auxiliary energy demand and reduce its
net power output. A utility that wants
to construct an NGCC unit to provide
500 MWe-net of power could build a
500 MWe-net plant knowing that it will
be de-rated by 11 percent (to a 444
MWe-net plant) with the installation
and operation of CCS. In the alternative,
the project developer could build a
larger 563 MWe-net NGCC plant
knowing that, with the installation of
the carbon capture system, the unit will
still be able to provide 500 MWe-net of
power to the grid. Although the use of
CCS imposes additional energy
demands on the affected units, those
units are able to accommodate those
demands by scaling larger, as needed.
Regardless of whether a unit is scaled
larger, the installation and operation of
CCS itself does not impact the unit’s
potential-to-emit any of the criteria or
hazardous air pollutants. In other
words, a new base load stationary
combustion turbine EGU constructed
using highly efficient generation (the
first component of the BSER) would not
see an increase in emissions of criteria
or hazardous air pollutants as a direct
result of installing and using 90 percent
or greater CO2 capture CCS to meet the
second phase standard of
performance.363
Scaling a unit larger to provide heat
and power to the CO2 capture
equipment would have the potential to
increase non-GHG air emissions.
However, most of them would be
mitigated or adequately controlled by
equipment needed to meet other CAA
requirements. In general, the emission
rates and flue gas concentrations of most
non-GHG pollutants from the
combustion of natural gas in stationary
combustion turbines are relatively low
compared to the combustion of oil or
coal in boilers. As such, it is not
necessary to use an FGD to pretreat the
flue gas prior to CO2 removal in the CO2
scrubber column. The sulfur content of
natural gas is low relative to oil or coal
and resulting SO2 emissions are
therefore also relatively low. Similarly,
PM emissions from combustion of
natural gas in a combustion turbine are
relatively low. Furthermore, the high
combustion efficiency of combustion
363 While the absolute onsite mass emissions
would not increase from the second component of
the BSER, the emissions rate on a lb/MWh-net basis
would increase by 13 percent.
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turbines results in relatively low
organic-HAP emissions, and there are
likely few, if any, metallic-HAP
emissions from combustion of natural
gas. Additionally, combustion turbines
at major sources of HAP are subject to
the stationary combustion turbine
NESHAP, which includes limits for
formaldehyde emissions for new
sources that may require installation of
an oxidation catalyst (87 FR 13183;
March 9, 2022). Regarding NOX
emissions, in most cases, the
combustion turbines in new combined
cycle units will be equipped with lowNOX burners to control flame
temperature and reduce NOX formation.
Additionally, new combined cycle units
may be subject to major NSR
requirements for NOX emissions, which
may necessitate the installation of SCR
to comply with a control technology
determination by the permitting
authority. See section XIII.A of this
preamble for additional details
regarding implications for the NSR
program. Although NOX concentrations
may be controlled by SCR, for some
amine solvents NOX in the postcombustion flue gas can react in the CO2
scrubber to form nitrosamines. A
conventional multistage water wash or
acid wash and a mist eliminator at the
exit of the CO2 scrubber is effective at
removal of gaseous amine and amine
degradation products (e.g., nitrosamine)
emissions.364 365
Stakeholders have shared with the
EPA concerns about the safety of CCS
projects and that historically
disadvantaged and overburdened
communities may bear a
disproportionate environmental burden
associated with CCS projects.366 For the
reasons noted above, the EPA does not
expect CCS projects to result in
uncontrolled or substantial increases in
emissions of non-GHG air pollutants
from new combustion turbines. The
EPA is committed to working with its
fellow agencies to foster meaningful
364 Sharma, S., Azzi, M., ‘‘A critical review of
existing strategies for emission control in the
monoethanolamine-based carbon capture process
and some recommendations for improved
strategies,’’ Fuel, 121, 178 (2014).
365 Mertens, J., et al., ‘‘Understanding
ethanolamine (MEA) and ammonia emissions from
amine-based post combustion carbon capture:
Lessons learned from field tests,’’ Int’l J. of GHG
Control, 13, 72 (2013).
366 In outreach with potentially vulnerable
communities, residents have voiced two primary
concerns. First, there is the concern that their
communities have experienced historically
disproportionate burdens from the environmental
impacts of energy production, and second, that as
the sector evolves to use new technologies such as
CCS and hydrogen, they may continue to face
disproportionate burden. This is discussed further
in section XIV.E of this preamble.
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engagement with communities and
protect communities from pollution.
This can be facilitated through the
existing detailed regulatory framework
for CCS projects and further supported
through robust and meaningful public
engagement early in the technological
deployment process. Furthermore, the
EPA is soliciting comment on additional
ways that may be identified to
responsibly advance the deployment of
CCS and ensure meaningful engagement
with local communities.
The use of water for cooling presents
an additional issue. Due to their
relatively high efficiency, combined
cycle EGUs have relatively small
cooling requirements compared to other
base load EGUs. According to NETL, a
combined cycle EGU without CCS
requires 190 gallons of cooling water per
MWh of electricity. CCS increases the
cooling water requirements due both to
the decreased efficiency and the cooling
requirements for the CCS process to 290
gallons per MWh, an increase of about
50 percent. However, because NGCC
units require limited amounts of cooling
water, the absolute amount of increase
in cooling water required due to use of
CCS does not present unsurmountable
concerns. In addition, many combined
cycle EGUs currently use dry cooling
technologies and the use of dry or
hybrid cooling technologies for the CO2
capture process would reduce the need
for additional cooling water. Therefore,
the EPA is proposing that the additional
cooling water requirements from CCS
are reasonable.
As noted in section VII.F.3 of this
preamble, PHMSA oversight of
supercritical CO2 pipeline safety
protects against environmental release
during transport and UIC Class VI
regulations under the SDWA in tandem
with GHGRP requirements ensure the
protection of USDWs and the security of
geologic sequestration.
(D) Impacts on the Energy Sector
The EPA does not believe that
determining CCS to be BSER for base
load units will cause reliability
concerns, for two independent reasons.
First, the EPA is proposing that the costs
of CCS are reasonable and comparable
to other controls the electric power
industry has used without significant
effects on reliability. Second, while CCS
is adequately demonstrated and cost
reasonable, the current proposal allows
companies that want to build a base
load combined cycle combustion
turbine a second pathway to meet its
requirements: building a unit that cofires low-GHG hydrogen in the
appropriate amount. In fact, companies
are pursing both of these options,
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including units with CCS, in various
stages of development. The EPA also
expects there to be considerable interest
in building intermediate load and
peaker units to meet market demand for
dispatchable generation. Indeed, the
portion of the combustion turbine fleet
that is operating at base load is
declining as shown in the EPA’s
reference case modeling (post-IRA 2022
reference case, see section IV.F of the
preamble). Finally, combined cycle
units are only one of many options that
companies have to build new
generation. For instance, in 2023,
combined cycle units are only expected
to represent 14 percent of all new
generating capacity built in the US and
only a portion of that is natural gas
combined cycle capacity.367 Finally,
several companies have recently
announced plans to move away from
new combined cycle projects in favor of
more non-base load combustion
turbines, renewables, and battery
storage. For example, Xcel recently
announced plans to build new
renewable power generation instead of
the combined cycle plant it had initially
proposed to replace the retiring Sherco
coal-fired plant.368 For these reasons,
determining CCS to be the BSER for
base load units will not cause reliability
concerns.
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(E) Extent of Reductions in CO2
Emissions
Designating CCS as a component of
the BSER for certain base load
combustion turbine EGUs prevents large
amounts of CO2 emissions. For example,
a new base load combined cycle EGU
without CCS could be expected to emit
45 million tons of CO2 over its operating
life. Use of CCS would avoid the release
of nearly 41 million tons of CO2 over the
operating life of the combined cycle
EGU. However, due to the auxiliary/
parasitic energy requirements of the
carbon capture system, capturing 90
percent of the CO2 does not result in a
corresponding 90 percent reduction in
CO2 emissions. According to the NETL
baseline report, adding a 90 percent CO2
capture system increases the EGU’s
gross heat rate by 7 percent and the
unit’s net heat rate by 13 percent. Since
more fuel would be consumed in the
CCS case, the gross and net emissions
rates are reduced by 89.3 percent and
88.7 percent respectively.
367 https://www.eia.gov/todayinenergy/
detail.php?id=55419.
368 https://cubminnesota.org/xcel-is-no-longerpursuing-gas-power-plant-proposes-morerenewable-power/.
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(F) Promotion of the Development and
Implementation of Technology
The EPA also considered whether
determining CCS to be a component of
the BSER for new base load combustion
turbines will advance the technological
development of CCS and concluded that
this factor supports our BSER
determination. A standard of
performance based on highly efficient
generation in combination with the use
of CCS—combined with the availability
of 45Q tax credits and investments in
supporting CCS infrastructure from the
IIJA—should incentivize additional use
of CCS, which should incentivize cost
reductions through the development
and use of better performing solvents or
sorbents. While solvent-based CO2
capture has been adequately
demonstrated at the commercial scale, a
determination that a component of the
BSER for new base load stationary
combustion turbine (and long term coalfired steam generating units) is the use
of CCS will also likely incentivize the
deployment of alternative CO2 capture
techniques at scale. Moreover, as noted
above, the cost of CCS has fallen in
recent years and is expected to continue
to fall; and further implementation of
the technology can be expected to lead
to additional cost reductions, due to
added experience and cost efficiencies
through scaling.
The experience gained by utilizing
CCS with stationary combustion turbine
EGUs, with their lower CO2 flue gas
concentration relative to other industrial
sources such as coal-fired EGUs, will
advance capture technology with other
lower CO2 concentration sources. The
EIA 2023 Annual Energy Outlook
projects that almost 862 billion kWh of
electricity will be generated from
natural gas-fired sources in 2040.369
Much of that generation is projected to
come from existing combined cycle
EGUs and further development of
carbon capture technologies could
facilitate increased retrofitting of those
EGUs.
(G) Proposed BSER
The Agency proposes that for new
natural gas-fired base load combustion
turbines, an efficient stationary
combined cycle combustion turbine
utilizing CCS at a capture rate of 90
percent, beginning in 2035, qualifies as
the BSER because it is adequately
demonstrated; it entails reasonable costs
taking account of the IRC section 45Q
tax credit, it achieves significant
emission reductions, and it does not
have significant adverse non-air quality
369 Does not include 114 billion kilowatt hours
from natural gas-fired CHP projected in AEO 2023.
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33303
health or environmental impacts or
significant adverse energy requirements,
including on a nationwide basis. The
fact that it promotes useful technology
provides additional, although not
essential, support for this proposal.
iv. Low-GHG Hydrogen
As discussed, the EPA is proposing
two BSER pathways that new stationary
combustion turbines may take—one that
is based on the use of 90 percent CCS
and a separate BSER pathway based
upon co-firing low-GHG hydrogen. In
this section, the EPA explains why it
believes that CCS could form the basis
of the BSER. In section VII.F.3.c, we
discuss why we believe burning lowGHG hydrogen could also form the basis
of the BSER.
v. Basis for Proposal of a Second
Component of BSER, Based on CCS, in
2035
When considering whether a
technology should be BSER, the EPA
must consider both unit level and
nationwide questions. At the unit level,
the EPA must ask whether the
technology is proven, can be
implemented at reasonable cost, and
achieves emission reductions without
causing other significant environmental
or energy issues. With regard to CCS at
the unit level, the EPA believes there is
ample evidence to conclude that it is
available and cost reasonable (with the
45Q tax credits) today, and that a wellsited individual new unit could meet
the standard of performance based on
the application of 90 percent CCS on the
startup date of the facility. However,
when looking at the technology from a
nationwide basis, the EPA must take
larger system-wide impacts into
consideration. For CCS, this includes
questions about the development and
availability of infrastructure for
transportation and storage 370 as well as
considerations related to the lead time
needed to scale manufacturing and the
installation of carbon capture
equipment to meet the amount of
capacity potentially subject to this
proposed BSER (in addition to meeting
IRA-driven demand for CCS in other
sectors).
The EPA considered establishing the
start of phase 2 of the standard of
performance as early as 2030 on the
assumption that projects that commence
construction in the period immediately
following this rulemaking will need at
least that amount of time to implement
the BSER. However, the EPA is also
370 For further information on timing associated
with CO2 transport and storage design, engineering,
and construction, see GHG Mitigation Measures for
Steam Generating Units TSD, chapter 4.7.1.
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lotter on DSK11XQN23PROD with PROPOSALS2
proposing to determine that the BSER
for long-term coal-fired steam generating
units (those that will be in operation
beyond 2040) is the use of 90 percent
capture CCS and that the associated
standard of performance for those units
is effective beginning in 2030. The EPA
is also aware that a significant number
of new base load combined cycle
stationary combustion turbines are
projected to be constructed by 2030, and
that there are other, non-power sector
industries that will also be pursuing
implementation of CCS in that
timeframe. The EPA believes that while
CCS poses low supply chain risk due to
the required infrastructure relying on
common and readily available raw
materials and CCS infrastructure can be
supplied in large part by domestic
components,371 the deployment of CCS
infrastructure, including the demand for
the manufacturing and installation of
CCS equipment and CO2 pipeline
infrastructure, and the demand for
conducting sequestration site
characterization and permitting, should
be prioritized for the higher GHGemitting fleet of existing long-term coalfired steam generating units. The EPA
also understands that many utilities and
power generating companies are trying
to assess their near-term and long-term
base load generating needs and may
have useful information to provide to
the record that would help to assess the
demand for CCS. Therefore, in
consideration of these factors, the EPA
is proposing that phase 2 of the standard
of performance begin in 2035 to ensure
achievability of the standard. The EPA
also recognizes that commenters may
have more information about
implementing CCS on a broader scale
that would help to assess whether 2030
or 2035 (or somewhere in between)
would be an appropriate start date for
phase 2 of the standards of performance
that are based, in part, on the use of
CCS. For this reason, the EPA solicits
comment on whether the compliance
date for phase 2 of the standards of
performance should begin earlier than
2035, including as early as 2030.
c. BSER for Base Load Subcategory of
Combustion Turbines Adopting the
Low-GHG Hydrogen Co-Firing Pathway
and Intermediate Load Subcategory—
Second and Third Components
This section describes the second and
third components of the EPA’s proposed
BSER for the subcategory of base load
371 U.S. Department of Energy, Achieving
American Leadership in the Carbon Capture,
Transport, and Storage Supply Chain, March 23,
2022 (DOE/OP–0001–1). https://www.energy.gov/
sites/default/files/2022-03/Carbon%20
Capture%20factsheet.pdf.
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combustion turbines that are adopting
the low-GHG hydrogen co-firing
pathway and the second component for
combustion turbines in the intermediate
load subcategory. For both
subcategories, the EPA is proposing that
the second component of the BSER is
co-firing 30 percent (by volume) lowGHG hydrogen and that sources meet a
corresponding standard of performance
beginning in 2032. For base load
combustion turbines in this subcategory
of sources that adopt the low-GHG
hydrogen co-firing pathway, the EPA is
proposing that the third component of
the BSER is co-firing 96 percent (by
volume) low-GHG hydrogen and that
sources meet a corresponding standard
of performance beginning in 2038. The
EPA is also soliciting comment on
whether, in lieu of providing a
subcategory for base load combustion
turbines that adopt the low-GHG
hydrogen co-firing pathway, a single
BSER for base load combustion turbines
should be selected based on application
of CCS with 90 percent capture—which
could also be met by co-firing 96
percent (by volume) low-GHG hydrogen.
The first part of this section is a
background discussion concerning
several key aspects of the hydrogen
industry as it is currently developing. At
the outset, the EPA summarizes the
activities of some power producers and
turbine manufacturers to develop and
demonstrate hydrogen co-firing as a
viable decarbonization technology for
the power sector. The EPA then
discusses the GHG emissions
performance of stationary combustion
turbines when hydrogen is used as a
fuel. This discussion includes the
different methods of production and the
associated GHG emissions for each. The
second part of this section describes the
proposed second component of the
BSER, which is co-firing 30 percent (by
volume) low-GHG hydrogen and the
third component of the BSER, which,
for certain units, is co-firing 96 percent
(by volume) low-GHG hydrogen.
The EPA is also proposing a
definition of low-GHG hydrogen. The
EPA is proposing that hydrogen
qualifies as low-GHG hydrogen if it is
produced through a process that results
in a GHG emission rate of less than 0.45
kilograms of CO2 equivalent per
kilogram of hydrogen (kg CO2e/kg H2)
on a well-to-gate basis consistent with
the system boundary established in IRC
section 45V (Credit for Production of
Clean Hydrogen) of the IRA. Hydrogen
produced by electrolysis (splitting water
into hydrogen and oxygen) using nonemitting energy sources such as solar,
wind, nuclear, and hydroelectric power,
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can produce hydrogen with carbon
intensities lower than 0.45 kg CO2e/kg
H2, which could qualify as low-GHG
hydrogen for the purposes of this
proposed BSER.372 However, the EPA is
also soliciting comment on whether a
specific definition of low-GHG
hydrogen should be included in the
final rule. The third part of this section
explains why the EPA proposes that cofiring 30 percent (by volume) low-GHG
hydrogen qualifies as a component of
the BSER. Co-firing 30 percent (by
volume) hydrogen is technically feasible
and well-demonstrated in new
combustion turbines, it will be
supported by an adequate supply of
hydrogen by 2032, it will be of
reasonable cost, it will ensure
reductions of GHG emissions, and it
will be consistent with the other BSER
factors. The EPA also includes in this
section an explanation of why the
Agency thinks that highly efficient
generating technology combined with
co-firing only low-GHG hydrogen is the
‘‘best’’ system of emission reduction,
taking into account the statutory
considerations. This third part of this
section also explains why the EPA
proposes that co-firing 96 percent (by
volume) low-GHG hydrogen qualifies as
a third component of the BSER for base
load combustion turbines that are
subject to a second phase standard of
performance based on co-firing 30
percent (by volume) low-GHG hydrogen.
The EPA proposes that co-firing 96
percent (by volume) low-GHG hydrogen
is technically feasible and welldemonstrated in new combustion
turbines, it will be supported by an
adequate supply of low-GHG hydrogen
by 2038, it will be of reasonable cost, it
will ensure reductions of GHG
emissions, and it will be consistent with
the other BSER factors.
i. Lower Emitting Fuels
The EPA is not proposing lower
emitting fuels as the second component
of BSER for base load or intermediate
load combustion turbines because it
would achieve few emission reductions
compared to co-firing low-GHG
hydrogen.
ii. Highly Efficient Generation
For the reasons described above, the
EPA is proposing that highly efficient
generation technology in combination
with best operating and maintenance
practices continues to be a component
of the BSER that is reflected in the
372 U.S. Department of Energy (DOE). Pathways to
Commercial Liftoff: Clean Hydrogen, March 2023.
https://www.energy.gov/articles/doe-releases-newreports-pathways-commercial-liftoff-accelerateclean-energy-technologies.
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second phase of the standards of
performance for base load turbines that
are adopting the low-GHG hydrogen cofiring pathway and intermediate load
combustion turbines. Highly efficient
generation reduces fuel use as well as
the absolute amount and cost of lowGHG hydrogen that would be required
to comply with the second phase
standards.
iii. CCS
lotter on DSK11XQN23PROD with PROPOSALS2
The EPA is not proposing the use of
CCS as a component of the BSER for
base load turbines combusting that are
adopting low-GHG hydrogen co-firing or
intermediate load combustion turbines.
As described previously, simple cycle
technology is the most common
combustion turbine technology
applicable to the intermediate load
subcategory and the Agency is limiting
consideration of CCS to base load
combined cycle EGUs. Intermediate
load combustion turbines tend to start
and stop frequently and have relatively
short periods of continuous operation.
CCS systems could have difficulty
starting fast enough to get significant
levels of CO2 capture. The EPA solicits
comment on flexible CCS technologies
that could be used by intermediate load
combustion turbines. In addition, the
CCS equipment could essentially
remain idle for much of the time while
these intermediate units are not
running. For these reasons, CCS would
be less cost-effective for intermediate
load combustion turbine EGUs—
particularly at much lower capacity
factors—as compared to base load
combined cycle units that are not on the
pathway to combusting 96 percent (by
volume) low-GHG hydrogen.
With respect to base load combustion
turbine EGUs, as explained previously,
the EPA is proposing two BSER
pathways that new base load stationary
combustion turbines may take—one that
is based on the use of 90 percent CCS
and a separate BSER pathway based
upon co-firing low-GHG. In this section,
the EPA explains why it believes that
co-firing with low-GHG hydrogen could
form the basis of the BSER. In section
VII.C.3.b.iii, we discuss why we believe
CCS could also form the basis of the
BSER.
iv. Background Discussion of Hydrogen
and the Electric Power Sector, Hydrogen
Co-Firing in Combustion Turbines, and
Hydrogen Production Processes
Hydrogen in the United States is
primarily used for refining petroleum
and producing fertilizer, with smaller
amounts also used in sectors like metals
treatment, processing foods, and
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production of specialty chemicals.373 In
recent years, applications of hydrogen
have expanded to include co-firing in
combustion turbines used to generate
electricity. In fact, many models of
existing combustion turbines that are
used for electricity generation have
successfully demonstrated the ability to
co-fire blends of 5 to 10 percent
hydrogen by volume without
modification to the combustion system.
Furthermore, combustion of hydrogen
blends as high as 20 to 30 percent by
volume are being tested and
demonstrated; and new turbine designs
that can accommodate co-firing much
greater percentages of hydrogen are
being developed.
Several power producers made
financial investments and began work
on hydrogen co-firing projects prior to
passage of the IRA in August 2022. For
example, in early 2021, the
Intermountain Power Agency (IPA)
project in Utah began the transition
away from operating an 1,800–MW coalfired steam generating unit to an 840–
MW combined cycle combustion
turbine that will integrate 30 percent by
volume hydrogen co-firing at startup in
2025.374 IPA and its partners have
announced plans to produce low-GHG
hydrogen via solar-powered electrolysis
with storage in underground geologic
formations en route to combusting 100
percent low-GHG hydrogen in the
combined cycle unit by 2045. IPA also
has agreements to sell its electricity to
the Los Angeles Department of Water
and Power.
Another example is the Long Ridge
Energy Generation Project in Ohio.375
The 485–MW combined cycle
combustion turbine became operational
in 2021 and is designed to transition to
100 percent hydrogen in the future.376
The unit successfully co-fired 5 percent
by volume hydrogen in March
2022.377 378 The planned next step for
373 U.S. Department of Energy (DOE). National
Clean Hydrogen Strategy and Roadmap. September
2022. https://www.hydrogen.energy.gov/pdfs/cleanhydrogen-strategy-roadmap.pdf.
374 Intermountain Power Agency (2022). https://
www.ipautah.com/ipp-renewed/.
375 Hering, G. (2021). First major US hydrogenburning power plant nears completion in Ohio. S&P
Global Market Intelligence. https://
www.spglobal.com/platts/en/market-insights/latestnews/electric-power/081221-first-major-ushydrogen-burning-power-plant-nears-completionin-ohio.
376 McGraw, D. (2021). World science community
watching as natural gas-hydrogen power plant
comes to Hannibal, Ohio. Ohio Capital Journal.
https://ohiocapitaljournal.com/2021/08/27/worldscience-community-watching-as-natural-gashydrogen-power-plant-comes-to-hannibal-ohio/.
377 McGraw, D. (2021). World science community
watching as natural gas-hydrogen power plant
comes to Hannibal, Ohio. Ohio Capital Journal.
https://ohiocapitaljournal.com/2021/08/27/world-
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Long Ridge is to co-fire 20 percent by
volume hydrogen with the existing
turbine design, which has been
commercially available since 2017 and
can co-fire 15 to 20 percent by volume
hydrogen without modification.379
Furthermore, in June 2022, Southern
Company successfully demonstrated the
co-firing of a 20 percent by volume
hydrogen blend at Georgia Power’s Plant
McDonough-Atkinson. The co-firing
demonstration was performed on a
combustion turbine at partial and full
loads and produced a 7 percent
reduction in CO2 emissions.380 In
September 2022, the New York Power
Authority (NYPA) successfully co-fired
a 44 percent by volume blend of
hydrogen in a retrofitted combustion
turbine. According to the Electric Power
Research Institute (EPRI), the project
demonstrated a 14 percent reduction in
CO2 at a 35 percent by volume hydrogen
blend. The unit’s existing SCR
controlled NOX emissions within permit
limits.381 382 383 We note other projects to
develop combustion turbines that co-fire
hydrogen in section IV.E of this
preamble.
Other power producers have
implemented large low-GHG hydrogen
plans that integrate multiple elements of
their generating assets. In Florida,
NextEra announced in June 2022 a
comprehensive carbon emissions
reduction plan that will eventually
convert 16 GW of natural gas-fired
generation to operate on low-GHG
hydrogen as part of the utility’s 2045
science-community-watching-as-natural-gashydrogen-power-plant-comes-to-hannibal-ohio/.
378 Defrank, Robert (2022). Cleaner Future in
Sight: Long Ridge Energy Terminal in Monroe
County Begins Blending Hydrogen. https://
www.theintelligencer.net/news/community/2022/
04/cleaner-future-in-sight-long-ridge-energyterminal-in-monroe-county-begins-blendinghydrogen.
379 Patel, S. (April 22, 2022). First Hydrogen Burn
at Long Ridge HA-Class Gas Turbine Marks
Triumph for GE. Power. https://
www.powermag.com/nypa-ge-successfully-pilothydrogen-retrofit-at-aeroderivative-gas-turbine/.
380 Patel, S. (2022). Southern Co. Gas-Fired
Demonstration Validates 20% Hydrogen Fuel
Blend. https://www.powermag.com/southern-cogas-fired-demonstration-validates-20-hydrogen-fuelblend/.
381 Palmer, W., & Nelson, B. (2021). An H Future:
2
GE and New York power authority advancing green
hydrogen initiative. https://www.ge.com/news/
reports/an-h2-future-ge-and-new-york-powerauthority-advancing-green-hydrogen-initiative.
382 Van Voorhis, S. (2021). New York to test green
hydrogen at Long Island power plant. Utility Dive.
https://www.utilitydive.com/news/new-york-totest-green-hydrogen-at-long-island-power-plant/
603130/.
383 Electric Power Research Institute (EPRI).
(2022, September 15). Hydrogen Co-Firing
Demonstration at New York Power Authority’s
Brentwood Site: GE LM6000 Gas Turbine. Low
Carbon Resources Initiative. https://www.epri.com/
research/products/000000003002025166.
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GHG reduction goal.384 Also, NextEra’s
Cavendish NextGen Hydrogen Hub will
produce hydrogen with a 25–MW
electrolyzer system powered by solar
energy and the hydrogen will then be
co-fired by combustion turbines at
Florida Power and Light’s 1.75–GW
Okeechobee power plant.385
One of the first power producers to
invest in hydrogen as a fuel for
combustion turbines was Entergy,
which reached an agreement with
turbine manufacturer Mitsubishi Power
in 2020 to develop hydrogen-capable
combined cycle facilities that include
low-GHG hydrogen production, storage,
and transportation components.386 In
October 2022, Entergy and New Fortress
Energy announced plans to collaborate
on a renewable energy and 120–MW
hydrogen production plant in southeast
Texas.387 The partnership includes
electricity transmission infrastructure as
well as the development of renewable
energy resources and the offtake of lowGHG hydrogen. A feature of the
agreement is the potential to supply
hydrogen to Entergy’s Orange County
Advanced Power Station, which
received approval from the Public
Utility Commission of Texas in
November 2022.388 The 1,115–MW
power plant will replace end-of-life gas
generation with new combined cycle
combustion turbines that are ready to
co-fire hydrogen with the ability to
move to 100 percent hydrogen in the
future. Construction will begin in 2023
and the project will be completed in
2026.
Hydrogen offers unique solutions for
decarbonization because of its potential
to provide dispatchable, clean energy
with long-term storage and seasonal
capabilities. For example, hydrogen is
an energy carrier that can provide longterm storage of low-GHG energy that can
be co-fired in combustion turbines and
used to balance load with the increasing
384 NextEra Energy (2022). Zero Carbon Blueprint.
https://www.nexteraenergy.com/content/dam/nee/
us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
385 Clean Energy Group. Hydrogen Projects in the
U.S. https://www.cleanegroup.org/ceg-projects/
hydrogen/projects-in-the-us/.
386 Mitsubishi Power Americas. (September 23,
2020). Mitsubishi Power and Entergy to Collaborate
and Help Decarbonize Utilities in Four States.
https://power.mhi.com/regions/amer/news/
20200923.html.
387 Entergy. (October 19, 2022). Entergy Texas and
New Fortress Energy partner to advance hydrogen
economy in Southeast Texas. https://
www.entergynewsroom.com/news/entergy-texasnew-fortress-energy-partner-advance-hydrogeneconomy-in-southeast-texas/.
388 Entergy. (November 28, 2022). Entergy Texas
receives approval to build a cleaner, more reliable
power station in Southeast Texas. https://
www.entergynewsroom.com/news/entergy-texasreceives-approval-build-cleaner-more-reliablepower-station-in-southeast-texas/.
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to warming through increasing
concentrations of methane and ozone.
Hydrogen is not a greenhouse gas as
defined by the Framework Convention
on Climate Change under the IPCC, and
its secondary impacts on warming
should mitigate over time as methane
emissions are controlled. Even as
hydrogen scales and much larger
volumes are consumed, with the
attendant potential for emissions of
hydrogen to oxidize in the atmosphere,
we expect the benefits of low-GHG
hydrogen as part of a BSER pathway to
outweigh any such effects in the future.
volumes of variable generation.389 These
services can enhance the reliability of
the power system while facilitating the
integration of variable renewable energy
resources and supporting
decarbonization of the electric grid.
Hydrogen has the potential to mitigate
curtailment, which is the deliberate
reduction of electric output below what
could have been produced. Curtailment
often occurs when RTOs need to
balance the grid’s energy supply to meet
demand. For example, in 2020, the
California Independent System Operator
(CAISO) curtailed an estimated 1.5
million MWh of solar generation.390
Curtailment will likely increase as the
capacity of variable generation
continues to expand. One technology
with the potential to reduce curtailment
is energy storage, and some power
producers envision a role for hydrogen
to supplement natural gas as a fuel to
support the balancing and reliability of
an increasingly decarbonized electric
grid.
Rapid progress is being made, and,
due to the demonstrated ability of new
and existing combustion turbines to cofire hydrogen, other utility owners/
operators have publicly made long-term
commitments to hydrogen co-firing and
have identified the technology as a key
component of their future operations
and GHG reduction strategies. As
highlighted by the earlier examples, the
outlook expressed by multiple power
producers and developers includes a
future generation asset mix that retains
combustion turbines fired exclusively
with hydrogen. Utilities in vertically
integrated States and merchant
generators in wholesale markets rely on
combustion turbines to provide reliable,
dispatchable power.
Hydrogen gas released into the
atmosphere will also have climate and
air quality effects through atmospheric
chemical reactions. In particular,
hydrogen is known to react with the
hydroxyl radical, reducing
concentrations of the hydroxyl radical
in the atmosphere. Because the
hydroxyl radical is important for the
destruction of many other gases, a
reduction in hydroxyl radical
concentrations will lead to increased
lifetimes of many other gases—
including methane and tropospheric
ozone. This means that hydrogen gas
emissions can also indirectly contribute
Hydrogen is used in industrial
processes, and as discussed previously,
in recent years, applications of
hydrogen co-firing have expanded to
include stationary combustion turbines
used to generate electricity. However, at
present, nearly all industrial hydrogen
is produced via methods that are GHGintensive. To fully evaluate the potential
GHG emission reductions from co-firing
low-GHG hydrogen in a combustion
turbine EGU, it is important to consider
the different processes of producing the
hydrogen and the GHG emissions
associated with each process. The
following discussion highlights the
primary methods of hydrogen
production as well as the sources of
energy used during production and the
level of GHG emissions that result from
each production method. The varying
levels of CO2 emissions associated with
hydrogen production are wellrecognized, and stakeholders routinely
refer to hydrogen on the basis of the
different production processes and their
different GHG intensities.391
More than 95 percent of the dedicated
hydrogen currently produced in the U.S.
originates from natural gas using steam
methane reforming (SMR). This method
produces hydrogen by adding steam and
heat to natural gas in the presence of a
catalyst. Methane reacts with the steam
to produce hydrogen, carbon monoxide
(CO), and trace amounts of CO2. Further,
the CO byproduct is routed to a second
process, known as a water-gas shift
reaction, to react with more steam to
create additional hydrogen and CO2.
After these processes, the CO2 is
removed from the gas stream, leaving
389 For example, when the sun is not shining and/
or the wind is not blowing.
390 Walton, R. (August 25, 2021). CAISO forced to
curtail 15% of California utility-scale solar in
March, 5% last year. Power Engineering. https://
www.power-eng.com/solar/caiso-forced-to-curtail15-of-california-utility-scale-solar-in-march-5-lastyear/#gref.
391 Some organizations have developed a
convention for labeling each hydrogen production
method, based on the GHG emissions associated
with each method, according to a color scheme. The
color labels are insufficiently specific for the
purposes of this proposed rule, so the EPA
generally does not refer to hydrogen using this color
convention.
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almost pure hydrogen.392 CO2 emissions
are generated from the conversion
process itself and from the creation of
the thermal energy and steam (assuming
the boilers are fueled by natural gas) or
external energy sources powering the
production process. Because the thermal
efficiency of SMR of natural gas is
generally 80 percent or less,393 less
overall energy is in the produced
hydrogen than in the natural gas
required to produce the hydrogen.
Therefore, the use of hydrogen
produced through SMR in a combustion
turbine would consume more natural
gas than would have been consumed if
the combustion turbine had burned the
natural gas directly. Therefore, co-firing
hydrogen derived from SMR based on
fossil fuels without CCS results in
higher overall CO2 emissions than using
the natural gas directly in the EGU.
The GHG emissions from hydrogen
production via SMR can be controlled
with CCS technology at different points
in the production process. There are
varying levels of CO2 capture for
different techniques, but typically a
range of 65 to 90 percent is viable.394
The autothermal reforming (ATR) of
methane is a similar technology to SMR,
but ATR utilizes natural gas in the
process itself without an external heat
source.395 CCS can also be applied to
ATR.
Another process to produce hydrogen
is methane pyrolysis. Methane pyrolysis
is the thermal decomposition of
methane in the absence (or near
absence) of oxygen, which produces
hydrogen and solid carbon (i.e., carbon
black) as the only byproducts. Pyrolysis
uses energy to power its hydrogen
production process, and therefore the
level of its overall GHG emissions
depends on the carbon intensity of its
energy inputs. For SMR, ATR, and
pyrolysis technologies, emissions from
methane extraction, production, and
transportation are also significant
392 U.S. Department of Energy (DOE) (n.d.).
Hydrogen Production: Natural Gas Reforming.
https://www.energy.gov/eere/fuelells/hydrogenproduction-natural-gas-reforming. For each kg of
hydrogen produced through SMR, 4.5 kg of water
is consumed.
393 Thermal efficiency is the amount of energy in
the production (e.g., hydrogen) compared to the
energy input to the process (e.g., natural gas). At an
efficiency of 80 percent, the product contains 80
percent of the energy input and 20 percent is lost.
394 Powell, D. (2020). Focus on Blue Hydrogen.
Gaffney Cline. https://www.gaffneycline.com/sites/
g/files/cozyhq681/files/2021–08/Focus_on_Blue_
Hydrogen_Aug2020.pdf.
395 ‘‘Comparative assessment of blue hydrogen
from steam methane reforming, autothermal
reforming, and natural gas decomposition
technologies for natural gas production regions,’’
Energy Conversion and Management, February 15,
2022.
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aspects of their GHG emissions
footprints.396
In contrast to the three methods
discussed above, electrolysis does not
use methane as a feedstock. In
electrolysis, hydrogen is produced by
splitting water into its components,
hydrogen and oxygen (O2), via
electricity. During electrolysis, a
negatively charged cathode and
positively charged anode are submerged
in water and an electric current is
passed through the water. The result is
hydrogen molecules appearing at the
negative cathodes and O2 appearing at
the positive anodes. Electrolysis does
not emit GHG emissions at the hydrogen
production site; the overall GHG
emissions associated with electrolysis
are instead dependent upon the source
of the energy used to decompose the
water.397 According to the DOE,
electrolysis powered by fossil fuel
energy supplied by the electric grid,
based on a national average, would
generate overall GHG emissions double
those of hydrogen produced via SMR
without CCS.398 399 However,
electrolysis powered by wind, solar,
hydroelectric, or nuclear energy is
generally considered to lower overall
GHG emissions.400 401 402 It should be
396 In addition, methane extraction operations are
known to contribute to air toxics including
benzene, ethylbenzene, and n-hexane. https://
www.epa.gov/controlling-air-pollution-oil-andnatural-gas-industry/basic-information-oil-andnatural-gas.
397 Similarly, the overall GHG emissions
associated with methane pyrolysis are dependent
upon the source of the energy used to decompose
the methane and is a key factor to whether it
qualifies as low-GHG hydrogen.
398 DOE (2022). DOE National Clean Hydrogen
Strategy and Roadmap. Draft—September 2022.
https://www.hydrogen.energy.gov/pdfs/cleanhydrogen-strategy-roadmap.pdf.
399 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023: https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB–0329-update.pdf. From the Liftoff
report, ‘‘Carbon intensities are based on data from
the Carnegie Mellon Power Sector Carbon Index as
well as national averages in grid mix carbon
intensity—in some states, grid carbon intensity can
be as high as 40 kg CO2e/kg H2.’’
400 U.S. Department of Energy (DOE) (n.d.).
Hydrogen Production: Electrolysis. https://
www.energy.gov/eere/fuelcells/hydrogenproduction-electrolysis.
401 For each kg of hydrogen produced through
electrolysis, 9 kg of byproduct oxygen are also
produced and 9 kg of purified water are consumed.
To reduce the cost of hydrogen production, this
byproduct oxygen could be captured and sold. For
each gallon of water consumed, 0.057 MMBtu of
hydrogen is produced. According to the water use
requirements for combined cycle EGUs with cooling
towers, if this hydrogen is later used to produce
electricity in a combined cycle EGU, overall water
requirements would be greater than a combined
cycle EGU with CCUS.
402 Electrolysis and other technologies that break
apart water to form hydrogen and oxygen consume
more water than SMR without CCS. Resource
Assessment for Hydrogen Production. National
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noted that electrolytic systems utilizing
even a small portion of grid-based
electricity may not have lower overall
GHG emissions and carbon intensities
than SMR without CCS.403 This concern
is likely to be mitigated over time as the
carbon intensity of the grid declines,
given the influx of new renewable
generation—the EPA’s post-IRA 2022
reference case projects a lower carbon
intensity of the grid-—coupled with
expected retirements of higher-emitting
sources. Naturally occurring hydrogen
stored in subsurface geologic formations
is also gaining attention as a potential
low-GHG source of hydrogen.
vi. The EPA’s Proposed BSER and
Definition of Low-GHG Hydrogen
The EPA is proposing that the second
component of the BSER for new
combustion turbines in the relevant
subcategories is co-firing 30 percent (by
volume) low-GHG hydrogen and that
sources meet a corresponding standard
of performance by 2032. The EPA is also
proposing that new base load
combustion turbines that are subject to
a standard of performance based on cofiring 30 percent (by volume) low-GHG
hydrogen in 2032 must also meet a more
stringent standard of performance based
on a BSER of co-firing 96 percent (by
volume) low-GHG hydrogen by 2038.
This section describes the factors the
EPA considered in determining what
level of co-firing qualifies as a
component of the BSER for affected
sources and the timing for when that
level of co-firing could be technically
feasible and of reasonable cost. Key
factors informing this determination
include the magnitude of CO2 emission
reductions at the combustion turbines,
the availability of combustion turbines
capable of co-firing hydrogen, potential
infrastructure limitations, and access to
low-GHG hydrogen.
The relationship between the volume
of hydrogen fired and the reduction in
CO2 stack emissions is exponential. At
low levels of co-firing there are modest
emission reduction benefits, but these
reduction benefits amplify as the
volume of hydrogen increases due to the
lower energy density of hydrogen
Renewable Energy Laboratory (NREL/TP–5400–
77198, July 2020). https://www.nrel.gov/docs/
fy20osti/77198.pdf. Aside from methane pyrolysis
and byproduct hydrogen, other hydrogen
production methods consume water during the
production process and indirectly due to electricity
generation upstream. The moisture present in coal
and biomass could be recovered and used in the
water gas shift reaction to reduce (or eliminate)
water requirements.
403 U.S. Department of Energy (DOE). Pathways to
Commercial Liftoff: Clean Hydrogen. March 2023.
https://www.energy.gov/articles/doe-releases-newreports-pathways-commercial-liftoff-accelerateclean-energy-technologies.
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compared to natural gas. For example,
co-firing 10 percent hydrogen by
volume yields approximately a 3
percent CO2 reduction at the stack, cofiring 30 percent hydrogen yields a 12
percent CO2 reduction, co-firing 75
percent hydrogen yields a 49 percent
CO2 reduction, and at 100 percent
hydrogen co-firing there are zero CO2
emissions at the stack.
Importantly, co-firing 30 percent
hydrogen by volume is consistent with
existing technologies across multiple
combustion turbine designs and should
be considered a minimal level for
evaluation as a system of emission
reduction. While all major
manufacturers are developing
combustion turbines that can co-fire
higher volumes of hydrogen, some
combustion turbine models are already
able to co-fire relatively high
percentages.404 Several currently
available new combustion turbine
models can burn up to 75 percent
hydrogen by volume.405 Combustion
turbine designs capable of co-firing 30
percent hydrogen by volume are
available from multiple manufacturers
at multiple sizes. As such, a BSER that
included co-firing 30 percent hydrogen
by volume would not pose challenges
for near-term implementation for the
EPA’s proposed second phase standards
beginning in 2032. The EPA is soliciting
comment on whether the new and
reconstructed combustion turbines will
have available combustion turbine
designs that would allow higher levels
of hydrogen co-firing, such as 50
percent or more by volume by 2030 or
2032. If such combustion turbines are
sufficiently available, this would
support moving forward the starting
compliance date of the second phase of
the standards of performance and/or
increasing the percent of hydrogen cofiring assumed in establishing the
standards.
Because the cost of natural gas is
lower than the cost of hydrogen, most
new combustion turbines are not, at the
present time, designed to burn 100
percent hydrogen when they are placed
into service. However, some turbines are
available now that can combust 100
percent hydrogen in the future and there
is significant evidence that such
turbines will be more widely available
by the 2030s.406 Multiple vendors have
indicated that they intend to have
404 Mitsubishi Power Americas. https://
power.mhi.com/special/hydrogen/article_1.
405 Overcoming technical challenges of hydrogen
power plants for the energy transition. https://
www.nsenergybusiness.com.
406 https://www.dieselgasturbine.com/news/
siemens-energy-explores-gas-turbines-future-in-netzero-energy-mix/8024799.article.
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turbines available that fire 100 percent
hydrogen in that timeframe.407 408 409 For
example, as noted in section IV.E of this
preamble, the LADWP Scattergood
Modernization project includes plans to
have a hydrogen-ready combustion
turbine in place when the 346–MW
combined cycle plant (potential for up
to 830 MW) begins initial operations in
2029. LADWP foresees the plant
running on 100 percent electrolytic
hydrogen by 2035.410 The
Intermountain Power Project, also noted
in section IV.E of this preamble,
commenced construction in 2022 on an
840–MW M501 JAC Mitsubishi Hitachi
Power Systems combustion turbine
designed to operate using 30 percent (by
volume) hydrogen upon startup. The
plant is projected to be operational by
July 2025 and to transition to 100
percent hydrogen by 2045.411 Several
existing gas turbine technologies are
capable of operating with 100 percent
hydrogen, including Siemens Energy’s
SGT–A35 and General Electric’s B, E,
and F class gas turbines.412 Comments
submitted to the EPA’s non-regulatory
docket confirm that at the present time,
existing units can be retrofitted to
operate using 100 percent hydrogen.
DOE’s National Energy Technology Lab
states: Based on data from a literature
survey and input from manufacturers,
NETL has found that today’s modern gas
turbines can reliably combust 30–60
percent hydrogen fuels with similar
NOX emissions as compared to their
pure natural gas counterparts. Public
and private research is underway to
produce a 100 percent hydrogen-fueled
turbine. NETL anticipates that industry
will achieve this technology by around
2030 based on current research progress
and publicly announced forecasts.’’ 413
407 Mitsubishi highlights four hydrogen projects
at CERAWeek. https://www.power-eng.com/
hydrogen/mitsubishi-power-highlights-fourhydrogen-projects/#gref.
408 Constellation Energy Corporation’s Comments
on EPA Draft White Paper: Available and Emerging
Technologies for Reducing Greenhouse Gas
Emissions from Combustion Turbine Electric
Generating Units Docket ID No. EPA–HQ–OAR–
2022–0289. Docket comments noted, ‘‘Retrofits
using existing technology are available to achieve
50–100% hydrogen combustion by volume at some
generators.’’
409 Siemens Energy to provide hydrogen-capable
turbines to back up utility-scale solar installation in
Nebraska. https://press.siemens-energy.com/global/
en/pressrelease/siemens-energy-provide-hydrogencapable-turbines-back-utility-scale-solarinstallation.
410 https://clkrep.lacity.org/onlinedocs/2023/230039_rpt_DWP_02-03-2023.pdf.
411 IPP Renewed—Intermountain Power
Agency.ipautah.com.
412 ICF. Retrofitting Gas Turbine Facilities for
Hydrogen Blending.
413 National Energy Technology Laboratory, A
Literature Review of Hydrogen and Natural GAS
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Turbine projects that have recently been
built and that are currently under
construction (such as the Longview
turbine and the Intermountain Power
Project discussed elsewhere in this
preamble) are being developed with the
understanding that these technology
advances will be retrofittable to these
types of turbines. It is worth noting that
in many cases, existing turbines are able
to co-fire large amounts of hydrogen
without significant re-engineering. This
is because their burners are developed
relatively simply and are able to
combust large amounts of hydrogen. In
retrospect almost all new turbines are
designed with more sophisticated
burners that closely control the mixture
of air and fuel to maximize efficiency
while limiting nitrogen oxide
generation. Because hydrogen has very
different characteristics than natural gas
such as higher flame temperature, these
burners need to be re-engineered to
accommodate large amounts of
hydrogen 414 415 For more information
about the status of combustion turbines
with respect to combusting hydrogen
see the TSD, ‘‘Hydrogen in Combustion
Turbine EGUs,’’ in the docket for this
rulemaking.
Access to low-GHG hydrogen,
however, is also an important
component of the BSER analysis.
Midstream infrastructure limitations
and the adequacy and availability of
hydrogen storage facilities currently
present obstacles and increase prices for
delivered low-GHG hydrogen. This is
part of the rationale for why the EPA is
not proposing hydrogen co-firing as part
of the first component of the BSER.
Moving gas via pipeline tends to be the
least expensive transport and today
there are 1,600 miles of dedicated
hydrogen pipeline infrastructure.416 As
noted later in a section of this preamble,
based on industry announcements,
many electrolytic hydrogen production
projects will be sited near existing
Turbines: Current State of the Art With Regard to
Performance and NOX Control (DOE/NETL–2022/
3812), August 12, 2022. https://netl.doe.gov/sites/
default/files/publication/A-Literature-Review-ofHydrogen-and-Natural-Gas-Turbines-081222.pdf;
Department of Energy, National Energy Technology
Laboratory, ‘‘Experts Discuss Use of HydrogenFueled Turbines to Drive Clean Energy’’ September
15, 2022. https://netl.doe.gov/node/12058.
414 Siemens Energy, ‘‘Ten Fundamentals to
Hydrogen Readiness’’ September 2022. https://
www.siemens-energy.com/global/en/news/
magazine/2022/hydrogen-ready.html.
415 General Electric, ‘‘Hydrogen-Fueled Gas
Turbines’’ https://www.ge.com/content/dam/
gepower-new/global/en_US/downloads/gas-newsite/future-of-energy/hydrogen-overview.pdf.
416 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf.
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infrastructure and, in certain cases, will
provide combustion turbines access to
supply and delivery solutions.
Hydrogen blending into existing natural
gas pipelines presents another mode of
transport and distribution that is
actively in use in Hawaii and under
exploration in other areas of the
country.417 On-road distribution
methods include gas-phase trucking and
liquid hydrogen trucking, the latter
requiring cooling and compression prior
to transport. Different regional
distribution solutions may emerge
initially in response to localized
hydrogen demand.
Gaseous and liquified hydrogen
storage technologies are developing,
along with lined hard rock storage and
limited but promising geologic salt
cavern storage. Increased storage
capacity and market demand for lowGHG hydrogen is anticipated in
response to Federal H2Hub investments
as low-GHG hydrogen develops from a
localized fuel into a national
commodity.
Given the growth in the hydrogen
sector and Federal funding for the
H2Hubs, which will explicitly explore
and incentivize hydrogen distribution,
the EPA therefore believes hydrogen
distribution and storage infrastructure
will not present a barrier to access for
new combustion turbines opting to cofire 30 percent low-GHG hydrogen by
volume in 2032 and to co-fire 96 percent
low-GHG hydrogen by volume in 2038.
The EPA is soliciting comment on the
expected low-GHG hydrogen
availability by those dates. The EPA is
also soliciting comment on whether
hydrogen infrastructure is likely to be
sufficiently developed by 2030 to
provide access to low-GHG hydrogen for
new and reconstructed combustion
turbines. If so, this would support
moving forward the compliance date of
the second phase of the standards of
performance and/or increase the percent
of hydrogen co-firing assumed in
establishing the standards.
Whether there will be sufficient
volumes of low-GHG hydrogen for new
sources to co-fire 30 percent by volume
between 2030 and 2032 and then for
some base load sources to co-fire 96
percent by 2038 will depend on the
deployment of additional low-GHG
electric generation sources, the growth
of electrolyzer capacity, and market
demand. Along with the power sector,
the industrial and transportation sectors
are also advancing hydrogen-ready
technologies. Industries and
policymakers in those sectors are
417 https://www.hawaiigas.com/clean-energy/
decarbonization.
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actively planning to use hydrogen to
drive decarbonization. For the industrial
sector where hydrogen is a chemical
input to the process or a replacement for
liquid fuels, multiple projection
pathways are being considered as
approaches to lower the GHG intensity
of these sectors. The production
pathways for the industrial sector
include, but are not limited to, fossilderived hydrogen in combination with
CCS. However, due to thermodynamic
inefficiencies in using hydrogen to
produce electricity, it is likely that only
a specific type of low-GHG hydrogen
will be used in the power sector.
Announcements of co-firing
applications support this assertion, and
as discussed in another section of this
preamble, the power sector is already
focused on utilizing low-GHG hydrogen,
electricity generators are likely to have
ample access to low-GHG hydrogen and
in sufficient quantities to support 30
percent co-firing by 2032 and 96 percent
by 2038. The DOE’s estimates of clean
hydrogen production volumes of 10
MMT by 2030 and 20 MMT by 2040,
referenced throughout this rulemaking,
do not apportion which type of
hydrogen is likely to be produced, just
that it is ‘clean.’ 418 The available credits
for the lowest GHG hydrogen
production tier under IRC section 45V
tax subsidies going into effect in 2023,
as outlined in another section of this
preamble, are three times higher than
the credit values allotted for other
hydrogen production tiers in IRC
section 45V. This incentive can be
combined with additional monetization
access through direct pay and
transferability, and therefore has the
potential to drive significant volumes of
electrolytic hydrogen, which is likely to
be considered as low-GHG hydrogen in
this proposal.419 The EPA’s hydrogen
co-firing BSER proposal, if finalized,
would create a significant additional
demand driver for electrolytic hydrogen
not considered in the DOE’s hydrogen
production goals of 10 MMT by 2030
and 20 MMT by 2040. Indeed, high
volumes of electrolytic hydrogen were
central to pathways enabling the power
sector to achieve net-zero emissions by
418 DOE, as required by the IIJA, proposed a Clean
Hydrogen Production Standard (CHPS) of having an
overall emissions rate of 4 kg CO2e/kg H2. CHPS is
not an actual standard, rather a non-binding tool for
DOE’s internal use with selecting projects under the
H2Hubs program. DOE’s proposed CHPS can be
found at https://www.hydrogen.energy.gov/pdfs/
clean-hydrogen-production-standard.pdf.
419 ‘‘The Hydrogen Credit Catalyst: How US
Treasury guidance on a new tax credit could shape
the clean hydrogen economy, the future of
American industry, and orient the power sector for
full decarbonization,’’ Rocky Mountain Institute,
February 27, 2023.
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2035 according to analysis by the
National Renewable Energy Laboratory
(NREL).420 These incentives will be
multiplied by investments through the
DOE’s H2Hub program. Electrolytic
production costs, inclusive of the 45V
PTC, are estimated to fall to less than
$0.40/kg by 2030; this could translate to
delivered cost of hydrogen for
combustion turbines in 2030 between
$0.70/kg and $1.15/kg depending on
storage and distribution costs.421 The
EPA is soliciting comment on whether
sufficient quantities of low-GHG
hydrogen are likely to be available at
reasonable costs by 2030. If so, this
would support moving forward the
compliance date of the second
component of the BSER and/or increase
the percent of hydrogen co-firing
assumed in establishing the standard of
performance.
As discussed earlier, an important
feature of hydrogen as a potential fuel
for combustion turbines is the level of
GHG emissions generated during the
production process, with different
processes resulting in different levels of
GHG emissions. The EPA proposes to
conclude that co-firing with low-GHG
hydrogen (but not other forms of
hydrogen) appropriately considers the
statutory factors and constitutes the
‘‘best’’ system of emission reduction.
Here, the EPA discusses the proposed
definition of low-GHG hydrogen. In the
IIJA and IRA, Congress established
programs to support the development of
low-GHG hydrogen, including section
40314 of the IIJA which established a $8
billion Clean Hydrogen Hubs H2Hubs
program, the $500 million Clean
Hydrogen Manufacturing and Recycling
Program, and a $1 billion Clean
Hydrogen Electrolysis Program to
further electrolysis development.
Section 40315 of the IIJA required DOE
to establish a non-regulatory Clean
Hydrogen Production Standard (CHPS).
Most recently, in the IRA, section
13204, Congress authorized the clean
hydrogen production tax credit (45V).
Several Federal agencies, including the
EPA, are implementing those programs.
DOE consulted the EPA while
developing its proposed CHPS, which
included examining various hydrogen
production processes and the spectrum
of resulting overall carbon intensities.
420 Denholm, Paul, Patrick Brown, Wesley Cole, et
al. 2022. Examining Supply-Side Options to
Achieve 100% Clean Electricity by 2035. Golden,
CO: National Renewable Energy Laboratory. NREL/
TP[1]6A40–81644. https://www.nrel.gov/docs/
fy22osti/81644.pdf.
421 U.S. Department of Energy (DOE). Pathways to
Commercial Liftoff: Clean Hydrogen. March 2023.
https://liftoff.energy.gov/wp-content/uploads/2023/
03/20230320-Liftoff-Clean-H2-vPUB-0329update.pdf.
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That collaborative process provided
useful points of reference for the EPA to
use in proposing a definition in this
rulemaking.
In enacting the IRA, Congress
recognized that different methods of
hydrogen production generate different
amounts of GHG emissions and sought
to encourage lower-emitting production
methods through the multi-tier
hydrogen production tax credit (IRC
section 45V). The IRC section 45V tax
credits provide four tiers of tax credits,
and thus award the highest amount of
tax credits to the hydrogen production
processes with the lowest estimated
GHG emissions. The highest tier of the
credits is $3/kg H2 for 0.0 to 0.45 kg
CO2e/kg H2 produced, and the lowest is
$0.6/kg H2 for 2.5 to 4.0 kg CO2e/kg
H2.422 Congress also provided a
definition of ‘‘clean hydrogen’’ in
section 822 of the IIJA. This provision
sets out a non-binding goal intended for
use in development of the DOE’s Clean
Hydrogen Production Standard (CHPS)
and DOE’s funding programs to promote
promising new hydrogen technologies.
Several Federal agencies are engaging
in low-GHG hydrogen-related efforts,
some of which implement the IRA and
IIJA provisions. As discussed earlier in
this section, the DOE is working on a
Clean Hydrogen Production
Standard,423 an $8 billion Clean
Hydrogen Hub solicitation,424 and
several hydrogen-related research and
development grant programs.425 The
Department of the Treasury is taking
public comment on examining
appropriate parameters for evaluating
overall emissions associated with
hydrogen production pathways as it
prepares to implement IRC section
45V.426 Within the EPA, there are
rulemaking efforts that could impact
low-GHG hydrogen production
pathways, namely the proposed and
supplemental oil and gas emission
guidelines to reduce methane emissions.
The IIJA includes both a textual
definition of ‘‘clean hydrogen’’ and
requires the DOE to develop a Clean
Hydrogen Production Standard: these
two references are related but distinct.
Upon review of the reference points that
these legislative provisions and Agency
422 These amounts assume that wage and
apprenticeship requirements are met.
423 U.S. Department of Energy (DOE). (September
22, 2022). Clean Hydrogen Production Standard.
Hydrogen and Fuel Cell Technologies Office.
https://www.energy.gov/eere/fuelcells/articles/
clean-hydrogen-production-standard.
424 https://www.energy.gov/oced/regional-cleanhydrogen-hubs.
425 https://www.hydrogen.energy.gov/funding_
opportunities.html.
426 https://home.treasury.gov/news/pressreleases/jy0993.
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programs provide, it is apparent that the
clean hydrogen definition in section 822
of the IIJA is not appropriate for the
purposes of this rule. As noted, this
provision sets a non-binding goal for use
in the development of the DOE’s Clean
Hydrogen Production Standard (CHPS)
and the DOE’s funding programs to
promote promising new hydrogen
technologies. The definition of clean
hydrogen in the IIJA is limited to GHGs
emitted at the hydrogen production site
and is therefore not intended to
consider overall GHG emissions
associated with that production method.
According to the IIJA, clean hydrogen as
defined as part of the CHPS is ‘‘. . .
hydrogen produced with a carbon
intensity equal to or less than 2
kilograms of carbon dioxide-equivalent
produced at the site of production per
kilogram of hydrogen produced’’
(emphasis added). A significant portion
of the GHG emissions associated with
hydrogen derived from natural gas
originates from upstream methane
emissions, which are not accounted for
in the CHPS definition.427 That
definition was taken into consideration,
along with multiple other data points,
for development of the CHPS. In CHPS
draft guidance, a target of 4 kg CO2e/kg
H2 on a well-to-gate basis, which aligns
with full range of the IRC section 45V
definition in the IRA.428
In contrast, the EPA believes that the
highest tier of the IRC section 45V(b)(2)
production tax credit is salient for
purposes of the present rule. That
provision provides the highest available
amount of production tax credit for
hydrogen produced through a process
that has a GHG emissions rate of 0.45 kg
CO2e/kg H2 or less, from well-to-gate. As
explained further below, the EPA
proposes that co-firing hydrogen that
meets this criterion qualifies as a
component of the ‘‘best’’ system of
emission reduction, taking into account
the statutory considerations. Thus,
consistent with the tiered approach and
system boundaries in the IRA definition
of clean hydrogen, the EPA is proposing
that low-GHG hydrogen is hydrogen that
is produced through a process that has
a GHG emissions rate of 0.45 kg CO2e/
kg H2 or less, from well-to-gate. Each of
the subsequent hydrogen production
categories outlined in 45V(b)(2) convey
increasingly higher amounts of GHG
emissions (from a well-to-gate analysis),
making them less suitable to be a
component of the BSER.
Electrolyzers with various low-GHG
energy inputs, like solar, wind,
hydroelectric, and nuclear, appear most
likely to produce hydrogen that would
meet the 0.45 kg CO2e/kg H2 or less,
from well-to-gate criteria.429 Hydrogen
production pathways using methane as
a feedstock induce upstream methane
emissions associated with extraction,
production, and transport of the
methane. SMR and ATR also release
heating and process-related CO2
emissions that are difficult to capture at
high rates economically. High
contributions to overall GHG emission
rates may disqualify certain hydrogen
production pathways from producing
low-GHG hydrogen. The EPA recognizes
that the pace and scale of government
programs and private research suggest
that we will gain significant experience
and knowledge on this topic during the
timeframe of this proposed rulemaking.
Accordingly, the EPA is soliciting
comment broadly on its proposed
definition for low-GHG hydrogen, and
on alternative approaches, to ensure that
co-firing low-GHG hydrogen minimizes
GHG emissions, and that combustion
turbines subject to this standard utilize
only low-GHG hydrogen.
The EPA is also taking comment on
whether it is necessary to provide a
definition of low-GHG hydrogen in this
rule. Given the incentives provided in
both the IRA and IIJA for low-GHG
hydrogen production and the current
trajectory of hydrogen use in the power
sector, by 2032, the start date for
compliance with the proposed second
phase of the standards for this rule, lowGHG hydrogen may be the most
common source of hydrogen available
for electricity production. For the most
part, companies that have announced
that they are exploring the use of
hydrogen co-firing have stated that they
intend to use low-GHG hydrogen. These
power suppliers include NextEra, Los
Angeles Department of Power and
Water, and New York Power Authority,
as discussed earlier in this section.
Many utilities and merchant generators
own nuclear, wind, solar, and
hydroelectric generating sources as well
as combustion turbines. The EPA has
identified an emerging trend in which
energy companies with this broad
collection of generation assets are
planning to produce low-GHG hydrogen
for sale and to use a portion of it to fuel
their stationary combustion turbines.
This emerging trend lends support to
the view that the power sector is likely
427 Infrastructure Investment and Jobs Act of
20211Law PUBL058.PS (https://www.congress.gov).
428 U.S. Department of Energy Clean Hydrogen
Production Standard (CHPS) Draft Guidance
429 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB–0329-update.pdf.
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to have access to and will choose to
utilize low-GHG hydrogen for its cofiring applications. Some NGOs have
expressed concern that existing nonemitting assets will channel electricity
from the grid toward electrolyzers,
potentially increasing marginal
electricity generation from assets with
higher carbon intensities. The EPA
agrees these are important issues that
should be considered as levels of excess
zero carbon-emitting generation vary
diurnally and by region. The EPA notes
that these concerns should mitigate over
time as the carbon intensity of the grid
is projected to decline.
Moreover, by the next decade, costs
for low-GHG hydrogen are expected to
be competitive with higher-GHG forms
of hydrogen given declines due to
learning and the IRC section 45V
subsidies. Given the tax credits in IRC
section 45V(b)(2)(D) of $3/kg H2 for
hydrogen with GHG emissions of less
than 0.45 kg CO2e/kg H2, and substantial
DOE grant programs to drive down costs
of clean hydrogen, some entities project
the delivered costs of electrolytic lowGHG hydrogen to range from $1/kg H2
to $0/kg H2 or less.430 431 432 These
projections are more optimistic than,
but still comparable to, DOE projections
of 2030 for delivered costs of
electrolytic low-GHG hydrogen in the
range of $0.70/kg to $1.15/kg for power
sector applications, given R&D
advancements and economies of
scale.433 A growing number of studies
are demonstrating more efficient and
less expensive techniques to produce
low-GHG electrolytic hydrogen; and, tax
credits and market forces are expected
to accelerate innovation and drive down
costs even further over the next
decade.434 435 436 The combination of
competitive pricing and widespread netzero commitments throughout the
utility and merchant electricity
generation market has the potential to
drive future hydrogen co-firing
applications to be low-GHG
430 ‘‘US green hydrogen costs to reach sub-zero
under IRA: longer-term price impacts remain
uncertain,’’ S&P Global Commodity Insights,
September 29, 2022.
431 ‘‘DOE Funding Opportunity Targets Clean
Hydrogen Technologies’’ American Public Power,
January 31, 2023.
432 With the 45V PTC, delivered costs of hydrogen
are projected to fall in the range of $0.70/kg to
$1.15/kg for power sector applications.
433 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf.
434 ‘‘Sound waves boost green hydrogen
production,’’ Power Engineering, January 4, 2023.
435 ‘‘Direct seawater electrolysis by adjusting the
local reaction environment of a catalyst,’’ Nature
Energy, January 30, 2023.
436 https://h2new.energy.gov/.
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hydrogen.437 The EPA is therefore
soliciting comment on whether lowGHG hydrogen needs to be defined as
part of the BSER in this proposed
rulemaking.
vii. Justification for Proposing 30
Percent Co-Firing Low-GHG Hydrogen
and 96 Percent Co-Firing Low-GHG
Hydrogen as Components of the BSER
The EPA is proposing that co-firing 30
percent low-GHG hydrogen, as proposed
to be defined above, by new combustion
turbines in the relevant subcategories,
by 2032, meets the requirements under
CAA section 111(a)(1) to qualify as a
component of the BSER. Similarly, the
EPA is proposing that co-firing 96
percent low-GHG hydrogen by new base
load combustion turbines in the relevant
subcategory, by 2038, also meets the
requirements under CAA section
111(a)(1) to qualify as a component of
the BSER. As discussed below, co-firing
30 percent low-GHG hydrogen is
adequately demonstrated because it is
feasible and well-demonstrated for new
combustion turbines to co-fire that
percentage of hydrogen and multiple
combustion turbine vendors have targets
to have 100 percent hydrogen-capable
combustion turbines available by
around 2030 and are selling combustion
turbines today with the intention of
those combustion turbines being
retrofittable to 100 percent hydrogen
firing.438 439 Several project developers
have announced plans to transition from
lower levels of co-firing up to firing
with 100 percent hydrogen.
The EPA proposes that co-firing 30
percent low-GHG hydrogen by 2032 and
96 percent by 2038 qualify as a BSER
pathway for new baseload combustion
turbines. For the reasons discussed next,
the EPA proposes that co-firing lowGHG hydrogen on that pathway is
adequately demonstrated in light of the
capability of combustion turbines to cofire hydrogen and the EPA’s reasonable
expectation that adequate quantities of
low-GHG hydrogen will be available by
2032 and 2038 and at reasonable cost.
Moreover, combusting hydrogen will
achieve reductions because it does not
produce GHG emissions and will not
have adverse non-air quality health or
environmental impacts or energy
requirements, including on the
nationwide energy sector. Because the
437 DOE
Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf.
438 https://www.powermag.com/first-hydrogenburn-at-long-ridge-ha-class-gas-turbine-markstriumph-for-ge/.
439 https://www.doosan.com/en/media-center/
press-release_view?id=20172449.
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33311
production of low-GHG hydrogen
generates the fewest GHG emissions, the
EPA proposes that co-firing low-GHG
hydrogen, and not other types of
hydrogen, qualifies as the ‘‘best’’ system
of emission reduction. The fact that cofiring low GHG hydrogen creates market
demand for, and advances the
development of, low-GHG hydrogen, a
fuel that is useful for reducing
emissions in the power sector and other
industries, provides further support for
this proposal.
(A) Adequately Demonstrated
As part of the present rulemaking, the
EPA evaluated the ability of new
combustion turbines to operate with
certain percentages (by volume) of
hydrogen blended into their fuel
systems. This evaluation included an
analysis of the technical challenges of
co-firing hydrogen in a combustion
turbine EGU to generate electricity. The
EPA also evaluated available
information to determine if adequate
quantities of low-GHG hydrogen can be
reasonably expected to be available for
combustion turbine EGUs by 2032.
Although industrial combustion
turbines have been burning byproduct
fuels containing large percentages of
hydrogen for decades, utility
combustion turbines have only recently
begun to co-fire smaller amounts of
hydrogen as a fuel to generate
electricity. The primary technical
challenges of hydrogen co-firing are
related to certain physical
characteristics of the gas. When
hydrogen fuel is combusted, it produces
a higher flame speed than the flame
speed produced with the combustion of
natural gas; and hydrogen typically
combusts at a faster rate than natural
gas. When the combustion speed is
faster than the flow rate of the fuel, a
phenomenon known as ‘‘flashback’’ can
occur, which can lead to upstream
complications.440 Hydrogen also has a
higher flame temperature and a wider
flammability range compared to natural
gas.441
The industrial combustion turbines
currently burning hydrogen are smaller
than the larger utility combustion
turbines and use diffusion flame
combustion, often in combination with
water injection, for NOX control. While
440 Inoue, K., Miyamoto, K., Domen, S., Tamura,
I., Kawakami, T., & Tanimura, S. (2018).
Development of Hydrogen and Natural Gas Cofiring Gas Turbine. Mitsubishi Heavy Industries
Technical Review. Volume 55, No. 2. June
2018.https://power.mhi.com/randd/technicalreview/pdf/index_66e.pdf.
441 Andersson, M., Larfeldt, J., Larsson, A. (2013).
Co-firing with hydrogen in industrial gas turbines.
https://sgc.camero.se/ckfinder/userfiles/files/
SGC256(1).pdf.
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water injection requires demineralized
water and is generally only a NOX
control option for simple cycle turbines,
existing simple cycle combustion
turbines have successfully demonstrated
that relatively high levels of hydrogen
can be co-fired in combustion turbines
using diffusion flame and supports the
EPA’s proposal to determine that cofiring 30 percent hydrogen is technically
feasible for new base load and
intermediate load stationary combustion
turbine EGUs by 2032 and that co-firing
higher levels—up to 96 percent by
volume—is feasible by 2038. The EPA
solicits comment on these proposed
findings.
The more commonly used NOX
combustion control for base load
combined cycle turbines is dry low NOX
(DLN) combustion. Even though the
ability to co-fire hydrogen in
combustion turbines that are using DLN
combustors to reduce emissions of NOX
is currently more limited, all major
combustion turbine manufacturers have
developed DLN combustors for utility
EGUs that can co-fire hydrogen.442
Moreover, the major combustion turbine
manufacturers are designing combustion
turbines that will be capable of
combusting 100 percent hydrogen by
2030, with DLN designs that assure
acceptable levels of NOX
emissions.443 444 Several developers
have announced installations with plans
to initially co-fire lower percentages of
low-GHG hydrogen by volume before
gradually increasing their co-firing
percentages—to as high as 100 percent
in some cases—depending on the pace
of the anticipated expansion of lowGHG hydrogen production processes
and associated infrastructure. The goals
of equipment manufacturers and the fact
that existing combined cycle
combustion turbines have successfully
demonstrated the ability to co-fire
various percentages of hydrogen
supports the EPA’s proposal to
determine that co-firing 30 percent
hydrogen is technically feasible for new
base load stationary combustion turbine
EGUs by 2032 and that co-firing 96
percent hydrogen is technically feasible
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442 Siemens
Energy (2021). Overcoming technical
challenges of hydrogen power plants for the energy
transition. NS Energy. https://
www.nsenergybusiness.com/news/overcomingtechnical-challenges-of-hydrogen-power-plants-forenergy-transition/.
443 Simon, F. (2021). GE eyes 100% hydrogenfueled power plants by 2030. https://
www.euractiv.com/section/energy/news/ge-eyes100-hydrogen-fuelled-power-plants-by-2030/.
444 Patel, S. (2020). Siemens’ Roadmap to 100%
Hydrogen Gas Turbines. https://
www.powermag.com/siemens-roadmap-to-100hydrogen-gas-turbines/.
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for new base load stationary combustion
turbine EGUs by 2038.
The combustion characteristics of
hydrogen can lead to localized higher
temperatures during the combustion
process. These ‘‘hotspots’’ can increase
emissions of the criteria pollutant
NOX.445 NOX emissions resulting from
the combustion of high percentage by
volume blends of hydrogen are also of
concern in many regions of the country.
For turbines using diffusion flame
combustion, water or steam injection is
used to control emissions of NOX. The
level of water injection can be varied for
different levels of NOX control and
adjustments can be made to address any
potential increases in NOX that would
occur from co-firing hydrogen in
combustion turbines using diffusion
flame combustion. As stated previously,
all major combustion turbine
manufacturers have developed DLN
combustors for utility EGUs that can cofire hydrogen and are designing
combustion turbines that will be
capable of combusting 100 percent
hydrogen by 2030, with DLN designs
that assure acceptable levels of NOX
emissions. In addition, EGR in diffusion
flame combustion turbines reduces the
oxygen concentration in the combustor
and limits combustion temperatures and
NOX formation. Furthermore, while
combustion controls can achieve low
levels of NOX, many new intermediate
load and base load combustion turbines
using DLN combustion also use
selective catalytic reduction (SCR) to
reduce NOX emissions even further. The
design level of control from SCR can be
tied to the exhaust gas concentration. At
higher levels of incoming NOX, either
the reagent injection rate can be
increased and/or the size of the catalyst
bed can be increased.446 The EPA has
concluded that any potential increases
in NOX emissions do not change the
Agency’s view that on balance, co-firing
low-GHG hydrogen qualifies as a
component of the BSER.
As noted above, at present, most of
the hydrogen produced in the U.S. is
produced for the industrial sector
through SMR, which is a high GHGemitting process. Limited quantities of
hydrogen are currently being produced
via SMR with CCS, which reduces
some, but not all, of the associated GHG445 Guarco, J., Langstine, B., Turner, M. (2018).
Practical Consideration for Firing Hydrogen Versus
Natural Gas. Combustion Engineering Association.
https://cea.org.uk/practical-considerations-forfiring-hydrogen-versus-natural-gas/.
446 Siemens Energy (2021). Overcoming technical
challenges of hydrogen power plants for the energy
transition. NS Energy. https://
www.nsenergybusiness.com/news/overcomingtechnical-challenges-of-hydrogen-power-plants-forenergy-transition/.
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emitting processes. Only small-scale
facilities are currently producing
hydrogen through electrolysis with
renewable or nuclear energy, and as
described below, much larger facilities
are under development.
However, as also noted above,
incentives in recent Federal legislation
are anticipated to significantly increase
the availability of low-GHG hydrogen by
2032, including for the utility power
sector. The IIJA, enacted in 2021,
allocated more than $9 billion to the
DOE for research, development, and
demonstration of low-GHG hydrogen
technologies and the creation of at least
four regional low-GHG hydrogen hubs.
The DOE has indicated its intention to
fund between six and 10 hubs.447 In
addition, the IRA provided significant
incentives to invest in low-GHG
hydrogen production (For additional
discussion of the IIJA and/or IRA, see
section IV.E of this preamble.)
Programs from the IIJA and IRA have
been successful in prompting the
development of new low-GHG hydrogen
projects and infrastructure. As of August
2022, 374 new projects had been
announced that would produce 2.2
megatons (Mt) of low-GHG hydrogen
annually, which represents a 21 percent
increase over current output.448
Examples include:
• In June 2022, the DOE issued a
$504.4 million loan guarantee to finance
Advanced Clean Energy Storage (ACES),
a low-GHG hydrogen production and
long-term storage facility in Delta,
Utah.449 The facility will use 220 MW
of electrolyzers powered by renewable
energy to produce low-GHG hydrogen.
The hydrogen will be stored in salt
caverns and serve as a long-term fuel
supply for the combustion turbine at the
Intermountain Power Agency (IPA)
project, which is described earlier in
this section.
• In January 2023, NextEra
announced an 800–MW solar project in
the central U.S. to support the
development of low-GHG hydrogen as
well as plans to produce its own low447 IIJA authorized a total of $9.5B for hydrogen
related programs ($8 billion for Clean Hydrogen
Hubs H2Hubs, $1B for electrolyzer research and
development and $500 million for hydrogen-related
manufacturing incentives). See also: U.S. Dept. of
Energy, Regional Clean Hydrogen Hubs. https://
www.energy.gov/oced/regional-clean-hydrogenhubs.
448 Energy Futures Initiative (February 2023). U.S.
Hydrogen Demand Action Plan. https://
energyfuturesinitiative.org/reports/.
449 U.S. Department of Energy (DOE). (2022). Loan
Office Programs. Advanced Clean Energy Storage.
https://www.energy.gov/lpo/advanced-cleanenergy-storage.
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GHG hydrogen at a facility in
Arizona.450
• In New York, Constellation
(formerly Exelon Generation) is
exploring the potential benefits of
integrating onsite low-GHG hydrogen
production, storage, and usage at its
Nine Mile Point nuclear station. The
project is funded by a DOE grant and
includes partners such as Nel Hydrogen,
Argonne National Laboratory, Idaho
National Laboratory, and the National
Renewable Energy Laboratory. The
project is expected to generate an
economical supply of low-GHG
hydrogen that will be safely captured,
stored, and potentially taken to market
as a source of power for other purposes,
including industrial applications such
as transportation.451
• Bloom Energy began installation of
a 240-kW electrolyzer at Xcel Energy’s
Prairie Island nuclear plant in
Minnesota in September 2022 to
produce low-GHG hydrogen. The
demonstration project, designed to
create ‘‘immediate and scalable
pathways’’ for producing cost-effective
hydrogen, is expected to be operational
in 2024 and is also funded with a DOE
grant.452
• In California, Sempra subsidiary
SoCalGas has announced plans to
develop the nation’s largest hydrogen
infrastructure system called ‘‘Angeles
Link.’’ When operational, the project
will provide enough hydrogen to
convert up to four natural gas-fired
power plants. Developers predict the
increased access to hydrogen will also
displace 3 million gallons of diesel fuel
from heavy-duty trucks.453 454
• In December 2022, Air Products and
AES announced plans to build a $4billion low-GHG hydrogen production
facility at the site of a former coal-fired
power plant in Texas.455 456 The plant is
450 Penrod, Emma. (January 30, 2023). NextEra
charts path for renewables expansion, but
campaign finance allegations loom in the
background. Utility Dive. https://
www.utilitydive.com/news/nextera-renewablesexpansion-green-hydrogen-solar-alleged-campaignfinance-violation/641475/.
451 https://www.exeloncorp.com/newsroom/
Pages/DOE-Grant-to-Support-Hydrogen-ProductionProject-at-Nine-Mile-Point.aspx.
452 https://www.utilitydive.com/news/bloomenergy-hydrogen-xcel-nuclear-prairie-island/
632148/.
453 https://www.socalgas.com/sustainability/
hydrogen/angeles-link.
454 Penrod, Emma. (February 18, 2022). SoCalGas
begins developing 100% clean hydrogen pipeline
system. Utility Dive. https://www.utilitydive.com/
news/socalgas-begins-developing-100-cleanhydrogen-pipeline-system/619170/.
455 McCoy, Michael. (December 8, 2022). Air
Products plans big green hydrogen plant in U.S.
Chemical and Engineering News. https://
cen.acs.org/energy/hydrogen-power/Air-Productsplans-big-green/100/web/2022/12.
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expected to be completed in 2027, and
once operational, will produce
approximately 200 metric tons of lowGHG hydrogen per day from
electrolyzers powered by 1.4 GW of
wind and solar energy, as noted earlier.
This follows an announcement by Air
Products in October 2022 to invest $500
million in a low-GHG hydrogen
production facility in New York. This
35 metric-ton-per-day project is also
expected to be operational by 2027, and
in July 2022, received approval from the
New York Power Authority for 94 MW
of hydroelectric power.457
• The DOE National Clean Hydrogen
Strategy and Roadmap identified a
plausible path forward for the
production of 10 MMT of low-GHG
hydrogen annually by 2030, 20 MMT
annually by 2040, and 50 MMT
annually by 2050.
• The NREL Clean Grid 2035 analysis
examined several pathways for the
power sector to reach net-zero emissions
by 2035: each of those pathways
included at least 10 MMT of electrolytic
hydrogen by 2035, demonstrating how
electrolytic hydrogen technologies
support rapid grid decarbonization.458
• The H2@Scale is a DOE initiative
that brings together stakeholders to
advance affordable hydrogen
production, transport, storage, and
utilization to enable decarbonization
and revenue opportunities across
multiple sectors.
These legislative actions, utility
initiatives, and industrial sector
production and infrastructure projects
indicate that sufficient low-GHG
hydrogen and sufficient distribution
infrastructure can reasonably be
expected to be available by 2032, when
offtake scales after 2030,459 so that, at a
minimum, the majority of new
combustion turbines could co-fire lowGHG hydrogen. The EPA specifically
solicits comment on whether rural areas
456 Air Products (December 8, 2022). Air Products
and AES Announce Plans to Invest Approximately
$4 Billion to Build First Mega-scale Green Hydrogen
Production Facility in Texas. https://
www.airproducts.com/news-center/2022/12/1208air-products-and-aes-to-invest-to-build-first-megascale-green-hydrogen-facility-in-texas/.
457 Air Products (October 6, 2022). Air Products
to Invest About $500 Million to Build Green
Hydrogen Production Facility in New York. https://
www.airproducts.com/news-center/2022/10/1006air-products-to-build-green-hydrogen-productionfacility-in-new-york.
458 Denholm, Paul, Patrick Brown, Wesley Cole, et
al. 2022. Examining Supply-Side Options to
Achieve 100% Clean Electricity by 2035. Golden,
CO: National Renewable Energy Laboratory NREL/
TP[1]6A40–81644. https://www.nrel.gov/docs/
fy22osti/81644.pdf.
459 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf.
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and small utility distribution systems
(serving 50,000 customers or less) can
expect to have access to low-GHG
hydrogen. To the extent low-GHG
hydrogen might be less available in
rural areas compared to areas with
higher population densities, the EPA
solicits comment if sufficient electric
transmission capacity is available, or
could be constructed, such that
electricity generated from low-GHG
hydrogen could be transmitted to these
rural areas.
By 2035, substantial additional
amounts of renewable energy are
expected to be available, which can
support the production of low-GHG
hydrogen through electrolysis.
(B) Costs
There are three sets of potential costs
associated with co-firing hydrogen in
combustion turbines: (1) The capital
costs of combustion turbines that have
the capability of co-firing hydrogen; (2)
pipeline infrastructure to deliver
hydrogen; and (3) the fuel costs related
to production of low-GHG hydrogen.
As stated previously, manufacturers
are already developing combustion
turbines that can co-fire up to 100
percent hydrogen. Accordingly, this
limits the amount of additional costs
needed to allow combustion turbines to
co-fire 30 percent (by volume) hydrogen
and, later, 96 percent (by volume).
According to data from EPRI’s US–
REGEN model, the heat rate of a
hydrogen-fired combustion turbine
model plant is 5 percent higher and the
capital, fixed, and non-fuel variable
costs are 10 percent higher than a
natural gas-fired combustion turbine.460
However, the EPA is soliciting comment
on what additional costs would be
required to ensure that combustion
turbines are able to co-fire between 30
to 96 percent (by volume) hydrogen and
if there are efficiency impacts from cofiring hydrogen.
With respect to pipeline
infrastructure, there are approximately
1,600 miles of dedicated hydrogen
pipelines currently operating in the U.S.
Existing natural gas infrastructure may
be capable of accepting blends of
hydrogen with modest investments, but
the actual limits will vary depending on
pipeline materials, age, and operating
conditions. Due to the lower energy
density of hydrogen relative to natural
gas, the piping required to deliver pure
hydrogen would have to be larger, and
the material used to construct the piping
could need to be specifically designed
460 https://us-regen-docs.epri.com/v2021a/
assumptions/electricity-generation.html#newgeneration-capacity.
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to be able to handle higher
concentrations of hydrogen that would
prevent embrittlement and leaks. These
risks can be mitigated through
deployment of new pipeline
infrastructure designed for compatibility
with hydrogen in support of a new
combustion turbine installation. The
majority of announced combustion
turbine EGU projects proposing to cofire hydrogen are located close to the
source of hydrogen. Therefore, the fuel
delivery systems (i.e., pipes) for new
combustion turbines can be designed to
transport hydrogen without additional
costs. Therefore, the EPA proposes that
co-firing rates of 30 percent and up to
100 percent by volume would have
limited, if any, additional capital costs
for new combustion turbine EGU
projects. The EPA is soliciting comment
on if additional infrastructure costs,
such as bulk hydrogen storage in salt
caverns, should be accounted for when
determining the costs of hydrogen cofiring.
The primary cost for co-firing
hydrogen is the cost of hydrogen
relative to natural gas. The cost of
delivered hydrogen depends on the
technology used to produce the
hydrogen and the cost to transport the
hydrogen to the end user. For context,
the DOE National Clean Hydrogen
Strategy and Roadmap cites the current
cost of low-GHG electrolytic hydrogen
production at approximately $5/kg. The
DOE has established a goal of reducing
the cost of low-GHG hydrogen
production to $1/kg (equivalent to $7.4/
MMBtu) by 2030, which is
approximately the same as the current
production costs of hydrogen from SMR.
Using $1/kg (equivalent to $7.4/MMBtu)
as the delivered cost of low-GHG
hydrogen, co-firing 30 percent (by
volume) hydrogen in a combined cycle
EGU operating at a capacity factor of 65
percent would increase both the
levelized cost of electricity (LCOE) by
$2.9/MWh.461 This is a 6 percent
increase from the baseline LCOE. A 96
percent (by volume) co-firing rate
increases the LCOE by $21/MWh, a 47
percent increase in the baseline LCOE.
Regardless of the level of hydrogen cofiring, the CO2 abatement cost is $64/ton
($70/metric ton) at the affected
facility.462 For an aeroderivative simple
cycle combustion turbine operating at a
capacity factor of 40 percent, co-firing
30 percent hydrogen increases the LCOE
by $4.1/MWh, representing a 5 percent
461 The EIA long-term natural gas price for
utilities is $3.69/MMBtu.
462 The abatement cost of co-firing low-GHG
hydrogen is determined by the relative delivered
cost of the low-GHG hydrogen and natural gas.
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increase from the baseline LCOE. A 96
percent (by volume) co-firing rate
increases the LCOE by $30/MWh, a 31
percent increase in the baseline LCOE.
However, DOE’s projected goal of $1/
kg production costs (equivalent to $7.4/
MMBtu) for low-GHG hydrogen was
established prior to the IIJA incentives
and IRA tax subsidies for low-GHG
hydrogen production, CCS, and
generation from renewable sources.
These subsidies could be equivalent to,
or even exceed, the production costs of
low-GHG hydrogen. Even when the cost
to transport the hydrogen from the
production facility to the end user is
accounted for, the cost of low-GHG
hydrogen to the end user could be less
than $1/kg. Assuming a delivered price
of $0.75/kg ($5.6/MMBtu), the CO2
abatement costs for co-firing hydrogen
would be $32/ton ($35/metric ton). For
a combined cycle EGU, the LCOE
increase would be $1.4/MWh and $11/
MWh for the 30 percent and 96 percent
(by volume) cases, respectively. For a
simple cycle EGU, the LCOE would be
$2.1/MWh and $15/MWh for the 30
percent and 96 percent (by volume)
cases, respectively. If the delivered cost
of low-GHG hydrogen is $0.50/kg ($3.7/
MMBtu), this would represent cost
parity with natural gas and abatement
costs would be zero.
The EPA is proposing to determine
that the increase in operating costs from
a BSER based on low-GHG hydrogen is
reasonable.
(C) Non-Air Quality Health and
Environmental Impact and Energy
Requirements
The co-firing of hydrogen in
combustion turbines in the amounts that
the EPA proposes as the BSER would
not have adverse non-air quality health
and environmental impacts. It would
result in NOX emissions, but those
emissions can be controlled, as
described in section VII.F.3.c.vii.(A) of
this preamble.
In addition, co-firing hydrogen in the
amounts proposed would not have
adverse impacts on energy
requirements, including either the
requirements of the combustion turbines
to obtain fuel or on the energy sector
more broadly, particularly with respect
to reliability. As discussed in sections
VII.F.3.c.vii.(A)–(B), combustion
turbines can be constructed to co-fire
high volumes of hydrogen in lieu of
natural gas, and the EPA expects that
low-GHG hydrogen will be available in
sufficient quantities and at reasonable
cost. Any impact on the energy sector
would be further mitigated by the large
amounts of existing generation that
would not be subject to requirements in
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this rule and the projected new capacity
in the base case modeling.
(D) Extent of Reductions in CO2
Emissions
The site-specific reduction in CO2
emissions achieved by a combustion
turbine co-firing hydrogen is dependent
on the volume of hydrogen blended into
the fuel system. Due to the lower energy
density by volume of hydrogen
compared to natural gas, an affected
source that combusts 30 percent by
volume hydrogen with natural gas
would achieve approximately a 12
percent reduction in CO2 emissions
versus firing 100 percent natural gas.463
A source combusting 100 percent
hydrogen would have zero CO2 stack
emissions because hydrogen contains no
carbon, as previously discussed. A
source co-firing 96 percent by volume
hydrogen (approximately 89 percent by
heat input) would achieve an
approximate 90 percent CO2 emission
reduction, which is roughly equivalent
to the emission reduction achieved by
sources utilizing 90 percent CCS.
(E) Promotion of the Development and
Implementation of Technology
Determining co-firing 30 percent (by
volume) low-GHG hydrogen by 2032
and co-firing 96 percent (by volume) to
be components of the BSER would
generally advance technology
development in both the production of
low-GHG hydrogen and the use of
hydrogen in combustion turbines. This
would facilitate co-firing larger amounts
of low-GHG hydrogen and facilitate cofiring low-GHG hydrogen in existing
combustion turbines. Developing new
configurations for flame dimensions and
turbine modifications to adjust for the
characteristics unique to hydrogen
combustion are technology forcing
advancements that industry appears to
be already leaning into based on the
project announcements. Thus, co-firing
low-GHG hydrogen fulfills the
requirements of BSER to generally
advance technology development. In
addition, co-firing 30 percent (by
volume) low-GHG hydrogen by 2032
would promote additional technology
development and infrastructure to
facilitate co-firing at higher amounts of
low-GHG hydrogen in 2038. As
discussed in the preceding section,
there are multiple combustion turbine
projects planned by industry to co-fire
hydrogen initially and progress to firing
with 100 percent hydrogen. Fueling
combustion turbines with 100 percent
hydrogen would eliminate all carbon
463 The energy density by volume of hydrogen is
lower than natural gas.
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dioxide stack emissions. It would also
promote reliability because it would
provide grid operators with asset
options, in addition to battery and
energy storage, capable of voltage
support and frequency regulation. These
are asset characteristics that will be
required in increasing capacities as
more variable generation is deployed.
lotter on DSK11XQN23PROD with PROPOSALS2
(F) Basis for Proposing Co-Firing LowGHG Hydrogen, Not Other Types of
Hydrogen, as the ‘‘Best’’ System of
Emissions Reduction
In this section, the EPA explains
further why the type of hydrogen cofired as a component of the BSER must
be limited to low-GHG hydrogen, and
not include other types of hydrogen.
The EPA explains further the proposed
definition of low-GHG hydrogen as 0.45
kg CO2e/kg H2 or less from the
production of hydrogen, from well-togate. Finally, the Agency summarizes
the reasons, described above, for the
proposal that co-firing 30 percent lowGHG hydrogen meets the criteria under
CAA section 111 as the BSER.
(1) Limitation of Co-Firing to Low-GHG
Hydrogen
Hydrogen is a zero-GHG emitting fuel
when combusted, so that co-firing it in
a combustion turbine in place of natural
gas reduces GHG emissions at the stack.
Co-firing low-emitting fuels—sometimes
referred to as clean fuels—is a
traditional type of emissions control,
and recognized as a system of emission
reduction under CAA section 111. In
West Virginia v. EPA, the Supreme
Court noted that in the EPA’s prior CAA
section 111 actions, the Agency has
treated ‘‘measures that improve the
pollution performance of individual
sources’’ as ‘‘system[s] of emission
reduction,’’ 142 S. Ct. at 2615,464 and
further noted with approval a statement
the EPA made in the Clean Power Plan
that ‘‘fuel-switching’’ was one of the
‘‘more traditional air pollution control
measures.’’ 142 S. Ct. at 2611 (quoting
80 FR 64784; October 23, 2015). The
EPA has relied on lower-emitting fuels
as the BSER in several CAA section 111
rules. See 44 FR 33580, 33593 (June 11,
1979) (coal that undergoes washing
prior to its combustion to remove sulfur,
so that its combustion emits fewer SO2
emissions); 72 FR 32742 (June 13, 2007)
(same); 80 FR 64510 (October 23, 2015)
(natural gas and clean fuel oil). Co-firing
hydrogen in a combustion turbine in
place of natural gas reduces GHG
464 As discussed in section V.B.4 of this preamble,
the ACE Rule took the position that under CAA
section 111(a)(1), a ‘‘system of emission reduction’’
must be limited to measures that apply at or to the
source. 84 FR 32524 (July 8, 2019).
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emissions at the source and therefore
plainly qualifies as a ‘‘system of
emission reduction.’’ This is true even
if that phrase is narrowly defined to be
limited to controls measures that can be
applied at and to the source and that
reduce emissions from the source, as the
ACE Rule provided, or if it is defined
more broadly.465
In the present proposal, the EPA
recognizes that even though the
combustion of hydrogen is zero-GHG
emitting, its production entails a range
of GHG emissions, from low to high,
depending on the method. As noted in
VII.F.3.c.v of this preamble, these
differences in GHG emissions from the
different methods of hydrogen
production are well-recognized in the
energy sector, and, in fact, hydrogen is
generally characterized by its
production method and the attendant
level of GHG emissions.
Accordingly, the EPA is proposing to
require that to qualify as the ‘‘best’’
system of emission reduction, the
hydrogen that is co-fired must be lowGHG hydrogen, as defined above. This
is because the purpose of CAA section
111 is to reduce pollution that
endangers human health and welfare to
the extent achievable, CAA section
111(b), through promulgation of
standards of performance that reflect the
‘‘best’’ system of emission reduction
that, taking into account certain factors,
is adequately demonstrated. CAA
section 111(a)(1). Co-firing hydrogen at
combustion turbines when that
hydrogen is produced with large
amounts of GHG emissions would
ultimately result in increasing overall
GHG emissions, compared to
combusting solely natural gas at the
combustion turbine. To avoid this
anomalous outcome, in evaluating a
‘‘system of emission reduction’’ of cofiring hydrogen, the GHG emissions
from producing the hydrogen should be
465 Co-firing hydrogen in place of fossil fuel
(generally, natural gas in a combustion turbine) may
be contrasted with co-firing biomass in place of
fossil fuel (generally, coal in a steam generating
unit). The ACE Rule rejected co-firing biomass as
a potential BSER for existing coal-fired steam
generating units. The rule explained that co-firing
biomass does not meet the definition of a ‘‘system
of emission reduction,’’ under the ACE Rule’s
interpretation of that term, because co-firing
biomass in place of coal at a steam generating unit
does not reduce emissions emitted from that source;
rather, any emission reductions rely on accounting
for activities that occur upstream. 84 FR 32546 (July
8, 2019). In contrast, as discussed in the
accompanying text, co-firing hydrogen in place of
natural gas at a combustion turbine achieves
emission reductions at the source. For that reason,
co-firing hydrogen qualifies as a ‘‘system of
emission reduction,’’ even as the ACE Rule defined
the term. As noted in section V.C.3.a of this
preamble, the EPA has proposed to reject that
definition as too narrow.
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33315
recognized to determine whether cofiring that hydrogen is the ‘‘best’’ system
of emission reduction, within the
meaning of CAA section 111(a)(1). The
EPA recognizes that the production of
low-GHG hydrogen also results in fewer
emissions of other air pollutants,
although it also requires the use of more
water, compared to other methods of
producing hydrogen, in particular, ones
involving methane, as discussed in
section VII.F.3.c.v of this preamble. All
these factors, considered together, point
towards co-firing low-GHG hydrogen,
and not other types of hydrogen, as the
‘‘best’’ system of emission reduction.
D.C. Circuit caselaw supports
applying the term ‘‘best’’ in this manner.
In several cases decided under CAA
section 111(a)(1) as enacted by the 1970
CAA Amendments, which did not
provide that the EPA must consider
non-air quality health and
environmental impacts in determining
the BSER,466 the court stated that the
EPA must consider whether byproducts
of pollution control equipment could
cause environmental damage in
determining whether the pollution
control equipment qualified as the best
system of emission reduction. See
Portland Cement Ass’n v. Ruckelshaus,
465 F.2d 375, 385 n.42 (D.C. Cir. 1973),
cert. denied, 417 U.S. 921 (1974) (stating
that ‘‘[t]he standard of the ‘best system’
is comprehensive, and we cannot
imagine that Congress intended that
‘best’ could apply to a system which did
more damage to water than it prevented
to air’’); Essex Chemical Corp. v.
Ruckelshaus, 486 F.2d 427, 439 (D.C.
Cir. 1973) (remanding because the EPA
failed to consider ‘‘the significant land
or water pollution potential’’ from
byproducts of air pollution control
equipment). The situation here is
analogous because a standard that
allowed for co-firing with other
hydrogen would create more damage (in
the form of GHG emissions) than it
prevented, the precise problem CAA
section 111 is intended to address.
Considering the overall emissions
impact of the production of fuel used by
the affected facility to lower its
466 As enacted under the 1970 CAA Amendments,
CAA section 111(a)(1) read as follows:
The term ‘‘standard of performance’’ means a
standard for emissions of air pollutants which
reflects the degree of emission limitation achievable
through the application of the best system of
emission reduction which (taking into account the
cost of achieving such reduction) the Administrator
determines has been adequately demonstrated.
In the 1977 CAA Amendments, Congress revised
section 111(a)(1) to incorporate a reference to ‘‘nonair quality health and environmental impacts,’’ and
Congress retained that phrase in the 1990 CAA
Amendments when it revised CAA section 111(a)(1)
to read as it currently does.
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emissions—here, hydrogen—is
consistent with considering the
environmental impacts of the
byproducts of pollution control
technology used by the affected facility
to lower its emissions.
In addition, the EPA’s proposed
determination that co-firing low-GHG
hydrogen qualifies as the BSER is
supported by the IRA and its legislative
history. In the IRA, Congress enacted or
expanded tax credits to encourage the
production and use of low-GHG
hydrogen.467 In addition, as discussed
in section IV.E.1 of this preamble, IRA
section 60107 added new CAA section
135, LEEP. This provision provides $1
million for the EPA to assess the GHG
emissions reductions from changes in
domestic electricity generation and use
anticipated to occur annually through
fiscal year 2031; and further provides
$18 million for the EPA to promulgate
additional CAA rules to ensure GHG
emissions reductions that go beyond the
reductions expected in that assessment.
CAA section 135(a)(5)–(6). The
legislative history of this provision
makes clear that Congress anticipated
that the EPA could promulgate rules
under CAA section 111(b) to ensure
GHG emissions reductions from fossil
fuel-fired electricity generation. 168
Cong. Rec. E879 (August 26, 2022)
(statement of Rep. Frank Pallone, Jr.).
The legislative history goes on to state
that ‘‘Congress anticipates that EPA may
consider . . . clean hydrogen as [a]
candidate[ ] for BSER for electric
generating plants. . . .’’ Id.
Most broadly, proposing that only
low-GHG hydrogen qualifies as part of
the co-firing BSER is required by the
‘‘reasoned decisionmaking’’ that the
Supreme Court has long held, including
recently in Michigan v. EPA, 576 U.S.
743 (2015), that ‘‘[f]ederal
administrative agencies are required to
engage in.’’ Id. at 751 (internal quotation
marks omitted and citation omitted). In
Michigan, the Court held that CAA
section 112(n)(1)(A), which directs the
EPA to regulate hazardous air pollutants
from coal-fired power plants if the EPA
‘‘finds such regulation is appropriate
and necessary,’’ must be interpreted to
require the EPA to consider the costs of
the regulation. The Court explained that
if the EPA failed to consider cost, it
could promulgate a regulation to
467 These tax credits include IRC section 45V (tax
credit for production of hydrogen through low- or
zero-emitting processes), IRC section 48 (tax credit
for investment in energy storage property, including
hydrogen production), IRC section 45Q (tax credit
for CO2 sequestration from industrial processes,
including hydrogen production); and the use of
hydrogen in transportation applications, IRC
section 45Z (clean fuel production tax credit), IRC
section 40B (sustainable aviation fuel credit).
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eliminate power plant emissions
harmful to human health but do so
through the use of technologies that ‘‘do
even more damage to human health’’
than the emissions they eliminate. Id. at
752. The Court emphasized, ‘‘No
regulation is ‘appropriate’ if it does
significantly more harm than good.’’ Id.
Here, as explained above, permitting
EGUs to burn high-GHG hydrogen
would ‘‘do even more damage to human
health’’ than the emissions eliminated
and therefore could not be considered
‘‘reasoned decisionmaking.’’ Id. at 751.
Likewise, the Supreme Court has long
said that an agency engaged in reasoned
decisionmaking may not ignore ‘‘an
important aspect of the problem.’’ Motor
Vehicles Mfrs. Ass’n v. State Farm Auto
Ins. Co., 463 U.S. 29, 43 (1983).
Permitting EGUs to burn high-GHG
hydrogen to meet the standard of
performance here would ignore an
important aspect of the problem being
addressed, contrary to reasoned
decisionmaking.
The proposed standard of
performance that is founded upon a
BSER of burning hydrogen and the
requirement that owners and operators
seeking to burn hydrogen use low-GHG
hydrogen are distinct requirements that
could function independently. It may
not be necessary to require that only
low-GHG hydrogen be used to comply
for owners and operators choosing this
pathway included in the BSER in order
to be confident that low-GHG hydrogen
will be used to meet the standard.
Incentives in the IRA may render
production of low-GHG hydrogen less
costly than higher-GHG hydrogen at
some point, thus pushing the hydrogen
market toward low-GHG hydrogen. In
addition, the EPA may also initiate a
rulemaking to regulate GHG emissions
from hydrogen production under
section 111 of the CAA. The EPA
solicits comment on whether it is
necessary to define and require lowGHG in this rulemaking. Similarly, the
EPA also solicits comment as to whether
the low-GHG hydrogen requirement
could be treated as severable from the
remainder of the standard such that the
standard could function without this
requirement.
(2) Definition of Low-GHG Hydrogen
As noted in section VII.F.3.c.vi of this
preamble, the EPA proposes a definition
for low-GHG hydrogen that aligns with
the highest of the four tiers of tax credit
available for hydrogen production, IRC
section 45V(b)(2)(D). Under this
provision, taxpayers are eligible for a tax
credit of $3 per kilogram of hydrogen
that is produced with a GHG emissions
rate of 0.45 kg CO2e/kg H2 or less, from
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Sfmt 4702
well-to-gate. This amount is three times
higher than the amount for the next tier
of credit, which is for hydrogen
produced with a GHG emissions rate
between 1.5 and 0.45 kg CO2e/kg H2,
from well-to-gate, IRC section
45V(b)(2)(C); and four and five times
higher than the amount for the next two
tiers of credit, respectively. IRC section
45V(b)(2)(B), (A). With these provisions,
Congress indicated its judgement as to
what constitutes the lowest-GHG
hydrogen production, and its intention
to incentivize production of that type of
hydrogen. Congress’s views inform the
EPA’s proposal to define low-GHG
hydrogen for purposes the BSER for this
CAA section 111 rulemaking consistent
with IRC section 45V(b)(2)(D).
It should be noted that the EPA is not
proposing that the ‘‘clean hydrogen’’
definition in section 822 of the IIJA is
appropriate for the EPA’s regulatory
purposes. This definition is designed for
a non-regulatory purpose. It sets out a
non-binding goal, not a standard or a
regulatory definition, intended for use
in development of the DOE’s CHPS and
funding programs to promote promising
new hydrogen technologies.
For the reasons discussed above, cofiring low-GHG hydrogen qualifies as
the BSER because it is adequately
demonstrated, is of reasonable cost,
does not have adverse non-air quality
health or environmental impacts or
energy requirements—in fact, it offers
potential benefits to the energy sector—
and reduces GHG emissions. The fact
that this control promotes the
advancement of hydrogen co-firing in
combustion turbines provides
additional support for proposing it as
part of the BSER. Finally, Congress’s
direction to choose the ‘‘best’’ system of
emissions reduction and principles of
reasoned decision-making dictate that
the standard should be based on
burning low-GHG hydrogen, and not
using other forms of hydrogen.
4. Other Options for BSER
The EPA considered several other
systems of emission reduction as
candidates for the BSER for combustion
turbines, but is not proposing them as
the BSER. They include CHP and the
hybrid power plant, as discussed below.
a. Combined Heat and Power (CHP)
CHP, also known as cogeneration, is
the simultaneous production of
electricity and/or mechanical energy
and useful thermal output from a single
fuel. CHP requires less fuel to produce
a given energy output, and because less
fuel is burned to produce each unit of
energy output, CHP has lower emission
rates and can be more economic than
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separate electric and thermal generation.
However, a critical requirement for a
CHP facility is that it primarily
generates thermal output and generates
electricity as a byproduct and must
therefore be physically close to a
thermal host that can consistently
accept the useful thermal output. It can
be particularly difficult to locate a
thermal host with sufficiently large
thermal demands such that the useful
thermal output would impact the
emissions rate. The refining, chemical
manufacturing, pulp and paper, food
processing, and district energy systems
tend to have large thermal demands.
However, the thermal demand at these
facilities is generally only sufficient to
support a smaller EGU, approximately a
maximum of several hundred MW. This
would limit the geographically available
locations where new generation could
be constructed in addition to limiting its
size. Furthermore, even if a sufficiently
large thermal host were in close
proximity, the owner/operator of the
EGU would be required to rely on the
continued operation of the thermal host
for the life of the EGU. If the thermal
host were to shut down, the EGU could
be unable to comply with the standard
of performance. This reality would
likely result in difficulty in securing
funding for the construction of the EGU
and could also lead the thermal host to
demand discount pricing for the
delivered useful thermal output. For
these reasons, the EPA is not proposing
CHP as the BSER.
b. Hybrid Power Plant
Hybrid power plants combine two or
more forms of energy input into a single
facility with an integrated mix of
complementary generation methods.
While there are multiple types of hybrid
power plants, the most relevant type for
this proposal is the integration of solar
energy (e.g., concentrating solar
thermal) with a fossil fuel-fired EGU.
Both coal-fired and NGCC EGUs have
operated using the integration of
concentrating solar thermal energy for
use in boiler feed water heating,
preheating makeup water, and/or
producing steam for use in the steam
turbine or to power the boiler feed
pumps.
One of the benefits of integrating solar
thermal with a fossil fuel-fired EGU is
the lower capital and operation and
maintenance (O&M) costs of the solar
thermal technology. This is due to the
ability to use equipment (e.g., HRSG,
steam turbine, condenser, etc.) already
included at the fossil fuel-fired EGU.
Another advantage is the improved
electrical generation efficiency of the
non-emitting generation. For example,
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solar thermal often produces steam at
relatively low temperatures and
pressures, and the conversion of the
thermal energy in the steam to
electricity is relatively low. In a hybrid
power plant, the lower quality steam is
heated to higher temperatures and
pressures in the boiler (or HSRG) prior
to expansion in the steam turbine,
where it produces electricity. Upgrading
the relatively low-grade steam produced
by the solar thermal facility in the boiler
improves the relative conversion
efficiencies of the solar thermal to
electricity process. The primary
incremental costs of the non-emitting
generation in a hybrid power plant are
the costs of the mirrors, additional
piping, and a steam turbine that is 10 to
20 percent larger than that in a
comparable fossil-only EGU to
accommodate the additional steam load
during sunny hours. A drawback of
integrating solar thermal is that the
larger steam turbine will operate at part
loads and reduced efficiency when no
steam is provided from the solar thermal
panels (i.e., the night and cloudy
weather). This limits the amount of
solar thermal that can be integrated into
the steam cycle at a fossil fuel-fired
EGU.
In the 2018 Annual Energy
Outlook,468 the levelized cost of
concentrated solar power (CSP) without
transmission costs or tax credits is $161/
MWh. Integrating solar thermal into a
fossil fuel-fired EGU reduces the capital
cost and O&M expenses of the CSP
portion by 25 and 67 percent compared
to a stand-alone CSP EGU
respectively.469 This results in an
effective LCOE for the integrated CSP of
$104/MWh. Assuming the integrated
CSP is sized to provide 10 percent of the
maximum steam turbine output and the
relative capacity factors of a NGCC and
the CSP (those capacity factors are 65
and 25 percent, respectively) the overall
annual generation due to the
concentrating solar thermal would be 3
percent of the hybrid EGU output. This
would result in a three percent
reduction in the overall CO2 emissions
and a one percent increase in the LCOE,
without accounting for any reduction in
the steam turbine efficiency. However,
these costs do not account for potential
reductions in the steam turbine
efficiency due to being oversized
relative to a non-hybrid EGU. A 2011
technical report by the National
468 EIA, Annual Energy Outlook 2018, February 6,
2018. https://www.eia.gov/outlooks/aeo/.
469 B. Alqahtani and D. Patin
˜ o-Echeverri, Duke
University, Nicholas School of the Environment,
‘‘Integrated Solar Combined Cycle Power Plants:
Paving the Way for Thermal Solar,’’ Applied Energy
169:927–936 (2016).
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Renewable Energy Laboratory (NREL)
cited analyses indicating solaraugmentation of fossil power stations is
not cost-effective, although likely less
expensive and containing less project
risk than a stand-alone solar thermal
plant. Similarly, while commenters
stated that solar augmentation has been
successfully integrated at coal-fired
plants to improve overall unit
efficiency, commenters did not provide
any new information on costs or
indicate that such augmentation is costeffective. The EPA is soliciting comment
on updated costs for hybrid power
plants and if the use of hybrid power
plants could be incorporated as part of
the BSER for base load combustion
turbines.
In addition, solar thermal facilities
require locations with abundant
sunshine and significant land area in
order to collect the thermal energy.
Existing concentrated solar power
projects in the U.S. are primarily located
in California, Arizona, and Nevada with
smaller projects in Florida, Hawaii,
Utah, and Colorado. NREL’s 2011
technical report on the solar-augment
potential of fossil-fired power plants
examined regions of the U.S. with ‘‘good
solar resource as defined by their direct
normal insolation (DNI)’’ and identified
sixteen States as meeting that criterion:
Alabama, Arizona, California, Colorado,
Florida, Georgia, Louisiana, Mississippi,
Nevada, New Mexico, North Carolina,
Oklahoma, South Carolina, Tennessee,
Texas, and Utah. The technical report
explained that annual average DNI has
a significant effect on the performance
of a solar-augmented fossil plant, with
higher average DNI translating into the
ability of a hybrid power plant to
produce more steam for augmenting the
plant. The technical report used a
points-based system and assigned the
most points for high solar resource
values. An examination of a NRELgenerated DNI map of the U.S. reveals
that States with the highest DNI values
are located in the southwestern U.S.,
with only portions of Arizona,
California, Nevada, New Mexico, and
Texas (plus Hawaii) having solar
resources that would have been
assigned the highest points by the NREL
technical report (7 kWh/m2/day or
greater).
The EPA is not proposing hybrid
power plants as the BSER because of
gaps in the EPA’s knowledge about
costs, and concerns about the costeffectiveness of the technology, as noted
above.
5. Subcategories
Stationary combustion turbines are
defined in the 2015 NSPS to include
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both simple cycle and combined cycle
EGUs. In addition, 40 CFR part 60,
subpart TTTT includes three
subcategories for combustion turbines—
natural gas-fired base load EGUs,
natural gas-fired non-base load EGUs,
and multi-fuel-fired EGUs. Base load
EGUs are those that sell electricity in
excess of the site-specific electric sales
threshold to an electric distribution
network on both a 12-operating-month
and 3-year rolling average basis. Nonbase load EGUs are those that sell
electricity at or less than the sitespecific electric sales threshold to an
electric distribution network on both a
12-operating-month and 3-year rolling
average basis. Multi-fuel-fired EGUs
combust 10 percent or more (by heat
input) of fuels not meeting the
definition of natural gas on a 12operating-month rolling average basis.
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a. Legal Basis for Subcategorization
As noted in section V.C.1, CAA
section 111(b)(2) provides that the EPA
‘‘may distinguish among classes, types,
and sizes within categories of new
sources for the purpose of establishing
. . . standards [of performance].’’ The
D.C. Circuit has held that the EPA has
broad discretion in determining whether
and how to subcategorize under CAA
section 111(b)(2). Lignite Energy
Council, 198 F3d at 933. As also noted
in section V.C.1, in prior CAA section
111 rules, the EPA has subcategorized
on numerous bases, including, among
other things, fuel type and load.
b. Electric Sales Subcategorization (Low,
Intermediate, and Base Load
Combustion Turbines)
As noted earlier, in the 2015 NSPS,
the EPA established separate standards
for natural gas-fired base load and nonbase load stationary combustion
turbines. The electric sales threshold
distinguishing the two subcategories is
based on the design efficiency of
individual combustion turbines. A
combustion turbine qualifies as a nonbase load turbine, and is thus subject to
a less stringent standard of performance,
if it has net electric sales equal to or less
than the design efficiency of the turbine
(not to exceed 50 percent) multiplied by
the potential electric output (80 FR
64601; October 23, 2015). If the net
electric sales exceed that level on both
a 12-operating month and 3 calendar
year basis, then the combustion turbine
is in the base load combustion
subcategory and is subject to a more
stringent standard of performance.
Subcategory applicability can change on
a month-to-month basis since
applicability is determined each
operating month. For additional
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discussion on this approach, see the
2015 NSPS (80 FR 64609–12; October
23, 2015). The 2015 NSPS non-base load
subcategory is broad and includes
combustion turbines that assure grid
reliability by providing electricity
during periods of peak electric demand.
These peaking turbines tend to have low
annual capacity factors and sell a small
amount of their potential electric
output. The non-base load subcategory
in the 2015 NSPS also includes
combustion turbines that operate at
intermediate annual capacity factors but
are not considered base load EGUs.
These intermediate load EGUs provide a
variety of services, including providing
dispatchable power to support variable
generation from renewable sources of
electricity. The need for this service has
been expanding as the amount of
electricity from wind and solar
continues to grow. In the 2015 NSPS,
the EPA determined the BSER for the
non-base load subcategory to be the use
of lower emitting fuels (e.g., natural gas
and Nos. 1 and 2 fuel oils). In 2015, the
EPA explained that efficient generation
did not qualify as the BSER due in part
to the challenge of determining an
achievable output-based CO2 emissions
rate for all combustion turbines in this
subcategory.
In this action, the EPA is proposing
changes to the subcategories in 40 CFR
part 60, subpart TTTTa that will be
applicable to sources that commence
construction or reconstruction after the
date of this proposed rulemaking. First,
the Agency is proposing the definition
of design efficiency so that the heat
input calculation of an EGU is based on
the higher heating value (HHV) of the
fuel instead of the lower heating value
(LHV), as explained immediately below.
It is important to note that this would
have the effect of lowering the electric
sales threshold. In addition, the EPA is
proposing to further divide the non-base
load subcategory into separate
intermediate and low load
subcategories.
i. Higher Heating Value as the Basis for
Calculation of the Design Efficiency
The heat rate is the amount of energy
used by an EGU to generate one kWh of
electricity and is often provided in units
of Btu/kWh. As the thermal efficiency of
a combustion turbine EGU is increased,
less fuel is burned per kWh generated
and there is a corresponding decrease in
emissions of CO2 and other air
pollutants. The electric energy output as
a fraction of the fuel energy input
expressed as a percentage is a common
practice for reporting the unit’s
efficiency. The greater the output of
electric energy for a given amount of
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fuel energy input, the higher the
efficiency of the electric generation
process. Lower heat rates are associated
with more efficient power generating
plants.
Efficiency can be calculated using the
HHV or the LHV of the fuel. The HHV
is the heating value directly determined
by calorimetric measurement of the fuel
in the laboratory. The LHV is calculated
using a formula to account for the
moisture in the combustion gas (i.e.,
subtracting the energy required to
vaporize the water in the flue gas) and
is a lower value than the HHV.
Consequently, the HHV efficiency for a
given EGU is always lower than the
corresponding LHV efficiency because
the reported heat input for the HHV is
larger. For U.S. pipeline natural gas, the
HHV heating value is approximately 10
percent higher than the corresponding
LHV heating value and varies slightly
based on the actual constituent
composition of the natural gas.470 The
EPA default is to reference all
technologies on a HHV basis,471 and the
Agency is proposing to base the heat
input calculation of an EGU on HHV for
purposes of the definition of design
efficiency. However, it should be
recognized that manufacturers of
combustion turbines typically use the
LHV to express the efficiency of
combustion turbines.472
Similarly, the electric energy output
for an EGU can be expressed as either
of two measured values. One value
relates to the amount of total electric
power generated by the EGU, or gross
output. However, a portion of this
electricity must be used by the EGU
facility to operate the unit, including
compressors, pumps, fans, electric
motors, and pollution control
equipment. This within-facility
electrical demand, often referred to as
the parasitic load or auxiliary load,
reduces the amount of power that can be
delivered to the transmission grid for
distribution and sale to customers.
Consequently, electric energy output
may also be expressed in terms of net
470 The HHV of natural gas is 1.108 times the LHV
of natural gas. Therefore, the HHV efficiency is
equal to the LHV efficiency divided by 1.108. For
example, an EGU with a LHV efficiency of 59.4
percent is equal to a HHV efficiency of 53.6 percent.
The HHV/LHV ratio is dependent on the
composition of the natural gas (i.e., the percentage
of each chemical species (e.g., methane, ethane,
propane, etc.)) within the pipeline and will slightly
move the ratio.
471 Natural gas is also sold on a HHV basis.
472 European plants tend to report thermal
efficiency based on the LHV of the fuel rather than
the HHV for both combustion turbines and steam
generating EGUs. In the U.S., boiler efficiency is
typically reported on a HHV basis.
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output, which reflects the EGU gross
output minus its parasitic load.473
When using efficiency to compare the
effectiveness of different combustion
turbine EGU configurations and the
applicable GHG emissions control
technologies, it is important to ensure
that all efficiencies are calculated using
the same type of heating value (i.e.,
HHV or LHV) and the same basis of
electric energy output (i.e., MWh-gross
or MWh-net). Most emissions data are
available on a gross output basis and the
EPA is proposing output-based
standards based on gross output.
However, to recognize the superior
environmental benefit of minimizing
auxiliary/parasitic loads, the Agency is
proposing to include optional
equivalent standards on a net output
basis. To convert from gross to netoutput based standards, the EPA used a
1 percent auxiliary load for simple cycle
turbines, a 2 percent auxiliary load for
combined cycle turbines, and a 7
percent auxiliary load for combined
cycle EGUs using 90 percent CCS.
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ii. Lowering the Threshold Between the
Base Load and Non-Base Load
Subcategories
The subpart TTTT distinction
between a base load and non-base load
combustion turbine is determined by
the unit’s actual electric sales relative to
its potential electric sales, assuming the
EGU is operated continuously (i.e.,
percent electric sales). Specifically,
stationary combustion turbines are
categorized as non-base load and are
subsequently subject to a less stringent
standard of performance, if they have
net electric sales equal to or less than
their design efficiency (not to exceed 50
percent) multiplied by their potential
electric output (80 FR 64601; October
23, 2015). Because the electric sales
threshold is based in part on the design
efficiency of the EGU, more efficient
combustion turbine EGUs can sell a
higher percentage of their potential
electric output while remaining in the
non-base load subcategory. This
approach recognizes both the
environmental benefit of combustion
turbines with higher design efficiencies
and provides flexibility to the regulated
473 It is important to note that net output values
reflect the net output delivered to the electric grid
and not the net output delivered to the end user.
Electricity is lost as it is transmitted from the point
of generation to the end user and these ‘‘line loses’’
increase the farther the power is transmitted. 40
CFR part 60, subpart TTTT provides a way to
account for the environmental benefit of reduced
line losses by crediting CHP EGUs, which are
typically located close to large electric load centers.
See 40 CFR 60.5540(a)(5)(i) and the definitions of
gross energy output and net energy output in 40
CFR 60.5580.
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community. In the 2015 NSPS, it was
unclear how often high-efficiency
simple cycle EGUs would be called
upon to support increased generation
from variable renewable generating
resources. Therefore, the Agency
determined it was appropriate to
provide maximum flexibility to the
regulated community. To do this, the
Agency based the numeric value of the
design efficiency, which is used to
calculate the electric sales threshold, on
the LHV efficiency. This had the impact
of allowing combustion turbines to sell
a greater share of their potential electric
output while remaining in the non-base
load subcategory.
For the reasons noted below, the EPA
is proposing in 40 CFR part 60, subpart
TTTTa that the design efficiency be
based on the HHV efficiency instead of
LHV efficiency and that the 50 percent
maximum and 33 percent minimum
restriction not be included. When
determining the potential electric
output used in calculating the electric
sales threshold in 40 CFR part 60,
subpart TTTT, design efficiencies of
greater than 50 percent are reduced to
50 percent and design efficiencies of
less than 33 percent are increased to 33
percent for determining electric sales
threshold subcategorization criteria. The
50 percent criterion was established to
limit non-base load EGUs from selling
greater than 55 percent of their potential
electric sales.474 The 33 percent
criterion is included to be consistent
with applicability thresholds in the
electric utility criteria pollutant NSPS
(40 CFR part 60, subpart Da). Neither of
those criteria are appropriate for 40 CFR
part 60, subpart TTTTa, and the EPA is
not proposing that they be used to
determine the electric sales threshold.
By basing the electric sales threshold on
the HHV design efficiency, the 50
percent restriction is no longer
appropriate because currently available
combined cycle designs operating as
intermediate load combustion turbines
would be limited to selling 55 percent
of their potential electric output. If this
restriction were maintained, it would
reduce the regulatory incentive for
manufacturers to invest in programs to
develop higher efficiency combustion
turbines. The EPA is also proposing to
eliminate the 33 percent minimum
design efficiency in the calculation of
the potential electric output. The EPA is
474 While
the design efficiency is capped at 50
percent on a LHV basis, the base load rating
(maximum heat input of the combustion turbine) is
on a HHV basis. This mixture of LHV and HHV
results in the electric sales threshold being 11
percent higher than the design efficiency. The
design efficiency of all new combined cycle EGUs
exceed 50 percent on a LHV basis.
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unaware of any new combustion
turbines with design efficiencies of less
than 33 percent; and this will likely
have no cost or emissions impact.
However, this provides assurance that
new combustion turbines will maximize
design efficiencies. Because of this
relationship between the electric sales
threshold and the design efficiency of
an individual EGU, the proposed
definition of design efficiency would
have the effect of lowering the electric
sales threshold between the base load
and non-base load subcategories. For
combined cycle EGUs, the current base
load electric sales threshold is 55
percent. Proposing the definition of the
design efficiency to be based on HHV
would make the base load electric sales
threshold for combined cycle EGUs
between 46 and 55 percent.475 The
current electric sales threshold for
simple cycle turbines (i.e., non-base
load) peaks in a range of 40 to 49
percent of potential electric sales. Under
the proposed definition, simple cycle
turbines would be able to sell no more
than between 33 and 40 percent of their
potential electric output without
moving into the base load subcategory.
A design efficiency definition based on
the HHV will have the effect of
decreasing the electric sales threshold in
relative terms by 19 percent and
absolute terms by 7 to 9 percent.476 The
EPA is soliciting comment on whether
the intermediate/base load electric sales
threshold should be reduced further.
The EPA is considering a range that
would lower the base load electric sales
threshold for simple cycle combustion
turbines to between 29 to 35 percent
(depending on the design efficiency)
and to between 40 to 49 percent for
combined cycle combustion turbines
(depending on the design efficiency).
This would be equivalent to reducing
the design efficiency by 6 percent (e.g.,
multiplying by 0.94) when determining
the electric sales threshold.
The EPA determined that proposing
to lower the electric sales threshold is
appropriate for new combustion
turbines because, as will be discussed
later, the first component of BSER for
both intermediate load and base load
turbines is based on highly efficient
generation. Combined cycle units are
significantly more efficient than simple
cycle turbines; and therefore, in general,
475 The electric sales threshold for combined
cycle EGUs with the highest design efficiencies
would remain at 55 percent.
476 The design efficiency appears twice in the
equation used to determine the electric sales
threshold. Amending the design efficiency to use
the HHV numeric value results in a larger reduction
in the electric sales threshold than the difference
between the HHV and LHV design efficiency.
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the EPA should be focusing its
determination of the BSER for base load
units on that more efficient technology.
In the 2015 NSPS, the EPA used a
higher sales threshold because of the
argument that less efficient simple cycle
turbine technology served a unique role
that could not be served by more
efficient combined cycle technology. At
the time, the EPA determined that a
BSER based exclusively on that more
efficient technology could exclude the
building of simple cycle turbines that
are needed to maintain electric
reliability. With improvements to the
ramp rates for combined cycle units and
with integrated renewable/energy
storage projects becoming more
common, these less efficient simple
cycle turbines are no longer the only
technology that can serve this purpose.
Further, as EGUs operate more, they
have more hours of steady state
operation relative to hours of startup/
cycling. Amending the electric sales
threshold would result in GHG
reductions by assuring that the most
efficient generating and lowest emitting
combustion turbine technology is used
for each subcategory. Therefore, the
proposed change to calculate the design
efficiency on a HHV basis will result in
additional emission reductions at
reasonable costs.
Based on EIA 2022 model plants,
combined cycle EGUs have a lower
levelized cost of electricity (LCOE) at
capacity factors above approximately 40
percent compared to simple cycle EGUs
operating at the same capacity factors.
This supports the proposed base load
electric threshold of 40 percent for
simple cycle turbines because it would
be cost effective for owners/operators of
simple cycle turbines to add heat
recovery if they elected to operate their
unit as a base load unit. Furthermore,
based on an analysis of monthly
emission rates, recently constructed
combined cycle EGUs maintain a 12operating-month emissions rates at 12operating-month capacity factors of less
than 55 percent (the base load electric
sales threshold in subpart TTTT)
relative to operation at higher capacity
factors. Therefore, the base load
subcategory operating range could be
expanded in subpart TTTTa without
impacting the stringency of the numeric
standard. However, at 12-operatingmonth capacity factors of less than
approximately 50 percent, emission
rates of combined cycle EGUs increase
relative to operation at a higher capacity
factor. It takes longer for a HRSG to
begin producing steam that can be used
to generate additional electricity than
the time it takes a combustion engine to
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reach full power. Under operating
conditions with a significant number of
starts and stops, typical of intermediate
and especially low load combustion
turbines, there may not be enough time
for the HRSG to generate steam that can
be used for additional electrical
generation. To maximize overall
efficiency, combined cycle EGUs often
use combustion turbine engines that are
less efficient than the most efficient
simple cycle combustion turbine
engines. Under operating conditions
with frequent starts and stops where the
HRSG does not have sufficient time to
begin generating additional electricity, a
combined cycle EGU may be no more
efficient than a highly efficient simple
cycle EGU. Above capacity factors of
approximately 40 percent, the average
run time per start for combined cycle
EGUs tends to increase significantly and
the HRSG would be available to
contribute additional electric
generation. For more information on the
impact of capacity factors on the
emission rates of combined cycle EGUs
see the Efficient Generation at
Combustion Turbine Electric Generating
Units TSD, which is available in the
rulemaking docket.
After the 2015 NSPS was finalized,
some stakeholders expressed concerns
about the approach for distinguishing
between base load and non-base load
turbines. They posited a scenario in
which increased utilization of wind and
solar resources, combined with low
natural gas prices, would create the
need for certain types of simple cycle
turbines to operate for longer time
periods than had been contemplated
when the 2015 NSPS was being
developed. Specifically, stakeholders
have claimed that in some regional
electricity markets with large amounts
of variable renewable generation, some
of the most efficient new simple cycle
turbines—aeroderivative turbines—
could be called on to operate at capacity
factors greater than their design
efficiency. However, if those new
simple cycle turbines were to operate at
those higher capacity factors, they
would become subject to the more
stringent standard of performance for
base load turbines. As a result,
according to these stakeholders, the new
aeroderivative turbines would have to
curtail their generation and instead,
less-efficient existing turbines would be
called upon to run by the regional grid
operators, which would result in overall
higher emissions. The EPA evaluated
the operation of simple cycle turbines in
areas of the country with relatively large
amounts of variable renewable
generation and did not find a strong
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correlation between the percentage of
generation from the renewable sources
and the 12-operating-month capacity
factors of simple cycle turbines. In
addition, the vast majority of simple
cycle turbines that commenced
operation between 2010 and 2016 (the
most recent simple cycle combustion
turbines not subject to 40 CFR part 60,
subpart TTTT) have operated well
below the base load electric sales
threshold in 40 CRF part 60, subpart
TTTT. Therefore, the Agency does not
believe that the concerns expressed by
stakeholders necessitates any revisions
to the regulatory scheme. In fact, as
noted above, the EPA is proposing that
the electric sales threshold can be
lowered without impairing the
availability of simple cycle turbines
where needed, including to support the
integration of variable generation. The
EPA believes that the proposed
threshold is not overly restrictive since
a simple cycle turbine could operate on
average for more than 8 hours a day.
iii. Low and Intermediate Load
Subcategories
The EPA is proposing in 40 CFR part
60, subpart TTTTa to create a low load
subcategory to include combustion
turbines that operate only during
periods of peak electric demand (i.e.,
peaking units) which would be separate
from the intermediate load subcategory.
Low load combustion turbines also
provide ramping capability and other
ancillary serves to support grid
reliability. The EPA evaluated the
operation of recently constructed simple
cycle turbines to understand how they
operate and to determine at what
electric sales level or capacity factor
their emissions rate is relatively steady.
(Note that for purposes of this
discussion, we use the terms ‘‘electric
sales’’ and ‘‘capacity factor’’
interchangeably.) Peaking units only
operate for short periods of time and
potentially at relatively low duty
cycles.477 This type of operation reduces
the efficiency and increases the
emissions rate, regardless of the design
efficiency of the combustion turbine or
how it is maintained. For this reason, it
is difficult to establish a reasonable
output-based standard of performance
for peaking units.
To determine the electric sales
threshold—that is, to distinguish
477 The duty cycle is the average operating
capacity factor. For example, if an EGU operates at
75 percent of the fully rated capacity, the duty cycle
would be 75 percent regardless of how often the
EGU actually operates. The capacity factor is a
measure of how much an EGU is operated relative
to how much it could potentially have been
operated.
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between the intermediate load and low
load subcategories—the EPA evaluated
capacity factor electric sales thresholds
of 10 percent, 15 percent, 20 percent,
and 25 percent. The EPA found the 10
percent level problematic for two
reasons. First, simple cycle combustion
turbines operating at that level or lower
have highly variable emission rates, and
therefore it would be difficult for the
EPA to establish a meaningful outputbased standard of performance. In
addition, only one-third of simple cycle
turbines that have commenced
operation since 2015 have maintained
12-operating-month capacity factors of
less than 10 percent. Therefore, setting
the threshold at this level would bring
most new simple cycle turbines into the
intermediate load subcategory, which
would subject them to a more stringent
emission rate which is only achievable
for simple cycle combustion turbines
operating at higher capacity factors.
This could create a situation where
simple cycle turbines might not be able
to comply with the intermediate load
standard of performance while
operating at the low end of the
intermediate load capacity factor
subcategorization criteria.
Importantly, based on the EPA’s
review of hourly emissions data, above
a 15 percent capacity factor, GHG
emission rates for many simple cycle
combustion turbines begin to stabilize,
see the Simple Cycle Stationary
Combustion Turbine EGUs TSD, which
is available in the rulemaking docket. At
higher capacity factors, more time is
typically spent at steady state operation
rather than ramping up and down; and,
emission rates tend to be lower while in
steady state operation. Approximately
60 percent of recently constructed
simple cycle turbines have maintained
12-operating-month capacity factors of
15 percent or less while two-thirds of
recently constructed simple cycle
turbines have operated at capacity
factors of 20 percent or less; and, the
emission rates clearly stabilize for the
majority of simple cycle turbines
operating at capacity factors of greater
than 20 percent. Nearly 80 percent of
recently constructed simple cycle
turbines maintain maximum 12operating-month capacity factors of 25
percent or less. Based on this
information, the EPA is proposing the
low load electric sales threshold—again,
the dividing line to distinguish between
the intermediate- and low-load
subcategories—to be 20 percent and is
soliciting comment on a range of 15 to
25 percent. The EPA is also soliciting
comment on whether the low load
electric sales threshold should be
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determined by a site-specific threshold
based on three quarters of the design
efficiency of the combustion turbine.478
Under this approach, simple cycle
combustion turbines selling less than 18
to 22 percent of their potential electric
output (depending on the design
efficiency) would still be considered
low load combustion turbines. This
‘‘sliding scale’’ electric sales threshold
approach is similar to the approach the
EPA used in the 2015 NSPS to recognize
the environmental benefit of installing
the most efficient combustion turbines
for low load applications. Using this
approach, combined cycle EGUs would
be able to sell between 26 to 31 percent
of their potential electric output while
still being considered low load
combustion turbines.
Placing low load and intermediate
load combustion turbines into separate
subcategories is consistent with how
these units are operated and how
emissions from these units can be
quantified and controlled. Consistent
with the 2015 NSPS, the BSER analysis
for base load combustion turbine EGUs
assumes the use of combined cycle
technology and the BSER analysis for
intermediate and low load combustion
turbine EGUs assumes the use of simple
cycle technology. However, the Agency
notes that combined cycle EGUs can
elect to operate at lower levels of
electric sales and be classified as
intermediate or peaking EGUs. In this
case, owners/operators of combined
cycle EGUs would be required to
comply with the standards of
performance for intermediate or peaking
EGUs.
33321
c. Multi-Fuel-Fired Combustion
Turbines
40 CFR part 60, subpart TTTT
subcategorizes multi-fuel-fired
combustion turbines as EGUs that
combust 10 percent or more of fuels not
meeting the definition of natural gas on
a 12-operating-month rolling average
basis. The BSER for this subcategory is
the use of lower emitting fuels with a
corresponding heat input-based
standard of performance of 120 to 160
lb CO2/MMBtu, depending on the fuel,
for newly constructed and reconstructed
multi-fuel-fired stationary combustion
turbines.479 Lower emitting fuels for
these units include natural gas,
ethylene, propane, naphtha, jet fuel
kerosene, Nos. 1 and 2 fuel oils,
biodiesel, and landfill gas. The
definition of natural gas in 40 CFR part
60, subpart TTTT includes fuel that
maintains a gaseous state at ISO
conditions, is composed of 70 percent
by volume or more methane, and has a
heating value of between 35 and 41
megajoules (MJ) per dry standard cubic
meter (dscm, m3) (950 and 1,100 British
thermal units (Btu) per dry standard
cubic foot). Natural gas typically
contains 95 percent methane and has a
heating value of 1,050 Btu/lb.480 A
potential issue with the multi-fuel
subcategory is that owners/operators of
simple cycle turbines can elect to burn
10 percent non-natural gas fuels, such as
Nos. 1 or 2 fuel oil, and thereby remain
in that subcategory, regardless of their
electric sales. As a result, they would
remain subject to the less stringent
standard that applies to multi-fuel-fired
sources, the lower emitting fuels
standard. This could allow less efficient
combustion turbine designs to operate
as base load units without having to
improve efficiency and could allow
EGUs to avoid the need for efficient
design or best operating and
maintenance practices. These potential
circumventions would result in higher
GHG emissions.
To avoid these concerns, the EPA is
proposing to eliminate the multi-fuel
subcategory for low, intermediate, and
base load combustion turbines in 40
CFR part 60, subpart TTTTa. This
would mean that new multi-fuel-fired
turbines that commence construction or
reconstruction after the date of this
proposal will fall within a particular
subcategory depending on their level of
electric sales. The EPA also proposes
that the performance standards for each
subcategory be adjusted appropriately
for multi-fuel-fired turbines to reflect
the application of the BSER for the
subcategories to turbines burning fuels
with higher GHG emission rates than
natural gas. To be consistent with the
definition of lower emitting fuels in the
2015 Rule, the maximum allowable heat
input-based emissions rate would be
160 lb CO2/MMBtu. For example, a
standard of performance based on
efficient generation would be 33 percent
478 The calculation used to determine the electric
sales threshold includes both the design efficiency
and the base load rating. Since the base load rating
stays the same when adjusting the numeric value
of the design efficiency for applicability purposes,
adjustments to the design efficiency has twice the
impact. Specifically, using three quarters of the
design efficiency reduces the electric sales
threshold by half.
479 Combustion turbines co-firing natural gas with
other fuels must determine fuel-based site-specific
standards at the end of each operating month. The
site-specific standards depend on the amount of cofired natural gas. 80 FR 64616 (October 23, 2015).
480 Note that 40 CFR part 60, subpart TTTT
combustion turbines co-firing 25 percent hydrogen
by volume could be subcategorized as multi-fuelfired EGUs because the percent methane by volume
could fall below 70 percent, the heating value could
fall below 35 MJ/Sm3, and 10 percent of the heat
input could be coming from a fuel not meeting the
definition of natural gas.
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higher for a fuel oil-fired combustion
turbine compared to a natural gas-fired
combustion turbine. This would assure
that the BSER, in this case efficient
generation, is applied, while at the same
time accounting for the use of multiple
fuels. As explained in section VII.F, in
the second phase of the NSPS, the EPA
is proposing to further subcategorize
base load combustion turbines based on
whether the combustion turbine is
combusting hydrogen. During the first
phase of the NSPS, all base load
combustion turbines would be in a
single subcategory. Table 2 summarizes
the proposed electric sales subcategories
for combustion turbines.
TABLE 2—PROPOSED SALES THRESHOLDS FOR SUBCATEGORIES OF COMBUSTION TURBINE EGUS
Electric sales threshold
(percent of potential electric sales)
Subcategory
Low Load ........................................
Intermediate Load ...........................
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Base Load .......................................
≤20 percent.
>20 percent and ≤site-specific value determined based on the design efficiency of the affected facility.
• Between ∼ 33 to 40 percent for simple cycle combustion turbines.
• Between ∼ 45 to 55 percent for combined cycle combustion turbines.
>Site-specific value determined based on the design efficiency of the affected facility.
• Between ∼ 33 to 40 percent for simple cycle combustion turbines.
• Between ∼ 45 to 55 percent for combined cycle combustion turbines.
G. Proposed Standards of Performance
Once the EPA has determined that a
particular system or technology
represents BSER, the CAA authorizes
the Administrator to establish standards
of performance for new units that reflect
the degree of emission limitation
achievable through the application of
that BSER. As noted above, the EPA
proposes that because the technology for
reducing GHG emissions from
combustion turbines is advancing
rapidly, a multi-phase set of standards
of performance, which reflect a multicomponent BSER, is appropriate for
base load and intermediate load
combustion turbines. Under this
approach, for the first phase of the
standards, which applies as of the
effective date the final rule, the BSER is
highly efficient generation for both base
load and intermediate load combustion
turbines. During this phase, owners/
operators of EGUs will be subject to a
numeric standard of performance that is
representative of the performance of the
best performing EGUs in the
subcategory. For the second phase of the
standards, beginning in 2032 and 2035
respectively, the BSER for base load
turbines includes either 30 percent lowGHG hydrogen co-firing or 90 percent
capture CCS, and beginning in 2032 the
BSER for intermediate load EGUs
includes 30 percent low-GHG hydrogen
co-firing. The affected EGUs would be
subject to either an emissions rate that
reflects continued use of highly efficient
generation coupled with CCS, or one
that reflects continued use of highly
efficient generation coupled with cofiring low-GHG hydrogen. For the third
phase of the standards, beginning in
2038 for base load turbines that began
co-firing 30 percent low-GHG hydrogen
in 2032, the BSER includes co-firing 96
percent low-GHG hydrogen. In addition,
the EPA is proposing a single
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component BSER, applicable from the
date of proposal, for low load
combustion turbines.
1. Phase-1 Standards
The first component of the BSER is
the use of highly efficient combined
cycle technology for base load EGUs in
combination with the best operating and
maintenance practices, the use of highly
efficient simple cycle technology in
combination with the best operating and
maintenance practices for intermediate
load EGUs, and the use of lower
emitting fuels for low load EGUs.
For new and reconstructed natural
gas-fired base load combustion turbine
EGUs, the EPA proposes to find that the
most efficient available combined cycle
technology—which qualifies as the
BSER for base load combustion
turbines—supports a standard of 770 lb
CO2/MWh-gross for large natural gasfired EGUs (i.e., those with a nameplate
heat input greater than 2,000 MMBtu/h)
and 900 lb CO2/MWh-gross for natural
gas-fired small EGUs (i.e., those with a
nameplate base load rating of 250
MMBtu/h). The proposed standard of
performance for natural gas-fired base
load EGUs with base load ratings
between 250 MMBtu/h and 2,000
MMBtu/h would be between 900 and
770 lb CO2/MWh-gross and be
determined based on the base load
rating of the combustion turbine.481 The
EPA proposes to find that the most
efficient available simple cycle
technology—which qualifies as the
481 A new small natural gas-fired base load EGU
would determine the facility emissions rate by
taking the difference in the base load rating and 250
MMBtu/h, multiplying that number by 0.0743 lb
CO2/(MW * MMBtu), and subtracting that number
from 900 lb CO2/MWh-gross. The emissions rate for
a NGCC EGU with a base load rating of 1,000
MMBtu/h is 900 lb CO2/MWh-gross minus 750
MMBtu/h (1,000 MMBtu/h¥250 MMBtu/h) times
0.0743 lb CO2/(MW * MMBtu), which results in an
emissions rate of 844 lb CO2/MWh-gross.
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BSER for intermediate load combustion
turbines—supports a standard of 1,150
lb CO2/MWh-gross for natural gas-fired
EGUs. For new and reconstructed low
load combustion turbines, the EPA
proposes to find that the use of lower
emitting fuels—which qualifies as the
BSER—supports a standard that ranges
from 120 lb CO2/MMBtu to 160 lb CO2/
MMBtu depending on the fuel burned.
The EPA proposes these standards to
apply at all times and compliance to be
determined on a 12-operating-month
rolling average basis.
The EPA has determined that these
standards of performance are achievable
specifically for natural gas-fired base
load and intermediate load combustion
turbine EGUs. However, combustion
turbine EGUs burn a variety of fuels,
including fuel oil during natural gas
curtailments. Owners/operators of
combustion turbines burning fuels other
than natural gas would not necessarily
be able to comply with the proposed
standards for base load and intermediate
load natural gas-fired combustion
turbines using highly efficient
generation. Therefore, the Agency is
proposing that owners/operators of
combustion turbines burning fuels other
than natural gas may elect to use the
ratio of the heat input-based emissions
rate of the specific fuel(s) burned to the
heat input-based emissions rate of
natural gas to determine a site-specific
standard of performance for the
operating period. For example, the
NSPS emissions rate for a large base
load combustion turbine burning 100
percent distillate oil during the 12operaitng month period would be 1,070
lb CO2/MWh-gross.482
482 The heat input-based emission rates of natural
gas and distillate oil are 117 and 163 lb CO2/
MMBtu, respectively. The ratio of the heat inputbased emission rates (1.39) is multiplied by the
natural gas-fired standard of performance (770 lb
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To determine what emission rates are
currently achieved by existing highefficiency combined cycle EGUs and
simple cycle EGUs, the EPA reviewed
12-operating-month generation and CO2
emissions data from 2015 through 2021
for all combined and simple cycle EGUs
that submitted continuous emissions
monitoring system (CEMS) data to the
EPA’s emissions collection and
monitoring plan system (ECMPS). The
data were sorted by the lowest
maximum 12-operating-month
emissions rate for each unit to identify
long-term emission rates on a lb CO2/
MWh-gross basis that have been
demonstrated by the existing combined
cycle and simple cycle EGU fleets. Since
an NSPS is a never-to-exceed standard,
the EPA is proposing that use of longterm data are more appropriate than
shorter term data in determining an
achievable standard. These long-term
averages account for degradation and
variable operating conditions, and the
EGUs should be able to maintain their
current emission rates, as long as the
units are properly maintained. While
annual emission rates indicate a
particular standard is achievable for
certain EGUs in the short term, they are
not necessarily representative of
emission rates that can be maintained
over an extended period using highly
efficient generating technology in
combination with best operating and
maintenance practices.
To determine the 12-operating-month
average emissions rate that is achievable
by application of the BSER, the EPA
calculated 12-month CO2 emission rates
by dividing the sum of the CO2
emissions by the sum of the gross
electrical energy output over the same
period. The EPA did this separately for
combined cycle EGUs and simple cycle
EGUs to determine the emissions rate
for the base load and intermediate load
subcategories, respectively.
For base load combustion turbines,
the EPA evaluated three emission rates:
730, 770, and 800 lb CO2/MWh-gross.
An emissions rate of 730 lb CO2/MWhgross has been demonstrated by a single
combined cycle facility—the
Okeechobee Clean Energy Center. This
facility is a large 3-on-1 combined cycle
EGU that commenced operation in 2019
and uses a recirculating cooling tower
for the steam cycle. Each turbine is rated
at 380 MW and the three HRSGs feed a
single steam turbine of 550 MW. The
EPA is not proposing to use the
emissions rate of this EGU to determine
the standard of performance, for
multiple reasons. The Okeechobee
CO2/MWh) to get the applicable emissions rate
(1,070 lb CO2/MWh).
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Clean Energy Center uses a 3-on-1
multi-shaft configuration but, many
combined cycle EGUs use a 1-on-1
configuration. Combined cycle EGUs
using a 1-on-1 configuration can be
designed such that both the combustion
turbine and steam turbine are arranged
on one shaft and drive the same
generator. This configuration has
potential capital cost and maintenance
costs savings and a smaller plant
footprint that can be particularly
important for combustion turbines
enclosed in a building. In addition, a
single shaft configuration has higher net
efficiencies when operated at part load
than a multi-shaft configuration. Basing
the standard of performance on the
performance of multi-shaft combined
cycle EGUs could limit the ability of
owners/operators to construct new
combined cycle EGUs in spaceconstrained areas (typically urban
areas 483) and combined cycle EGUs
with the best performance when
operated as intermediate load EGUs.484
Either of these outcomes could result in
greater overall emissions from the
power sector. An advantage of multishaft (2-on-1 and 3-on-1) configurations
is that the turbine engine can be
installed initially and run as a simple
cycle EGU, with the HRSG and steam
turbines added at a later date, all of
which allows for more flexibility for the
regulated community. In addition, a
single large steam turbine can generate
electricity more efficiently than
multiple smaller steam turbines,
increasing the overall efficiency of
comparably sized combined cycle EGUs.
According to Gas Turbine World 2021,
multi-shaft combined cycle EGUs have
design efficiencies that are 0.7 percent
higher than single shaft combined cycle
EGUs using the same turbine engine.485
The efficiency of the Rankine cycle
(i.e., HRSG plus the steam turbine) is
determined in part by the ability to cool
the working fluid (e.g., steam) after it
has been expanded through the turbine.
All else equal, the lower the
483 Generating electricity closer to electricity
demand can reduce stress on the electric grid,
reducing line losses and freeing up transmission
capacity to support additional generation from
variable renewable sources. Further, combined
cycle EGUs located in urban areas could be
designed as CHP EGUs, which have potential
environmental and economic benefits.
484 Power sector modeling projects that combined
cycle EGUs will operate at lower capacity factors in
the future. Combined cycle EGUs with lower base
load efficiencies, but higher part load efficiencies
could have lower overall emission rates.
485 According to the data in Gas Turbine World
2021, while there is a design efficiency advantage
of going from a 1-on-1 configuration to a 2-on-1
configuration (assuming the same turbine engine)
there is no efficiency advantage of 3-on-1
configurations compared to 2-on-1 configurations.
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33323
temperature that can be achieved, the
more efficient the Rankine cycle. The
Okeechobee Clean Energy Center used a
recirculating cooling system, which can
achieve lower temperatures than EGUs
using dry cooling systems and therefore
would be more efficient and have a
lower emissions rate. However dry
cooling systems have lower water
requirements and therefore could be the
preferred technology in arid regions or
in areas where water requirements
could have significant ecological
impacts. Therefore, the EPA proposes
that the efficient generation standard for
base load EGUs should account for the
use of dry cooling.
Finally, the Okeechobee Clean Energy
Center is a relatively new EGU and full
efficiency degradation might not be
accounted for in the emissions analysis.
Therefore, the EPA is not proposing that
an emissions rate of 730 lb CO2/MWhgross is an appropriate nationwide
standard. However, the EPA is soliciting
comment on whether the use of
alternate working fluid, such as
supercritical CO2, or other potential
efficiency improvements would make
this emissions rate an appropriate
standard of performance for base load
combustion turbines.
An emissions rate of 770 lb CO2/
MWh-gross has been demonstrated by
14 percent of recently constructed
combined cycle EGUs. These turbines
include combined cycle EGUs using 1on-1 configurations and dry cooling, are
manufactured by multiple companies,
and have long-term emissions data that
fully account for potential degradation
in efficiency. One of the best performing
large combined cycle EGUs that has
maintained an emissions rate of 770 lb
CO2/MWh-gross is the Dresden plant,
located in Ohio.486 This 2-on-1
combined cycle facility, uses a
recirculating cooling tower, and has
maintained an emissions rate of 765 lb
CO2/MWh-gross, measured over 12
operating months with 99 percent
confidence. The turbine engines are
rated at 2,250 MMBtu/h, which
demonstrates that the standard of 770 lb
CO2/MWh-gross is achievable at a heat
input rating of 2,000 MMBtu/h. In
addition, while a 2-on-1 configuration
and a cooling tower are more efficient
than a 1-on-1 configuration and dry
cooling, the Dresden Energy Facility
does not use the most efficient
combined cycle design currently
available. Multiple more efficient
designs have been developed since the
486 The Dresden Energy Facility is listed as being
located in Muskingum County, Ohio, as being
owned by the Appalachian Power Company, as
having commenced commercial operation in late
2011. The facility ID (ORISPL) is 55350 1A and 1B.
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Dresden Energy Facility commenced
operation a decade ago that more than
offset these efficiency losses. Therefore,
the EPA proposes that while the
Dresden combined cycle EGUs uses a 2on-1 configuration with a cooling tower,
it demonstrates that an emissions rate of
770 lb CO2/MWh-gross is achievable for
all new large combined cycle EGUs. For
additional information on the EPA
analysis of emission rates for high
efficiency base load combined cycle
EGUs, see the Efficient Generation at
Combustion Turbine Electric Generating
Units TSD, which is available in the
rulemaking docket.
The EPA is not proposing an
emissions rate of 800 lb CO2/MWh-gross
because it does not represent the most
efficient combined cycle EGUs designs.
Nearly half of recently constructed
combined cycle EGUs have maintained
an emissions rate of 800 lb CO2/MWhgross. However, the EPA is soliciting
comment on whether this higher
emissions rate is appropriate on grounds
that it would increase flexibility and
reduce costs to the regulated community
by allowing more available designs to
operate as base load combustion
turbines.
With respect to small combined cycle
combustion turbines, the best
performing unit is the Holland Energy
Park facility in Holland, Michigan,
which commenced operation in 2017
and uses a 2-on-1 configuration and a
cooling tower.487 The 50 MW turbine
engines have individual heat input
ratings of 590 MMBtu/h and serve a
single 45 MW steam turbine. The
facility has maintained a 12-operating
month, 99 percent confidence emissions
rate of 870 lb CO2/MWh-gross. This
long-term data accounts for degradation
and variable operating conditions and
demonstrates that a base load
combustion turbine EGU with a turbine
rated at 250 MMBtu/h should be able to
maintain an emissions rate of 900 lb
CO2/MWh-gross.488 In addition, there is
a commercially available HRSG that
uses supercritical CO2 instead of steam
as the working fluid. This HRSG would
be significantly more efficient than the
487 The Holland Park Energy Center is a CHP
system that uses hot water in the cooling system for
a snow melt system that uses a warm water piping
system to heat the downtown sidewalks to clear the
snow during the winter. Since this useful thermal
output is low temperature, it does not materially
reduce the electrical efficiency of the EGU. If the
useful thermal output were accounted for, the
emissions rate of the Holland Energy Park would be
lower. The facility ID (ORISPL) is 59093 10 and 11.
488 To estimate an achievable emissions rate for
an efficient combined cycle EGU at 250 MMBtu/h
the EPA assumed a linear relationship for combined
cycle efficiency with turbine engines with base load
ratings of less than 2,000 MMBtu/h.
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HRSG that uses dual pressure steam,
which is common for small combined
cycle EGUs.489 When these efficiency
improvements are accounted for, a new
small natural gas-fired combined cycle
EGU would be able to maintain an
emissions rate of 850 lb CO2/MWhgross. Therefore, the Agency is soliciting
comment on whether the small natural
gas-fired base load combustion turbine
standard of performance should be 850
lb CO2/MWh-gross.
In summary, the Agency solicits
comment on the following range of
potential standards of performance:
• New and reconstructed natural gasfired base load combustion turbines
with a heat input rating that is greater
than 2,000 MMBtu/h: a range of 730–
800 lb CO2/MWh-gross;
• New and reconstructed natural gasfired base load combustion turbines
with a heat input rating of 250 MMBtu/
h: a range of 850 to 900 lb CO2/MWhgross.
For intermediate load combustion
turbines, the EPA evaluated the
performance of recently constructed
high efficiency natural gas-fired simple
cycle EGUs. The EPA evaluated three
emission rates for the intermediate load
standard of performance: 1,200, 1,150,
and 1,100 lb CO2/MWh-gross. Sixty two
percent of recently constructed
intermediate load simple cycle EGUs
have maintained an emissions rate of
1,200 lb CO2/MWh-gross, 17 percent
have maintained an emissions rate of
1,150 lb CO2/MWh-gross, and 6 percent
have maintained an emissions rate of
1,100 lb CO2/MWh-gross. However, the
units that have maintained an emissions
rate of 1,100 lb CO2/MWh-gross
generally have a single large
aeroderivative combustion turbine
design. In contrast, the ones that have
maintained an emission rate of 1,150 lb
CO2/MWh-gross have multiple different
designs, including an industrial frame
combustion turbine design, and are
made by multiple manufacturers.
Therefore, the EPA is proposing an
intermediate load standard of
performance of 1,150 lb CO2/MWhgross. The Agency is soliciting comment
on whether the standard should be
1,100 lb CO2/MWh-gross, or whether
that would result in unacceptably high
costs because currently only a single
design for a large aeroderivative simple
cycle turbine would be able to meet this
standard. The Agency is also soliciting
comment on a standard of performance
489 If the combustion turbine engine exhaust
temperature is 500°C or greater, a HRSG using 3
pressure steam without a reheat cycle could
potentially provide an even greater increase in
efficiency (relative to a HRSG using 2 pressure
steam without a reheat cycle).
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of 1,200 lb CO2/MWh-gross. While this
would achieve fewer GHG reductions, it
would increase flexibility, and
potentially reduce costs, to the regulated
community by allowing the currently
available designs to operate as
intermediate load combustion turbines.
For additional information on the EPA
analysis of emission rates for high
efficiency intermediate load simple
cycle EGUs, see the Efficient Generation
at Combustion Turbine Electric
Generating Units TSD, which is
available in the rulemaking docket
The EPA is also soliciting comment
on whether the use of steam injection is
applicable to intermediate load
combustion turbines. Steam injection is
the use of a relatively low cost HRSG to
produce steam that is injected into the
combustion chamber of the combustion
turbine engine instead of using a
separate steam turbine.490 Advantages of
steam injection include improved
efficiency and increases the output of
the combustion turbine as well as
reducing NOX emissions. Combustion
turbines using steam injection have
characteristics in-between simple cycle
and combined cycle combustion
turbines. They are more efficient, but
more complex and have higher capital
costs than simple cycle combustion
turbines without steam injection.
Combustion turbines using steam
injection are simpler and have lower
capital costs than combined EGUs but
have lower efficiencies. The EPA is
aware of a single combustion turbine
that is using steam injection that has
maintained a 12-operaitng month
emission rates of less than 1,000 lb CO2/
MWh-gross. The EPA requests that
commenters include information on
whether this technology would be
applicable to intermediate load
combustion turbines and could be part
of either the first or second component
of the BSER along with cost
information.491
2. Phase-2 Standards
The use of CCS and hydrogen cofiring are both approaches developers
are considering to reduce GHG
emissions beyond highly efficient
generation. However, as noted above,
these approaches apply to different
subcategories and are not applicable to
490 A steam injected combustion turbine would be
considered a combined cycle combustion turbine
(for NSPS purposes) because energy from the
turbine engine exhaust is recovered in a HRSG and
that energy is used to generate additional
electricity.
491 The second component of the BSER, 30
percent low-GHG hydrogen co-firing, would reduce
the emissions rate to 880 lb CO2/MWh-gross.
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the same EGUs. The proposed phase-2
standards are in table 3.
TABLE 3—PHASE-2 STANDARDS OF PERFORMANCE
Subcategory
BSER
Low load .............................................................
Intermediate load ...............................................
Lower emitting fuels .........................................
Highly efficient simple cycle technology coupled with co-firing 30 percent (by volume)
low-GHG hydrogen.
Highly efficient combined cycle technology
coupled with 90 percent CCS.
Highly efficient combined cycle technology
coupled with co-firing 30 percent (by volume) low-GHG hydrogen.
Base load adopting the CCS pathway ..............
Base load adopting the low-GHG hydrogen cofiring pathway.
Co-firing 30 percent by volume lowGHG hydrogen reduces emissions by 12
percent. The EPA applied this percent
reduction to the emission rates for the
intermediate load and base load units
adopting the low-GHG hydrogen cofiring pathway subcategories, to
determine the phase-1 standards. For
the base load combustion turbines
adopting the CCS subcategory, the EPA
reduced the emissions rate by 89
percent to determine the CCS based
phase-2 standards.492 The CCS percent
reduction is based on a CCS system
capturing 90 percent of the emitting CO2
being operational anytime the
combustion turbine is operating.
However, if the carbon capture
equipment has lower availability/
reliability than the combustion turbine
or the CCS equipment takes longer to
startup than the combustion turbine
itself there would be periods of
operation where the CO2 emissions
would not be controlled by the carbon
capture equipment. As noted in section
VII.F.3.b.iii(A)(2) of this preamble, the
operating availability (i.e., the amount
of time a process operates relative to the
Standard of performance
amount of time it planned to operate) of
industrial processes is usually less than
100 percent. Assuming that CO2 capture
achieves 90 percent capture when
available to operate, that CCS is
available to operate 90 percent of the
time the combustion turbine is
operating, and that the combustion
turbine operates the same whether or
not CCS is available to operate, total
emission reductions would be 81
percent. Higher levels of emission
reduction could occur for higher capture
rates coupled with higher levels of
operating availability relative to
operation of the combustion turbine. If
the combustion turbine were not
permitted to operate when CCS was
unavailable, there may be local
reliability consequences or issues
during startup or shutdown, and the
EPA is soliciting comment on how to
balance these issues. Additionally, the
EPA is soliciting comment on the range
of reduction in emission rate of 75 to 90
percent.
The standards of performance for the
intermediate and base load combustion
turbines would also be adjusted based
120–160 lb CO2/MMBtu.
1,000 lb CO2/MWh-gross.
90 lb CO2/MWh-gross.
680 lb CO2/MWh-gross.
on the uncontrolled emission rates of
the fuels relative to natural gas. For 100
percent distillate oil-fired combustion
turbines, the emission rates would be
1,300 lb CO2/MWh-gross, 120 lb CO2/
MWh-gross, and 910 lb CO2/MWh-gross
for the intermediate load, non low-GHG
hydrogen co-firing base load, and lowGHG hydrogen co-firing base load
subcategories respectively.
3. Phase-3 Standards
The third component of the BSER is
applicable to owner/operators of base
load combustion turbines that elect to
implement early GHG reductions (i.e.,
comply with an emissions rate of 680 lb
CO2/MWh-gross starting in January
2032). The phase 3 BSER standard of
performance increases the GHG
reduction requirements and is based on
co-firing 96 percent by volume low-GHG
hydrogen in addition to the use of
highly efficient combined cycle
technology in combination with the best
operating and maintenance practices.
The proposed phase-3 standards are in
table 4.
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TABLE 4—PHASE-3 STANDARDS OF PERFORMANCE
Subcategory
BSER
Standard of performance
Base load electing to implement early GHG reductions.
Highly efficient combined cycle technology
coupled with co-firing 89 percent (by heat
input) low-GHG hydrogen.
90 lb CO2/MWh-gross.
Co-firing 89 percent by heat input (96
percent by volume) low-GHG hydrogen
reduces GHG emissions by 89 percent.
The EPA applied this percent reduction
to the emission rates for base load under
phase 1 of the BSER. Similar to the
phase 1 and 2 standards of performance,
the numeric standard would be adjusted
based on the uncontrolled emission
rates of the fuels relative to natural gas.
For 100 percent distillate oil-fired
combustion turbines, the emission rates
would be 120 lb CO2/MWh-gross.
As a variation on proposing the date
for meeting this standard as 2038, the
EPA solicits comment on proposing the
date as 2035, coupled with authorizing
an approach for crediting early
reductions, under which a source that
achieves reductions due to co-firing
low-GHG hydrogen starting in 2032 may
apply credit for those reductions to its
emission rate beginning in 2035.
Another, more stringent, variation of
this approach would be to allow credit
only for reductions below the emission
rate otherwise required by 2032. Other
492 The 89 percent reduction from CCS accounts
for the increased auxiliary load of a 90 percent post
combustion amine-based capture system. Due to
rounding, the proposed numeric standards of
performance do not necessarily match the standards
that would be determined by applying the percent
reduction to the phase 1 standards.
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variations would allow sources to
generate credits from reductions from
co-firing low-GHG hydrogen, or from
any other reductions below their
standard of performance, in any year
before 2035. In this manner, the source
would be authorized to comply with its
2035 standard in part through use of
credits generated by making reductions
beginning in 2032. Under such an
approach, early credits could only be
used by the unit that generated those
credits. For instance, a unit co-firing 30
percent low-GHG hydrogen prior to
2035 would be able to generate credits
that it could use in 2035 and beyond.
This would allow a unit co-firing lowGHG hydrogen to ramp up the amount
it co-fired over time, while still
achieving the same amount of emission
reductions that would have been
achieved had the unit co-fired enough
low-GHG hydrogen (e.g., 96 percent by
volume) starting in 2035. Another
variation on this approach would be to
treat such a crediting scheme as a
compliance alternative to the CCS BSER
by showing equivalent emission
reductions, rather than the standard
itself.
The EPA proposes the following
mechanism to ensure that affected
sources in the base load subcategory
comply with the applicable standard of
performance in the event that the EPA
finalizes both the CCS pathway (that is,
the use of 90-percent-capture CCS by
2035) and the low-GHG hydrogen
pathway (that is, co-firing 30 percent
low-GHG hydrogen by 2032 and 96
percent by 2038). The EPA proposes
that affected sources must notify the
EPA by January 1, 2031, which pathway
they are selecting, and thus which
standard they intend to comply with. If
they select the low-GHG hydrogen
pathway, they must comply with the
applicable standard based on co-firing
30 percent hydrogen (by volume) in
2032 through 2037. In addition, in 2033
through 2037, they must be prepared to
demonstrate that they complied with
the applicable standard based on cofiring 30 percent low-GHG hydrogen in
the preceding years, beginning in 2032.
In 2038, they must comply with the
applicable standard based on co-firing
96 percent (by volume) now-GHG
hydrogen.
H. Reconstructed Stationary
Combustion Turbines
In the previous sections, the EPA
explained the background of and
requirements for new and reconstructed
stationary combustion turbines and
evaluated various control technology
configurations to determine the BSER.
Because the BSER is the same for new
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and reconstructed stationary
combustion turbines, the Agency is
proposing to use the same emissions
analysis for both new and reconstructed
stationary combustion turbines. For
each of the subcategories, the EPA is
proposing that the proposed BSER
results in the same standard of
performance for new stationary
combustion turbines and reconstructed
stationary combustion turbines. Since
reconstructed turbines could likely
incorporate technologies to co-fire
hydrogen as part of the reconstruction
process at little or no cost, the low-GHG
hydrogen co-firing would likely to be
similar to those for newly constructed
combustion turbines. For CCS, the EPA
approximated the cost to add CCS to a
reconstructed combustion turbine by
increasing the capital costs of the carbon
capture equipment by 10 percent
relative to the costs for a newly
constructed combustion turbine. This
increases the capital cost from $949/kW
to $1,044/kW.493 Using a 12-year
amortization period, a 90 percentcapture amine-based post combustion
CCS system increases the LCOE by $8.5/
MWh and has overall CO2 abatement
costs of $25/ton ($28/metric ton).
A reconstructed stationary
combustion turbine is not required to
meet the standards if doing so is
deemed to be ‘‘technologically and
economically’’ infeasible.494 This
provision requires a case-by-case
reconstruction determination in the
light of considerations of economic and
technological feasibility. However, this
case-by-case determination would
consider the identified BSER, as well as
technologies the EPA considered, but
rejected, as BSER for a nationwide rule.
One or more of these technologies could
be technically feasible and of reasonable
cost, depending on site-specific
considerations and if so, would likely
result in sufficient GHG reductions to
comply with the applicable
reconstructed standards. Finally, in
some cases, equipment upgrades, and
best operating practices would result in
sufficient reductions to achieve the
reconstructed standards.
I. Modified Stationary Combustion
Turbines
CAA section 111(a)(4) defines a
‘‘modification’’ as ‘‘any physical change
in, or change in the method of operation
of, a stationary source’’ that either
‘‘increases the amount of any air
pollutant emitted by such source or . . .
493 The kW value used as reference for the costs
is the output from the combined cycle EGU prior
to the installation of the CCS.
494 40 CFR 60.15(b)(2).
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results in the emission of any air
pollutant not previously emitted.’’
Certain types of physical or operational
changes are exempt from consideration
as a modification. Those are described
in 40 CFR 60.2, 60.14(e).
In the 2015 NSPS, the EPA did not
finalize standards of performance for
stationary combustion turbines that
conduct modifications; instead, the EPA
concluded that it was prudent to delay
issuing standards until the Agency
could gather more information (80 FR
64515; October 23, 2015). There were
several reasons for this determination:
few sources had undertaken NSPS
modifications in the past, the EPA had
little information concerning them, and
available information indicated that few
owners/operators of existing
combustion turbines would undertake
NSPS modifications in the future; and
since the Agency eliminated proposed
subcategories for small EGUs in the
2015 NSPS, questions were raised as to
whether smaller existing combustion
turbines that undertake a modification
could meet the final performance
standard of 1,000 lb CO2/MWh-gross.
It continues to be the case that the
EPA is aware of no evidence indicating
that owners/operators of combustion
turbines intend to undertake actions
that could qualify as NSPS
modifications in the future. EPA is not
proposing, or soliciting comment on
whether it should propose, standards of
performance for modifications of
combustion turbines.
J. Startup, Shutdown, and Malfunction
In its 2008 decision in Sierra Club v.
EPA, 551 F.3d 1019 (D.C. Cir. 2008), the
U.S. Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) vacated
portions of two provisions in the EPA’s
CAA section 112 regulations governing
the emissions of HAP during periods of
SSM. Specifically, the court vacated the
SSM exemption contained in 40 CFR
63.6(f)(1) and 40 CFR 63.6(h)(1), holding
that, the SSM exemption violates the
requirement under section 302(k) of the
CAA that some CAA section 112
standard apply continuously. Consistent
with Sierra Club v. EPA, the EPA is
proposing standards in this rule that
apply at all times. The NSPS general
provisions in 40 CFR 60.11(c) currently
exclude opacity requirements during
periods of startup, shutdown, and
malfunction and the provision in 40
CFR 60.8(c) contains an exemption from
non-opacity standards. These general
provision requirements would
automatically apply to the standards set
in an NSPS, unless the regulation
specifically overrides these general
provisions. The NSPS subpart TTTT (40
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CFR part 60 subpart TTTT), does not
contain an opacity standard, thus, the
requirements at 40 CFR 60.11(c) are not
applicable. The NSPS subpart TTTT
also overrides 40 CFR 60.8(c) in table 3
and requires that sources comply with
the standard(s) at all times. In reviewing
NSPS subpart TTTT and proposing the
new NSPS subpart TTTTa, the EPA is
proposing to retain in subpart TTTTa
the requirements that sources comply
with the standard(s) at all times.
Therefore, the EPA is proposing in table
3 of the new subpart TTTTa to override
the general provisions for SSM
provisions. The EPA is proposing that
all standards in subpart TTTTa apply at
all times.
The EPA has attempted to ensure that
the general provisions we are proposing
to override are inappropriate,
unnecessary, or redundant in the
absence of the SSM exemption. The
EPA is specifically seeking comment on
whether we have successfully done so.
In proposing the standards in this
rule, the EPA has taken into account
startup and shutdown periods and, for
the reasons explained in this section of
the preamble, has not proposed
alternate standards for those periods.
The EPA analysis of achievable
standards of performance used CEMS
data that includes all period of
operation. Since periods of startup,
shutdown, and malfunction were not
excluded from the analysis, the EPA is
not proposing alternate standard for
those periods of operation.
Periods of startup, normal operations,
and shutdown are all predictable and
routine aspects of a source’s operations.
Malfunctions, in contrast, are neither
predictable nor routine. Instead, they
are, by definition, sudden, infrequent,
and not reasonably preventable failures
of emissions control, process, or
monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as
not requiring emissions that occur
during periods of malfunction to be
factored into development of CAA
section 111 standards. Nothing in CAA
section 111 or in case law requires that
the EPA consider malfunctions when
determining what standards of
performance reflect the degree of
emission limitation achievable through
‘‘the application of the best system of
emission reduction’’ that the EPA
determines is adequately demonstrated.
While the EPA accounts for variability
in setting standards of performance,
nothing in CAA section 111 requires the
Agency to consider malfunctions as part
of that analysis. The EPA is not required
to treat a malfunction in the same
manner as the type of variation in
performance that occurs during routine
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operations of a source. A malfunction is
a failure of the source to perform in a
‘‘normal or usual manner’’ and no
statutory language compels the EPA to
consider such events in setting CAA
section 111 standards of performance.
The EPA’s approach to malfunctions in
the analogous circumstances (setting
‘‘achievable’’ standards under CAA
section 112) has been upheld as
reasonable by the D.C. Circuit in U.S.
Sugar Corp. v. EPA, 830 F.3d 579, 606–
610 (2016).
K. Testing and Monitoring Requirements
Because the NSPS reflects the
application of the best system of
emission reduction under conditions of
proper operation and maintenance, in
doing the NSPS review, the EPA also
evaluates and determines the proper
testing, monitoring, recordkeeping and
reporting requirements needed to ensure
compliance with the NSPS. This section
will include a discussion on the current
testing and monitoring requirements of
the NSPS and any additions the EPA is
proposing to include in 40 CFR part 60,
subpart TTTTa.
1. General Requirements
The current rule allows three
approaches for determining compliance
with its emissions limits: Continuous
measurement using CO2 CEMS and flow
measurements for all EGUs; calculations
using hourly heat input and ‘F’
factors 495 for EGUs firing uniform oil or
gas or non-uniform fuels; or Tier 3
calculations using fuel use and carbon
content as described in GHGRP
regulations for EGUs firing non-uniform
fuels. The first two approaches are in
use for carbon dioxide by the Acid Rain
program (40 CFR part 75), to which
most, if not all, of the EGUs affected by
NSPS subpart TTTT are already subject,
while the last approach is in use for
carbon dioxide, nitrous oxide, and
methane reporting from stationary fuel
combustion sources (40 CFR part 98,
subpart C).
The EPA believes continuing the use
of these familiar approaches already in
use by other programs represents a costeffective means of obtaining quality
assured data requisite for determining
carbon dioxide mass emissions.
Therefore, no changes to the current
ways of collecting carbon dioxide and
associated data needed for mass
determination, such as flow rates, fuel
heat content, fuel carbon content, and
the like, are proposed. Because no
changes are proposed and because the
495 An F factor is the ratio of the gas volume of
the products of combustion to the heat content of
the fuel.
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33327
cost and burden for EGU owners or
operators are already accounted for by
other rulemakings, this aspect of the
proposed rule is designed to have
minimal, if any, cost or burden
associated with carbon dioxide testing
and monitoring. In addition, the
proposal contains no changes to
measurement and testing requirements
for determining electrical output, both
gross and net, as well as thermal output,
to current existing requirements.
However, the EPA requests comment
on whether continuous carbon dioxide
and flow measurements should become
the sole means of compliance for this
rule. Such a switch would increase costs
for those EGU owners or operators who
are currently relying on the oil- or gasfired or non-uniform fuel-fired
calculation-based approaches for
compliance. By way of reference, the
annualized cost associated with
adoption and use of continuous carbon
dioxide and flow measurements where
none now exist is estimated to be about
$52,000. To the extent that the rule were
to mandate continuous carbon dioxide
and flow measurements in accordance
with what is currently allowed as one
option and that an EGU lacked this
instrumentation, its owner or operator
would need to incur this annual cost to
obtain such information and to keep the
instrumentation calibrated.
2. Requirements for Sources
Implementing CCS
The CCS process is also subject to
monitoring and reporting requirements
under the EPA’s GHGRP (40 CFR part
98). The GHGRP requires reporting of
facility-level GHG data and other
relevant information from large sources
and suppliers in the U.S. The ‘‘suppliers
of carbon dioxide’’ source category of
the GHGRP (GHGRP subpart PP)
requires those affected facilities with
production process units that capture a
CO2 stream for purposes of supplying
CO2 for commercial applications or that
capture and maintain custody of a CO2
stream in order to sequester or
otherwise inject it underground to
report the mass of CO2 captured and
supplied. Facilities that inject a CO2
stream underground for long-term
containment in subsurface geologic
formations report quantities of CO2
sequestered under the ‘‘geologic
sequestration of carbon dioxide’’ source
category of the GHGRP (GHGRP subpart
RR). In 2022, to complement GHGRP
subpart RR, the EPA proposed the
‘‘geologic sequestration of carbon
dioxide with enhanced oil recovery
(EOR) using ISO 27916’’ source category
of the GHGRP (GHGRP subpart VV) to
provide an alternative method of
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reporting geologic sequestration in
association with EOR.496 497 498
The current rule leverages the
regulatory requirements under GHGRP
subpart RR and does not reference
GHGRP subpart VV. The EPA is
proposing that any affected unit that
employs CCS technology that captures
enough CO2 to meet the proposed
standard and injects the captured CO2
underground must report under GHGRP
subpart RR or proposed GHGRP subpart
VV. If the emitting EGU sends the
captured CO2 offsite, it must assure that
the CO2 is managed at a facility subject
to the GHGRP requirements, and the
facility injecting the CO2 underground
must report under GHGRP subpart RR or
proposed GHGRP subpart VV. This
proposal does not change any of the
requirements to obtain or comply with
a UIC permit for facilities that are
subject to the EPA’s UIC program under
the Safe Drinking Water Act.
The EPA also notes that compliance
with the standard is determined
exclusively by the tons of CO2 captured
by the emitting EGU. The tons of CO2
sequestered by the geologic
sequestration site are not part of that
calculation, though the EPA anticipates
that the quantity of CO2 sequestered will
be substantially similar to the quantity
captured. However, to verify that the
CO2 captured at the emitting EGU is
sent to a geologic sequestration site, we
are leveraging regulatory reporting
requirements under the GHGRP. The
BSER is determined to be adequately
demonstrated based solely on geologic
sequestration that is not associated with
EOR. However, EGUs also have the
compliance option to send CO2 to EOR
facilities that report under GHGRP
subpart RR or proposed GHGRP subpart
VV. We also emphasize that this
proposal does not involve regulation of
downstream recipients of captured CO2.
That is, the regulatory standard applies
exclusively to the emitting EGU, not to
any downstream user or recipient of the
captured CO2. The requirement that the
496 87
FR 36920 (June 21, 2022).
Standards Organization (ISO)
standard designated as CSA Group (CSA)/American
National Standards Institute (ANSI) ISO
27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage—Carbon
Dioxide Storage Using Enhanced Oil Recovery (CO2EOR) (referred to as ‘‘CSA/ANSI ISO 27916:2019’’).
498 As described in 87 FR 36920 (June 21, 2022),
both subpart RR and proposed subpart VV (CSA/
ANSI ISO 27916:2019) require an assessment and
monitoring of potential leakage pathways;
quantification of inputs, losses, and storage through
a mass balance approach; and documentation of
steps and approaches used to establish these
quantities. Primary differences relate to the terms in
their respective mass balance equations, how each
defines leakage, and when facilities may
discontinue reporting.
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emitting EGU assure that captured CO2
is managed at an entity subject to the
GHGRP requirements is thus exclusively
an element of enforcement of the EGU
standard. This will avoid duplicative
monitoring, reporting, and verification
requirements between this proposal and
the GHGRP, while also ensuring that the
facility injecting and sequestering the
CO2 (which may not necessarily be the
EGU) maintains responsibility for these
requirements. Similarly, the existing
regulatory requirements applicable to
geologic sequestration are not part of the
proposed rule.
3. Requirements for Sources Co-Firing
Low-GHG Hydrogen
Because the EPA is basing its
proposed definition of low-GHG
hydrogen consistent with IRC section
45V(b)(2)(D), it is reasonable, if possible
and practicable, for the EPA to adopt, in
whole or in part, the eligibility,
monitoring, verification, and reporting
protocols associated with IRC section
45V(b)(2)(D) when finalized by Treasury
for the production of low-GHG
hydrogen, and apply those protocols, as
applicable, to requirements the EPA
establishes for the demonstration by
EGUs that they are using low-GHG
hydrogen. Adopting very similar
requirements for demonstrations by
EGUs that they are using low-GHG
hydrogen would help ensure there are
not dueling eligibility requirements for
low-GHG hydrogen production with
overall emissions rates of 0.45 kg CO2e/
kg H2 or less. Adopting similar methods
for assessing GHG emissions associated
with hydrogen production pathways
would create clarity and certainty and
reduce confusion.
The EPA is taking comment on its
proposal to closely follow Treasury
protocols in determining how EGUs
demonstrate compliance with the fuel
characteristics required in this
rulemaking. The EPA is taking comment
on what forms of acceptable
mechanisms and documentary evidence
should be required for EGUs to
demonstrate compliance with the
obligation to co-fire low-GHG hydrogen,
including proof of production pathway,
overall emissions calculations or
modeling results and input, purchasing
agreements, contracts, and energy
attribute certificates. Given the
complexities of tracking produced
hydrogen and the public interest in such
data, the EPA is also taking comment on
whether EGUs should be required to
make fully transparent their sources of
low-GHG hydrogen and the
corresponding quantities procured. The
EPA is also seeking comment on
requiring that EGUs using low-GHG
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hydrogen demonstrate that their
hydrogen is exclusively from facilities
that only produce low-GHG hydrogen,
as a means of reducing demonstration
burden and opportunities for double
counting that could otherwise occur for
hydrogen purchased from facilities that
produce multiple types of hydrogen and
the complex recordkeeping and
documentation that would be necessary
to reliably verify that the hydrogen
purchased from such facilities qualifies.
The EPA solicits comment on a
mechanism to operationalize such a
provision.
Treasury is currently developing
implementing rules for IRC section 45V.
Congress specified that tax credit
eligibility for the credit tiers
(45V(b)(2)(A), 45(V)(b)(2)(B), 45(b)(2)(C),
and 45V(b)(2)(D)) should be based on an
assessment of the estimated well-togate 499 GHG emissions of hydrogen
production, determined based on the
most recent Greenhouse gases,
Regulated Emissions, and Energy use in
Transportation model (GREET model) or
a successor model as determined by the
Secretary of Treasury. Consistent with
its proposal to define low-GHG
hydrogen consistent with IRC section
45V(b)(2)(D), the EPA is also proposing
that, for the purpose of demonstrating
compliance with the requirement to
combust low-GHG hydrogen under this
NSPS, the maximum extent possible the
same methodology specified in IRC
section 45V and requirements currently
under development should apply. One
example would be requiring that the
owner/operator of the combustion
turbine obtain from the hydrogen
producer from which they purchase
low-GHG hydrogen the hydrogen
producer’s calculation of GHG levels
associated with its hydrogen production
using the GREET well-to-gate analysis.
The GREET model is well established,
designed to adapt to evolving
knowledge, and capable of including
technological advances. The EPA
solicits comment on whether the
Agency should consider unrelated or
third-party verification as part of the
standards required for EGUs to
demonstrate compliance. Given the
499 Well-to-gate analysis of lifecycle GHG
emissions represents a smaller scope than cradle-tograve analysis. Well-to-gate emissions of hydrogen
production include those associated with fossil fuel
or electricity feedstock production and delivery to
the hydrogen facility; the hydrogen production
process itself; and any associated CCS applied at
the hydrogen production facility. Well-to-gate
analysis does not consider emissions associated
with the manufacture or end-of-life of the hydrogen
production facility or facilities providing feedstock
inputs to the hydrogen production facility. Nor does
it consider emissions associated with
transportation, distribution, and use of hydrogen
beyond the production facility.
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sequential timing of EPA and Treasury
processes, the EPA may take further
action, after promulgation of this NSPS,
to provide additional guidance on
application of Treasury’s framework for
IRC section 45V to this particular
context. The EPA requests comment on
its proposal to adopt as much as
possible the methodology specified in
IRC section 45V and any associated
implementing requirements established
by Treasury, once the methodology and
implementing requirements are
finalized, as part of the obligations for
EGUs to demonstrate compliance with
the requirement to combust low-GHG
hydrogen under this NSPS.
Although proposing to incorporate as
much as possible Treasury’s eligibility,
monitoring, reporting, and verification
protocols, the EPA recognizes that
Treasury protocols concern hydrogen
production, whereas the EPA’s
proposed requirements apply to affected
EGUs that use the hydrogen to
demonstrate compliance with the lowGHG hydrogen co-firing obligations. The
EPA is also taking comment on several
underlying policy issues relevant to
ensuring that hydrogen used to comply
with this rule is low-GHG hydrogen.
One reason that the EPA is considering
whether an alternative method to the
Treasury guidance may be needed to
determine whether hydrogen meets the
requirements to be considered low-GHG
is because hydrogen production
facilities that begin construction after
2032 will not be eligible for the tax
credits. The EPA wants to make sure a
pathway exists for low-GHG hydrogen
to be used for compliance purposes
even if the producer began construction
after 2032 and is not receiving tax
credits.
Given this and other uncertainties, the
EPA is taking comment on issues that
would be relevant should the Agency
develop its own protocols for EGUs to
demonstrate compliance with the
overall emissions rate in IRC section
45V(b)(2)(D) for co-firing as BSER in this
rulemaking.
The EPA is also taking comment on
strategies the EPA could adopt to inform
its own eligibility, monitoring, reporting
and verification protocols for ensuring
compliance with the 0.45 kg CO2e/kg H2
or less emission rate for compliance
with the low-GHG provisions of this
rule, if the EPA does not adopt
Treasury’s protocols. The purpose of
these strategies would be to ensure that
EGUs are using only low-GHG
hydrogen, i.e., hydrogen that results in
GHG emissions of less than 0.45 kg CO2
per kg H2. The EPA is taking comment
on the appropriateness of requiring
EGUs to provide verification that the
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hydrogen they use complies with this
standard, as demonstrated by the
GREET model for estimating the GHG
emissions associated with hydrogen
production from well-to-gate, and to
what extent EGUs should be required to
verify the accuracy of the energy inputs
and conclusions of the GREET model for
the hydrogen used by the EGU to
comply with this rule.
Several important considerations with
respect to determining overall GHG
emissions rates for hydrogen production
pathways have been raised by
researchers and have been picked up in
trade press coverage.500 501 Given the
importance of these issues, the recent
accumulation of relevant research, and
the range of stakeholder positions, the
EPA is taking comment on the need for
(and design of) approaches and
appropriate timeframes for allowing
EGUs to meet requirements for
geographic and temporal alignment
requirements to verify that the hydrogen
used by the EGU is compliant with this
rulemaking, recognizing that EPA’s lowGHG standard for compliance would not
begin until 2032. The EPA is soliciting
comment on these issues, as they relate
to co-firing low-GHG hydrogen in
combustion turbines and the requisite
need to only utilize the lowest-GHG
hydrogen in these applications as
specified in IRC section 45V,
specifically IRC section 45V(b)(2)(D).
The EPA notes this is one of multiple
forthcoming opportunities for public
comment on this suite of issues, and the
EPA’s proposal is specific to low-GHG
hydrogen in the context of qualifying a
co-firing fuel as part of BSER.
It is important to note that the
landscape for methane emissions
monitoring and mitigation is changing
rapidly. For example, the EPA is in the
process of developing enhanced data
reporting requirements for petroleum
and natural gas systems under its
GHGRP, and is in the process of
finalizing requirements under New
Source Performance Standards and
Emission Guidelines for the oil and gas
sector that will result in mitigation of
methane emissions. With these changes,
it is expected that the quality of data to
verify methane emissions will improve
and methane emissions rates will
change over time. Adequately
identifying and accounting for overall
emissions associated with methanebased feedstocks is essential in the
determination of accurate overall
500 Without Sufficient Guardrails, the Hydrogen
Tax Credit Could Increase Emissions—Union of
Concerned Scientists. ucsusa.org.
501 Hydrogen’s Power Grid Demands Under
Scrutiny in Tax Credit. bloomberglaw.com.
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emissions rates to comply with the lowGHG hydrogen standards in this rule.
The EPA is taking comment on how
methane leak rates can be appropriately
quantified and conservatively estimated
given the inherent uncertainties and
wide range of basin-specific
characteristics. The EPA is soliciting
comment on whether EGUs should be
required to produce a demonstration of
augmented in-situ monitoring
requirements to determine upstream
emissions when methane feedstock is
used for low-GHG hydrogen used by the
EGU for compliance with this rule. The
EPA is also taking comment on whether
EGUs should use a default assumption
for upstream methane leak rates in the
event monitoring protocols are not
finalized as part of this rulemaking, and
what an appropriate default leak rate
should be, including what evidence
would be necessary for the EGU to
deviate from that default assumption.
The EPA is also taking comment on the
appropriateness of requiring EGUs to
provide CEMS data for SMR or ATR
processes seeking to produce qualifying
low-GHG hydrogen for co-firing to
ensure the amount of carbon captured
by CCS is properly and consistently
monitored and outage rates and times
are recorded and considered. The EPA
is soliciting comment on providing
EGUs with a representative and climateprotective default assumption for carbon
capture rates associated with SMR and
ATR hydrogen pathways, inclusive of
outages, if CCS is used for low-GHG
hydrogen production as part of this
rulemaking, including what evidence
would be necessary for the EGU to
deviate from that default assumption.
These topics are particularly important
to ensuring use of low-GHG hydrogen
given the DOE estimate that by 2050,
reformation-based production with CCS
may account for 50–80 percent of total
U.S. hydrogen production.502 The EPA
is taking comment on requiring
substantiation of energy inputs used in
any overall GHG emissions assessment
for hydrogen production used by EGUs
for compliance with this requirement.
In comparison with petrochemicalbased hydrogen production pathways
discussed above, electrolyzer-based
hydrogen production has the potential
for lower-GHG hydrogen because the
technology is based on splitting water
(H2O) molecules rather than splitting
hydrocarbons (e.g., CH4).503 For EGUs
502 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf.
503 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
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relying on hydrogen produced using
this pathway, the EPA is seeking
comment on the method for assuring
that energy inputs to that production are
consistent with the low-GHG hydrogen
standard that EGUs would be required
to meet under this rule. Specifically, the
EPA is taking comment on requiring
EGUs to provide substantiation of lowGHG energy inputs into any overall
emissions assessment for electrolytic
hydrogen production pathways for
hydrogen used by the EGUs to comply
with the low-GHG hydrogen standard in
this rule. Energy Attribute Certificates
(EACs) (EACs from renewable sources
are sometimes known as Renewable
Energy Credits or RECs) are produced
for each megawatt hour of low-GHG
generation and therefore offer a
measurable, auditable, and verifiable
approach for determining the GHG
emissions associated with the energy
used to make the low-GHG hydrogen.
EACs with specific attributes are
commonly used in the electricity
markets to substantiate corporate clean
energy commitments and use, as well as
for utility compliance with State RPS
and CES programs. The EPA is taking
comment on requiring EGUs to provide
EAC verification for low-GHG emission
energy inputs into GHG emissions
assessments for hydrogen used by that
EGU to comply with the low-GHG
standard in this rule, for all hydrogen
pathways. The EPA is seeking comment
on allowing EGUs to use EACs as part
of the documentation required for
verifying the use of low-GHG hydrogen.
The EPA is taking comment on
allowing EGUs to comply with the lowGHG hydrogen standard in this rule if
they demonstrate that the hydrogen
used is produced from: (1) dedicated
low-GHG emitting electricity from a
generator sited on the utility side of a
meter that is contractually obligated to
a electrolyzer, (2) a generator collocated
with an electrolyzer and sited behind a
common utility meter, or (3) a generator
whereby the electrolyzer and generator
are collocated but not interconnected to
the grid and have no grid exchanges of
power. The EPA is also taking comment
on approaches for EGUs to demonstrate
that purchased hydrogen produced from
an electrolyzer could meet the low-GHG
standard, in whole or part, through an
allotment of zero emitting electricity to
a portion of the electrolyzer’s hydrogen
output. Many announced hydrogen
production projects pair electrolyzers
with renewable (including
hydroelectric) or nuclear energy, which
are likely capable of producing lowwp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf.
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GHG hydrogen. Wind and solar
renewable generation sources are
variable, and nuclear units go offline for
refueling purposes. In these cases, and
others, grid-based electricity, which
often has a high carbon intensity might
be pursued in combination with EACs
for each megawatt hour of grid-based
energy used. Aligning the time and
place (temporal and geographic
alignment) of EACs used to allocate and
describe delivered grid-based electricity
consumed could potentially help ensure
that hydrogen used is low-GHG
hydrogen.504 Some degree of alignment
geographically, for example delivery of
power to the balancing authority in
which the electricity is consumed by the
electrolyzer, could ensure that EACs
used are representative of the allocation
of the energy mix consumed by the
electrolyzers. However, alignment could
also entail trade-offs, about which the
EPA would like more information.
In the case of temporal matching, the
central issue is whether a producer must
obtain sufficient EACs to match the total
electricity demand of the electrolyzer on
an annual basis corresponding to an
overall emissions rates of 0.45 kg CO2e/
kg H2 or less, or whether the producer
must verify that it has obtained an EAC
for low carbon generation on a more
granular timeframe, such as an hourly or
monthly basis, for each time period the
electrolyzer is running. In other words,
how can book and claim methods for
grid-connected systems be developed to
reliably claim total energy input
emissions are equivalent to a pure offgrid zero-carbon emitting system.
Considerations around how grid-based
electricity can effectively assure zerocarbon emitting energy inputs as
validated by EACs have received greater
attention since passage of the IRA.
Solutions offered by researchers at
Princeton University include requiring
new grid-based hydrogen producers to
match 100 percent of electricity
consumption on an hourly basis with
new carbon-free generation
(substantiated through EACs with
hourly attributes), with an estimated
cost impact of $1/kg.505 Other research
analyzing near-term emissions benefits
of hourly EAC alignment with respect to
IRC section 45V implementation is
growing, with some divergent views
about the emissions benefits of more
precise alignment requirements.506
504 ‘‘How Can Hydrogen Producers Show That
They Are ‘‘Clean’’?, Resources for the Future,
October 27, 2022.
505 Princeton Citation: Minimizing emissions
from grid-based hydrogen production in the United
States—IOPscience January 2023.
506 American Council on Renewable Energy
(ACORE), ‘‘Analysis of Hourly & Annual GHG
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Several research papers have focused on
the expense, trade-offs, and benefits of
phasing in new and hourly EAC
alignment requirements.507 An MIT
Energy Initiative Working Paper
examined emissions benefits of hourly
alignment and supported a ‘‘ ‘a phased
approach’. . . annual matching in the
near term with a re-evaluation leaning
towards hourly matching later on in the
decade’’.508 A Rhodium Report found
that while ‘‘[r]equiring a high degree of
stringency across regional, temporal,
and additionality variables on day one
. . . increases the total subsidized cost
of hydrogen production’’ in the initial
phase of the program, and concludes
that ultimately ‘‘policymakers can’t
ignore the long-term emissions risk’’
and recommends, ‘‘[t]o construct
emissions guardrails, the IRS can
establish target dates for ratcheting up
the certainty on key implementation
details like a transition to more
temporally granular matching. Such
phase-in approaches give the hydrogen
and power industries the signposts they
need to develop the tracking tools,
calculation approaches, contract
language, and other key elements to
assure green hydrogen contributes to
decarbonization.’’ 509 This analysis did
not consider potential system-wide
emissions impacts if costs present a
near-term barrier to electrolytic
hydrogen production, and reformationbased methods continue to dominate
hydrogen production market share
moving forward. Other research, for
example from Princeton, supports
hourly time-matching, additionality,
and location requirements—arguing that
all three pillars are important in
ensuring low-GHG outcomes and that
additional costs are not unreasonable.
Research by Energy Innovation aligns
with the Princeton study with respect to
locational and additionality
requirements and diverges in its
recommendation of phasing in hourly
EAC requirements by 2026.510
Emissions: Accounting for Hydrogen Production’’,
April 2023. acore.org.
507 Energy Futures Initiative, ‘‘The Hydrogen
Demand Action Plan’’, February 2023. https://
energyfuturesinitiative.org/wp-content/uploads/
sites/2/2023/02/EFI-Hydrogen-Hubs-FINAL-2-1.pdf.
508 MIT Energy Initiative, April 2023 ‘‘Producing
hydrogen from electricity: How modeling
additionality drives the emissions impact of timematching requirements’’ Anna Cybulsky, Michael
Giovanniello, Tim Schittekatte, Dharik S.
Mallapragada.
509 Rhodium Group, ‘‘Scaling Green Hydrogen in
a post-IRA World’’ March 16, 2023. https://rhg.com/
research/scaling-clean-hydrogen-ira/.
510 https://energyinnovation.org/wp-content/
uploads/2023/04/Smart-Design-Of-45V-HydrogenProduction-Tax-Credit-Will-Reduce-Emissions-AndGrow-The-Industry.pdf.
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The European Commission proposed
a phased-in approach to defining what
constitutes ‘renewable hydrogen’ for the
European Union (EU). The EU
framework includes multiple
components including temporal
alignment requirements: monthly EAC
alignment is required at the onset of the
program, and hourly EAC alignment
requirements are phased-in by
2030.511 512 An impact assessment of the
temporal alignment requirements is to
be completed in 2028 and could impact
the timing of the hourly EAC phase-in
requirements. The EU hydrogen
requirements and conditions will apply
to domestic producers and imports and
do not expire. EAC alignment
requirements impact both new and
existing projects. Geographic alignment
for EACs is required at the onset of the
EU program, whereas vintage
requirements necessitating new zerocarbon emitting energy source-based
generation, often called ‘additional’, are
phased in after 2028. The EU proposal
was released in February and must be
approved by the European Parliament
and the Council of the EU within four
months: amendments to the underlying
policy are not permitted. Notably,
unlike the United States, the EU has a
carbon policy for power sector
emissions that could help ensure that
additional electricity demand from
hydrogen production does not result in
additional power sector CO2 emissions.
The EU and stakeholders examining
costs and benefits of temporal EAC
alignment requirements generally find
that hourly EAC alignment is preferred
before the 2032 proposed effective date
of hydrogen co-firing requirements in
this proposed rule, with most
converging on or before 2030.513 514
The EPA is soliciting comment on
requiring EGUs to use geographic and
511 C_2023_1087_1_EN_ACT_part1_v8.pdf.
(europa.eu)
512 European Commission, ‘‘Commission sets out
rules for renewable hydrogen’’ Brussels, February
13, 2023. See: Hydrogen (europa.eu), Delegated
regulation on Union methodology for RFNBOs.
(europa.eu)
513 https://energyinnovation.org/wp-content/
uploads/2023/04/Smart-Design-Of-45V-HydrogenProduction-Tax-Credit-Will-Reduce-Emissions-AndGrow-The-Industry.pdf.
514 April 12, 2023, memorandum, ‘‘How annual
matching for the Inflation Reduction Act’s (IRA)
45V clean hydrogen tax credit can accelerate
progress towards the Biden administration’s
decarbonization and clean hydrogen goals’’ signed
by 23 companies, addressed to Treasury Secretary
Janet Yellen, Energy Secretary Jennifer Granholm
and Senior Advisor to the President for Clean
Energy Innovation and Implementation Mr. John
Podesta, indicated an openness to examine hourly
EAC requirements in 2032 or earlier and asserted,
‘‘recent studies warn that overly stringent temporal
matching would hinder the development of clean
hydrogen industry.’’
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temporal alignment approaches for
EAC-related requirements and the
appropriate timing and trade-offs of
such approaches. The EPA is soliciting
comment on the appropriateness of
requiring geographic alignment for
EACs used in conjunction with energy
inputs at the balancing authority level at
the onset of the compliance period for
BSER in 2032. Similarly, the EPA is
soliciting comments on the
appropriateness of requiring hourly EAC
alignment requirements at the onset of
the compliance period for BSER in
2032. Relatedly, the EPA is taking
comment on whether any hourly EAC
alignment requirements should affect
both existing and new projects
beginning in 2032, regardless of when a
project became operational and a
recipient of IRC section 45V credits.
Hourly tracking systems are evolving
to meet this need in real time. For
example, PJM announced it would
introduce EACs with hourly data
stamping for low-GHG generators in
March 2023. M–RETS, a regional
attribute tracking system headquartered
in the Midwest, has also introduced the
capability to track hourly energy
attributes. While several tracking
systems are announcing or have started
issuing hourly EACs, standardized
methods, and nationwide coverage is
still developing. Recognizing that the
timing of EPA’s proposed regulations
would not require such tracking systems
to be fully functional until the 2030s,
the EPA is taking comment on the
suitability of emerging and
differentiated tracking systems to
provide the infrastructure for hourly
energy attribute tracking for EGUs
complying with low-GHG hydrogen
standards. The EPA is also taking
comment on the need for energy
attribute tracking systems to uniformly
approach the issuance, allocation,
tracking and retirement of hourly EACs
using similar approaches to ensure a
common and consistent national
practice.
L. Mechanisms To Ensure Use of Actual
Low-GHG Hydrogen
The EPA is soliciting comment on
appropriate mechanisms to ensure that
the low-GHG hydrogen used by EGUs is
actually low-GHG, and guard against
EGU use of hydrogen that is falsely
claimed to be low-GHG hydrogen. The
EPA solicits comment on whether EGUs
should be required to provide an
independent third-party verification
that hydrogen the EGU uses to comply
with this regulation meets the
requirements for low-GHG hydrogen.
EPA also solicits comment on whether
any such verifying third party must hold
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33331
an active accreditation from an
accrediting body, such as the California
Air Resources Board’s Low Carbon
Fuels Standards Program or the
International Standards Organization
14064 Code. EPA seeks comment on any
other mechanisms to ensure that
hydrogen used by EGUs meets the lowGHG standard and what the remedy
should be if an EGU uses hydrogen that
is determined not to meet the definition
of low-GHG hydrogen.
M. Recordkeeping and Reporting
Requirements
The current rule (subpart TTTT of 40
CFR part 60) requires EGU owners or
operators to prepare reports in
accordance with the Acid Rain
Program’s ECMPS and, for the EGUs
relying on the compliance approaches
contained in Appendix G of 40 CFR part
75, with the reporting requirements of
that Appendix. Such reports are to be
submitted quarterly. The EPA believes
all EGU owners and operators have
extensive experience in using the
ECMPS and use of a familiar system
ensures quick and effective rollout of
the program in today’s proposal.
Because all EGUs are expected to be
covered by and included in the ECMPS,
minimal, if any, costs for reporting are
expected for this proposal. In the
unlikely event that a specific EGU is not
already covered by and included in the
ECMPS, the estimated annual per unit
cost would be about $8,500.
The current rule’s recordkeeping
requirements at 40 CFR part 60.5560
rely on a combination of general
provision requirements (see 40 CFR
60.7(b) and (f)), requirements at subpart
F of 40 CFR part 75, and an explicit list
of items, including data and
calculations; the EPA proposes to retain
those existing subpart TTTT of 40 CFR
part 60 requirements in the new NSPS
subpart TTTTa of 40 CFR part 60. The
annual cost of those recordkeeping
requirements would be the same
amount as is required for subpart TTTT
of 40 CFR part 60 recordkeeping. As the
recordkeeping in subpart TTTT of 40
CFR part 60 will be replaced by similar
recordkeeping in subpart TTTTa of 40
CFR part 60 upon promulgation, this
annual cost for recordkeeping will be
maintained.
N. Additional Solicitations of Comment
and Proposed Requirements
This section includes additional
issues the Agency is specifically
soliciting comment on. It also provides
a summary of some of the key
considerations the EPA is soliciting
comment on with respect to the
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proposed CAA section 111(b)
requirements.
1. CCS and Co-Firing Low-GHG
Hydrogen as BSER for the Base Load
Subcategory
As described above, the EPA is
proposing to establish two subcategories
with different standards for the base
load subcategory, each based on a
different BSER pathway. The first is
based on a BSER of CCS with 90 percent
capture by 2035. The second is based on
a BSER of co-firing 30 percent (by
volume) low-GHG hydrogen by 2032
and co-firing 96 percent (by volume) by
2038. (Both pathways include efficient
equipment and operation and
maintenance as an initial component of
the BSER.) In other sections of this
preamble, the EPA solicits comment on
variations in the amount of emissions
reduction and the dates for compliance
for each pathway.
The EPA believes that if it finalizes a
subcategory approach with different
standards in which sources may choose
between the two standards and BSER
pathways, each must achieve
environmentally comparable emission
reductions. Thus, if the EPA determines
based on all of the statutory
considerations that CCS with 90 percent
capture qualifies as the BSER for base
load combustion sources, then co-firing
hydrogen could qualify as well only if
it also achieves comparable reductions.
Because the emissions standards are
technology neutral, if the two pathways
can achieve the same emissions
reductions at the same time, there
would be no need to establish separate
subcategories and standards as sources
could adopt either BSER pathway to
meet the standard. But the EPA also
believes that these two technologies
may achieve comparable emissions
reductions at slightly different times,
thus potentially necessitating two
alternate standards. The EPA solicits
comment on the differences in
emissions reductions in both scale and
time that would result from the two
standards and BSER pathways,
including how to calculate the different
amounts of emission reductions, how to
compare them, and what conclusions to
draw from those differences. From the
perspective of an individual turbine, the
proposed co-firing with low-GHG
hydrogen-based standard results in
earlier emission reductions because it
takes effect in 2032, three years before
the CCS-based standard, but the lowGHG hydrogen-based standard could
also result in fewer total emission
reductions because the 90 percent
emission rate reduction is not required
until 2038, three years after the CCS-
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based standard. Although early
emission reductions have value in
addressing climate change, it is the
cumulative impact of the emission
reductions that is of primary importance
given the short time-scale over which
those early reductions are occurring.
The EPA also solicits comment on the
potential benefits of prescribing two
separate standards for new base load
combustion turbines. Owners and
operators of new combustion turbine
EGUs are currently pursuing both CCS
and co-firing with low-GHG hydrogen as
approaches for reducing GHG
emissions, and both require the
development of infrastructure that may
proceed at a different pace and scale
and achieve emissions reductions on
different timelines with respect to each
technology. Although both CCS and cofiring with low-GHG hydrogen are, or
are expected to be, broadly available
throughout the United States, the EPA
solicits comment on whether individual
locations where new base load
combustion turbines might be
constructed might lend themselves more
to one technology than the other (based
on pipeline availability, proximity to
hydrogen production or geologic
sequestration sites, etc.). The EPA
recognizes that the design of CAA
section 111—whereby sources decide
which emissions controls they use to
meet standards of performance—
provides sources with operational
flexibility so long as they achieve the
standard. A subcategory approach,
however, may allow the EPA to consider
the potentially differing scale and pace
at which these technologies can achieve
environmentally equivalent emissions
reductions and whether there are
characteristics of units that make one or
the other pathways ‘‘best’’ for those
types of units.
As an alternative to the proposed
approach of two standards and BSER
pathways for the base load subcategory,
the EPA is soliciting comment on
having a single standard, which would
be based on CCS with 90 percent
capture (along with efficiency as the
initial component of the BSER). Under
this alternative, the EPA would not
establish a separate base load
subcategory for combustion turbines
that adopt the low-GHG hydrogen cofiring pathway.
The EPA solicits comment on whether
finalizing a single, CCS-based standard
for the baseload subcategory better
reflects the more likely uses of hydrogen
as a source of fuel in new combustion
turbines. The EPA has proposed a
standard for base load combustion
turbines that adopt the low-GHG
hydrogen co-firing in part because the
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Agency understands a number of power
companies are actively developing
combustion turbines that are designed
to co-fire hydrogen. However, the
Agency recognizes that power
companies may ultimately come to
utilize low-GHG hydrogen as a storage
fuel reserved for intermediate load
combustion turbines that support
variable renewable generation, rather
than for combustion turbines that
generate at base load. An approach in
which the EPA establishes a single CCSbased second phase standard for base
load combustion turbines, along with a
second phase standard for intermediate
load combustion turbines that is based
on low-GHG hydrogen as a component
of the BSER, would align with this
potential scenario. In addition, if an
owner or operator of a new combustion
turbine does seek to utilize low-GHG
hydrogen for base load generation, a
single CCS-based second phase standard
for base load combustion turbines
would not preclude owners and
operators from utilizing low-GHG
hydrogen as a means of compliance.
Owners/operators could also comply
with a CCS-based standard by co-firing
96 percent (by volume) low-GHG
hydrogen from the outset of the second
phase—rather than the proposed
approach that would delay requirements
for this level of co-firing until 2038.
2. Co-Firing Low-GHG Hydrogen as
BSER for Intermediate Load Combined
Cycle and Simple Cycle Subcategories
The EPA is also soliciting comment
on subcategorizing intermediate load
combustion turbines into an
intermediate load combined cycle
subcategory and an intermediate load
simple cycle subcategory. The BSER for
both subcategories would be two
components: (1) Highly efficient
generation (either combined cycle
technology or simple cycle technology,
respectively) and (2) co-firing 30 percent
(by volume) low-GHG hydrogen, with
the first component applying when the
source commences operation and the
second component applying in the year
2032. Dividing the intermediate load
subcategory into these two subcategories
would assure that intermediate load
combined cycle turbines would have a
more stringent standard of
performance—that is, expressed in a
lower lb CO2/MWh—than intermediate
load simple cycle turbines.
3. Integrated Onsite Generation and
Energy Storage
Integrated equipment is currently
included as part of the affected facility
and the EPA is soliciting comment on
the best approach to recognizing the
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environmental benefits of onsite
integrated non-emitting generation and
energy storage. The EPA is proposing
regulatory text to clarify that the output
from integrated renewables is included
as output when determining the NSPS
emissions rate. The EPA is also
proposing that the output from the
integrated renewable generation is not
included when determining the net
electric sales for applicability purposes.
In the alternative, the EPA is soliciting
comment on whether instead of
exempting the generation from the
integrated renewables from counting
toward electric sales, the potential
output from the integrated renewables
would be included when determining
the design efficiency of the facility.
Since the design efficiency is used when
determining the electric sales threshold
this would increase the allowable
electric sales for subcategorization
purposes. Including the integrated
renewables when determining the
design efficiency of the affected facility
would have the impact of increasing the
operational flexibility of owners/
operators of intermediate load
combustion turbines. Renewables
typically have much lower 12-operating
month capacity factors than the
intermediate electric sales threshold so
could allow the turbine engine itself to
operate at a higher capacity factor while
still being considered an intermediate
load EGU. Conversely, if the integrated
renewables operate at a 12-operating
month capacity factor of greater than 20
percent that would reduce the ability of
a peaking turbine engine to operate
while still remaining in the low load
subcategory. However, even if a
combustion turbine engine itself were to
operate at a capacity factor of less than
20 percent and become categorized as
an intermediate load combustion
turbine when the output form the
integrated renewables are considered,
the output from the integrated
renewables could lower the emissions
rate such that the affected facility would
be in compliance with the intermediate
load standard of performance.
For integrated energy storage
technologies, the EPA is soliciting
comment on including the rated output
of the energy storage when determining
the design efficiency of the affected
facility. Similar to integrated
renewables, this would increase the
flexibility of owner/operators to operate
at higher capacity factors while
remaining in the low and intermediate
load subcategories. The EPA is not
proposing that the output from the
energy storage be considered in either
determining the NSPS emissions rate or
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as net electric sales for
subcategorization applicability
purposes. While additional energy
storage will allow for integration of
additional variable renewable
generation, the energy storage devices
could be charged using grid supplied
electricity that is generated from other
types of generation. Therefore, this is
not necessarily stored low-GHG
electricity.
4. Definition of System Emergency
40 CFR part 60, subpart TTTT (and
the proposed 40 CFR part 60, subpart
TTTTa) include a provision that
electricity sold during hours of
operation when a unit is called upon to
operate due to a system emergency is
not counted toward the percentage
electric sales subcategorization
threshold.515 The EPA concluded that
this exclusion is necessary to provide
flexibility, to maintain system
reliability, and to minimize overall costs
to the sector (80 FR 64612; October 23,
2015). Some in the regulated
community have informed the Agency
that additional clarification on a system
emergency would need to be
determined and documented for
compliance purposes. The intent is that
the local grid operator would determine
which EGUs are essential to maintain
grid reliability. The EPA is soliciting
comments on amending the definition
of system emergency to clarify how it
would be implemented. The current text
is any abnormal system condition that
the RTO, Independent System Operators
(ISO) or control area Administrator
determines requires immediate
automatic or manual action to prevent
or limit loss of transmission facilities or
generators that could adversely affect
the reliability of the power system and
therefore call for maximum generation
resources to operate in the affected area,
or for the specific affected EGU to
operate to avert loss of load.
5. Definition of Natural Gas
40 CFR part 60, subpart TTTT (and
the proposed 40 CFR part 60, subpart
TTTTa) include a definition of natural
gas. Natural gas is a fluid mixture of
hydrocarbons (e.g., methane, ethane, or
propane), composed of at least 70
percent methane by volume or that has
a gross calorific value between 35 and
41 megajoules (MJ) per dry standard
cubic meter (950 and 1,100 Btu per dry
standard cubic foot), that maintains a
gaseous state under ISO conditions.
515 Electricity sold by units that are not called
upon to operate due to a system emergency (e.g.,
units already operating when the system emergency
is declared) is counted toward the percentage
electric sales threshold.
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Finally, natural gas does not include the
following gaseous fuels: Landfill gas,
digester gas, refinery gas, sour gas, blast
furnace gas, coal-derived gas, producer
gas, coke oven gas, or any gaseous fuel
produced in a process which might
result in highly variable CO2 content or
heating value. The EPA is soliciting
comment on if the exclusions for
specific gases such as landfill gas, etc.
are necessary of if they should be
deleted. If landfill gas, coal-derived gas,
or other gases are processed to meet the
methane and heating value content of
pipeline quality natural gas they could
be mixed into the pipeline network and
it is the intent that this mixture be
considered natural gas for the purposes
of 40 CFR part 60, subpart TTTT and the
proposed 40 CFR part 60, subpart
TTTTa.
6. Summary of Solicitation of Comment
on BSER Variations
This section summarizes the
variations on the subcategories and on
BSER for combustion turbines on which
the EPA is soliciting comment. It is
intended to highlight certain aspects of
the proposal the Agency is soliciting
comment on and is not intended to
cover all aspects of the proposal.
For the low load subcategory, the EPA
is soliciting comment on:
• An electric sales threshold of
between 15 to 25 percent for all
combustion turbines regardless of the
specific design efficiency.
• An electric sales threshold based on
three quarters of the design efficiency of
the combustion turbine. This would
result in electric sales thresholds of 18
to 22 percent for simple cycle turbines
and 26 to 31 percent for combined cycle
turbines.
• Applying a second component of
BSER, co-firing 30 percent (by volume)
low-GHG hydrogen by 2032.
For the intermediate load subcategory,
the EPA is soliciting comment on:
• An efficiency-based standard of
performance of between 1,000 to 1,200
lb CO2/MWh-gross.
• The use of steam injection as part
of the first BSER component.
• An electric sales threshold based on
94 percent of the design efficiency. This
would result in electric sales thresholds
of 29 to 35 percent for simple cycle
turbines and 40 to 49 percent for
combined cycle turbines.
• A hydrogen co-firing range of 30 to
50 percent by volume as the second
component of the BSER.
• Beginning implementation of the
second component of the BSER (i.e.,
hydrogen co-firing) as early as 2030.
• The second component of the BSER
would establish separate subcategories
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for simple and combined cycle
intermediate load combustion turbines,
both based on co-firing low-GHG
hydrogen.
• Adding a third phase standard
based on higher levels of low-GHG
hydrogen co-firing by 2038.
For the base load subcategory, the
EPA is soliciting comment on:
• An efficiency-based standard of
performance of between 730 to 800 lb
CO2/MWh-gross for large combustion
turbines.
• An efficiency-based standard of
performance of between 850 to 900 lb
CO2/MWh-gross for small combustion
turbines.
• Beginning implementation of the
second component of the BSER (i.e.,
CCS or hydrogen co-firing) as early as
2030.
• Beginning implementation of the
third component of the co-firing lowGHG hydrogen-based BSER earlier than
2038.
• Whether the third component of the
hydrogen BSER should be 96 percent by
volume or a lower volume—note that if
it is a lower volume that raises issues as
to whether the BSER would be
appropriate if EPA found that a CCS
BSER of 90% for NGCCs was generally
applicable
• A hydrogen co-firing range of 30 to
50 percent as the second component of
the BSER for combustion turbines cofiring hydrogen.
• A single standard based on either a
CCS-based BSER or a co-firing lowGHG-hydrogen based BSER for all base
load combustion turbines.
• A carbon capture rate of 90 to 95
percent as the second component of the
CCS-based BSER.
O. Compliance Dates
The EPA is proposing that affected
sources that commenced construction or
reconstruction after May 23, 2023,
would need to meet the requirements of
40 CFR part 60, subpart TTTTa upon
startup of the new or reconstructed
affected facility or the effective date of
the final rule, whichever is later. This
proposed compliance schedule is
consistent with the requirements in
section 111 of the CAA.
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VIII. Requirements for New, Modified,
and Reconstructed Fossil Fuel-Fired
Steam Generating Units
A. 2018 NSPS Proposal
The EPA promulgated NSPS for GHG
emissions from fossil fuel-fired steam
generating units in 2015. 80 FR 64510
(October 23, 2015). As discussed in
section V.B.2 of this preamble, on
December 20, 2018, the EPA proposed
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amendments that would revise the
determination of the BSER for control of
GHG emissions from newly constructed
coal-fired steam generating units in 40
CFR part 60, subpart TTTT (83 FR
65424; December 20, 2018). The EPA is
not reopening for comment or soliciting
comment on the 2018 NSPS Proposal,
and intends to further address it in a
separate action.
1. Additional Amendments
The EPA is proposing multiple less
significant amendments. These
amendments would be either strictly
editorial and would not change any of
the requirements of 40 CFR part 60,
subpart TTTT or are intended to add
additional compliance flexibility. The
proposed amendments would also be
incorporated into the proposed subpart
TTTTa. For additional information on
these amendments, see the redline
strikeout version of the rule showing the
proposed amendments. First, the EPA is
proposing editorial amendments to
define acronyms the first time they are
used in the regulatory text. Second, the
EPA is proposing to add International
System of Units (SI) equivalent for
owners/operators of stationary
combustion turbines complying with a
heat input-based standard. Third, the
EPA is proposing to fix errors in the
current 40 CFR part 60, subpart TTTT
regulatory text referring to part 63
instead of part 60. Fourth, as a practical
matter owners/operators of stationary
combustion turbines subject to the heat
input-based standard of performance
need to maintain records of electric
sales to demonstrate that they are not
subject to the output-based standard of
performance. Therefore, the EPA is
proposing to add a specific requirement
that owner/operators maintain records
of electric sales to demonstrate they did
not sell electricity above the threshold
that would trigger the output-based
standard. Next, the EPA is proposing to
update the ANSI, ASME, and ASTM test
methods to include more recent
versions of the test methods. Finally, the
EPA is proposing to add additional
compliance flexibilities for EGUs either
serving a common electric generator or
using a common stack. Specifically, for
EGUs serving a common electric
generator, the EPA is soliciting
comment on whether the Administrator
should be able to approve alternate
methods for determining energy output.
For EGUs using a common stack, the
EPA is soliciting comment on whether
specific procedures should be added for
apportioning the emissions and/or if the
Administrator should be able to approve
site-specific alternate procedures.
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B. Eight-Year Review of NSPS for Fossil
Fuel-Fired Steam Generating Units
1. New Construction and Reconstruction
The EPA promulgated NSPS for GHG
emissions from fossil fuel-fired steam
generating units in 2015. As noted in
section IV.F, the EPA is not aware of
any plans by any companies to
undertake new construction of a new
fossil fuel-fired steam generating unit, or
to undertake a reconstruction of an
existing fossil fuel-fired steam
generating unit, that would be subject to
the 2015 NSPS for steam generating
units. Accordingly, the EPA does not
consider it necessary, nor a good use of
agency resources, to review the NSPS
for new construction or reconstruction.
See ‘‘New Source Performance
Standards (NSPS) Review: Advanced
notice of proposed rulemaking,’’ 76 FR
65653, 65658 (October 24, 2011)
(suggesting it may not be necessary for
the EPA to review an NSPS when no
new construction, modification, or
reconstruction is expected in the source
category). Should events change and the
EPA learns that companies plan to
undertake construction of a new fossil
fuel-fired steam generating unit or
reconstruction of an existing fossil fuelfired steam generating unit, the EPA
would consider reviewing these
standards.
2. Modifications
In the 2015 NSPS, the EPA issued
final standards for a steam generating
unit that implements a ‘‘large
modification,’’ defined as a physical
change, or change in the method of
operation, that results in an increase in
hourly CO2 emissions of more than 10
percent when compared to the source’s
highest hourly emissions in the
previous 5 years. Such a modified steam
generating unit is required to meet a
unit-specific CO2 emission limit
determined by that unit’s best
demonstrated historical performance (in
the years from 2002 to the time of the
modification). The 2015 NSPS did not
include standards for a steam generating
unit that implements a ‘‘small
modification,’’ defined as a change that
results in an increase in hourly CO2
emissions of less than or equal to 10
percent when compared to the source’s
highest hourly emissions in the
previous 5 years. 80 FR 64514 (October
23, 2015).
In the 2015 NSPS, the EPA explained
its basis for promulgating this rule as
follows. The EPA has historically been
notified of only a limited number of
NSPS modifications involving fossil
steam generating units and therefore
predicted that very few of these units
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would trigger the modification
provisions and be subject to the
proposed standards. Given the limited
information that we have about past
modifications, the agency has
concluded that it lacks sufficient
information to establish standards of
performance for all types of
modifications at steam generating units
at this time. Instead, the EPA has
determined that it is appropriate to
establish standards of performance at
this time for larger modifications, such
as major facility upgrades involving, for
example, the refurbishing or
replacement of steam turbines and other
equipment upgrades that result in
substantial increases in a unit’s hourly
CO2 emissions rate. The agency has
determined, based on its review of
public comments and other publicly
available information, that it has
adequate information regarding the
types of modifications that could result
in large increases in hourly CO2
emissions, as well as on the types of
measures available to control emissions
from sources that undergo such
modifications, and on the costs and
effectiveness of such control measures,
upon which to establish standards of
performance for modifications with
large emissions increases at this time.
Id. at 64597–98. The EPA is not
reopening any aspect of these
determinations concerning
modifications in the 2015 NSPS, except,
as noted below, for the BSER and
associated requirements for large
modifications.
Because the EPA has not promulgated
a NSPS for small modifications, any
existing steam generating unit that
undertakes a change that increases its
hourly CO2 emissions rate by 10 percent
or less would continue to be treated as
an existing source that is subject to the
CAA section 111(d) requirements being
proposed today.
With respect to large modifications,
we explained in the 2015 NSPS that
they are rare, but there is record
evidence indicating that they may
occur. Id. at 64598. Because the EPA is
proposing requirements for existing
sources that are, on their face, more
stringent than the requirements for large
modifications, the EPA believes it is
appropriate to review and revise the
latter requirements to minimize the
anomalous incentive that an existing
source could have to undertake a large
modification for the purpose of avoiding
the more stringent requirements that it
would be subject to if it remained an
existing source. Accordingly, the EPA is
proposing to revise the BSER for large
modifications to mirror the BSER for the
subcategory of coal-fired steam
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generating units that plan to operate
past December 31, 2039, that is, the use
of CCS with 90 percent capture of CO2.
The EPA believes that it is reasonable to
assume that any existing source that
invests in a physical change or change
in the method of operation that would
qualify as a large modification expects
to continue to operate past 2039.
Accordingly, the EPA proposes that CCS
with 90 percent capture qualifies as the
BSER for such a source for the same
reasons that it qualifies as the BSER for
existing sources that plan to operate
past December 31, 2039. The EPA
discusses these reasons in section
X.D.1.a. The EPA is proposing to
determine that CCS with 90 percent
capture qualifies as the BSER for large
modifications, and not the controls
determined to be the BSER in the 2015
NSPS, due to the recent reductions in
the cost of CCS. The EPA does not
believe there are any considerations
relative to a source undertaking a large
modification that point towards a
control system other than CCS with 90
percent capture qualifying as the BSER.
The Agency solicits comment on this
issue.
By the same token, the EPA is
proposing that the degree of emission
limitation associated with CCS with 90
percent capture is an 88.4 percent
reduction in emission rate (lb CO2/
MWh-gross basis), the same as proposed
for existing sources with CCS with 90
percent capture. See section X.D.1.a.iv.
Based on this degree of emission
limitation, the EPA is proposing that the
standard of performance for steam
generating units that undertake large
modifications after the date of
publication of this proposal is a unitspecific emission limit determined by
an 88.4 percent reduction in the unit’s
best historical annual CO2 emission rate
(from 2002 to the date of the
modification). The EPA is proposing
that an owner/operator of a modified
steam generating unit comply with the
proposed emissions rate upon startup of
the modified affected facility or the
effective date of the final rule,
whichever is later. The EPA is
proposing the same testing, monitoring,
and reporting requirements as are
currently in 40 CFR part 60, subpart
TTTT.
C. Projects Under Development
Finally, during the 2015 NSPS
rulemaking, the EPA identified the Plant
Washington project in Georgia and the
Holcomb 2 project in Kansas as EGU
‘‘projects under development’’ based on
representations by developers that the
projects had commenced construction
prior to the proposal of the 2015 NSPS
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33335
and, thus, would not be new sources
subject to the final NSPS (80 FR 64542–
43; October 23, 2015). The EPA did not
set a performance standard at the time
but committed to doing so if new
information about the projects became
available. These projects were never
constructed and are no longer expected
to be constructed.
The Plant Washington project was to
be an 850–MW supercritical coal-fired
EGU. The Environmental Protection
Division (EPD) of the Georgia
Department of Natural Resources issued
air and water permits for the project in
2010 and issued amended permits in
2014.516 517 518 In 2016, developers filed
a request with the EPD to extend the
construction commencement deadline
specified in the amended permit, but
the director of the EPD denied the
request, effectively canceling the
approval of the construction permit and
revoking the plant’s amended air quality
permit.519
The Holcomb 2 project was intended
to be a single 895–MW coal-fired EGU
and received permits in 2009 (after
earlier proposals sought approval for
development of more than one unit). In
2020, after developers announced they
would no longer pursue the Holcomb 2
expansion project, the air permits were
allowed to expire, effectively canceling
the project.
For these reasons, the EPA is
proposing to remove these projects
under the applicability exclusions in
subpart TTTT.
IX. Proposed ACE Rule Repeal
The EPA is proposing to repeal the
ACE Rule. A general summary of the
ACE Rule, including its regulatory and
judicial history, is included in section
V.B of this preamble. The repeal of the
ACE Rule is intended to stand alone and
be severable from the other aspects of
this rule. The EPA proposes to repeal
the ACE Rule on three grounds that
together, and each independently,
justify the rule’s repeal. First, as a policy
matter, the EPA believes that the suite
of heat rate improvements (HRI) the
ACE Rule selected as the BSER should
be reexamined and are no longer an
appropriate BSER for existing coal-fired
EGUs. The EPA concludes that the suite
of HRI set forth in the ACE Rule provide
516 https://www.gpb.org/news/2010/07/26/judgerejects-coal-plant-permits.
517 https://www.southernenvironment.org/pressrelease/court-rules-ga-failed-to-set-safe-limits-onpollutants-from-coal-plant/.
518 https://permitsearch.gaepd.org/
permit.aspx?id=PDF-OP-22139.
519 https://www.southernenvironment.org/wpcontent/uploads/legacy/words_docs/EPD_Plant_
Washington_Denial_Letter.pdf.
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negligible CO2 reductions at best and, in
many cases, could increase CO2
emissions because of the rebound effect,
as explained in section X.D.5.a. These
concerns taken together, along with new
evidence, and the EPA’s experience in
implementing the ACE Rule, cast doubt
on the ACE Rule’s minimal projected
emission reductions and increase the
likelihood that the ACE Rule could
make CO2 pollution worse. As a result,
the EPA has determined it is
appropriate to repeal the rule, and to
reevaluate whether other technologies
constitute the BSER.
Second, the ACE Rule rejected CCS
and natural gas co-firing as the BSER for
reasons that no longer apply. This rule
should be repealed so that EPA may
determine the BSER based on evaluating
all the candidate technologies. Since the
ACE Rule was promulgated, changes in
the power industry, developments in
the costs of controls, and new Federal
subsidies have made these other
technologies more broadly available and
less expensive. The EPA is now
proposing that these technologies are
the BSER for certain subcategories of
sources, as described in section X of this
preamble.
Third, the EPA concludes that the
ACE Rule conflicted with CAA section
111 and the EPA’s implementing
regulations because it did not
specifically identify the BSER or the
‘‘degree of emission limitation
achievable though application of the
[BSER],’’ but set forth an indeterminate
range of values. Thus, the rule did not
provide the States with adequate
guidance on the degree of emission
limitation that must be reflected in the
standards of performance so that a State
plan would be approvable by the EPA.
Along with this, the ACE Rule also
improperly departed from the statutory
framework of CAA section 111(d) by
categorically precluding States from
allowing their sources to comply with
standards of performance by trading or
averaging. Properly construed, CAA
section 111(d) gives States discretion to
provide sources with certain
compliance flexibilities, including
trading or averaging in appropriate
circumstances so long as the other
requirements of section 111 are met as
described below.
A. Summary of Selected Features of the
ACE Rule
The ACE Rule determined that the
BSER for coal-fired EGUs was a ‘‘list of
‘candidate technologies,’ ’’ consisting of
seven types of the ‘‘most impactful HRI
technologies, equipment upgrades, and
best operating and maintenance
practices,’’ (84 FR 32536; July 8, 2019),
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including, among others, ‘‘Boiler Feed
Pumps’’ and ‘‘Redesign/Replace
Economizer.’’ Id. at 32537 (table 1). The
rule provided a range of improvements
in heat rate that each of the seven
‘‘candidate technologies’’ could achieve
if applied to coal-fired EGUs of different
capacities. For six of the technologies,
the expected level of improvement in
heat rate ranged from 0.1–0.4 percent to
1.0–2.9 percent, and for the seventh
technology, ‘‘Improved Operating and
Maintenance (O&M) Practices,’’ the
range was ‘‘0 to >2%.’’ Id. The ACE Rule
explained that States must review each
of their designated facilities, on either a
source-by-source or group-of-sources
basis, and ‘‘evaluate the applicability of
each of the candidate technologies.’’ Id.
at 32550. States were to use the list of
HRI technologies ‘‘as guidance but will
be expected to conduct unit-specific
evaluations of HRI potential, technical
feasibility, and applicability for each of
the BSER candidate technologies.’’ Id. at
32538.
The ACE Rule emphasized that States
had ‘‘inherent flexibility’’ in
undertaking this task with ‘‘a wide
range of potential outcomes.’’ Id. at
32542. The ACE Rule provided that
States could conclude that it was not
appropriate to apply some technologies.
Id. at 32550. Moreover, if a State did
decide to apply a particular technology
to a particular source, the State could
determine the level of heat rate
improvement from the technology to be
anywhere within the range that the EPA
had identified for that technology, or
even outside that range. Id. at 32551.
The ACE Rule stated that after the State
evaluated the technologies and
calculated the amount of HRI in this
way, it should determine the standard of
performance that the source could
achieve, Id. at 32550, and then adjust
that standard further based on the
application of source-specific factors
such as remaining useful life. Id. at
32551.
The ACE Rule then identified the
process by which States had to take
these actions. States must ‘‘evaluat[e]
each’’ of the seven candidate
technologies and provide a summary,
which ‘‘include[s] an evaluation of the
. . . degree of emission limitation
achievable through application of the
technologies.’’ Id. at 32580. Then, the
State must provide a variety of
information about each power plant,
including, the plant’s ‘‘annual
generation,’’ ‘‘CO2 emissions,’’ ‘‘[f]uel
use, fuel price, and carbon content,’’
‘‘operation and maintenance costs,’’
‘‘[h]eat rates,’’ ‘‘[e]lectric generating
capacity,’’ and the ‘‘timeline for
implementation,’’ among other
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information. Id. at 32581. The EPA
explained that the purpose of this data
was to allow the Agency to ‘‘adequately
and appropriately review the plan to
determine whether it is satisfactory.’’ Id.
at 32558.
The ACE Rule projected a very low
level of overall emission reduction if
States generally applied the set of
candidate technologies to their sources.
The rule was projected to achieve a lessthan-1-percent reduction in powersector CO2 emissions by 2030.520
Further, the EPA also projected that it
would increase CO2 emissions from
power plants in 15 States and the
District of Columbia because of the
‘‘rebound effect’’ as sources
implemented HRI measures and became
more efficient. This phenomenon is
explained in more detail in section
X.D.5.a.521
The ACE Rule considered several
other control measures as the BSER,
including co-firing with natural gas and
CCS, but rejected them. The ACE Rule
rejected co-firing with natural gas
primarily on grounds that it was too
costly in general, and especially for
sources that have limited or no access
to natural gas. 84 FR 32545 (July 8,
2019). The rule also concluded that
generating electricity by co-firing
natural gas in a utility boiler would be
an inefficient use of the gas when
compared to combusting it in a
combustion turbine. Id. The ACE Rule
rejected CCS on grounds that it was too
costly. Id. at 32548. The rule identified
the high capital and operating costs of
CCS and noted the fact that the IRC 45Q
tax credit, as it then applied, would
provide only limited benefit to sources.
Id. at 32548–49.
In addition, the ACE Rule interpreted
CAA section 111 to preclude States from
allowing their sources to trade or
average to demonstrate compliance with
their standards of performance. Id. at
32556–57.
B. Developments Undermining ACE
Rule’s Projected Emission Reductions
The EPA’s first basis for proposing to
repeal the ACE Rule is that there is
doubt that the rule would achieve even
the limited emissions reductions
projected at the time of promulgation if
it were implemented now, and
implementation could increase CO2
520 ACE
Rule RIA 3–11, table 3–3.
rebound effect becomes evident by
comparing the results of the ACE Rule IPM runs for
the 2018 reference case, EPA, IPM State-Level
Emissions: EPAv6 November 2018 Reference Case,
EPA–HQ–OAR–2017–0355–26720, and for the
‘‘Illustrative ACE Scenario. IPM State-Level
Emissions: Illustrative ACE Scenario, EPA–HQ–
OAR–2017–0355–26724.
521 The
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emissions instead. Thus, the EPA
concludes that as a matter of the
Agency’s policy judgment it is
appropriate to repeal the rule and
evaluate whether other technologies
qualify as the BSER given new factual
developments. This action is consistent
with the Supreme Court’s instruction in
FCC v. Fox Television Stations, Inc., 556
U.S. 502 (2009), where the Supreme
Court explained that an agency issuing
a new policy ‘‘need not demonstrate to
a court’s satisfaction that the reasons for
the new policy are better than the
reasons for the old one.’’ Instead, ‘‘it
suffices that the new policy is
permissible under the statute, that there
are good reasons for it, and that the
agency believes it to be better, which the
conscious change of course adequately
indicates.’’ Id. at 514–16 (emphasis in
original; citation omitted).
Two factors, taken together,
undermine the ACE Rule’s projected
emission reductions and create the risk
that implementation of the ACE Rule
could increase—rather than reduce—
CO2 emissions from coal-fired EGUs.
First, HRI technologies achieve only
limited GHG emission reductions. The
ACE Rule projected that if States
generally applied the set of candidate
technologies to their sources, the rule
would achieve a less-than-1-percent
reduction in power-sector CO2
emissions by 2030.522 The EPA now
doubts that even these minimal
reductions would be achieved. The ACE
Rule’s projected benefits were premised
in part on a 2009 technical report by
Sargent & Lundy that evaluated the
effects of HRI technologies. In 2023,
Sargent & Lundy issued an updated
report which details that the HRI
selected as the BSER in the ACE Rule
would bring fewer emissions reductions
than estimated in 2009. The 2023 report
concludes that, with few exceptions,
HRI technologies are less effective at
reducing CO2 emissions than assumed
in 2009. And most sources had already
optimized application of HRIs, and so
there are fewer opportunities to reduce
emissions than previously anticipated.
Second, for a subset of sources, HRI
are likely to cause a rebound effect
leading to an increase in GHG emissions
for those sources for the reasons
explained in section X.D.5.a. The
estimate of the rebound effect was quite
pronounced in the ACE Rule’s own
analysis—the rule projected that it
would increase CO2 emissions from
power plants in 15 States and the
District of Columbia. Specifically, the
EPA prepared modeling projections to
understand the impacts of the ACE
522 ACE
Rule RIA 3–11, table 3–3.
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Rule. These projections assumed that,
consistent with the rule, sources would
impose a small degree of efficiency
improvements. The modeling showed
that the rule would not result in
absolute emissions reductions across all
affected sources, and some would
instead increase absolute emissions. See
EPA, IPM State-Level Emissions: EPAv6
November 2018 Reference Case, EPA–
HQ–OAR–2017–0355–26720 (providing
ACE reference case); IPM State-Level
Emissions: Illustrative ACE Scenario,
EPA–HQ–OAR–2017–0355–26724
(providing illustrative scenario).
Despite the fact that the ACE Rule was
projected to increase emissions in many
States, these States were nevertheless
obligated under the rule to assemble
detailed State plans that evaluated
available technologies and the
performance of each existing coal-fired
power plant, as described in section
IX.A of this preamble. For example, the
State was required to analyze the plant’s
‘‘annual generation,’’ ‘‘CO2 emissions,’’
‘‘[f]uel use, fuel price, and carbon
content,’’ ‘‘operation and maintenance
costs,’’ ‘‘[h]eat rates,’’ ‘‘[e]lectric
generating capacity,’’ and the ‘‘timeline
for implementation,’’ among other
information. 84 FR 32581 (July 8, 2019).
This evaluation and the imposition of
standards of performance was mandated
even though the State plan would lead
to an increase rather than decrease CO2
emissions.
In this context, the data undermining
the ACE Rule’s limited, projected
emission reductions along with the risk
that implementation of the rule could
increase CO2 pollution raises doubts
that the HRI satisfies the statutory
criteria to constitute the BSER for this
category of sources. The core element of
the BSER analysis is whether the
emission reduction technology selected
reduces emissions. See Essex Chem.
Corp. v. Ruckelshaus, 486 F.2d 427, 441
(D.C. Cir. 1973) (noting ‘‘counter
productive environmental effects’’
questioned whether the BSER selected
was in fact the ‘‘best’’).
The EPA’s experience in
implementing the ACE Rule reinforces
these concerns. After the ACE Rule was
promulgated, one State drafted a State
plan that set forth a standard of
performance that allowed the affected
source to increase its emission rate. The
draft partial plan would have applied to
one source, the Longview Power, LLC
facility, and would have established a
standard of performance, based on the
State’s consideration of the ‘‘candidate
technologies,’’ that was higher (i.e., less
stringent) than the source’s historical
emission rate. Thus, the draft plan
would not have achieved any emission
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33337
reductions from the source, and instead
would have allowed the source to
increase its emissions, if it was
finalized.523
Because there is doubt that the
minimal reductions projected by the
ACE Rule would be achieved, and
because the rebound effect could lead to
an increase in emissions for many
sources in many States, the EPA
concludes that it is appropriate to repeal
the ACE Rule and reevaluate the BSER
for this category of sources.
C. Developments Showing That Other
Technologies Are the BSER for This
Source Category
Since the promulgation of the ACE
Rule in 2019, the factual underpinnings
of the rule have changed in several
ways, and lead EPA to propose that HRI
are not the BSER for coal-fired power
plants.
Along with changes in the anticipated
reductions from HRI, it makes sense for
the EPA to reexamine the BSER because
the costs of two control measures, cofiring with natural gas and CCS, have
fallen substantially for sources with
longer-term operating horizons such
that the EPA may determine that these
measures satisfy the requirements for
the BSER for the source categories
identified below. As noted, the ACE
Rule rejected natural gas co-firing as the
BSER on grounds that it was too costly
and would lead to inefficient use of
natural gas. But as discussed in section
X.D.2.b.ii of this preamble, the costs of
natural gas co-firing have substantially
decreased, and the EPA is proposing
that the costs of co-firing 40 percent by
volume natural gas are reasonable for
existing coal-fired EGUs in the mediumterm subcategory, i.e., units that plan to
operate during, in general, the 2032 to
2040 period. In addition, the changed
circumstances, including that natural
gas is available in greater amounts, and
there are fewer coal-fired EGUs,
mitigates the concerns the ACE Rule
identified about inefficient use of
natural gas. See section X.D.2.b.iii(B).
Similarly, the ACE Rule rejected CCS
as the BSER on grounds that it was too
costly. But as discussed in section
X.D.1.b.ii of this preamble, the costs of
CCS have substantially declined, partly
because of developments in the
technology that have lowered capital
costs, and partly because the IRA
extended and increased the IRC section
45Q tax credit so that it defrays a higher
523 West Virginia CAA § 111(d) Partial Plan for
Greenhouse Gas Emissions from Existing Electric
Utility Generating Units (EGUs), https://dep.wv.gov/
daq/publicnoticeandcomment/Documents/
Proposed%20WV%20ACE%20State%
20Partial%20Plan.pdf.
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portion of the costs of CCS.
Accordingly, for coal-fired EGUs that
will continue to operate past 2040, the
EPA is proposing that the costs of CCS,
which have fallen to approximately $7–
$12/MWh, are reasonable.
The reductions from these two
technologies are substantial. For longterm coal-fired steam generating units,
the BSER of 90 percent capture CCS
results in substantial CO2 emissions
reductions amounting to emission rates
that are 88.4 percent lower on a lb/
MWh-gross basis and 87.1 percent lower
on a lb/MWh-net basis compared to
units without capture, as described in
section X.D.4 of this preamble. And for
the BSER for medium-term units, 40
percent natural gas co-firing achieves
reductions of 16 percent, as described in
section X.D.2.b.iv of this preamble.
Given the availability of more
effective, cost-reasonable technology,
the EPA concludes that HRIs are not the
BSER for all coal-fired EGUs.
The EPA is thus proposing to adopt a
new policy and change its regulatory
scheme for coal-fired power plants. As
discussed in section X.C.3 of this
preamble, the EPA is proposing to
subcategorize coal-fired power plants
according to the time that they will
continue to operate. For sources in the
imminent-term and near-term
subcategories—which include sources
that, in general, have federally
enforceable commitments to
permanently cease operations by 2032
or 2035, respectively—the EPA is
proposing that the BSER is routine
methods of operation and maintenance,
with associated presumptive standards
of performance that do not permit an
increased emission rate and are not
anticipated to have a rebound effect;
and the EPA is soliciting comment on
whether co-firing some amount of
natural gas should be part of the BSER.
For sources in the medium-term
subcategory—which includes sources
that are not in the other subcategories
and that have a federally enforceable
commitment to permanently cease
operations by 2040—the EPA is
proposing that the BSER is co-firing 40
percent by volume natural gas. The EPA
concludes this control measure is
appropriate because it achieves
substantial reductions at reasonable
cost. In addition, the EPA believes that
because a large supply of natural gas is
available, devoting part of this supply
for fuel for a coal-fired steam generating
unit in place of a percentage of the coal
burned at the unit is an appropriate use
of natural gas and will not adversely
impact the energy system, as described
in section X.D.2.b.iii(B) of this
preamble.
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For sources in the long-term
subcategory—which includes sources
that do not have a federally enforceable
commitment to permanently cease
operations by 2040—the EPA is
proposing that the BSER is CCS with 90
percent capture of CO2. The EPA
believes that this control measure is
appropriate because it achieves
substantial reductions at reasonable
cost, as described in section X.D.1.c of
this preamble.
The EPA is not proposing HRI as the
BSER for any coal-fired EGUs. As
discussed in section X.D.5.a, the EPA
does not consider HRIs an appropriate
BSER for the imminent-term and nearterm subcategories because these
technologies would achieve few, if any,
emissions reductions and may increase
emissions due to the rebound effect. The
EPA is proposing to reject HRI as the
BSER for the medium-term and longterm subcategories because HRI could
also lead to a rebound effect. Most
importantly, changed circumstances
show that co-firing natural gas and CCS
are available at reasonable cost, and will
achieve more GHG emissions
reductions. Accordingly, the EPA
believes that HRI do not qualify as the
BSER for any coal-fired EGUs, and that
other approaches meet the statutory
standard. For these reasons, the EPA
proposes to repeal the ACE Rule.
D. Insufficiently Precise Degree of
Emission Limitation Achievable From
Application of the BSER
The third independent reason why
the EPA is proposing to repeal the ACE
Rule is that the rule did not identify
with sufficient specificity the BSER or
the degree of emission limitation
achievable through the application of
the BSER. Thus, States lacked adequate
guidance on the BSER they should
consider and level of emission
reduction that the standards of
performance must achieve. The ACE
Rule determined the BSER to be a suite
of HRI ‘‘candidate technologies,’’ but
did not identify with specificity the
degree of emission limitation States
should apply in developing standards of
performance for their sources. As a
result, the ACE Rule conflicted with
CAA section 111 and the implementing
regulations, and thus failed to provide
States adequate guidance so that they
could ensure that their State plans were
satisfactory and approvable by the EPA.
CAA section 111 and the EPA’s longstanding implementing regulations
establish a clear process for the EPA and
States to regulate emissions of certain
air pollutants from existing sources.
‘‘The statute directs EPA to (1)
‘determine[ ],’ taking into account
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various factors, the ‘best system of
emission reduction which . . . has been
adequately demonstrated,’ (2) ascertain
the ‘degree of emission limitation
achievable through the application’ of
that system, and (3) impose an
emissions limit on new stationary
sources that ‘reflects’ that amount.’’
West Virginia v. EPA, 142 S. Ct. 2587,
2601 (2022) (quoting 42 U.S.C. 7411(d)).
Further, ‘‘[a]lthough the States set the
actual rules governing existing power
plants, EPA itself still retains the
primary regulatory role in Section
111(d) . . . [and] decides the amount of
pollution reduction that must ultimately
be achieved.’’ Id. at 2602.
Once the EPA makes these
determinations, the State must establish
‘‘standards of performance’’ for its
sources that are based on the degree of
emission limitation that the EPA
determines in the emissions guidelines.
CAA section 111(a)(1) makes this clear
through its definition of ‘‘standard of
performance’’ as ‘‘a standard for
emissions of air pollutants which
reflects the degree of emission
limitation achievable through the
application of the [BSER].’’ After the
EPA determines the BSER, 40 CFR
60.22(b)(5), and the degree of emission
limitation achievable from application
of the BSER, ‘‘the States then submit
plans containing the emissions
restrictions that they intend to adopt
and enforce in order not to exceed the
permissible level of pollution
established by EPA.’’ 142 S. Ct. at 2602
(citing 40 CFR 60.23, 60.24; 42 U.S.C.
7411(d)(1)).
The EPA then reviews the plan and
approves it if the standards of
performance are ‘‘satisfactory,’’ under
CAA section 111(d)(2)(A). The EPA’s
long-standing implementing regulations
make clear that the EPA’s basis for
determining whether the plan is
‘‘satisfactory’’ includes that the plan
must contain ‘‘emission standards . . .
no less stringent than the corresponding
emission guideline(s).’’ 40 CFR 60.24(c).
The EPA’s revised implementing
regulations contain the same
requirement. 40 CFR 60.24a(c). In
addition, under CAA section 111(d)(1),
in ‘‘applying a standard of performance
to any particular source’’ a State may
consider, ‘‘among other factors, the
remaining useful life of the existing
source to which such standard applies.’’
This is also known as the RULOF
provision and is discussed in section
XII.D.2.
In the ACE Rule, the EPA recognized
that the CAA required it to determine
the BSER and identify the degree of
emission limitation achievable through
application of the BSER. 84 FR 32537
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(July 8, 2019). But the rule did not make
those determinations. Rather, the ACE
Rule described the BSER as a list of
‘‘candidate technologies.’’ And the rule
described the degree of emission
limitation achievable by application of
the BSER as ranges of reductions from
the HRI technologies. The rule thus
shifted the responsibility for
determining the BSER and degree of
emission limitation achievable from the
EPA to the States. Accordingly, the ACE
Rule did not meet the CAA section 111
requirement that the EPA determine the
BSER or the degree of emission
limitation from application of the BSER.
As described above, the ACE Rule
identified the HRI in the form of a list
of seven ‘‘candidate technologies,’’
accompanied by a wide range of
percentage improvements to heat rate
that these technologies could provide.
Indeed, for one of them, improved O&M
practices (that is, operation and
management practices), the range was
‘‘0 to >2%’’, which is effectively
unbounded. 84 FR 32537 (table 1) (July
8, 2019). The ACE Rule was clear that
this list was simply the starting point for
a State to calculate the standards of
performance for its sources. That is, the
seven sets of technologies were
‘‘candidate[s]’’ that the State could, but
was not required to, apply and if the
State did choose to apply one or more
of them, the State could do so in a
manner that yielded any percentage of
heat rate improvement within the range
that the EPA identified, or even outside
that range, if the State chose. Thus, as
a practical matter, the ACE Rule did not
determine the BSER or any degree of
emission limitation from application of
the BSER, and so States had no
guidance on how to craft approvable
State plans. In this way, EPA effectively
abdicated its responsibilities, and
directed each State to determine for its
sources what the BSER would be (that
is, which HRI technologies should be
applied to the source and with what
intensity), and, based on that, what the
degree of emission limitation achievable
by application of the BSER. See 84 FR
32537–38 (July 8, 2019).
The only constraints that the ACE
Rule imposed on the States were
procedural ones, and those did not give
the EPA any benchmark to determine
whether a plan could be approved or
give the States any certainty on whether
their plan would be approved. As noted
above, when a State submitted its plan,
it needed to show that it evaluated each
candidate technology for each source or
group of sources, explain how it
determined the degree of emission
limitation achievable, and include data
about the sources. But because the ACE
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Rule did not identify a BSER or include
a degree of emission limitation that the
standards must reflect, the States lacked
specific guidance on how to craft
adequate standards of performance, and
the EPA had no benchmark against
which to evaluate whether a State’s
submission was ‘‘satisfactory’’ under
CAA section 111(d)(2)(A). Thus, the
EPA’s review of State plans was
essentially a standardless exercise,
notwithstanding the Agency’s
longstanding view that it was
‘‘essential’’ that ‘‘EPA review . . . [state]
plans for their substantive adequacy.’’
40 FR 53342–43 (November 17, 1975).
In 1975, the EPA explained that it was
not appropriate to limit its review based
‘‘solely on procedural criteria’’ because
otherwise ‘‘states could set extremely
lenient standards . . . so long as EPA’s
procedural requirements were met.’’ Id.
at 53343.
Finally, the ACE Rule’s approach to
determining the BSER and degree of
emission limitation departed from prior
emission guidelines under CAA section
111(d), in which the EPA included a
numeric degree of emission limitation.
See, e.g., 42 FR 55796, 55797 (October
18, 1977) (limiting emission rate of acid
mist from sulfuric acid plants to 0.25
grams per kilogram of acid); 44 FR
29828, 29829 (May 22, 1979) (limiting
concentrations of total reduced sulfur
from most of the subcategories of kraft
pulp mills, such as digester systems and
lime kilns, to 5, 20, or 25 ppm over 12hour averages); 61 FR 9905, 9919
(March 12, 1996) (limiting concentration
of non-methane organic compounds
from solid waste landfills to 20 parts per
million by volume or 98-percent
reduction). In the ACE Rule, the EPA
did not grapple with this change in
position as required by FCC v. Fox
Television Stations, Inc., 556 U.S. 502
(2009), or explain why it was
appropriate to provide a boundless
degree of emission limitation achievable
in this context.
For this reason, the EPA proposes to
repeal the ACE Rule. Its failure to
determine the BSER and the associated
degree of emission limitation achievable
from application of the BSER deviated
from CAA section 111 and the
implementing regulations. Without
these determinations, the ACE Rule
lacked any benchmark that would guide
the States in developing their State
plans, and by which the EPA could
determine whether those State plans
were satisfactory.
E. ACE Rule’s Preclusion of Emissions
Trading or Averaging
While not an independent basis for
repeal, the ACE Rule also interpreted
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CAA section 111(d) to bar States from
allowing emissions trading or averaging
among their sources in all cases, which
further shows that the ACE Rule
misconstrued section 111(d) and the
appropriate roles for the EPA and for the
States. A trading program might allocate
allowances authorizing a particular
level of emissions; a facility would not
need to reduce its emissions so long as
it traded for sufficient allowances. And
an averaging program, for example,
might require a group of facilities to
reduce their average emissions to a
particular level. So long as some
facilities reduced their emissions
sufficiently below that level, it would
not be necessary for every facility to
reduce its emissions. Cf. Chevron
U.S.A., Inc. v. Natural Res. Def. Council,
Inc., 467 U.S. 837, 863 n.37 (1984)
(explaining the ‘ ‘‘bubble’ or ‘netting’
concept). CAA section 111(d) accords
States discretion in developing State
plans, and allows States to include
compliance flexibilities like trading or
averaging in circumstances the EPA has
determined are appropriate, as long as
the plan achieves equivalent emissions
reductions to the EPA’s emission
guidelines. The ACE Rule’s legal
interpretation that CAA section 111(d)
always precludes the State from
adopting those flexibilities was
incorrect.
Under CAA section 111, EPA
promulgates emission guidelines that
identify the degree of emission
limitation achievable through the
application of the BSER as determined
by the Administrator. Each State must
then ‘‘submit to the Administrator a
plan’’ to achieve the degree of emission
limitation identified by EPA. 42 U.S.C.
7411(d)(a). That plan must ‘‘establish[ ]
standards of performance for any
existing source’’ that emits certain air
pollutants, and also ‘‘provide[ ] for the
implementation and enforcement of
such standards of performance.’’ Under
CAA section 111(a)(1), a ‘‘standard of
performance’’ is defined as ‘‘a standard
for emissions of air pollutants which
reflects the degree of emission
limitation achievable through the
application of the [BSER].’’ Although
such standards of performance must
‘‘reflect[ ] the degree of emission
limitation achievable through the
application of the [BSER],’’ 42 U.S.C.
7411(a)(1), States need not compel
regulated sources to adopt the particular
components of the BSER itself.
The ACE Rule interpreted CAA
section 111(a)(1) and (d) to preclude
States from allowing their sources to
trade or average to demonstrate
compliance with their standards of
performance. 84 FR 32556–57 (July 8,
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2019). The ACE Rule based this
interpretation on its view that CAA
section 111 limits the type of ‘‘system’’
that the EPA may select as the BSER to
‘‘measures that apply at and to an
individual source and reduce emissions
from that source.’’ Id. at 32523–24. The
ACE Rule also concluded that the
compliance measures the States include
in their plans ‘‘should correspond with
the approach used to set the standard in
the first place,’’ and therefore must also
be limited to measures that apply at and
to an individual source and reduce
emissions from that source. Id. at 32556.
In its recently published notice of
proposed rulemaking to amend the CAA
section 111(d) implementing
regulations, the EPA has proposed to
determine that the ACE Rule’s legal
interpretation as to the type of ‘‘system’’
that may be selected as a BSER, and the
universal prohibition of trading and
averaging, was incorrect. ‘‘Implementing
Regulations under 40 CFR part 60
Subpart Ba Adoption and Submittal of
State Plans for Designated Facilities:
Proposed Rule,’’ 87 FR 79176, 79207–
79208 (December 23, 2022). As
discussed in that document, no
provision in CAA section 111(d), by its
terms, precludes States from having
flexibility in determining which
measures will best achieve compliance
with the EPA’s emission guidelines.
Specifically, the plain language of
section 111(d) does not affirmatively bar
States from considering averaging and
trading as a compliance measure where
appropriate for a particular emission
guideline. Under section 111(d)(1),
States must ‘‘establish[ ],’’
‘‘implement[ ],’’ and ‘‘enforce[ ]’’
‘‘standards of performance for any
existing source.’’ A State plan that
specifies what each existing source must
do to satisfy plan requirements is
naturally characterized as establishing
‘‘standards of performance for [each]
existing source,’’ even if measures like
trading and averaging are identified as
potential means of compliance. Trading
and averaging programs may be
appropriate as a policy matter as well
because, in some circumstances, they
can help to ensure that costs are
reasonable by enabling market force to
identify the facilities whose emissions
can be reduced most cost-effectively.
Nothing in the text of section 111
precludes States from considering a
source’s acquisition of allowances in
implementing and enforcing a standard
of performance for that particular
source, so long as the State plan
achieves the required level of emission
reductions.
Further supporting this statutory
interpretation, section 111(d) requires a
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‘‘procedure similar to that provided by
Section 7410.’’ Consideration of the
section 110 framework reinforces the
absence of any mandate that States
consider only compliance measures that
apply at and to an individual source.
‘‘States have ‘wide discretion’ in
formulating their plans’’ under section
110. Alaska Dep’t of Envtl. Conservation
v. EPA, 540 U.S. 461, 470 (2004)
(citation omitted); see Union Elec. Co. v.
EPA, 427 U.S. 246, 269 (1976)
(‘‘Congress plainly left with the States,
so long as the national standards were
met, the power to deter-mine which
sources would be burdened by
regulation and to what extent.’’); Train
v. Natural Res. Def. Council, Inc., 421
U.S. 60, 79 (1975) (‘‘[S]o long as the
ultimate effect of a State’s choice of
emission limitations is compliance with
the national standards for ambient air,
the State is at liberty to adopt whatever
mix of emission limitations it deems
best suited to its particular situation.’’).
Exercising that discretion, States have
included measures that do not apply at
or to a source in their section 1410
plans. For example, States have
employed NOX and SO2 trading
programs to comply with section
7410(a)(2)(D)(i)(I), the ‘‘Good Neighbor
Provision.’’ Section 110 thus does not
distinguish between measures that do or
don’t apply at or to a source for
compliance, and there is no sound
reason to read section 111’s comparably
broad language differently.
Such flexibility is consistent with the
framework of cooperative federalism
that CAA section 111(d) establishes,
which vests States with substantial
discretion. As the U.S. Supreme Court
has explained, CAA section 111(d)
‘‘envisions extensive cooperation
between federal and state authorities,
generally permitting each State to take
the first cut at determining how best to
achieve EPA emissions standards within
its domain.’’ American Elec. Power Co.
v. Connecticut, 564 U.S. 410, 428 (2011)
(citations omitted).
To be sure, as discussed above, EPA
retains an important role in reviewing
State plans for adequacy. Under 111(d),
each State must ‘‘submit to the
Administrator a plan’’ to achieve the
degree of emission limitation identified
by EPA. That plan must ‘‘establish[ ]
standards of performance for any
existing source for [the] air pollutant’’
and also ‘‘provide[ ] for the
implementation and enforcement of
such standards of performance.’’ Id. If a
State elects not to submit a plan, or
submits a plan that EPA does not find
‘‘satisfactory,’’ EPA must promulgate a
plan that establishes Federal standards
of performance for the State’s existing
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sources. 42 U.S.C. 7411(d)(2)(A). Thus,
the flexibility that CAA section 111(d)
grants to States in adopting measures for
their State plans is not unfettered. As
the Supreme Court stated in West
Virginia, ‘‘The Agency, not the States,
decides the amount of pollution
reduction that must ultimately be
achieved.’’ 142 S. Ct. at 2602. State
plans then must contain ‘‘emissions
restrictions that they intend to adopt
and enforce in order not to exceed the
permissible level of pollution
established by EPA.’’ Id. Thus, EPA
bears the burden of ensuring that the
permissible level of pollution is not
exceeded by any State plan. When a
compliance flexibility compromises the
ability of the State plan to achieve the
necessary emission reductions, then the
EPA may reasonably preclude reliance
on such measures, or otherwise
conclude that the State plan is not
satisfactory.
Thus, the EPA proposed to disagree
with the ACE Rule’s conclusion that
State plan compliance measures must
always apply at and to an individual
source and reduce emissions of that
source. As noted in section V.B.6, the
U.S. Supreme Court in West Virginia v.
EPA, 142 S. Ct. 2587 (2022), did not
address the scope of the States’
compliance flexibilities in developing
State plans. The Court also declined to
address whether CAA section 111 limits
the type of ‘‘system’’ the EPA may
consider to measures that apply
substantially at and to an individual
source. See id. at 2615.
For these reasons, in its notice of
proposed rulemaking to amend the CAA
section 111(d) implementing
regulations, EPA proposes to interpret
CAA section 111 as permitting each
State to adopt measures that allow its
sources to meet their emissions limits in
the aggregate, when the EPA
determines, in any particular emission
guideline, that it is appropriate to do so,
given, inter alia, the pollution, sources,
and standards of performance at issue.
Thus, it is the EPA’s proposed position
that CAA 111(d) authorizes the EPA to
approve State plans under particular
emission guidelines that achieve the
requisite emission limitation through
the aggregate reductions from those
sources, including through trading or
averaging where appropriate for a
particular emission guideline and
consistent with the intended
environmental outcomes of the
guideline. As discussed in section XII.E,
the EPA is proposing to allow trading
and averaging under the proposed
emission guidelines and requesting
comment on whether and how such
compliance mechanisms could be
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implemented to ensure equivalency
with the emission reductions that would
be achieved if each affected source was
achieving its applicable standard of
performance.
The ACE Rule’s flawed legal
interpretation that CAA section 111(d)
universally precludes States from
emissions trading is incorrect and adds
to EPA’s rationale for proposing to
repeal the rule.
X. Proposed Regulatory Approach for
Existing Fossil Fuel-Fired Steam
Generating Units
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A. Overview
In this section of the preamble, the
EPA explains the basis for its proposed
emission guidelines for GHG emissions
from existing fossil fuel-fired steam
generating units for States’ use in plan
development. This includes proposing
different subcategories of designated
facilities, the BSER for each
subcategory, and the degree of emission
limitation achievable by application of
each proposed BSER. The EPA is
proposing subcategories for steam
generating units based on the type and
amount of fossil fuel (i.e., coal, oil, and
natural gas) fired in the unit.
For existing coal-fired steam
generating units that plan to operate in
the long-term, the EPA is proposing CCS
with 90 percent capture as BSER, based
on a review of emission control
technologies detailed further in this
section of the preamble and
accompanying TSDs, available in the
docket. The EPA is soliciting comment
on a range of maximum capture rates
(90 to 95 percent or greater) and, to
potentially account for the amount of
time the capture equipment operates
relative to operation of the steam
generating unit, a slightly lower
achievable degree of emission limitation
(75 to 90 percent reduction in average
annual emission rate, defined in terms
of pounds of CO2 per unit of
generation).
During the EPA’s engagement with
stakeholders to inform this proposed
rule, industry stakeholders noted that
many coal-fired sources have plans to
permanently cease operation in the
coming years, and that GHG control
technologies might not be cost
reasonable for those units operating on
shorter timeframes. These stakeholders
recommended that the emission
guidelines account for industry plans
for permanently ceasing operation of
coal-fired steam generating units by
establishing a ‘‘subcategory pathway’’
with less stringent requirements.
Consistent with this stakeholder
input, the EPA proposes to provide
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subcategories for coal-fired steam
generating units planning to
permanently cease operations in the
2030s. The EPA recognizes that the cost
reasonableness of GHG control
technology options differ depending on
a coal-fired steam generating unit’s
expected operating time horizon.
Accordingly, the EPA is proposing to
divide the subcategory for coal-fired
units into additional subcategories
based on operating horizon (i.e., dates
for electing to permanently cease
operation) and, for one of those
subcategories, load level (i.e., annual
capacity factor), with a separate BSER
and degree of emission limitation
corresponding to each subcategory. For
long-term coal-fired units, the EPA is
proposing that CCS satisfies the BSER
criteria, as noted above. For mediumterm units, the EPA is proposing natural
gas co-firing at 40 percent of annual heat
input as BSER. The EPA is soliciting
comment on the percent of natural gas
co-firing from 30 to 50 percent and the
degree of emission limitation defined by
a reduction in emission rate from 12 to
20 percent. For imminent-term and
near-term coal-fired steam generating
units, the EPA is proposing a BSER of
routine methods of operation and
maintenance. Because of differences in
performance between units, the EPA is
proposing to determine the associated
degree of emission limitation as no
increase in emission rate. For imminentterm and near-term coal-fired steam
generating units, the EPA is also
soliciting comment on a potential BSER
based on low levels of natural gas cofiring.
For natural gas- and oil-fired steam
generating units, the EPA is proposing
a BSER of routine methods of operation
and maintenance and a degree of
emission limitation of no increase in
emission rate. Further, the EPA is
proposing to divide subcategories for
oil- and natural gas-fired units based on
capacity and, in some cases, geographic
location. Because natural gas- and oilfired steam generating units with similar
annual capacity factors perform
similarly to one another, the EPA is
proposing presumptive standards of
performance of 1,300 lb CO2/MWh-gross
for base load units (i.e., those with
annual capacity factors greater than 45
percent) and 1,500 lb CO2/MWh-gross
for intermediate load units (i.e., those
with annual capacity factors between 8
and 45 percent). Because natural gasand oil-fired steam generating units
with low load have large variations in
emission rate, the EPA is not proposing
a BSER or degree of emission limitation
for those units in this action. However,
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33341
the EPA is soliciting comment on a
potential BSER of ‘‘uniform fuels’’ and
degree of emission limitation defined on
a heat input basis by 120 to 130 lb CO2/
MMBtu for low load natural gas-fired
steam generating units and 150 to 170
lb CO2/MMBtu for low load oil-fired
steam generating units. Also, because
non-continental oil-fired steam
generating units operate at intermediate
and base load, and because there are
relatively few of those units for which
to define a limit on a fleet-wide basis,
the EPA is proposing a degree of
emission limitation for those units of no
increase in emission rate and
presumptive standards based on unitspecific emission rates, as detailed in
section XII of this preamble. The EPA is
soliciting comment on ranges of annual
capacity factors to define the thresholds
between the load levels and ranges in
the degrees of emission limitation, as
specified in section X.E of this
preamble.
It should be noted that the EPA is
proposing a compliance date of January
1, 2030, as discussed in section XII of
this preamble on State plan
development.
The remainder of this section is
organized into the following
subsections. Subsection B describes the
proposed applicability requirements for
existing steam generating units.
Subsection C provides the explanation
for the proposed subcategories.
Subsection D contains, for coal-fired
steam generating units, a summary of
the systems considered for the BSER,
detailed discussion of the systems and
other options considered, and
explanation and justification for the
determination of BSER and degree of
emission limitation. Subsection E
contains, for natural gas- and oil-fired
steam generating units, a summary of
the systems considered for the BSER,
detailed discussion of the systems and
other options considered, and
explanation and justification for the
determination of BSER and degree of
emission limitation.
B. Applicability Requirements for
Existing Fossil Fuel-Fired Steam
Generating Units
For the emission guidelines, the EPA
is proposing that a designated facility 524
is any fossil fuel-fired electric utility
steam generating unit (i.e., utility boiler
or IGCC unit) that: (1) Was in operation
or had commenced construction on or
524 The term ‘‘designated facility’’ means ‘‘any
existing facility . . . which emits a designated
pollutant and which would be subject to a standard
of performance for that pollutant if the existing
facility were an affected facility.’’ See 40 CFR
60.21a(b).
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before January 8, 2014; 525 (2) serves a
generator capable of selling greater than
25 MW to a utility power distribution
system; and (3) has a base load rating
greater than 260 GJ/h (250 MMBtu/h)
heat input of fossil fuel (either alone or
in combination with any other fuel).
Consistent with the implementing
regulations, the term ‘‘designated
facility’’ is used throughout this
preamble to refer to the sources affected
by these emission guidelines.526 For this
action, consistent with prior CAA
section 111 rulemakings concerning
EGUs, the term ‘‘designated facility’’
refers to a single EGU that is affected by
these emission guidelines. The rationale
for this proposal concerning
applicability is the same as that for 40
CFR part 60, subpart TTTT (80 FR
64543–44; October 23, 2015). The EPA
incorporates that discussion by
reference here.
Section 111(a)(6) of the CAA defines
an ‘‘existing source’’ as ‘‘any stationary
source other than a new source.’’
Therefore, the emission guidelines
would not apply to any EGUs that are
new after January 8, 2014, or
reconstructed after June 18, 2014, the
applicability dates of 40 CFR part 60,
subpart TTTT. Moreover, because the
EPA is now proposing revised standards
of performance for coal-fired steam
generating units that undertake a
modification, a modified source would
be considered ‘‘new,’’ and therefore not
subject to these emission guidelines, if
the modification occurs after the date
this proposal is published in the
Federal Register. Any source that has
modified prior to that date would be
considered an existing source that is
subject to these emission guidelines.
In addition, the EPA is proposing to
include in the applicability
requirements of the emission guidelines
the same exemptions as discussed for 40
CFR part 60, subpart TTTT in section
VII.E.1 of this preamble. Designated
EGUs that may be excluded from a State
plan are: (1) Units that are subject to 40
CFR part 60, subpart TTTT, as a result
of commencing a qualifying
modification or reconstruction; (2)
steam generating units subject to a
federally enforceable permit limiting
net-electric sales to one-third or less of
their potential electric output or 219,000
525 Under CAA section 111, the determination of
whether a source is a new source or an existing
source (and thus potentially a designated facility)
is based on the date that the EPA proposes to
establish standards of performance for new sources.
526 The EPA recognizes, however, that the word
‘‘facility’’ is often understood colloquially to refer
to a single power plant, which may have one or
more EGUs co-located within the plant’s
boundaries.
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MWh or less on an annual basis and
annual net-electric sales have never
exceeded one-third or less of their
potential electric output or 219,000
MWh; (3) non-fossil fuel units (i.e., units
that are capable of deriving at least 50
percent of heat input from non-fossil
fuel at the base load rating) that are
subject to a federally enforceable permit
limiting fossil fuel use to 10 percent or
less of the annual capacity factor; (4)
CHP units that are subject to a federally
enforceable permit limiting annual netelectric sales to no more than either
219,000 MWh or the product of the
design efficiency and the potential
electric output, whichever is greater; (5)
units that serve a generator along with
other steam generating unit(s), where
the effective generation capacity
(determined based on a prorated output
of the base load rating of each steam
generating unit) is 25 MW or less; (6)
municipal waste combustor units
subject to 40 CFR part 60, subpart Eb;
(7) commercial or industrial solid waste
incineration units that are subject to 40
CFR part 60, subpart CCCC; or (8) EGUs
that derive greater than 50 percent of the
heat input from an industrial process
that does not produce any electrical or
mechanical output or useful thermal
output that is used outside the affected
EGU. The EPA solicits comment on the
proposed definition of ‘‘designated
facility’’ and applicability exemptions
for fossil fuel-fired steam generating
units.
The exemptions listed above at (4),
(5), (6), and (7) are among the current
exemptions at 40 CFR 60.5509(b), as
discussed in section VII.E.1 of this
preamble. The exemptions listed above
at (2), (3), and (8) are exemptions the
EPA is proposing to revise for 40 CFR
part 60, subpart TTTT, and the rationale
for proposing the exemptions is in
section VII.E.1 of this preamble. For
consistency with the applicability
requirements in 40 CFR part 60, subpart
TTTT, we are proposing these same
exemptions for the applicability of the
emission guidelines.
The EPA is, in general, proposing the
same emission guidelines for fossil fuelfired steam generating units in noncontinental areas (i.e., Hawaii, the
Virgin Islands, Guam, American Samoa,
the Commonwealth of Puerto Rico, and
the Northern Mariana Islands) and noncontiguous areas (non-continental areas
and Alaska) as the EPA is proposing for
comparable units in the contiguous 48
States. However, units in noncontinental and non-contiguous areas
operate on small, isolated electric grids,
may operate differently from units in
the contiguous 48 States, and may have
limited access to certain components of
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the proposed BSER due to their
uniquely isolated geography or
infrastructure. Therefore, the EPA is
soliciting comment on the proposed
BSER and degrees of emission limitation
for units in non-continental and noncontiguous areas, and the EPA is
soliciting comment on whether those
units in non-continental and noncontiguous areas should be subject to
different, if any, requirements.
The EPA notes that existing IGCC
units are included in the proposed
applicability requirements and that, in
section X.C.1 of this preamble, the EPA
is proposing to include those units in
the subcategory of coal-fired steam
generating units. IGCC units gasify coal
or solid fossil fuel (e.g., pet coke) to
produce syngas (a mixture of carbon
monoxide and hydrogen), and either
burn the syngas directly in a combined
cycle unit or use a catalyst for water-gas
shift (WGS) to produce a precombustion gas stream with a higher
concentration of CO2 and hydrogen,
which can be burned in a hydrogen
turbine combined cycle unit. As
described in section X.D of this
preamble, the proposed BSER for coalfired steam generating units includes cofiring natural gas and CCS, depending
on their operating horizon. The few
IGCC units that now operate in the U.S.
either burn natural gas exclusively—and
as such operate as natural gas combined
cycle units—or in amounts near to the
40 percent level of the natural gas cofiring BSER. Additionally, IGCC units
are suitable for pre-combustion CO2
capture. Because the CO2 concentration
in the pre-combustion gas, after WGS, is
high relative to coal-combustion flue
gas, pre-combustion CO2 capture for
IGCC units can be performed using
either an amine-based capture process
or a physical absorption capture
process. For these reasons, the EPA is
not proposing to distinguish IGCC units
from other coal-fired steam generating
EGUs, so that the BSER of co-firing for
medium-term coal-fired units and CCS
for long-term coal-fired units apply to
IGCC units.527
C. Subcategorization of Fossil Fuel-Fired
Steam Generating Units
Steam generating units can have a
broad range of technical and operational
differences. Based on these differences,
they may be subcategorized, and
different BSER and degrees of emission
limitation may be applicable to different
subcategories. Subcategorizing allows
for determining the most appropriate
527 For additional details on pre-combustion CO
2
capture, please see the GHG Mitigation Measures for
Steam Generating Units TSD.
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Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed Rules
control requirements for a given class of
steam generating unit. Therefore, the
EPA is proposing subcategories for
steam generating units based on fossil
fuel type, operating horizon and load
level, and is proposing different BSER
and degrees of emission limitation for
those different subcategories. The EPA
notes that in section XII.B of this
preamble comment is solicited on the
compliance deadline (i.e., January 1,
2030), for imminent-term and near-term
coal-fired steam generating units, and
different subcategories of natural gasand oil-fired steam generating units.
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1. Subcategorization by Fossil Fuel Type
In this action, the EPA is proposing
definitions for subcategories of existing
fossil fuel-fired steam generating units
based on the type and amount of fossil
fuel used in the unit. The subcategory
definitions proposed for these emission
guidelines are based on the definitions
in 40 CFR part 63, subpart UUUUU, and
using the fossil fuel definitions in 40
CFR part 60, subpart TTTT.
A coal-fired steam generating unit is
an electric utility steam generating unit
or IGCC unit that meets the definition of
‘‘fossil fuel-fired’’ and that burns coal
for more than 10.0 percent of the
average annual heat input during the 3
calendar years prior to the proposed
compliance deadline (i.e., January 1,
2030), or for more than 15.0 percent of
the annual heat input during any one of
those calendar years, or that retains the
capability to fire coal after December 31,
2029.
An oil-fired steam generating unit is
an electric utility steam generating unit
meeting the definition of ‘‘fossil fuelfired’’ that is not a coal-fired steam
generating unit and that burns oil for
more than 10.0 percent of the average
annual heat input during the 3 calendar
years prior to the proposed compliance
deadline (i.e., January 1, 2030), or for
more than 15.0 percent of the annual
heat input during any one of those
calendar years, and that no longer
retains the capability to fire coal after
December 31, 2029.
A natural gas-fired steam generating
unit is an electric utility steam
generating unit meeting the definition of
‘‘fossil fuel-fired’’ that is not a coal-fired
or oil-fired steam generating unit and
that burns natural gas for more than 10.0
percent of the average annual heat input
during the 3 calendar years prior to the
proposed compliance deadline (i.e.,
January 1, 2030), or for more than 15.0
percent of the annual heat input during
any one of those calendar years, and
that no longer retains the capability to
fire coal after December 31, 2029.
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2. Subcategorization of Natural Gas- and
Oil-Fired Steam Generating Units by
Load Level
The EPA is also proposing additional
subcategories for oil-fired and natural
gas-fired steam generating units, based
on load levels: ‘‘low’’ load, defined by
annual capacity factors less than 8
percent; ‘‘intermediate’’ load, defined by
annual capacity factors greater than or
equal to 8 percent and less than 45
percent; and ‘‘base’’ load, defined by
annual capacity factors greater than or
equal to 45 percent. In addition, the
EPA is soliciting comment on a range
from 5 to 20 percent to define the
threshold value between low and
intermediate load and a range from 40
to 50 percent to define the threshold
value between intermediate and base
load. Because non-continental oil-fired
units may operate differently, the EPA
is proposing a separate subcategory for
intermediate and base load noncontinental oil-fired units. The rationale
for the proposed load thresholds and
other subcategories is detailed in the
description of the BSER for oil- and
natural gas-fired steam generating units
in section X.E of this preamble.
3. Subcategorization of Coal-Fired
Steam Generating Units by Operating
Horizon and Load Level
The EPA is proposing CCS with 90
percent capture as BSER for existing
coal-fired steam generating units that
will operate in the long-term (i.e., those
that intend to operate on or after January
1, 2040), as detailed in section X.D of
this preamble. CCS is adequately
demonstrated at coal-fired steam
generating units, is cost reasonable,
achieves meaningful reductions in GHG
emissions, and meets the other criteria
for the BSER. The EPA is soliciting
comment on a range of maximum
capture rates (90 to 95 percent or
greater) and, to potentially account for
the amount of time the capture
equipment operates relative to operation
of the steam generating unit, a slightly
lower achievable degree of emission
limitation (75 to 90 percent reduction in
average annual emission rate, defined in
terms of pounds of CO2 per unit of
generation).
During the EPA’s engagement with
stakeholders to inform this proposed
rule, industry commenters to the preproposal docket noted that many
sources have plans to permanently cease
operation in the coming years, and that
GHG control technologies might not be
cost reasonable for those units operating
on shorter timeframes. Further, industry
stakeholders recommended that the
emission guidelines account for
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33343
industry plans for permanently ceasing
operation of coal-fired steam generating
units by establishing a ‘‘subcategory
pathway.’’ Specifically, industry
stakeholders requested that, ‘‘[The] EPA
should provide a subcategory pathway
for units to decommission/repower into
the early 2030s, which would include
enforceable shutdown obligations, as
part of an approach to existing unit
guidelines.’’ The stakeholders cited, as a
precedent, the EPA’s creation of—
targeted subcategories for unit closures in
other contexts, most notably the cessation of
coal subcategory in the 2020 Clean Water Act
(CWA) steam electric effluent guidelines . . .
that allows for decommissioning/repowering
by December 31, 2028. This subcategory
allows those facilities that have already filed
closure commitments to continue on a path
to decommission/repower these assets
without installing additional control
equipment that could extend the lives of
these units to support cost recovery.
EPA–HQ–OAR–2022–0723–0024. In
subsequent comment, industry
stakeholders reiterated that, ‘‘[The] EPA
should proactively include a
subcategory that allows for units to optin to a federally enforceable retirement
commitment as part of compliance with
regulations for existing sources under
CAA section 111(d).’’ EPA–HQ–OAR–
2022–0723–0038. Thus, industry
stakeholders recommended that EPA
allow existing sources that are on a path
to near term retirement to continue on
that path without having to install
additional control equipment.
The proposed emission guidelines are
aligned with this recommendation.
Many fossil fuel-fired steam generating
units have plans to cease operations, are
part of utilities with commitments to net
zero power by certain dates, or are in
States or localities with commitments to
net zero power by certain dates. Over
one-third of existing coal-fired steam
generating capacity has planned to cease
operation by 2032, and approximately
half of the capacity has planned to cease
operations by 2040.528 These plans are
part of the industry trend, described in
section IV.F and IV.I, in which owners
and operators of the nation’s coal fleet,
much of it aging, are replacing their
units with natural gas combustion
turbines and, increasingly, renewable
energy.
As industry stakeholders have
pointed out, in previous rulemakings,
the EPA has allowed coal-fired EGUs
with plans to voluntarily cease
operations in the near future to continue
with their plans without having to
install pollution control equipment. In
addition to the 2020 CWA steam electric
528 See
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effluent guidelines these stakeholders
cite, the EPA has also approved regional
haze State implementation plans in
which coal-fired EGUs that voluntarily
committed to cease operations by a
certain date were not subject to more
stringent controls.529
The EPA proposes to take the
approach requested by industry
stakeholders in this rulemaking. The
EPA recognizes that the cost
reasonableness of GHG control
technology options differ depending on
a coal-fired steam generating unit’s
expected operating time horizon.
Certain technologies that are cost
reasonable for EGUs that intend to
operate for the long term are less cost
reasonable for EGUs with shorter
operating horizons because of shorter
amortization periods and, for CCS, less
time to utilize the IRC section 45Q tax
credit.
Accordingly, the EPA is proposing to
divide the subcategory for coal-fired
units into additional subcategories
based on operating horizon (i.e., dates
for electing to permanently cease
operation) and, for one of those
subcategories, load level (i.e., annual
capacity factor), with a separate BSER
and degree of emission limitation
corresponding to each subcategory.
Coal-fired steam generating units would
be able to opt into these subcategories
if they elect to commit to permanently
ceasing operations by a certain date
(and, in the case of one subcategory,
elect to commit to an annual capacity
factor limitation), and also elect to make
such commitments federally enforceable
and continuing by including them in the
State plan.
Specifically, the EPA is proposing
four subcategories for steam generating
units by operating horizon (i.e.,
enforceable commitments to
permanently cease operations) and, in
one case, by load level (i.e., annual
capacity factor) as well. ‘‘Imminentterm’’ steam generating units are those
that (1) Have elected to commit to
permanently cease operations prior to
January 1, 2032, and (2) elect to make
that commitment federally enforceable
and continuing by having it included in
the State plan.530 ‘‘Near-term’’ steam
529 See, e.g., 76 FR 12651, 12660–63 (March 8,
2011) (best available retrofit technology
requirements for Oregon source based on
enforceable retirement that were to be made
federally enforceable in state implementation plan).
530 Operating conditions that are within the
control of a source must, under a range of CAA
programs, be made federally enforceable in order
for a source to rely on them as the basis for a less
stringent standard. See, e.g., 76 FR 12651, 12660–
63 (March 8, 2011) (best available retrofit
technology requirements for Oregon source based
on enforceable retirement that were to be made
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generating units are those that (1) Have
elected to commit to permanently cease
operations by December 31, 2034, as
well as to adopt an annual capacity
factor limit of 20 percent, and (2) elect
to make both conditions federally
enforceable and continuing by having
them included in the State plan.
‘‘Medium-term’’ steam generating units
are those that (1) Operate after
December 31, 2031, (2) have elected to
commit to permanently cease operations
prior to January 1, 2040, (3) elect to
make that commitment federally
enforceable and continuing by having it
included in the State plan, and (4) do
not meet the definition of near-term
units. ‘‘Long-term’’ steam generating
units are those that have not elected to
commit to permanently cease operations
prior to January 1, 2040. Details
regarding the implementation of
subcategories in State plans are
available in section XII.D of this
preamble.
The EPA is proposing the imminentterm subcategory based on a 2-year
operating horizon from the proposed
compliance deadline (January 1, 2030,
see section XII.B for additional details).
This proposed subcategory is designed
to accommodate units with operating
horizons short enough that no
additional CO2 control measures would
be cost reasonable. The EPA is
proposing the near-term subcategory to
provide an alternative option for units
that intend to operate for a slightly
longer horizon but as peaking units, i.e.,
that intend to run at lower load levels.
The load level of 20 percent for the
near-term subcategory is based on
spreading an average 2 years of
generation (i.e., 50 percent in each year,
a typical load level) that would occur
under the imminent-term subcategory
over the 5-year operating horizon of the
near-term subcategory. The EPA also
solicits comment on whether the
existence of the near-term subcategory
makes the imminent-term subcategory
unnecessary. More specifically, the EPA
federally enforceable in state implementation plan);
Guidance on Regional Haze State Implementation
Plans for the Second Implementation Period at 34,
EPA–457/B–19–003, August 2019 (to the extent a
state relies on an enforceable shutdown date for a
reasonable progress determination, that measure
would need to be included in the SIP and/or be
federally enforceable); 84 FR 32520, 32558 (July 8,
2019) (to the extent a state relies on a source’s
retirement date for a standard of performance under
111(d), that date must be included in the state plan
and will thus be made federally enforceable); 87 FR
79176, 79200–01 (December 23, 2022) (proposed
revisions to CAA section 111(d) implementing
regulations would require States to include
operating conditions, including retirements, in their
state plans whenever the state seeks to rely on that
operating condition as the basis for a less stringent
standard).
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requests comment on the potential to
remove the imminent-term subcategory,
which as proposed includes coal-fired
steam generating units that have elected
to commit to permanently cease
operations prior to January 1, 2032. The
EPA is considering an option in which
these units would instead be included
in the near-term subcategory (units that
have elected to commit to permanently
cease operations before January 1, 2035
and commit to adopt an annual capacity
factor limit of 20 percent) or the
medium-term subcategory (units that
have elected to commit to permanently
cease operations before January 1, 2040
and that are not near-term units). The
EPA further requests comment on an
alternative, modified approach for units
in the imminent-term subcategory that
could take into account how units
intending to cease operations operate in
practice in the period leading up to such
cessation. For instance, in their last few
years of operation, those units may
operate less than they have historically
operated, lowering their total CO2 mass
emissions, but at the same time raising
their emission rate (because lower
utilization may result in lower
efficiency). The EPA solicits comment
on whether it would be appropriate for
the imminent-term units’ standards of
performance to reflect the reduced
utilization and higher emission rates
through the use of an annual mass
emission limitation. Such a limitation
would account for lower utilization, but
also allow greater flexibility with regard
to hourly emission rate.
The EPA is proposing the 10-year
operating horizon (i.e., January 1, 2040)
as the threshold between medium-term
and long-term subcategories because
long-term units will have a longer
amortization period and may be better
able to fully utilize the IRC section 45Q
tax credit. For the analysis of BSER
costs of CCS for long-term units, the
EPA assumes a 12-year amortization
period as this is commensurate with the
time period the IRC section 45Q tax
credit would be available. Based on the
cost analysis performed under that
assumption, the EPA is proposing the
costs of CCS for long-term coal-fired
units are reasonable, as detailed in
section X.D.1.a.ii of this preamble. To
support the 10-year operating horizon
threshold, the costs for a 10-year
amortization period are shown here. For
a 10-year amortization period, assuming
a 50 percent capacity factor, costs of
CCS for a representative unit are $31/
ton of CO2 reduced or $27/MWh of
generation. Assuming a 70 percent
capacity factor, costs of CCS for a
representative unit are $6/ton of CO2
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reduced or $5/MWh of generation. For
the population of units planning to
operate on or after January 1, 2030, the
fleet average costs assuming a 50
percent capacity factor are $24/ton of
CO2 reduced or $22/MWh. For the
population of units planning to operate
on or after January 1, 2030, the fleet
average costs assuming a 70 percent
capacity factor are ¥$3/ton of CO2
reduced or ¥$2/MWh. Costs vary
depending on capacity factor
assumptions, but are in either case
generally comparable to the costs
detailed in section VII.F.3.b.iii(B)(5) of
this preamble of other controls on EGUs
($10.60 to $29.00/MWh) and less than
the costs in the 2016 NSPS regulating
GHGs for the Crude Oil and Natural Gas
source category of $98/ton of CO2e
reduced (80 FR 56627; September 18,
2015). The EPA is soliciting comment
on the dates and load levels used to
define the coal-fired subcategories and
is seeking data and analysis on the
impact of those alternative dates and
load levels on the compliance
requirements. As noted in section
X.D.1.a.ii(C) of this preamble, the costs
for CCS may be reasonable for units
with amortization periods as short as 8
years. Therefore, the EPA is specifically
soliciting comment on an operating
horizon of between 8 and 10 years (i.e.,
January 1, 2038, to January 1, 2040) to
define the date for the threshold
between medium-term and long-term
coal-fired steam generating units.
4. Legal Basis for Subcategorization
As noted in section V of this
preamble, the EPA has broad authority
under CAA section 111(d) to identify
subcategories. As also noted in section
V, the EPA’s authority to ‘‘distinguish
among classes, types, and sizes within
categories,’’ as provided under CAA
section 111(b)(2) and as we interpret
CAA section 111(d) to provide as well,
generally allows the Agency to place
types of sources into subcategories
when they have characteristics that are
relevant to the controls that the EPA
may determine to be the BSER for those
sources. One element of the BSER is
cost reasonableness. See CAA section
111(d)(1) (requiring the EPA, in setting
the BSER, to ‘‘tak[e] into account the
cost of achieving such reduction’’). As
noted in section V, the EPA’s longstanding regulations under CAA section
111(d) explicitly recognize that
subcategorizing may be appropriate for
sources based on the ‘‘costs of
control.’’ 531 Subcategorizing on the
basis of operating horizon is consistent
with a central characteristic of the coal531 40
CFR 60.22(b)(5), 60.22a(b)(5).
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fired power industry that is relevant for
determining the cost reasonableness of
control requirements: A large percentage
of the industry has announced, or is
expected to announce, dates for ceasing
operation, and the fact that many coalfired steam generating units intend to
cease operation affects what controls are
‘‘best’’ for different subcategories.
Whether the costs of control are
reasonable depends in part on the
period of time over which the affected
sources can amortize those costs.
Sources that have shorter operating
horizons will have less time to amortize
capital costs and the controls will
thereby be less cost-effective and
therefore may not qualify as the
BSER.532
In addition, subcategorizing by length
of period of continued operation is
similar to two other bases for
subcategorization on which the EPA has
relied in prior rules, each of which
implicates the cost reasonableness of
controls: The first is load level, noted in
section X.C of this preamble. For
example, in the 2015 NSPS, the EPA
divided new natural gas-fired
combustion turbines into the
subcategories of base load and non-base
load. 80 FR 64510, 64602 (table 15)
(October 23, 2015). The EPA did so
because the control technologies that
were ‘‘best’’-including consideration of
feasibility and cost-reasonableness—
depended on how much the unit
operated. The load level, which relates
to the amount of product produced on
a yearly or other basis, bears similarity
to a limit on a period of continued
operation, which concerns the amount
of time remaining to produce the
product. In both cases, certain
technologies may not be cost reasonable
because of the capacity to produce
product—i.e., because the costs are
spread over less product produced.
The second is fuel type, as also noted
in section X.C of this preamble. The
2015 NSPS provides an example of this
type of subcategorization as well. There,
the EPA divided new combustion
turbines into subcategories on the basis
of type of fuel combusted. Id.
Subcategorizing on the basis of the type
of fuel combusted may be appropriate
when different controls have different
costs, depending on the type of fuel, so
that the cost-reasonableness of the
control depends on the type of fuel. In
that way, it is similar to subcategorizing
by operating horizon because in both
cases, the subcategory is based upon the
532 Steam Electric Reconsideration Rule, 85 FR
64650, 64679 (October 13, 2020) (distinguishes
between EGUs retiring before 2028 and EGUs
remaining in operation after that time).
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33345
cost reasonableness of controls.
Subcategorizing by fuel type presents an
additional analogy to the present case of
subcategorizing on the basis of the
length of time when the source will
continue to operate because this
timeframe is tantamount to the length of
time when the source will continue to
combust the fuel. Subcategorizing on
this basis may be appropriate when
different controls for a particular fuel
have different costs, depending on the
length of time when the fuel will
continue to be combusted, so that the
cost-reasonableness of controls depends
on that timeframe. Some prior EPA rules
for coal-fired sources have made explicit
the link between length of time for
continued operation and type of fuel
combusted by codifying federally
enforceable retirement dates as the dates
by which the source must ‘‘cease
burning coal.’’ 533
It should be noted that
subcategorizing on the basis of operating
horizon does not preclude a State from
considering RULOF in applying a
standard of performance to a particular
source. EPA’s authority to set BSER for
a source category (including
subcategories) and a State’s authority to
invoke RULOF for individual sources
within a category or subcategory are
distinct. EPA’s statutory obligation is to
determine a generally applicable BSER
for a source category, and where that
source category encompasses different
classes, types, or sizes of sources, to set
generally applicable BSERs for
subcategories accounting for those
differences. By contrast, States’
authority to invoke RULOF is premised
on the State’s ability to take into
account the characteristics of a
particular source that may differ from
the assumptions EPA made in
determining BSER generally. As noted
above, the EPA is proposing these
subcategories in response to requests by
power sector representatives that this
rule accommodate the fact that there is
a class of sources that plans to
voluntarily cease operations in the near
term. Although the EPA has designed
the subcategories to accommodate those
requests, a particular source may still
present source-specific considerations—
whether related to its remaining useful
life or other factors—that the State may
consider relevant for the application of
that particular source’s standard of
performance, and that the State should
533 See 79 FR 5031, 5192 (January 30, 2014)
(explaining that ‘‘[t]he construction permit issued
by Wyoming requires Naughton Unit 3 to cease
burning coal by December 31, 2017 and to be
retrofitted to natural gas as its fuel source by June
30, 2018’’ (emphasis added)).
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address as described in section XII.D.2
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D. Determination of BSER for Coal-Fired
Steam Generating Units
The EPA evaluated two primary
control technologies as potentially
representing the BSER for existing coalfired steam generating units: CCS and
natural gas co-firing. This section of the
preamble discusses each of these
alternatives, based on the criteria
described in section V.C of this
preamble.
The EPA is proposing CCS with 90
percent capture as BSER for long-term
coal-fired steam generating units, that is,
ones that are expected to continue to
operate past 2039, because CCS can
achieve an appropriate amount of
emission reductions and satisfies the
other BSER criteria. Because CCS is less
cost reasonable for EGUs that do not
plan to operate in the long term, the
EPA is proposing other measures as
BSER for the other subcategories of
existing coal-fired steam generating
units.
Specifically, for medium-term units,
that is, ones that have elected to commit
to permanently cease operations after
December 31, 2031, and before January
1, 2040, and are not near-term units, the
EPA is proposing a BSER of 40 percent
natural gas co-firing on a heat input
basis. However, the EPA is taking
comment on the operating horizon (i.e.,
between 8 and 10 years, instead of the
proposed 10-year operating horizon)
that defines the threshold date between
medium-term and long-term coal-fired
steam generating units, and it is possible
that the costs of CCS may be considered
reasonable for some portion of the units
that may be covered by the mediumterm subcategory as proposed.
For imminent-term and near-term
units, that is, ones that have elected to
commit to permanently cease operations
before January 1, 2032, and between
December 31, 2031, and January 1, 2035,
coupled with an annual capacity factor
limit, respectively, the EPA is proposing
a BSER of routine methods of operation
and maintenance that maintain current
emission rates. The EPA is also
soliciting comment on a potential BSER
based on low levels of natural gas cofiring for imminent- and near-term
units.
1. Long-Term Coal-Fired Steam
Generating Units
In this section of the preamble, the
EPA evaluates CCS and natural gas cofiring as potential BSER for long-term
coal-fired steam generating units.
The EPA is proposing CCS with 90
percent capture of CO2 at the stack as
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BSER for long-term coal-fired steam
generating units. The Agency is taking
comment on the range of the amount of
capture of CO2 from 90 to 95 percent or
greater. CCS achieves substantial
reductions in emissions and can capture
and permanently sequester more than
90 percent of CO2 emitted by coal-fired
steam generating units. The technology
is adequately demonstrated, as
indicated by the facts that it has been
operated at scale and is widely
applicable to sources, and there are vast
sequestration opportunities across the
continental U.S. Additionally, the costs
for CCS are reasonable, in light of recent
technology cost declines and policies
including the tax credit under IRC
section 45Q. Moreover, the non-air
quality health and environmental
impacts and energy requirements of CCS
are not unreasonably adverse. These
factors provide the basis for proposing
CCS as BSER for these sources. In
addition, determining CCS as the BSER
promotes this useful GHG emission
control technology.
The EPA also evaluated natural gas
co-firing at 40 percent of heat input as
a potential BSER for long-term coal-fired
steam generating units. While the unit
level emission rate reductions of 16
percent achieved by 40 percent natural
gas co-firing are reasonable, those
reductions are substantially less than
CCS with 90 percent capture of CO2.
Therefore, because CCS achieves more
reductions at the unit level and is cost
reasonable, the EPA is not proposing
natural gas co-firing as the BSER for
these units.
a. CCS
In this section of the preamble, the
EPA evaluates the use of CCS as the
BSER for existing long-term coal-fired
steam generating units. This section
incorporates by reference the parts of
section VII.F.3.b.iii of this preamble that
discuss the aspects of CCS that are
common to new combustion turbines
and existing steam generating units.
This section also discusses additional
aspects of CCS that are relevant for
existing steam generating units and, in
particular, long-term units.
i. Adequately Demonstrated
The EPA is proposing that CCS is
technically feasible and has been
adequately demonstrated, based on the
utilization of the technology at existing
coal-fired steam generating units and
industrial sources in addition to
combustion turbines. While the EPA
would propose that CCS is adequately
demonstrated on those bases alone, this
determination is further corroborated by
EPAct05-assisted projects.
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The fundamental CCS technology has
been in existence for decades, and the
industry has extensive experience with
and knowledge about it. Indeed, even
without the requirements proposed
here, the EPA projects that 9 GW of
coal-fired steam generating units would
apply CCS by 2030. Thus, the EPA will
explain how existing and planned fossil
fuel-fired electric power plants and
other industrial projects that have
installed or expect to install some or all
of the components of CCS technology
support the EPA’s proposed
determination that CCS is adequately
demonstrated for existing coal-fired
power plants, and the EPA will explain
how EPAct05-assisted projects support
that proposed determination, consistent
with the legal interpretation of the
EPAct05 in section VII.F.3.b.iii(A) of
this preamble.
(A) CO2 Capture Technology
The technology of CO2 capture, in
general, is detailed in accompanying
TSDs (available in the docket) and in
section VII.F.3.b.iii of this preamble. As
noted there, solvent-based (i.e., aminebased) post-combustion CO2 capture is
the technology that is most applicable at
existing coal-fired steam generating
units. Technology considerations
specific to existing coal-fired steam
generating units, including energy
demands, non-GHG emissions, and
water use and siting, are discussed in
section X.D.1.a.iii of this preamble. As
detailed in section VII.F.3.b.iii(A) of this
preamble, the CO2 capture component
of CCS has been demonstrated at
existing coal-fired steam generating
units, industrial processes, and existing
combustion turbines. In particular,
SaskPower’s Boundary Dam Unit 3 has
demonstrated capture rates of 90
percent of the CO2 in flue gas using
solvent-based post-combustion capture
retrofitted to existing coal-fired steam
generating units. While the EPA would
propose that the CO2 capture
component of CCS is adequately
demonstrated on the basis of Boundary
Dam Unit 3 alone, CO2 capture has been
further demonstrated at other coal-fired
steam generating units (CO2 capture
from slipstreams of AES’s Warrior Run
and Shady Point) and industrial
processes (e.g., Quest CO2 capture
project), detailed descriptions of which
are provided in section
VII.F.3.b.iii(A)(2) of this preamble. The
core technology of CO2 capture applied
to combustion turbines is similar to that
of coal-fired steam generating units (i.e.,
both may use amine solvent-based
methods); therefore the demonstration
of CO2 capture at combustion turbines
(e.g., the Bellingham, Massachusetts,
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combined cycle unit), as detailed in
section VII.F.3.b.iii(A)(3) of this
preamble, provide additional support
for the adequate demonstration of CO2
capture for coal-fired steam generating
units. Finally, EPAct05-assisted CO2
capture projects (e.g., Petra Nova)
further corroborate the adequate
demonstration of CO2 capture.
(B) CO2 Transport
As discussed in section VII.F.3.b.iii of
this preamble, CO2 pipelines are
available and their network is
expanding in the U.S., and the safety of
existing and new supercritical CO2
pipelines is comprehensively regulated
by PHMSA.534 Other modes of CO2
transportation also exist.
Based on data from DOE/NETL
studies of storage resources, 77 percent
of existing coal-fired steam generating
units that have planned operation
during or after 2030 are within 80 km
(50 miles) of potential saline
sequestration sites, and another 5
percent are within 100 km (62 miles) of
potential sequestration sites.535
Additionally, of the coal-fired steam
generating units with planned operation
during or after 2030, 90 percent are
located within 100 km of one or more
types of sequestration formations,
including deep saline, unmineable coal
seams, and oil and gas reservoirs. This
distance is consistent with the distances
referenced in studies that form the basis
for transport cost estimates in this
proposal.536 537 As noted in section
VII.F.3.b.iii(A)(5) of this preamble, areas
without reasonable access to pipelines
for geologic sequestration can transport
CO2 to sequestration sites via other
transportation modes such as ship, road
tanker, or rail tank cars.
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(C) Geologic Sequestration of CO2
Geologic sequestration (i.e., the longterm containment of a CO2 stream in
534 PHMSA additionally initiated a rulemaking in
2022 to develop and implement new measures to
strengthen its safety oversight of CO2 pipelines
following investigation into a CO2 pipeline failure
in Satartia, Mississippi in 2020. For more
information, see: https://www.phmsa.dot.gov/news/
phmsa-announces-new-safety-measures-protectamericans-carbon-dioxide-pipeline-failures.
535 Sequestration potential as it relates to distance
from existing resources is a key part of the EPA’s
regular power sector modeling development, using
data from DOE/NETL studies. For details please see
Chapter 6 of the IPM documentation available at:
https://www.epa.gov/system/files/documents/202109/chapter-6-co2-capture-storage-andtransport.pdf.
536 The pipeline diameter was sized for this to be
achieved without the need for recompression stages
along the pipeline length.
537 Note that the determination that the BSER has
been adequately demonstrated does not require that
every source in the long-term coal-fired steam
generating unit subcategory be within 100 km of
CO2 storage.
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subsurface geologic formations) is well
proven and broadly available
throughout the U.S. Geologic
sequestration is based on a
demonstrated understanding of the
processes that affect the fate of CO2 in
the subsurface. As discussed in section
VII.F.3.a.iii of this preamble, there have
been numerous instances of geologic
sequestration in the U.S. and overseas,
and the U.S. has developed a detailed
set of regulatory requirements to ensure
the security of sequestered CO2. This
regulatory framework includes the UIC
Class VI well regulations, which are
under the authority of SDWA, and the
GHGRP, under the authority of the CAA.
Geologic sequestration potential for
CO2 is widespread and available
throughout the U.S. Through an
availability analysis of sequestration
potential in the U.S. based on resources
from the DOE, the USGS, and the EPA,
the EPA found that there are 43 States
with access to, or are within 100 km
from, onshore or offshore storage in
deep saline formations, unmineable coal
seams, and depleted oil and gas
reservoirs.
Sequestration potential as it relates to
distance from existing resources is a key
part of the EPA’s regular power sector
modeling development, using data from
DOE/NETL studies.538 These data show
that of the coal-fired steam generating
units with planned operation during or
after 2030, 60 percent are located within
the boundary of a saline reservoir, 77
percent are located within 40 miles (80
km) of the boundary of a saline
reservoir, and 82 percent are located
within 62 miles (100 km) of a saline
reservoir. Additionally, of the coal-fired
steam generating units with planned
operation during or after 2030, 90
percent are located within 100 km of
any of the considered formations,
including deep saline, unmineable coal
seams, and oil and gas reservoirs.539 540
As noted in section VII.F.3.b.iii(A)(5) of
this preamble, areas without reasonable
access to pipelines for geologic
sequestration can transport CO2 to
sequestration sites via other
transportation modes such as ship, road
tanker, or rail tank cars.
538 For details, please see Chapter 6 of the IPM
documentation. https://www.epa.gov/system/files/
documents/2021-09/chapter-6-co2-capture-storageand-transport.pdf.
539 The distance of 100 km is consistent with the
assumptions underlying the NETL cost estimates for
transporting CO2 by pipeline.
540 Note that the determination that the BSER has
been adequately demonstrated does not require that
every source in the long-term coal-fired steam
generating unit subcategory be within 100 km of
CO2 storage.
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ii. Costs
The EPA has analyzed the costs of
CCS for existing coal-fired long-term
sources, including costs for CO2 capture,
transport, and sequestration. The EPA is
proposing that this analysis
demonstrates that the costs of CCS for
these sources are reasonable. The EPA
also evaluated costs assuming a higher
capacity factor of 70 percent (resulting
in lower costs) and different
amortization periods, as discussed in
section X.D.1.a.ii(C) of this preamble.
The EPA is soliciting comment on the
assumptions in the cost analysis,
particularly with respect to the capacity
factor assumption. As elsewhere in this
section of the preamble, costs are
presented in 2019 dollars.
The EPA assessed costs of CCS for a
reference unit as well as the average cost
for the fleet of coal-fired steam
generating units with planned operation
during or after 2030. The reference unit,
which represents an average unit in the
fleet, has a 400 MW-gross nameplate
capacity and a 10,000 Btu/kWh heat
rate. Applying CCS to the reference unit
with a 12-year amortization period and
assuming a 50 percent annual capacity
factor—a typical value for the fleet—
results in annualized total costs that can
be expressed as an abatement cost of
$14/ton of CO2 reduced and an
incremental cost of electricity of $12/
MWh. Included in these estimates is the
EPA’s assessment that the transport and
storage costs are roughly $30/ton, on
average for the reference unit. For the
fleet of coal-fired steam generating units
with planned operation during or after
2030, and assuming a 12-year
amortization period and 50 percent
annual capacity factor and including
source specific transport and storage
costs, the average total costs of CCS are
$8/ton of CO2 reduced and $7/MWh.
These total costs also account for the
IRC section 45Q tax credit, a detailed
discussion of which is provided in
section VII.F.3.b.iii(B)(3) of this
preamble. Compared to the
representative costs of controls detailed
in section VII.F.3.b.iii(B)(5) of this
preamble (i.e., emission control costs on
EGUs of $10.60 to $29/MWh and the
costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas
source category of $98/ton of CO2e
reduced (80 FR 56627; September 18,
2015)) the costs for CCS on long-term
coal-fired steam generating units are
similar or better. Based on all of these
analyses, the EPA is proposing that for
the purposes of the BSER analysis, CCS
is cost reasonable for long-term coalfired steam generating units. The EPA
also evaluated costs of CCS under
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various other assumptions of
amortization period and annual capacity
factor. Finally, it is noted that these CCS
costs are lower than those in prior
rulemakings due to the IRC section 45Q
tax credit and reductions in the cost of
the technology.
(A) CO2 Capture Costs at Existing CoalFired Steam Generating Units
A variety of sources provide
information for the cost of CCS systems,
and they generally agree around a range
of cost. The EPA has relied heavily on
information recently developed by
NETL, in the U.S. Department of Energy,
in particular, ‘‘Cost and Performance
Baseline for Fossil Energy Plants,’’ 541
and the ‘‘Pulverized Coal Carbon
Capture Retrofit Database.’’ 542 In
addition, the EPA developed an
independent engineering cost
assessment for CCS retrofits, with
support from Sargent and Lundy.543
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(B) CO2 Transport and Sequestration
Costs
As discussed in section VII.F.3.b.iii of
this preamble, NETL’s ‘‘Quality
Guidelines for Energy System Studies;
Carbon Dioxide Transport and
Sequestration Costs in NETL Studies’’ is
one of the more comprehensive sources
of information on CO2 transport and
storage costs available. The Quality
Guidelines provide an estimation of
transport costs for a single point-topoint pipeline. Estimated costs reflect
pipeline capital costs, related capital
expenditures, and operations and
maintenance costs.544 These Quality
Guidelines also provide an estimate of
sequestration costs reflecting the cost of
site screening and evaluation,
permitting and construction costs, the
cost of injection wells, the cost of
injection equipment, operation and
maintenance costs, pore volume
acquisition expense, and long-term
liability protection. NETL’s Quality
Guidelines model costs for a given
cumulative storage potential.545
541 https://netl.doe.gov/projects/files/
CostAndPerformanceBaselineForFossilEnergyPlants
Volume1BituminousCoalAnd
NaturalGasToElectricity_101422.pdf.
542 https://netl.doe.gov/energy-analysis/
details?id=69db8281-593f-4b2e-ac68-061b17574fb8.
543 Detailed cost information, assessment of
technology options, and demonstration of cost
reasonableness can be found in the GHG Mitigation
Measures for Steam Generating Units TSD.
544 Grant, T., et al. ‘‘Quality Guidelines for Energy
System Studies; Carbon Dioxide Transport and
Storage Costs in NETL Studies.’’ National Energy
Technology Laboratory. 2019. https://
www.netl.doe.gov/energy-analysis/details?id=3743.
545 Details on CO transportation and
2
sequestration costs can be found in the GHG
Mitigation Measures for Steam Generating Units
TSD.
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(C) Amortization Period and Annual
Capacity Factor
In the EPA’s cost analysis for longterm coal-fired steam generating units,
the EPA assumes a 12-year amortization
period and a 50 percent annual capacity
factor. The 12-year amortization period
is consistent with the period of time
during which the IRC section 45Q tax
credit can be claimed and the 50 percent
annual capacity factor is consistent with
the historical fleet average. However,
increases in utilization are likely to
occur for units that apply CCS due to
the incentives provided by the IRC
section 45Q tax credit. Therefore, the
EPA also assessed the costs for CCS
retrofitted to existing coal-fired steam
generating units assuming a 70 percent
annual capacity factor. For a 70 percent
annual capacity factor and a 12-year
amortization period, the costs for the
reference unit are negative at ¥$8/ton
of CO2 reduced and ¥$7/MWh. The
negative costs indicate that the value of
the 45Q tax credit more than offsets the
costs to install and operate CCS. For
either capacity factor assumption, the
$/MWh costs are comparable to or less
than the costs for other controls
($10.60–$29.00/MWh) which are
detailed in section VII.F.3.b.iii(B)(5) of
this preamble.
As noted in section X.C.3 of this
preamble, the EPA is also taking
comment on the operating horizon that
defines the threshold date between the
definition of medium-term and longterm coal-fired steam generating units,
specifically an operating horizon
between 8 and 10 years (i.e., January 1,
2038 to January 1, 2040), instead of the
proposed 10-year operating horizon. For
a 70 percent annual capacity factor and
an 8-year amortization period,
annualized costs of applying CCS for the
reference unit are $24/ton of CO2
reduced and $21/MWh, and it is
possible that the cost of generation may
be reasonable relative to the
representative cost for wet FGD.
However, CCS may be less cost
favorable for units with shorter
amortization periods. For a 70 percent
annual capacity factor and a 7-year
amortization period, costs for the
reference unit are $39/ton of CO2
reduced and $34/MWh. Additional
details of the cost analysis are available
in the GHG Mitigation Measures for
Steam Generating Units TSD.
(D) Comparison to Costs for CCS in Prior
Rulemakings
In the CPP and ACE Rule, the EPA
determined that CCS did not qualify as
the BSER due to cost considerations.
Two key developments have led the
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EPA to reevaluate this conclusion: the
costs of CCS technology have fallen and
the extension and increase in the IRC
section 45Q tax credit, as included in
the IRA, in effect provide a significant
stream of revenue for sequestered CO2
emissions. The CPP and ACE Rule
relied on a 2015 NETL report estimating
the cost of CCS. NETL has issued
updated reports to incorporate the latest
information available, most recently in
2022, which show cost reductions. The
2015 report estimated incremental
levelized cost of CCS at a new
pulverized coal facility relative to a new
facility without CCS at $74/MWh
(2022$),546 while the 2022 report
estimated incremental levelized cost at
$44/MWh (2022$).547 Additionally, the
IRA increased the IRC section 45Q tax
credit from $50/metric ton to $85/metric
ton (and, in the case of EOR or certain
industrial uses, from $35/metric ton to
$60/metric ton), assuming prevailing
wage and apprenticeship conditions are
met. The IRA also enhanced the realized
value of the tax credit through the direct
pay and transferability monetization
options described in section IV.E.1. The
combination of lower costs and higher
tax credits significantly improves the
cost effectiveness of CCS for purposes of
determining whether it qualifies as the
BSER.
iii. Non-Air Quality Health and
Environmental Impact and Energy
Requirements
CCS for steam generating units is not
expected to have unreasonable adverse
consequences related to non-air quality
health and environmental impacts or
energy requirements. The EPA has
considered non-GHG emissions impacts,
the water use impacts, the transport and
sequestration of captured CO2, and
energy requirements resulting from CCS.
Because the non-air quality health and
environmental impacts are closely
related to the energy requirements, the
latter are discussed first.
As noted in section VII.F.3.b.iii(C) of
this preamble, stakeholders have shared
with the EPA concerns about the safety
of CCS projects and concerns that their
communities may bear a
546 Cost And Performance Baseline for Fossil
Energy Plants Volume 1: Bituminous Coal and
Natural Gas to Electricity, Rev. 3 (July 2015).
https://www.netl.doe.gov/projects/files/Costand
PerformanceBaselineforFossilEnergyPlants
Volume1aBitCoalPCandNaturalGastoElectRev3_
070615.pdf.
547 Cost And Performance Baseline for Fossil
Energy Plants Volume 1: Bituminous Coal and
Natural Gas to Electricity, Rev. 4A (October 2022).
https://netl.doe.gov/projects/files/
CostAndPerformanceBaselineForFossilEnergy
PlantsVolume1BituminousCoalAnd
NaturalGasToElectricity_101422.pdf.
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disproportionate environmental burden
associated with CCS projects. The EPA
is committed to working with its fellow
agencies to foster meaningful
engagement with communities and
protect communities from pollution
through the responsible deployment of
CCS. This can be facilitated through the
existing detailed regulatory framework
for CCS projects and further supported
through robust and meaningful public
engagement early in the technological
deployment process. CCS projects
undertaken pursuant to these emission
guidelines will, if the EPA finalizes
proposed revisions to the CAA section
111 implementing regulations,548 be
subject to requirements for meaningful
engagement as part of the State plan
development process. See section
XII.F.1.b of this preamble for additional
details.
(A) Energy Requirements
For a steam generating unit with 90
percent amine-based CO2 capture,
parasitic/auxiliary energy demand
increases and the net power output
decreases. Amine-based CO2 capture is
an energy-intensive process. In
particular, the solvent regeneration
process requires substantial amounts of
heat in the form of steam and CO2
compression requires a large amount of
electricity. Heat and power for the CO2
capture equipment can be provided
either by using the steam and electricity
produced by the steam generating unit
or by an auxiliary cogeneration unit.
However, any auxiliary source of heat
and power is part of the ‘‘designated
facility,’’ along with the steam
generating unit. The standards of
performance apply to the designated
facility. Thus, any CO2 emissions from
the connected auxiliary equipment need
to be captured or they will increase the
facility’s emission rate.
Using integrated heat and power can
reduce the capacity (i.e., the amount of
electricity that a unit can distribute to
the grid) of an approximately 474 MWnet (501 MW-gross) coal-fired steam
generating unit without CCS to
approximately 425 MW-net with CCS
and contributes to a reduction in net
efficiency of 23 percent.549 For retrofits
of CCS on existing sources, the
ductwork for flue gas and piping for
heat integration to overcome potential
spatial constraints are a component of
efficiency reduction. The EPA notes that
slightly greater efficiency reductions
548 87
FR 79176, 79190–92 (December 23, 2022).
‘‘Eliminating the
Derate of Carbon Capture Retrofits.’’ May 31,
2016.https://www.netl.doe.gov/energy-analysis/
details?id=d335ce79-84ee-4a0b-a27bc1a64edbb866.
549 DOE/NETL–2016/1796.
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than in the 2016 NETL retrofit report are
assumed for the BSER cost analyses, as
detailed in the GHG Mitigation
Measures for Steam Generating Units
TSD, available in the docket. Despite
decreases in efficiency, IRC section 45Q
tax credits provide an incentive for
increased generation with full operation
of CCS because the credits are
proportional to the amount of captured
and sequestered CO2 emissions and not
to the amount of electricity generated.
The Agency is proposing that the energy
penalty is relatively minor compared to
the GHG benefits of CCS and, therefore,
does not disqualify CCS as being
considered the BSER for existing coalfired steam generating units.
Additionally, the EPA considered the
impacts on the power sector, on a
nationwide and long-term basis, of
determining CCS to be the BSER for
long-term coal-fired steam generating
units. The EPA is proposing that
designating CCS as the BSER for
existing long-term coal-fired steam
generating units would have limited and
non-adverse impacts on the long-term
structure of the power sector. Absent the
requirements defined in this action, the
EPA projects that 9 GW of coal-fired
steam generating units would apply CCS
by 2030 and 35 GW of coal-fired steam
generating units, some without controls,
would remain in operation in 2040.
Designating CCS to be the BSER for
existing long-term coal-fired steam
generating units would likely result in
more of the coal-fired steam generating
unit capacity applying CCS. The time
available before the compliance
deadline of January 1, 2030, provides for
adequate resource planning, including
accounting for the downtime necessary
to install the CO2 capture equipment at
long-term coal-fired steam generating
units. While the IRC 45Q tax credit is
available, long-term coal-fired steam
generating units are anticipated to run at
base load conditions. Total generation
from coal-fired steam generating units in
the other subcategories would gradually
decrease over an extended period of
time through 2039, subject to the
commitments those units have chosen
to adopt. Any decreases in the amount
of generation from coal-fired steam
generating units, whether locally or
more broadly, are compensated for by
increased generation from other sources.
Additionally, for the long-term units
applying CCS, the EPA is proposing the
increase in the annualized cost of
generation for those units is reasonable.
Therefore, the EPA is proposing that
there would be no unreasonable impacts
on the reliability of electricity
generation. A broader discussion of
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reliability impacts of the proposed
actions is available in section XIV.F of
this preamble. Finally, changes in the
amount of generation from coal-fired
steam generating units may contribute
to additional generation from combined
cycle combustion turbines. Since these
EGUs have lower GHG and criteria
pollutant emission rates than existing
coal-fired steam generating units,
overall emissions from the power sector
would likely decrease.
(B) Non-GHG Emissions
For amine-based CO2 capture retrofits
to coal-fired steam generating units,
decreased efficiency and increased
utilization would otherwise result in
increases of non-GHG emissions;
however, importantly, most of those
impacts would be mitigated by the flue
gas conditioning required by the CO2
capture process and by other control
equipment that the units already have or
may need to install to meet other CAA
requirements. Decreases in efficiency
result in increases in the relative
amount of coal combusted per amount
of electricity generated and would
otherwise result in increases in the
amount of non-GHG pollutants emitted
per amount of electricity generated.
Additionally, increased utilization
would otherwise result in increases in
total non-GHG emissions. However,
substantial flue gas conditioning,
particularly to remove SO2, is critical to
limiting solvent degradation and
maintaining reliable operation of the
capture plant. To achieve the necessary
limits on SO2 levels in the flue gas for
the capture process, steam generating
units will need to add an FGD column,
if they do not already have one, and
may need an additional polishing
column (i.e., quencher). A wet FGD
column and a polishing column will
also reduce the emission rate of
particulate matter. Additional
improvements in particulate matter
removal may also be necessary to reduce
the fouling of other components (e.g.,
heat exchangers) of the capture process.
NOX emissions can cause solvent
degradation and nitrosamine formation
by chemical absorption of NOX,
depending on the chemical structure of
the solvent. The DOE’s Carbon
Management Pathway report notes that
monitoring and emission controls for
such degradation products are currently
part of standard operating procedures
for amine-based CO2 capture systems.550
550 U.S. Department of Energy (DOE). Pathways to
Commercial Liftoff: Carbon Management. https://
liftoff.energy.gov/wp-content/uploads/2023/04/
20230424-Liftoff-Carbon-Management-vPUB_
update.pdf.
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A conventional multistage water or acid
wash and mist eliminator at the exit of
the CO2 scrubber is effective at removal
of gaseous amine and amine degradation
products (e.g., nitrosamine)
emissions.551 552 NOX levels of the flue
gas required to avoid solvent
degradation and nitrosamine formation
in the CO2 scrubber vary. For most
units, the requisite limits on NOX levels
to assure that the CO2 capture process
functions properly may be met by the
existing NOX combustion controls, and
those units may not need to install SCR
for process purposes. However, most
existing coal-fired steam generating
units either already have SCR or will be
covered by proposed Federal
Implementation Plan (FIP) requirements
regulating interstate transport of NOX
(as an ozone precursors) from EGUs. See
87 FR 20036 (April 6, 2022). For units
not otherwise required to have SCR, an
increase in utilization from a CO2
capture retrofit could result in increased
NOX emissions at the source that,
depending on the quantity of the
emissions increase, may trigger major
NSR permitting requirements. Under
this scenario, the permitting authority
may determine that the NSR permit
requires the installation of SCR for those
units, based on applying the
requirements of major NSR.
Alternatively, a State could, as part of
its State plan, develop enforceable
conditions for a source expected to
trigger major NSR that would effectively
limit the unit’s ability to increase its
emissions in amounts that would trigger
major NSR. Under this scenario, with no
major NSR requirements applying due
to the limit on the emissions increase,
the permitting authority may conclude
for minor NSR purposes that installation
of SCR is not required for the units. See
section XIII.A of this preamble for
additional discussion of the NSR
program.
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(C) Water Use and Siting
Water consumption at the plant
increases when applying carbon
capture, due to solvent water makeup
and cooling demand. Water
consumption can increase by 36 percent
on a gross basis.553 A separate cooling
551 Sharma, S., Azzi, M., ‘‘A critical review of
existing strategies for emission control in the
monoethanolamine-based carbon capture process
and some recommendations for improved
strategies,’’ Fuel, 121, 178 (2014).
552 Mertens, J., et al., ‘‘Understanding
ethanolamine (MEA) and ammonia emissions from
amine-based post combustion carbon capture:
Lessons learned from field tests,’’ Int’l J. of GHG
Control, 13, 72 (2013).
553 DOE/NETL–2016/1796. ‘‘Eliminating the
Derate of Carbon Capture Retrofits.’’ May 31, 2016.
https://www.netl.doe.gov/energy-analysis/
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water system dedicated to a CO2 capture
plant may be necessary. However, the
amount of water consumption depends
on the design of the cooling system. For
example, the cooling system cited in the
CCS feasibility study for SaskPower’s
Shand Power station would rely entirely
on water condensed from the flue gas
and thus would not require any increase
in external water consumption.554
Regions with limited water supply may
rely on dry or hybrid cooling systems,
although, in areas with adequate water,
wet cooling systems can be more
effective.
With respect to siting considerations,
CO2 capture systems have a sizeable
physical footprint and a consequent
land-use requirement. The EPA is
proposing that the water use and siting
requirements are manageable and
therefore the EPA does not expect any
of these considerations to preclude coalfired power plants generally from being
able to install and operate CCS.
However, the EPA is soliciting comment
on these issues.
(D) Transport and Geologic
Sequestration
As noted in section VII.F.3.b.iii of this
preamble, PHMSA oversight of
supercritical CO2 pipeline safety
protects against environmental release
during transport and UIC Class VI
regulations under the SDWA, in tandem
with GHGRP subpart RR requirements,
ensure the protection of USDWs and the
security of geologic sequestration.
iv. Extent of Reductions in CO2
Emissions
CCS can be applied to coal-fired
steam generating units at the source and
reduce the CO2 emission rate by 90
percent or more. Increased steam and
power demand have a small impact on
the reduction in emission rate that
occurs with 90 percent capture.
According to the 2016 NETL Retrofit
report, 90 percent capture will result in
emission rates that are 88.4 percent
lower on a lb/MWh-gross basis and 87.1
percent lower on a lb/MWh-net basis
compared to units without capture.555
After capture, CO2 can be transported
details?id=e818549c-a565-4cbc-94db442a1c2a70a9.
554 International CCS Knowledge Centre. The
Shand CCS Feasibility Study Public Report. https://
ccsknowledge.com/pub/Publications/Shand_CCS_
Feasibility_Study_Public_Report_Nov2018_(202105-12).pdf.
555 DOE/NETL–2016/1796. ‘‘Eliminating the
Derate of Carbon Capture Retrofits.’’ May 31, 2016.
https://www.netl.doe.gov/energy-analysis/
details?id=e818549c-a565–4cbc-94db442a1c2a70a9.
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and securely sequestered.556 Although
steam generating units with CO2 capture
will have an incentive to operate at
higher utilization because the cost to
install the CCS system is largely fixed
and the IRC section 45Q tax credit
increases based on the amount of CO2
captured and sequestered, any increase
in utilization will be far outweighed by
the substantial reductions in emission
rate.
v. Technology Advancement
The EPA considered the potential
impact of designating CCS as the BSER
for long-term coal-fired steam generating
units on technology advancement, and
the EPA is proposing that designating
CCS as the BSER will provide for
meaningful advancement of CCS
technology, for many of the same
reasons as noted in section
VII.F.3.b.iii(F) of this preamble.
vi. Comparison With 2015 NSPS for
Newly Constructed Coal-Fired EGUs
In the 2015 NSPS, the EPA
determined that the BSER for newly
constructed coal-fired EGUs was based
on CCS with 16–23 percent capture,
based on the type of coal combusted,
and consequently, the EPA promulgated
standards of performance of 1,400 lb
CO2/MWh–g. 80 FR 64512 (Table 1),
64513 (October 23, 2015). The EPA
made those determinations based on the
costs of CCS at the time of that
rulemaking. In general, those costs were
significantly higher than at present, due
to recent technology cost declines as
well as related policies, including the
IRC section 45Q tax credit for CCS,
which was not available at that time for
purposes of consideration during the
development of the NSPS. Id. at 64562
(Table 8). Based on of these higher costs,
the EPA determined that 16–23 percent
capture qualified as the BSER, and not
a significantly higher percentage of
capture. Given the substantial
differences in the cost of CCS during the
time of the 2015 NSPS and the present
time, the capture percentage of the 2015
NSPS necessarily differed from the
capture percentage in this proposal,
and, by the same token, the associated
degree of emission limitation and
resulting standards of performance
necessarily differ as well.
b. Natural Gas Co-Firing
The EPA also evaluated natural gas
co-firing at 40 percent of the heat input
as the potential BSER for long-term coalfired steam generating units. Because
556 Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture
and Storage.
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the EPA is proposing natural gas cofiring as the BSER for medium-term
units, details that are common to
medium-term and long-term units are
discussed in section X.D.2.b of the
preamble. Based on the discussion
therein, the EPA is proposing that
natural gas co-firing is adequately
demonstrated and that the non-air
quality health and environmental effects
and energy requirements are not
unreasonable. The costs of natural gas
co-firing for a long-term unit may also
be reasonable. For example, for a
representative unit with a 10-year
amortization period, the cost of
reductions is $53/ton of CO2. Finally,
while 40 percent natural gas co-firing
achieves unit-level emission rate
reductions of 16 percent, those
reductions are less than CCS with 90
percent capture. Therefore, because CCS
achieves more reductions at the unit
level and is proposed as cost reasonable
for long-term units, the EPA is not
proposing natural gas co-firing as the
BSER for long-term coal-fired steam
generating units.
c. Conclusion
The EPA proposes that CCS at a
capture rate of 90 percent is the BSER
for long-term coal-fired steam generating
units because CCS is adequately
demonstrated, as indicated by the facts
that it has been operated at scale and is
widely applicable to sources and that
there are vast sequestration
opportunities across the continental
U.S. Additionally, accounting for recent
technology cost declines as well as
policies including the tax credit under
IRC section 45Q, the costs for CCS are
reasonable. Moreover, any adverse nonair quality health and environmental
impacts and energy requirements of
CCS, including impacts on the power
sector on a nationwide basis, are limited
and are outweighed by the benefits of
the significant GHG emission reductions
at reasonable cost. In contrast, co-firing
40 percent natural gas would achieve far
fewer emission reductions without
improving the cost effectiveness of the
control strategy. These considerations
provide the basis for proposing CCS as
the best of the systems of emission
reduction for long-term coal-fired power
plants. In addition, determining CCS as
the BSER promotes this useful control
technology. Although the EPA believes
that long-lived coal-fired power plants
will generally be able to implement and
operate CCS within the cost parameters
calculated as part of the BSER analysis,
and therefore that they would be able to
meet a standard of performance based
on CCS with 90 percent capture, the
EPA solicits comment on whether
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particular plants would be unable to do
so, including details of the
circumstances that might make
retrofitting with CCS unreasonable or
infeasible.
2. Medium-Term Coal-Fired Steam
Generating Units
In this section of the preamble, the
EPA evaluates CCS and natural gas cofiring as potential BSER for mediumterm coal-fired steam generating units.
In section X.D.1.a of this preamble,
the EPA evaluated CCS with 90 percent
capture of CO2 as the BSER for longterm coal-fired steam generating units.
Much of this evaluation is relevant for
medium-term units. However, because
they have shorter operating horizons
and, as a result, a shorter period for
amortization and for collecting the IRC
section 45Q tax credits, CCS would be
less cost effective for those units.
Therefore, the EPA is not proposing CCS
as BSER for medium-term coal-fired
steam generating units.
Instead, the EPA is proposing that 40
percent natural gas co-firing on a heat
input basis is the BSER for mediumterm coal-fired steam generating units.
Co-firing 40 percent natural gas, on an
annual average heat input basis, results
in a 16 percent reduction in CO2
emission rate. The technology has been
adequately demonstrated, can be
implemented at reasonable cost, does
not have adverse non-air quality health
and environmental impacts or energy
requirements, and achieves meaningful
reductions in CO2 emissions. Co-firing
also advances useful control technology
and has acceptable national and longterm impacts on the energy sector,
which provide additional, although not
essential, support for treating it as the
BSER.
a. CCS
In this section of the preamble, the
EPA evaluates the use of CCS as the
BSER for existing medium-term coalfired steam generating units. This
evaluation is much the same as the
evaluation for long-term units, with the
important difference of costs.
For long-term units, as discussed
earlier in this preamble, the EPA’s
analysis used to evaluate the
reasonableness of CCS costs employs a
12-year amortization period, which is
consistent with the period of time
during which the IRC section 45Q tax
credit can be claimed. However, existing
coal-fired steam generating units that
have elected to commit to permanently
cease operations prior to 2040—ones in
the medium-term subcategory, as well
as in the near-term, and imminent-term
subcategories—would have a shorter
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33351
period to amortize capital costs and also
would not be able to fully utilize the
IRC section 45Q tax credit. As a result,
for these sources, the cost effectiveness
of CCS is less favorable. As noted in
section X.D.1.a.ii(C) of this preamble,
for a 70 percent annual capacity factor
and a 7-year amortization period, costs
for the reference unit are $39/ton of CO2
reduced and $34/MWh. This $/MWh
generation cost is less favorable relative
to the representative cost ($/MWh) for
wet FGD, the costs for which are
detailed in section VII.F.3.b.iii(B)(5).
Due to the higher incremental cost of
generation, the EPA is not proposing
CCS as the BSER for medium-term coalfired steam generating units.
While the EPA is not proposing CCS
as BSER for the proposed subcategory of
medium-term units, the EPA is taking
comment on the operating horizon (i.e.,
between 8 and 10 years, instead of the
proposed 10-year operating horizon)
that most appropriately defines the
threshold date between medium-term
and long-term units and the EPA is also
taking comment on the level of costs of
CCS that should be considered
reasonable.
b. Natural Gas Co-Firing
In this section of the preamble, the
EPA evaluates natural gas co-firing as
potential BSER for medium-term coalfired steam generating units.
Considerations that are common to the
proposed subcategories of existing coalfired steam generating units are
discussed in section X.D.1.a of the
preamble, in addition to considerations
that are specific to medium-term units.
For a coal-fired steam generating unit,
the substitution of natural gas for some
of the coal, so that the unit fires a
combination of coal and natural gas, is
known as ‘‘natural gas co-firing.’’ The
EPA is proposing natural gas co-firing at
a level of 40 percent of annual heat
input as BSER for medium-term coalfired steam generating units.
i. Adequately Demonstrated
The EPA is proposing to find that
natural gas co-firing at the level of 40
percent of annual heat input is
adequately demonstrated for coal-fired
steam generating units. Many existing
coal-fired steam generating units already
use some amount of natural gas, and
several have co-fired at relatively high
levels at or above 40 percent of heat
input in recent years.
(A) Boiler Modifications
Most existing coal-fired steam
generating units can be modified to cofire natural gas in any desired
proportion with coal, up to 100 percent
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natural gas. Generally, the modification
of existing boilers to enable or increase
natural gas firing typically involves the
installation of new gas burners and
related boiler modifications, including,
for example, new fuel supply lines and
modifications to existing air ducts. The
introduction of natural gas as a fuel can
reduce boiler efficiency slightly, due in
large part to the relatively high
hydrogen content of natural gas.
However, since the reduction in coal
can result in reduced auxiliary power
demand, the overall impact on net heat
rate can range from a 2 percent increase
to a 2 percent decrease.
It is common practice for steam
generating units to have the capability
to burn multiple fuels onsite, and of the
565 coal-fired steam generating units
operating at the end of 2021, 249 of
them reported consuming natural gas as
a fuel or startup source. Coal-fired steam
generating units often use natural gas or
oil as a startup fuel, to warm the units
up before running them at full capacity
with coal. While startup fuels are
generally used at low levels (up to
roughly 1 percent of capacity on an
annual average basis), some coal-fired
steam generating units have co-fired
natural gas at considerably higher
shares. Based on hourly reported CO2
emission rates from the start of 2015
through the end of 2020, 29 coal-fired
steam generating units co-fired with
natural gas at rates at or above 60
percent of capacity on an hourly
basis.557 The capability of those units on
an hourly basis is indicative of the
extent of boiler burner modifications
and sizing and capacity of natural gas
pipelines to those units, and implies
that those units are technically capable
of co-firing at least 60 percent natural
gas on a heat input basis on average over
the course of an extended period (e.g.,
a year). Additionally, during that same
2015 through 2020 period, 29 coal-fired
steam generating units co-fired natural
gas at over 40 percent on an annual heat
input basis. Because of the number of
units that have demonstrated co-firing
above 40 percent of heat input, the EPA
is proposing that co-firing at 40 percent
is adequately demonstrated. A more
detailed discussion of the record of
natural gas co-firing, including current
trends, at coal-fired steam generating
units is included in the GHG Mitigation
Measures for Steam Generating Units
TSD.
557 U.S. Environmental Protection Agency (EPA).
‘‘Power Sector Emissions Data.’’ Washington, DC:
Office of Atmospheric Protection, Clean Air
Markets Division. Available from EPA’s Air Markets
Program Data website: https://campd.epa.gov.
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(B) Natural Gas Pipeline Development
In addition to any potential boiler
modifications, the supply of natural gas
is necessary to enable co-firing at
existing coal-fired steam boilers. As
discussed in the previous section, many
plants already have at least some access
to natural gas. In order to increase
natural gas access beyond current levels,
many will find it necessary to construct
natural gas supply pipelines.
The U.S. natural gas pipeline network
consists of approximately 3 million
miles of pipelines that connect natural
gas production with consumers of
natural gas. To increase natural gas
consumption at a coal-fired boiler
without sufficient existing natural gas
access, it is necessary to connect the
facility to the natural gas pipeline
transmission network via the
construction of a lateral pipeline. The
cost of doing so is a function of the total
necessary pipeline capacity (which is
characterized by the length, size, and
number of laterals) and the location of
the plant relative to the existing
pipeline transmission network. The EPA
estimated the costs associated with
developing new lateral pipeline
capacity sufficient to meet 60 percent of
the net summer capacity at each coalfired steam generating unit. As
discussed in the GHG Mitigation
Measures for Steam Generating Units
TSD, the EPA estimates that this lateral
capacity would be sufficient to enable
each unit to achieve 40 percent natural
gas co-firing on an annual average basis.
The EPA considered the availability
of the upstream natural gas pipeline
capacity to satisfy the assumed co-firing
demand implied by these new laterals.
This analysis included pipeline
development at all EGUs that could be
included in this subcategory. The EPA’s
assessment reviewed the reasonableness
of each assumed new lateral by
determining whether the peak gas
capacity of that lateral could be satisfied
without modification of the
transmission pipeline systems to which
it is assumed to be connected. This
analysis found that most, if not all,
existing pipeline systems are currently
able to meet the peak needs implied by
these new laterals in aggregate,
assuming that each existing coal-fired
unit in the analysis co-fired with natural
gas at a level implied by these new
laterals, or 60 percent of net summer
generating capacity. While this is a
reasonable assumption for the analysis
to support this mitigation measure in
the BSER context, it is also a
conservative assumption that overstates
the amount of natural gas co-firing
expected under the proposed rule.
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The maximum amount of pipeline
capacity, if all coal-fired steam capacity
in the medium-term subcategory
implemented the proposed BSER by cofiring 40 percent natural gas, would be
a fraction of the pipeline capacity
constructed recently. The EPA estimates
that this maximum total capacity would
be about 17.3 billion cubic feet per day,
which would require almost 4,000 miles
of pipeline costing roughly $13.3
billion. Over 5 years, this maximum
total incremental pipeline capacity
would amount to 800 miles per year and
approximately $2.7 billion per year in
capital expenditures, on average. By
comparison, based on data collected by
EIA, the total annual mileage of natural
gas pipelines constructed over the
2017–2021 period ranged from
approximately 1,000 to 2,500 miles per
year, with a total capacity of 10 to 25
billion cubic feet per day. This
represents an estimated annual
investment of up to nearly $15 billion.
These historical annual values are much
higher than the maximum annual values
that could be expected under this
proposed BSER measure—which, as
noted above, represent a conservative
estimate that overstates the amount of
co-firing that the EPA projects would
occur under this proposed rule.
These conservatively high estimates
of pipeline requirements also compare
favorably to industry projections of
future pipeline capacity additions.
Based on a review of a 2018 industry
report, titled ‘‘North America Midstream
Infrastructure through 2035: Significant
Development Continues,’’ investment in
midstream infrastructure development
is expected to average about $37 billion
per year through 2035, which is lower
than historical levels. Approximately
$10 to $20 billion annually is expected
to be invested in natural gas pipelines
through 2035. This report also projects
that an average of over 1,400 miles of
new natural gas pipeline will be built
through 2035, which is similar to the
approximately 1,670 miles that were
built on average from 2013 to 2017.
These values are considerably greater
than the average annual expenditure of
$2.7 billion on 800 miles per year of
new pipeline construction that would
be necessary for the entire operational
fleet of coal-fired steam generating units
to co-fire with natural gas. The actual
pipeline investment for this subcategory
would be substantially lower.
ii. Costs
The capital costs associated with the
addition of new gas burners and other
necessary boiler modifications depend
on the extent to which the current boiler
is already able to co-fire with some
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natural gas and on the amount of gas cofiring desired. The EPA estimates that,
on average, the total capital cost
associated with modifying existing
boilers to operate at up to 100 percent
of heat input using natural gas is
approximately $52/kW. These costs
could be higher or lower, depending on
the equipment that is already installed
and the expected impact on heat rate or
steam temperature.
While fixed O&M (FOM) costs can
potentially decrease as a result of
decreasing the amount of coal
consumed, it is common for plants to
maintain operation of one coal
pulverizer at all times, which is
necessary for maintaining several coal
burners in continuous service. In this
case, coal handling equipment would be
required to operate continuously and
therefore natural gas co-firing would
have limited effect on reducing the coalrelated FOM costs. Although, as noted,
coal-related FOM costs have the
potential to decrease, the EPA does not
anticipate a significant increase in
impact on FOM costs related to co-firing
with natural gas.
In addition to capital and FOM cost
impacts, any additional natural gas cofiring would result in incremental costs
related to the differential in fuel cost,
taking into consideration the difference
in delivered coal and gas prices, as well
as any potential impact on the overall
net heat rate. The EPA’s post-IRA 2022
reference case projects that in 2030, the
average delivered price of coal will be
$1.47/MMBtu and the average delivered
price of natural gas will be $2.53/
MMBtu. Thus, assuming the same level
of generation and no impact on heat
rate, the additional fuel cost would be
above $1/MMBtu on average in 2030.
The total additional fuel cost could
increase or decrease depending on the
potential impact on net heat rate. An
increase in net heat rate, for example,
would result in more fuel required to
produce a given amount of generation
and thus additional cost. In the GHG
Mitigation Measures for Steam
Generating Units TSD, the EPA’s cost
estimates assume a 1 percent increase in
net heat rate.
Finally, for plants without sufficient
access to natural gas, it is also necessary
to construct new natural gas pipelines
(‘‘laterals’’). Pipeline costs are typically
expressed in terms of dollars per inch of
pipeline diameter per mile of pipeline
distance (i.e., dollars per inch-mile),
reflecting the fact that costs increase
with larger diameters and longer
pipelines. On average, the cost for
lateral development within the
contiguous U.S. is approximately
$280,000 per inch-mile (2019$), which
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can vary based on site-specific factors.
The total pipeline cost for each coalfired steam generating unit is a function
of this cost, as well as a function of the
necessary pipeline capacity and the
location of the plant relative to the
existing pipeline transmission network.
The pipeline capacity required depends
on the amount of co-firing desired as
well as on the desired level of
generation—a higher degree of co-firing
while operating at full load would
require more pipeline capacity than a
lower degree of co-firing while
operating at partial load. It is reasonable
to assume that most plant owners would
develop sufficient pipeline capacity to
deliver the maximum amount of desired
gas use in any moment, enabling higher
levels of co-firing during periods of
lower fuel price differentials. Once the
necessary pipeline capacity is
determined, the total lateral cost can be
estimated by considering the location of
each plant relative to the existing
natural gas transmission pipelines as
well as the available excess capacity of
each of those existing pipelines. For
purposes of the cost reasonableness
estimates as follows, the EPA assumes
pipeline costs of $92/kW, which is the
median value of all unit-level pipeline
cost estimates, as explained in the GHG
Mitigation Measures for Steam
Generating Units TSD. The range in
costs reflects a range in the amortization
period of the capital costs over 6 to 10
years, which is consistent with the
amount of time over which the units in
the medium-term subcategory could be
operational.
The EPA sums the natural gas cofiring costs as follows: For a typical base
load coal-fired steam generating unit in
2030, the EPA estimates that the cost of
co-firing with 40 percent natural gas on
an annual average basis is
approximately $53 to $66/ton CO2
reduced, or $9 to $12/MWh, respective
to amortization periods of 10 to 6 years.
This estimate is based on the
characteristics of a typical coal-fired
unit in 2021 (400 MW capacity and an
average heat rate of 10,500 Btu/kWh)
operating at a typical capacity factor of
about 50 percent, and it assumes a
pipeline cost of $92/kW, as discussed
earlier in this preamble.
Based on the coal-fired steam
generating units that existed in 2021
and that do not have known plans to
cease operations or convert to gas by
2030, and assuming that each of those
units continues to operate at the same
level in 2030 as it operated in 2017–
2021, on average, the EPA estimates that
the weighted average cost of co-firing
with 40 percent natural gas on an
annual average basis is approximately
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$64 to $78/ton CO2 reduced, or $11 to
$14/MWh. The $/ton cost estimate is
lower than average for approximately 82
GW, and the $/MWh cost estimate is
lower than average for 86 GW (about 69
percent and 72 percent, respectively, of
the relevant coal fleet). These estimates
and all underlying assumptions are
explained in detail in the GHG
Mitigation Measures for Steam
Generating Units TSD.
As was described in section X.D.1 of
this preamble, the EPA has compared
the estimated costs discussed in section
X.D.2 of this preamble to costs that coalfired steam generating units have
incurred to install controls that reduce
other air pollutants, such as SO2.
Compared to the representative costs of
controls detailed in section
VII.F.3.b.iii(B)(5) of this preamble (i.e.,
emission control costs on EGUs of
$10.60 to $29/MWh and the costs in the
2016 NSPS regulating GHGs for the
Crude Oil and Natural Gas source
category of $98/ton of CO2e reduced (80
FR 56627; September 18, 2015)), both
estimates of annualized costs of natural
gas co-firing (approximately $53–$66/
ton or $9–$12/MWh for a typical unit
and $64–$78/ton or $11–$14/MWh on
average)) are comparable or lower. The
range of cost effectiveness estimates
presented in this section is lower than
previously estimated by the EPA in the
proposed CPP, for several reasons. Since
then, the expected difference between
coal and gas prices has decreased
significantly, from over $3/MMBtu to
about $1/MMBtu in this proposal.
Additionally, a recent analysis
performed by Sargent and Lundy for the
EPA supports a considerably lower
capital cost for modifying existing
boilers to co-fire with natural gas. The
EPA also recently conducted a highly
detailed facility-level analysis of natural
gas pipeline costs, the median value of
which is slightly lower than the value
used by the EPA previously to
approximate the cost of co-firing at a
representative unit.
Based on the cost analysis presented
in this section, the EPA is proposing
that the costs of natural gas co-firing are
reasonable for the medium-term coalfired steam generating unit subcategory.
iii. Non-Air Quality Health and
Environmental Impact and Energy
Requirements
Natural gas co-firing for steam
generating units is not expected to have
any significant adverse consequences
related to non-air quality health and
environmental impacts or energy
requirements.
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(A) Non-GHG Emissions
Non-GHG emissions are reduced
when steam generating units co-fire
with natural gas because less coal is
combusted. SO2, PM2.5, acid gas,
mercury and other hazardous air
pollutant emissions that result from coal
combustion are reduced proportionally
to the amount of natural gas consumed,
i.e., under this proposal, by 40 percent.
Natural gas combustion does produce
NOX emissions, but in lesser amounts
than from coal-firing. However, the
magnitude of this reduction is
dependent on the combustion system
modifications that are implemented to
facilitate natural gas co-firing.
Additionally, sufficient regulations
exist related to natural gas pipelines and
transport that assure natural gas can be
safely transported with minimal risk of
environmental release. PHMSA
develops and enforces regulations for
the safe, reliable, and environmentally
sound operation of the nation’s 2.6
million mile pipeline transportation
system. Recently, PHMSA finalized a
rule that will improve the safety and
strengthen the environmental protection
of more than 300,000 miles of onshore
gas transmission pipelines.558 PHMSA
also recently promulgated a rule
covering natural gas transmission,559 as
well as a rule that significantly
expanded the scope of safety and
reporting requirements for more than
400,000 miles of previously unregulated
gas gathering lines.560 Additionally,
FERC oversees the development of new
natural gas pipelines.
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(B) Energy Requirements
The introduction of natural gas cofiring will cause steam boilers to be
slightly less efficient due to the high
hydrogen content of natural gas. Cofiring at levels between 20 percent and
100 percent can be expected to decrease
boiler efficiency between 1 percent and
5 percent. However, despite the
decrease in boiler efficiency, the overall
net output efficiency of a steam
generating unit that switches from coalto natural gas-firing may change only
slightly, in either a positive or negative
direction. Since co-firing reduces coal
558 Pipeline Safety: Safety of Gas Transmission
Pipelines: Repair Criteria, Integrity Management
Improvements, Cathodic Protection, Management of
Change, and Other Related Amendments (87 FR
52224; August 24, 2022).
559 Pipeline Safety: Safety of Gas Transmission
Pipelines: MAOP Reconfirmation, Expansion of
Assessment Requirements, and Other Related
Amendments (84 FR 52180; October 1, 2019).
560 Pipeline Safety: Safety of Gas Gathering
Pipelines: Extension of Reporting Requirements,
Regulation of Large, High-Pressure Lines, and Other
Related Amendments (86 FR 63266; November 15,
2021).
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consumption, the auxiliary power
demand related to coal handling and
emissions controls typically decreases
as well. While a site-specific analysis
would be required to determine the
overall net impact of these
countervailing factors, generally the
effect of co-firing on net unit heat rate
can vary within approximately plus or
minus 2 percent.
The EPA previously determined in
the ACE Rule (84 FR 32520 at 32545;
July 8, 2019) that ‘‘co-firing natural gas
in coal-fired utility boilers is not the
best or most efficient use of natural gas
and [. . .] can lead to less efficient
operation of utility boilers.’’ That
determination was informed by the
more limited supply of natural gas, and
the larger amount of coal-fired EGU
capacity and generation, in 2019. Since
that determination, the expected supply
of natural gas has expanded
considerably, and the capacity and
generation of the existing coal-fired fleet
has decreased, reducing the total mass
of natural gas that might be required for
sources to implement this measure.
Additionally, the natural gas co-firing
measure is now being proposed for a
medium-term coal-fired steam
generating unit subcategory, a group of
units that will operate at most for 10
years following the compliance date,
which would further reduce the total
amount of required natural gas.
Furthermore, regarding the efficient
operation of boilers, the ACE
determination was based on the
observation that ‘‘co-firing can
negatively impact a unit’s heat rate
(efficiency) due to the high hydrogen
content of natural gas and the resulting
production of water as a combustion byproduct.’’ That finding does not
consider the fact that the effect of cofiring on net unit heat rate can vary
within approximately plus or minus 2
percent, and therefore the net impact on
overall utility boiler efficiency for each
steam generating unit is uncertain.
For all of these reasons, the EPA is
proposing that natural gas co-firing at
medium-term coal-fired steam
generating units does not result in any
significant adverse consequences related
to energy requirements.
Additionally, the EPA considered
longer term impacts on the energy
sector, and the EPA is proposing these
impacts are reasonable. Designating
natural gas co-firing as the BSER for
medium-term coal-fired steam
generating units would not have
significant adverse impacts on the
structure of the energy sector. Steam
generating units that currently are coalfired would be able to remain primarily
coal-fired. The replacement of some coal
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with natural gas as fuel in these sources
would not have significant adverse
effects on the price of natural gas or the
price of electricity.
iv. Extent of Reductions in CO2
Emissions
One of the primary benefits of natural
gas co-firing is emission reduction. CO2
emissions are reduced by approximately
4 percent for every additional 10
percent of co-firing. When shifting from
100 percent coal to 60 percent coal and
40 percent natural gas, CO2 stack
emissions are reduced by approximately
16 percent. Non-CO2 emissions are
reduced as well, as noted earlier in this
preamble.
v. Technology Advancement
Natural gas co-firing is already wellestablished and widely used by coalfired steam boiler generating units. As a
result, this proposed rule is not likely to
lead to technological advances or cost
reductions in the components of natural
gas co-firing, including modifications to
boilers and pipeline construction.
However, greater use of natural gas cofiring may lead to improvements in the
efficiency of conducting natural gas cofiring and operating the associated
equipment.
c. Conclusion
The EPA proposes that natural gas cofiring at 40 percent of heat input is the
BSER for medium-term coal-fired steam
generating units because natural gas cofiring is adequately demonstrated, as
indicated by the facts that it has been
operated at scale and is widely
applicable to sources. Additionally, the
costs for natural gas co-firing are
reasonable. Moreover, any adverse nonair quality health and environmental
impacts and energy requirements of
natural gas co-firing are limited and are
outweighed by the benefits of the
emission reductions at reasonable cost.
In contrast, CCS, although achieving
greater emission reductions, would be
less cost-effective, in general, for the
proposed subcategory of medium-term
units.
While the EPA is not proposing CCS
as BSER for the proposed subcategory
definition of medium-term units, the
EPA is taking comment on the operating
horizons that define the threshold date
between medium-term and long-term
units (i.e., between 8 and 10 years,
instead of the proposed 10-year
operating horizon) and on what amount
of costs should be considered
reasonable.
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3. Imminent-Term and Near-Term CoalFired Steam Generating Units
In this section of the preamble, the
EPA evaluates CCS, natural gas cofiring, low levels of natural gas co-firing,
and routine methods of operation and
maintenance as the BSER for imminentterm and near-term coal-fired steam
generating units. Primarily because of
the effect of a short operating horizon on
the cost of controls for these units, the
EPA proposes routine methods of
operation and maintenance as the BSER.
a. CCS
As noted in section X.D.2.a of this
preamble, the EPA is not proposing CCS
for medium-term units due to $/MWh
costs being less favorable based on the
appropriate cost metrics. Because of the
shorter operating horizons for
imminent-term and near-term coal-fired
steam generating units, CCS is less cost
favorable for them than for mediumterm units. Therefore, the EPA is not
proposing CCS as BSER for imminentterm or near-term coal-fired steam
generating units. Additional details of
cost values for amortization periods
representative of imminent-term and
near-term units are available in the GHG
Mitigation Measures for Steam
Generating Units TSD.
b. Natural Gas Co-Firing
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i. Natural Gas Co-Firing at 40 Percent
Much of the discussion of natural gas
co-firing in section X.D.2.b of this
preamble for medium-term units is
relevant for imminent-term and nearterm units, except that natural gas cofiring is less cost effective for the latter
units because of their short operating
horizons, particularly on a $/ton of CO2
reduced basis. For a 2-year amortization
period, annualized costs for the
representative unit are $130/ton of CO2
reduced and $23/MWh of generation.
Therefore, the EPA is not proposing
natural gas co-firing as BSER for
imminent-term or near-term units.
Additional details of cost are available
in the GHG Mitigation Measures for
Steam Generating Units TSD.
ii. Natural Gas Co-Firing at Low Levels
of Heat Input
Although higher levels of natural gas
co-firing may be less cost effective for
imminent-term and near-term units, it is
possible that lower levels of natural gas
co-firing may be cost reasonable. Many
units have demonstrated the ability to
co-fire with natural gas over short
periods of time and operating with those
same levels of natural gas co-firing over
longer periods of time (i.e., annually)
may achieve emission reductions. A low
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level of natural gas co-firing (up to 10
percent of annual heat input) is
adequately demonstrated and may be
broadly achievable, may achieve
reductions in GHG emissions, may be of
reasonable cost, and is unlikely to cause
unreasonable adverse non-air quality
health and environmental impacts or
result in substantial energy
requirements. Therefore, the EPA is
soliciting comment on low levels of
natural gas co-firing as a potential
component of the BSER for imminentterm and near-term coal-fired steam
generating units.
The EPA recognizes that different
coal-fired units may be already capable
of different natural gas co-firing rates (as
discussed in section X.D.2.b.i of this
preamble) and is therefore soliciting
comment on defining a potential BSER
on the basis of the maximum hourly
heat input of natural gas fired in the
unit (MMBtu/hr) relative to the
maximum hourly heat input the unit is
capable of (i.e., the nameplate capacity
on an MMBtu/hr basis). Alternatively,
the EPA is soliciting comment on a
fixed value of annual heat input
percentage that represents a low level of
natural gas co-firing, as well as the
definition of a low level of natural gas
co-firing that is based on the
characteristics of an existing facility
(e.g., the capacity of the existing
pipeline). The EPA is also soliciting
comment on a degree of emission
limitation resulting from low levels of
natural gas co-firing, as detailed in
section X.D.4.c of this preamble.
(1) Adequately Demonstrated
For many of the same reasons stated
in section X.D.2.b.i of this preamble for
natural gas co-firing at higher levels,
natural gas co-firing at low levels is
adequately demonstrated. The EPA also
identified that 369 of the 565 EGUs
operating at the end of 2021 have either
reported natural gas as a fuel source, are
located at a plant with a natural gas
generator, and/or are located at a plant
with a natural gas pipeline connection.
A large percentage of the existing fleet
of coal-fired steam generating units
would therefore likely be able to co-fire
natural gas at low levels without having
to make boiler modifications or build
additional pipelines.
(2) Costs
The costs of low levels of natural gas
co-firing may be reasonable because low
levels of natural gas co-firing likely
require little, if any, capital investment.
Additionally, the relatively small
increase in natural gas fuel use would
only result in a modest increase in total
fuel cost.
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(3) Non-Air Quality Health and
Environmental Impact and Energy
Requirements
For many of the same reasons stated
in section X.D.2.b.iii of this preamble,
low levels of natural gas co-firing are
unlikely to cause unreasonable adverse
non-air quality health and
environmental impacts or result in
substantial energy requirements.
Furthermore, low levels of natural gas
co-firing may require only limited
construction of additional infrastructure
as existing pipeline laterals to the units
should be of sufficient size to achieve
low levels of natural gas co-firing.
(4) Extent of Reductions in CO2
Emissions
The emission reductions achieved at
the unit from low levels of natural gas
co-firing of 1 to 10 percent may be
relatively low at around 0.4 to 4 percent,
respectively. However, these are likely
on average greater than the emission
reductions that could be achievable by
other technologies, such as HRI.
Furthermore, because the efficiency of
the unit is not increased as with HRI,
the unit likely does not move up in
dispatch order, and it is likely the unit
would not be subject to the rebound
effect. See section X.D.5 of this
preamble for a discussion of HRI.
(5) Technology Advancement
Low levels of natural gas co-firing do
not advance useful control technology,
for reasons similar to those discussed in
section X.D.2.b.v of this preamble.
c. Routine Methods of Operation and
Maintenance
For the imminent-term and near-term
coal-fired steam generating units, the
EPA is proposing that the BSER is
routine methods of operation and
maintenance already occurring at the
unit, so as to maintain the current unitspecific CO2 emission rates (expressed
as lb CO2/MWh).
Routine methods of operation and
maintenance are adequately
demonstrated because units already
operate by those methods. They will not
result in additional costs from any
controls, and will not create adverse
non-air quality health and
environmental impacts or energy
requirements. They will not achieve
CO2 emission reductions at the unit
level relative to current performance,
but they can prevent worsening of
emission rates over time. Although they
do not advance useful control
technology, they do not have adverse
impacts on the energy sector from a
nationwide or long-term perspective.
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4. Degree of Emission Limitation
Under CAA section 111(d), once the
EPA determines the BSER, it must
determine the ‘‘degree of emission
limitation’’ achievable by the
application of the BSER. States then
determine standards of performance and
include them in the State plans, based
on the specified degree of emission
limitation. Proposed presumptive
standards of performance are detailed in
section XII.D of this preamble. There is
substantial variation in emission rates
among coal-fired steam generating
units—the range is, approximately, from
1,700 lb CO2/MWh-gross to 2,500 lb
CO2/MWh-gross—which makes it
challenging to determine a single,
uniform emission limit. Accordingly, for
each of the four subcategories of coalfired steam generating units, the EPA is
proposing to determine the degree of
emission limitation by a percentage
change in emission rate, as follows:
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a. Long-Term Coal-Fired Steam
Generating Units
As discussed earlier in this preamble,
the EPA is proposing the BSER for longterm coal-fired steam generating units as
‘‘full-capture’’ CCS, defined as 90
percent capture of the CO2 in the flue
gas. The degree of emission limitation
achievable by applying this BSER can be
determined on a rate basis. A capture
rate of 90 percent results in reductions
in the emission rate of 88.4 percent on
a lb CO2/MWh-gross basis, and this
reduction in emission rate can be
observed over an extended period (e.g.,
an annual calendar-year basis).
Therefore, the EPA is proposing that the
degree of emission limitation for longterm units is an 88.4 percent reduction
in emission rate on a lb CO2/MWh-gross
basis over an extended period (e.g., an
annual calendar-year basis).
As noted in section X.D.1.a of this
preamble, new CO2 capture retrofits on
existing coal-fired steam generating
units may achieve capture rates greater
than 90 percent, and the EPA is taking
comment on a range of capture rates that
may be achievable. As noted in section
VII.F.3.b.iii(A)(2) of this preamble, the
operating availability (i.e., the amount
of time a process operates relative to the
amount of time it planned to operate) of
industrial processes is usually less than
100 percent. Assuming that CO2 capture
achieves 90 percent capture when
available to operate, that CCS is
available to operate 90 percent of the
time the coal-fired steam generating unit
is operating, and that the steam
generating unit operates the same
whether or not CCS is available to
operate, total emission reductions
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would be 81 percent. Higher levels of
emission reduction could occur for
higher capture rates coupled with
higher levels of operating availability
relative to operation of the steam
generating unit. If the steam generating
unit were not permitted to operate when
CCS was unavailable, there may be local
reliability consequences, and the EPA is
soliciting comment on how to balance
these issues. Additionally, the EPA is
soliciting comment on a range of the
degree of emission limitation
achievable, in the form of a reduction in
emission rate of 75 to 90 percent when
determined over an extended period
(e.g., an annual calendar-year basis).
b. Medium-Term Coal-Fired Steam
Generating Units
As discussed earlier in this preamble,
the BSER for medium-term coal-fired
steam generating units is 40 percent
natural gas co-firing. The application of
40 percent natural gas co-firing results
in reductions in the emission rate of 16
percent. Therefore, the degree of
emission limitation for these units is a
16 percent reduction in emission rate on
a lb CO2/MWh-gross basis over an
extended period (e.g., an annual
calendar-year basis).
c. Imminent-Term and Near-Term CoalFired Steam Generating Units
As discussed above, the BSER for
imminent-term and near-term coal-fired
steam generating units is routine
methods of operation and maintenance.
Application of this BSER results in no
increase in emission rate. Thus, the
degree of emission limitation
corresponding to the application of the
BSER is no increase in emission rate on
a lb CO2/MWh-gross basis over an
extended period (e.g., an annual
calendar-year basis).
Because the EPA is soliciting
comment on low levels of natural gas
co-firing as a potential BSER for
imminent-term and near-term units, the
EPA is also soliciting comment on the
degree of emission limitation that may
be achievable by application of low
levels of natural gas co-firing. The EPA
is soliciting comment on degrees of
emission limitation defined by
reductions in emission rate on a lb CO2/
MWh-gross basis that are equal to the
percent of heat input times 0.4, the
percent of reduction in emission rate
that may be achieved for each percent
of natural gas heat input. For example,
for natural gas co-firing at 1 to 10
percent, this results in a degree of
emission limitation of 0.4 to 4 percent
reduction in emission rate on a lb CO2/
MWh-gross basis (over an extended
period of time). More specifically, the
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EPA solicits comment on the degree of
emission limitation based on the
calculation method defined in the
preceding text up to a 4 percent
reduction in emission rate (lb CO2/
MWh-gross) over an extended period of
time. Alternatively, as the EPA is also
soliciting comment on a fixed percent of
low levels of natural gas co-firing, the
EPA is additionally soliciting comment
on a fixed degree of emission limitation
based on the same calculation method.
Because the reductions in GHG
emissions from low levels of natural gas
co-firing are relatively low and may be
challenging to measure, the EPA is also
soliciting comment on a degree of
emission limitation defined on a percent
of heat input basis, although the EPA
also recognizes that measurement of fuel
flow may also have challenges.
5. Other Emission Reduction Measures
a. Heat Rate Improvements
Heat rate is a measure of efficiency
that is commonly used in the power
sector. The heat rate is the amount of
energy input, measured in Btu, required
to generate one kWh of electricity. The
lower an EGU’s heat rate, the more
efficiently it operates. As a result, an
EGU with a lower heat rate will
consume less fuel and emit lower
amounts of CO2 and other air pollutants
per kWh generated as compared to a less
efficient unit. HRI measures include a
variety of technology upgrades and
operating practices that may achieve
CO2 emission rate reductions of 0.1 to
5 percent for individual EGUs. The EPA
considered HRI to be part of the BSER
in the CPP and to be the BSER in the
ACE Rule. However, the reductions that
may be achieved by HRI are small
relative to the reductions from natural
gas co-firing and CCS. Also, some
facilities that apply HRI would, as a
result of their increased efficiency,
increase their utilization and therefore
increase their CO2 emissions (as well as
emissions of other air pollutants), a
phenomenon that the EPA has termed
the ‘‘rebound effect.’’ Therefore, the
EPA is not proposing HRI as a part of
BSER.
i. CO2 Reductions From HRI in Prior
Rulemakings
In the CPP, the EPA quantified
emission reductions achievable through
heat rate improvements on a regional
basis by an analysis of historical
emission rate data, taking into
consideration operating load and
ambient temperature. The Agency
concluded that EGUs can achieve on
average a 4.3 percent improvement in
the Eastern Interconnection, a 2.1
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percent improvement in the Western
Interconnection, and a 2.3 percent
improvement in the Texas
Interconnection. See 80 FR 64789
(October 23, 2015). The Agency then
applied all three of the building blocks
to 2012 baseline data and quantified, in
the form of CO2 emission rates, the
reductions achievable in each
interconnection in 2030, and then
selected the least stringent as a national
performance rate. Id. at 64811–19. The
EPA noted that building block 1
measures could not by themselves
constitute the BSER because the
quantity of emission reductions
achieved would be too small and
because of the potential for an increase
in emissions due to increased utilization
(i.e., the ‘‘rebound effect’’).
A description of the ACE Rule is
detailed in section IX of this preamble.
ii. Updated CO2 Reductions From HRI
The HRI measures include
improvements to the boiler island (e.g.,
neural network system, intelligent
sootblower system), improvements to
the steam turbine (e.g., turbine overhaul
and upgrade), and other equipment
upgrades (e.g., variable frequency
drives). Some regular practices that may
recover degradation in heat rate to
recent levels—but that do not result in
upgrades in heat rate over recent design
levels and are therefore not HRI
measures—include practices such as inkind replacements and regular surface
cleaning (e.g., descaling, fouling
removal). Specific details of the HRI
measures are described in the GHG
Mitigation Measures for Steam
Generating Units TSD and an updated
2023 Sargent and Lundy HRI report
(Heat Rate Improvement Method Costs
and Limitations Memo), available in the
docket. Most HRI upgrade measures
achieve reductions in heat rate of less
than 1 percent. In general, the 2023
Sargent and Lundy HRI report, which
updates the 2009 Sargent and Lundy
HRI report, shows that HRI achieve less
reductions than indicated in the 2009
report, and shows that several HRI
either have limited applicability or have
already been applied at many units.
Steam path overhaul and upgrade may
achieve reductions up to 5.15 percent,
with the average being around 1.5
percent. Different combinations of HRI
measures do not necessarily result in
cumulative reductions in emission rate
(e.g., intelligent sootblowing systems
combined with neural network
systems). Some of the HRI measures
(e.g., variable frequency drives) only
impact heat rate on a net generation
basis by reducing the parasitic load on
the unit and would thereby not be
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observable for emission rates measured
on a gross basis. Assuming many of the
HRI measures could be applied to the
same unit, adding together the upper
range of some of the HRI percentages
could yield an emission rate reduction
of around 5 percent. However, the
reductions that the fleet could achieve
on average are likely much smaller. As
noted, the 2023 Sargent and Lundy HRI
report notes that, in many cases, units
have already applied HRI upgrades or
that those upgrades would not be
applicable to all units. The unit level
reductions in emission rate from HRI are
small relative to CCS or natural gas cofiring. In the CPP and ACE Rule, the
EPA viewed CCS and natural gas cofiring as too costly to qualify as the
BSER; those costs have fallen since
those rules and, as a result, CCS and
natural gas co-firing do qualify as the
BSER for the long-term and mediumterm subcategories, respectively.
iii. Potential for Rebound in CO2
Emissions
Reductions achieved on a rate basis
from HRI may not result in overall
emission reductions and could instead
cause a ‘‘rebound effect’’ from increased
utilization. A rebound effect would
occur where, because of an
improvement in its heat rate, a steam
generating unit experiences a reduction
in variable operating costs that makes
the unit more competitive relative to
other EGUs and consequently raises the
unit’s output. The increase in the unit’s
CO2 emissions associated with the
increase in output would offset the
reduction in the unit’s CO2 emissions
caused by the decrease in its heat rate
and rate of CO2 emissions per unit of
output. The extent of the offset would
depend on the extent to which the unit’s
generation increased. The CPP did not
consider HRI to be BSER on its own, in
part because of the potential for a
rebound effect. Analysis for the ACE
Rule, where HRI was the entire BSER,
observed a rebound effect for certain
sources in some cases. In this action,
where different subcategories of units
are proposed to be subject to different
BSER measures, steam generating units
in a hypothetical subcategory with HRI
as BSER could experience a rebound
effect. Because of this potential for
perverse GHG emission outcomes
resulting from deployment of HRI at
certain steam generating units, coupled
with the relatively minor overall GHG
emission reductions that would be
expected from this measure, the EPA is
not proposing HRI as the BSER for any
subcategory of existing coal-fired steam
generating units.
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E. Natural Gas-Fired and Oil-Fired
Steam Generating Units
In this section of the preamble, the
EPA is addressing natural gas- and oilfired steam generating units. The EPA is
proposing the BSER and degree of
emission limitation achievable by
application of the BSER for those units
and identifying the associated emission
rates that States may apply to these
units. For the reasons described here,
the EPA is proposing subcategories
based on load level (i.e., annual capacity
factor), specifically, units that are base
load, intermediate load, and low load.
At this time, the EPA is not proposing
requirements for low load units but is
taking comment on a BSER of lower
emitting fuels for those units. The EPA
is proposing routine methods of
operation and maintenance as BSER for
intermediate and base load units.
Applying that BSER would not achieve
emission reductions but would prevent
increases in emission rates. The EPA is
proposing presumptive standards of
performance that differ between
intermediate and base load units due to
their differences in operation, as
detailed in section XII.D.1.b.v of this
preamble. The EPA is also proposing a
separate subcategory for non-continental
oil-fired steam generating units, which
operate differently from continental
units, with presumptive standards of
performance detailed in section
XII.D.1.b.vi of this preamble.
Natural gas- and oil-fired steam
generating units combust natural gas or
distillate fuel oil or residual fuel oil in
a boiler to produce steam for a turbine
that drives a generator to create
electricity. In non-continental areas,
existing natural gas- and oil-fired steam
generating units may provide base load
power, but in the continental U.S., most
existing units operate in a loadfollowing manner. There are
approximately 200 natural gas-fired
steam generating units and fewer than
30 oil-fired steam generating units in
operation in the continental U.S. Fuel
costs and inefficiency relative to other
technologies (e.g., combustion turbines)
result in operation at lower annual
capacity factors for most units. Based on
data reported to EIA and CAMD for the
contiguous U.S., for natural gas-fired
steam generating units in 2019, the
average annual capacity factor was less
than 15 percent and 90 percent of units
had annual capacity factors less than 35
percent. For oil-fired steam generating
units in 2019, no units had annual
capacity factors above 8 percent.
Additionally, their load-following
method of operation results in frequent
cycling and a greater proportion of time
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spent at low hourly capacities, when
generation is less efficient. Furthermore,
because startup times for most boilers
are usually long, natural gas steam
generating units may operate in standby
mode between periods of peak demand.
Operating in standby mode requires
combusting fuel to keep the boiler
warm, and this further reduces the
efficiency of natural gas combustion.
Unlike coal-fired steam generating
units, the CO2 emission rates of oil- and
natural gas-fired steam generating units
that have similar annual capacity factors
do not vary considerably between units.
This is partly due to the more uniform
qualities (e.g., carbon content) of the
fuel used. However, the emission rates
for units that have different annual
capacity factors do vary considerably, as
detailed in the Natural Gas- and Oilfired Steam Generating Unit TSD. Low
annual capacity factor units cycle
frequently, have a greater proportion of
CO2 emissions that may be attributed to
startup, and have a greater proportion of
generation at inefficient hourly
capacities. Intermediate annual capacity
factor units operate more often at higher
hourly capacities, where CO2 emission
rates are lower. High annual capacity
factor units operate still more at base
load conditions, where units are more
efficient and CO2 emission rates are
lower. Based on these performance
differences between these load levels,
the EPA is, in general, proposing to
divide natural gas- and oil-fired steam
generating units into three subcategories
each—low load, intermediate load, and
base load—as specified in section X.C.2
of this preamble: ‘‘low’’ load is defined
by annual capacity factors less than 8
percent, ‘‘intermediate’’ load is defined
by annual capacity factors greater than
or equal to 8 percent and less than 45
percent, and ‘‘base’’ load is defined by
annual capacity factors greater than 45
percent.
1. Options Considered for BSER
The EPA has considered various
methods for controlling CO2 emissions
from natural gas- and oil-fired steam
generating units to determine whether
they meet the criteria for BSER. Cofiring natural gas cannot be the BSER for
these units because natural gas- and oilfired steam generating units already fire
large proportions of natural gas. Most
natural gas-fired steam generating units
fire more than 90 percent natural gas on
a heat input basis, and any oil-fired
steam generating units that would
potentially operate above an annual
capacity factor of around 15 percent
would combust natural gas as a large
proportion of their fuel as well. Nor is
CCS a candidate for BSER. The
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utilization of most gas-fired units, and
likely all oil-fired units, is relatively
low, and as a result, the amount of CO2
available to be captured is low.
However, the capture equipment would
still need to be sized for the nameplate
capacity of the unit. Therefore, the
capital and operating costs of CCS
would be high relative to the amount of
CO2 available to be captured.
Additionally, again due to lower
utilization, the amount of IRC section
45Q tax credits that owner/operators
could claim would be low. Because of
the relatively high costs and the
relatively low cumulative emission
reduction potential for these natural gasand oil-fired steam generating units, the
EPA is not proposing CCS as the BSER
for them.
The EPA has reviewed other possible
controls but is not proposing any of
them as the BSER for natural gas- and
oil-fired units either. Co-firing hydrogen
in a boiler is technically possible, but,
for the same reasons discussed in
section VII of this preamble, the only
hydrogen that could be considered for
the BSER would be low-GHG hydrogen,
and there is limited availability of that
hydrogen now and in the near future.
Additionally, for natural gas-fired steam
generating units, setting a future
standard based on hydrogen would have
limited GHG reduction benefits given
the low utilization of natural gas- and
oil-fired steam generating units. Lastly,
HRI for these types of units would face
many of the same issues as for coal-fired
steam generating units; in particular,
HRI could result in a rebound effect that
would increase emissions.
However, the EPA recognizes that
natural gas- and oil-fired steam
generating units could possibly, over
time, operate more, in response to other
changes in the power sector.
Additionally, some coal-fired steam
generating units have converted to 100
percent natural gas-fired, and it is
possible that more may do so in the
future. Moreover, in part because the
fleet continues to age, the plants may
operate with degrading emission rates.
In light of these possibilities, identifying
the BSER and degrees of emission
limitation for these sources would be
useful to provide clarity and prevent
backsliding in GHG performance.
Therefore, the EPA is proposing BSER
for intermediate and base load natural
gas- and oil-fired steam generating units
to be routine methods of operation and
maintenance, such that the sources
could maintain the emission rates (on a
lb/MWh-gross basis) currently
maintained by the majority of the fleet
across discrete ranges of annual capacity
factor. The EPA is proposing this BSER
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for intermediate load and base load
natural gas- and oil-fired steam
generating units, regardless of the
operating horizon of the unit.
A BSER based on routine methods of
operation and maintenance is
adequately demonstrated because units
already operate with those practices.
There are no or negligible additional
costs because there is no additional
technology that units are required to
apply and there is no change in
operation or maintenance that units
must perform. Similarly, there are no
adverse non-air quality health and
environmental impacts or adverse
impacts on energy requirements. Nor do
they have adverse impacts on the energy
sector from a nationwide or long-term
perspective. The EPA’s initial modeling,
which supports this proposed rule,
indicates that by 2040, a number of
natural gas-fired steam generating units
have remained in operation since 2030,
although at reduced annual capacity
factors. There are no CO2 reductions
that may be achieved at the unit level,
but applying the BSER should preclude
increases in emission rates. Routine
methods of operation and maintenance
do not advance useful control
technology, but this point is not
significant enough to offset their
benefits.
The EPA is also taking comment on,
but not proposing, a BSER of lower
emitting fuels for low load natural gasand oil-fired steam generating units. As
noted earlier in this preamble, non-coal
fossil fuels combusted in utility boilers
typically include natural gas, distillate
fuel oil (i.e., fuel oil No. 1 and No. 2),
and residual fuel oil (i.e., fuel oil No. 5
and No. 6). The EPA previously
established heat-input based fuel
composition as BSER in the 2015 NSPS
(termed ‘‘clean fuels’’ in that
rulemaking) for new non-base load
natural gas- and multi-fuel-fired
stationary combustion turbines (80 FR
64615–17; October 23, 2015), and the
EPA is similarly proposing lower
emitting fuels as BSER for new low load
combustion turbines as described in
section VII of this preamble. For low
load natural gas- and oil-fired steam
generating units, the high variability in
emission rates associated with the
variability of load at the lower-load
levels limits the benefits of a BSER
based on routine maintenance and
operation. That is because the high
variability in emission rates would
make it challenging to determine an
emission rate (i.e., on a lb CO2/MWhgross basis) that could serve as the
presumptive standard of performance
that would reflect application of a BSER
of routine operation and maintenance.
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On the other hand, for those units, a
BSER of ‘‘uniform fuels’’ and an
associated presumptive standard of
performance based on a heat input
basis, as described in section XII.D of
this preamble, may be reasonable. The
EPA is soliciting comment on the fuel
types that would constitute ‘‘uniform
fuels’’ specific to low load natural gasand oil-fired steam generating units.
2. Degree of Emission Limitation
As discussed above, because the
proposed BSER for base load and
intermediate load natural gas- and oilfired steam generating plants is routine
operation and maintenance, which the
units are, by definition, already
employing, the degree of emission
limitation by application of this BSER is
no increase in emission rate on a lb
CO2/MWh-gross basis over an extended
period of time (e.g., an annual calendar
year).
F. Summary
The EPA has evaluated options for
BSER for GHG emissions for fossil fuelfired steam generating units. The EPA is
proposing subcategorization of steam
generating units by the type of fossil
fuel fired in the unit, and, for each fuel
type, further levels of subcategorization.
For each subcategory, the EPA is
proposing a BSER and resulting degree
of emission limitation achievable by
application of that BSER, as
summarized in table 5, with
presumptively approvable standards of
performance for use in State plan
development (see section XII of this
preamble for details) included for
completeness. For coal-fired steam
generating units that plan to operate in
the long-term, the EPA is proposing a
BSER of CCS with 90 percent capture of
CO2. In response to industry stakeholder
input and recognizing that the cost
effectiveness of controls depends on a
unit’s expected operating time horizon,
which dictates the amortization period
33359
for the capital costs of the controls, the
EPA is proposing other BSER for coalfired units with shorter operating
horizons while taking comment on what
dates most appropriately define the
thresholds between these different
subcategories. For the different
subcategories of natural gas- and oilfired units, the EPA is proposing BSERs
based on routine methods of operation
and maintenance. The EPA solicits
comment on the proposed BSER and
degrees of emission limitation, as well
as the proposed subcategorization,
including the potential to remove the
imminent-term subcategory and include
units with earlier commitments to
permanently cease operations in either
the near-term or medium-term
subcategory. It is noted that for
imminent-term and near-term coal-fired
steam generating units, the EPA is also
soliciting comment on potential BSERs
based on co-firing low levels of natural
gas.
TABLE 5—SUMMARY OF PROPOSED BSER, SUBCATEGORIES, AND DEGREES OF EMISSION LIMITATION FOR AFFECTED
EGUS
Affected EGUs
BSER
Degree of emission
limitation
Presumptively
approvable standard
of performance 561
Ranges in values on
which the EPA is
soliciting comment
The achievable capture
rate from 90 to 95 percent or greater and the
achievable degree of
emission limitation defined by a reduction in
emission rate from 75
to 90 percent.
The percent of natural
gas co-firing from 30 to
50 percent and the degree of emission limitation from 12 to 20 percent.
Long-term existing coalfired steam generating
units.
Coal-fired steam generating units that have
not elected to commit
to permanently cease
operations by January
1, 2040.
CCS with 90 percent
capture of CO2.
88.4 percent reduction in
emission rate (lb CO2/
MWh-gross).
88.4 percent reduction in
annual emission rate
(lb CO2/MWh-gross)
from the unit-specific
baseline.
Medium-term existing
coal-fired steam generating units.
Coal-fired steam generating units that have
elected to commit to
permanently cease operations after December 31, 2031, and before January 1, 2040,
and that are not nearterm units.
Coal-fired steam generating units that have
elected to commit to
permanently cease operations after December 31, 2031, and before January 1, 2035,
and commit to adopt
an annual capacity factor limit of 20 percent.
Coal-fired steam generating units that have
elected to commit to
permanently cease operations before January 1, 2032.
Natural gas co-firing at
40 percent of the heat
input to the unit.
A 16 percent reduction in
emission rate (lb CO2/
MWh-gross).
A 16 percent reduction in
annual emission rate
(lb CO2/MWh-gross)
from the unit-specific
baseline.
Routine methods of operation.
No increase in emission
rate (lb CO2/MWhgross).
An emission rate limit (lb
CO2/MWh-gross) defined by the unit-specific baseline.
The presumptive standard: 0 to 2 standard
deviations in annual
emission rate above or
0 to 10 percent above
the unit-specific baseline.
Routine methods of operation.
No increase in emission
rate (lb CO2/MWhgross).
An emission rate limit (lb
CO2/MWh-gross) defined by the unit-specific baseline.
The presumptive standard: 0 to 2 standard
deviations in annual
emission rate above or
0 to 10 percent above
the unit-specific baseline.
Near-term existing coalfired steam generating
units.
Imminent-term existing
coal-fired steam generating units.
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Subcategory definition
561 Presumptive standards of performance are
discussed in detail in section XII of the preamble.
While States establish standards of performance for
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sources the EPA provides presumptively
approvable standards of performance based on the
degree of emission limitation achievable through
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application of the BSER for each subcategory.
Inclusion in this table is for completeness.
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TABLE 5—SUMMARY OF PROPOSED BSER, SUBCATEGORIES, AND DEGREES OF EMISSION LIMITATION FOR AFFECTED
EGUS—Continued
Presumptively
approvable standard
of performance 561
Subcategory definition
BSER
Base load continental existing oil-fired steam
generating units.
Oil-fired steam generating units with an annual capacity factor
greater than or equal
to 45 percent.
Routine methods of operation and maintenance.
No increase in emission
rate (lb CO2/MWhgross).
An annual emission rate
limit of 1,300 lb CO2/
MWh-gross.
Intermediate load continental existing oil-fired
steam generating units.
Oil-fired steam generating units with an annual capacity factor
greater than or equal
to 8 percent and less
than 45 percent.
Oil-fired steam generating units with an annual capacity factor
less than 8 percent.
Routine methods of operation and maintenance.
No increase in emission
rate (lb CO2/MWhgross).
An annual emission rate
limit of 1,500 lb CO2/
MWh-gross.
None proposed ...............
.........................................
.........................................
Intermediate and base
load non-continental existing oil-fired steam
generating units.
Non-continental oil-fired
steam generating units
with an annual capacity factor greater than
or equal to 8 percent.
Routine methods of operation and maintenance.
No increase in emission
rate (lb CO2/MWhgross).
An emission rate limit (lb
CO2/MWh-gross) defined by the unit-specific baseline.
Base load existing natural
gas-fired steam generating units.
Natural gas-fired steam
generating units with
an annual capacity factor greater than or
equal to 45 percent.
Routine methods of operation and maintenance.
No increase in emission
rate (lb CO2/MWhgross).
An annual emission rate
limit of 1,300 lb CO2/
MWh-gross.
Intermediate load existing
natural gas-fired steam
generating units.
Natural gas-fired steam
generating units with
an annual capacity factor greater than or
equal to 8 percent and
less than 45 percent.
Natural gas-fired steam
generating units with
an annual capacity factor less than 8 percent.
Routine methods of operation and maintenance.
No increase in emission
rate (lb CO2/MWhgross).
An annual emission rate
limit of 1,500 lb CO2/
MWh-gross.
None proposed ...............
.........................................
.........................................
Low load (continental and
non-continental) existing oil-fired steam generating units.
Low load existing natural
gas-fired steam generating units.
XI. Proposed Regulatory Approach for
Emission Guidelines for Existing Fossil
Fuel-fired Stationary Combustion
Turbines
A. Overview
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Degree of emission
limitation
Affected EGUs
Because the EPA has established
NSPS for GHG emissions from new
fossil fuel-fired stationary combustion
turbines under CAA section 111(b), it
has an obligation to also establish
emission guidelines for GHG emissions
from existing fossil-fuel fired stationary
combustion turbines under CAA section
111(d). Existing fossil fuel-fired
stationary combustion turbines already
represent a significant share of GHG
emissions from EGUs and are quickly
becoming the largest source of GHG
emissions from the power sector. As
other fossil fuel-fired EGUs reduce
utilization or retire, at least some of this
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generation may shift to the existing
combustion turbine fleet with
significant GHG emission implications,
particularly if the latter is not subject to
limits on GHG emissions. For these
reasons, the EPA intends to discharge its
obligation to prescribe emission
guidelines for these sources as
expeditiously as practicable. In this
document, the EPA is proposing
emission guidelines for certain existing
fossil fuel-fired stationary combustion
turbines and soliciting comment on
approaches that could be used to
establish emission guidelines for the
remaining units in the fleet.
In considering how to address this
problem, the EPA believes there are at
least two key factors to consider. The
first is that determining the BSER and
issuing emission guidelines covering
these units sooner rather than later is
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Ranges in values on
which the EPA is
soliciting comment
The threshold between
intermediate and base
load from 40 to 50 percent annual capacity
factor; the degree of
emission limitation
from 1,250 lb CO2/
MWh-gross to 1,800 lb
CO2/MWh-gross.
The degree of emission
limitation from 1,400 lb
CO2/MWh-gross to
2,000 lb CO2/MWhgross.
The threshold between
low and intermediate
load from 5 to 20 percent annual capacity
factor.
The presumptive standard: 0 to 2 standard
deviations in annual
emission rate above or
0 to 10 percent above
the unit-specific baseline.
The threshold between
intermediate and base
load from 40 to 50 percent annual capacity
factor; The acceptable
standard from 1,250 lb
CO2/MWh-gross to
1,400 lb CO2/MWhgross.
The acceptable standard
from 1,400 lb CO2/
MWh-gross to 1,600 lb
CO2/MWh-gross.
The threshold between
low and intermediate
load from 5 to 20 percent annual capacity
factor.
important to address the GHG emissions
from this growing portion of the
inventory. The second is related to the
size of the affected fleet and the
implications for the feasibility and
timing of implementing potential
candidates for BSER. As discussed later
in this section, there are at least three
technologies that could be applied to
reduce GHGs from existing combustion
turbines (CCS, hydrogen co-firing, and
heat rate improvements), all of which
are available today and are being
pursued to at least some degree by
owners and operators of these sources.
Although the EPA believes that these
technologies are available and
adequately demonstrated at the level of
individual existing combustion
turbines, emission guidelines for these
sources must also consider how much of
the fleet could reasonably implement
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one or more of these potential BSER
approaches in a given time frame.
Furthermore, the EPA is aware that
grid operators and power companies
currently rely on existing fossil fuelfired combustion turbines as a flexible
and readily dispatchable resource that
plays a key role in fulfilling resource
adequacy and operational reliability
needs. Although advancements in
energy storage and accelerated
development and deployment of zeroemitting resources may diminish
reliance on existing fossil fuel-fired
combustion turbines for reliability
purposes over time, it is imperative that
emission guidelines for these sources
not impair the reliability of the bulk
power system. For these reasons, the
EPA believes that it is important that a
BSER determination and associated
emission guidelines for existing fossil
fuel-fired combustion turbines rely on
GHG control options that can be feasibly
and cost-effectively implemented at a
scale commensurate with the size of the
regulated fleet, and provide sufficient
operational flexibility and lead time to
allow for smooth implementation of the
GHG emission limitations that preserves
system reliability.
Given the large size of the existing
combustion turbine fleet and the lead
time required to develop CCS and
hydrogen-related infrastructure, the EPA
believes the BSER for this category
entails significant lead time for
application of CCS or low-GHG
hydrogen co-firing. As a result, the EPA
is planning to break the existing
combustion turbine category into two
segments, and is focusing this proposal
on the largest and most frequently
operated (e.g., base load) existing
combustion turbines that have the
highest GHG emissions on an annual
basis. For these large and frequently
operated existing combustion turbines,
the EPA is proposing to determine that
the BSER consists of either application
of CCS by 2035, or application of lowGHG hydrogen co-firing beginning in
2032, based on an evaluation of the
statutory BSER criteria that mirrors
EPA’s evaluation of the BSER for new
base load combustion turbines. This
focused approach will limit GHG
emissions from the highest-emitting
existing natural gas combustion
turbines, while allowing sufficient lead
time for application of CCS or low-GHG
hydrogen co-firing and limiting the
amount of affected capacity to a degree
that is consistent with the availability of
these two GHG mitigation technologies.
The EPA intends to undertake a separate
rulemaking as expeditiously as
practicable that addresses emissions
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from the remaining combustion
turbines.
In this document, the EPA is
soliciting comment on both the scope of
these proposed emission guidelines (in
other words, the applicability
thresholds that would determine which
existing combustion turbines are in the
first segment) as well as the BSER for
units covered in this rulemaking. In
section XII of this preamble, the EPA is
also taking comment on the associated
State plan requirements associated with
the BSER for existing fossil fuel-fired
turbines.
As described in more detail below,
the EPA is proposing to determine that
the BSER for large and frequently
operated existing stationary combustion
turbines is the same as for the proposed
second phase of requirements for new
base load combustion turbines.
Accordingly, the EPA is proposing
emission guidelines for these existing
stationary combustion turbines that
would require either that these sources
achieve a degree of emission limitation
consistent with the use of CCS by 2035,
or achieve a degree of emission
limitation reflecting the utilization of 30
percent low-GHG hydrogen by volume
by 2032 (increasing to 96 percent lowGHG hydrogen by volume by 2038).
The EPA believes that it is important
to stagger CCS requirements for existing
coal-fired units and new and existing
fossil fuel-fired turbines to allow time
for both deployment of CCS
infrastructure and to accommodate
increased demand for specialized
engineering and construction labor
needed to build CCS equipment. The
EPA also believes that because coalfired units emit more CO2/MWh, that to
the extent that there are limitations to
the amount of CCS that can be installed
by 2030 it makes sense to focus a CCS
BSER on those coal-fired units first. A
2035 compliance timeframe would
allow for staggering of resources needed
to install CCS while still allowing
existing turbines to take advantage of
the IRC section 45Q tax credits to make
CCS controls more cost-effective or to
use hydrogen, produced at facilities
eligible for the 45V tax credits, making
hydrogen co-firing more cost
effective.562 In the rest of this section,
the EPA proposes regulations for the
first segment and solicits comment on
specific elements of the approach. This
section also briefly discusses what BSER
might look like for units in the second
rulemaking, and requests comments that
could inform the development of a
562 CCS projects that commence construction as
late as December 31, 2032 can qualify for the 45Q
tax credit.
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rulemaking defining BSER, degrees of
emission limitation, compliance
deadlines and other elements of an
emission guideline for those units at a
later date.
As explained in more detail later in
this section, the EPA is proposing that
the first segment it would cover would
be units greater than 300 MW with an
annual capacity factor of greater than 50
percent. The EPA projects that 37 GW
of capacity would meet these criteria in
2035, representing 14 percent of the
projected existing combustion turbine
capacity and 23 percent of the projected
generation from existing combustion
turbines in 2035. As is explained further
below, the EPA is proposing this
capacity factor and capacity threshold
after weighing the quantity of emissions
from these units and considerations
about the feasibility of installing
significant amounts of CCS and/or
hydrogen co-firing. In short, these units
offer the best opportunity to achieve
significant emissions reduction
consistent with what the EPA believes
these technologies will be capable of on
a national scale. Similar to its proposal
for new base load turbines, the EPA is
proposing that BSER for those existing
sources be both pathways, that is CCS
with 90 percent capture in 2035 and
clean hydrogen combusting 30 percent
by volume in 2032 and 96 percent by
volume in 2038. Alternatively, as with
the proposal for new base load turbines,
the EPA is taking comment on whether
to finalize a BSER with a single pathway
based on application of CCS with 90
percent capture, which could also be
met by co-firing with low-GHG
hydrogen as a compliance option, or
vice-versa. The EPA is also taking
comment on whether the compliance
date should begin earlier, including as
early as 2030.563
The EPA has promulgated several
prior rulemakings under both CAA
section 111(b) and section 111(d) that
provide the regulated sector with lead
time to accommodate the time needed to
deploy control technology. Section
VII.F.3.a of this preamble discusses, in
the section 111(b) context, precedent for
rulemakings that provide such lead
time. For additional examples under
CAA section 111(d), see 70 FR 28606,
28619 (May 18, 2005) (establishing
emission guidelines for electric utility
steam generating units, with a 13-year
compliance timeframe for a second
control phase); 61 FR 9905, 9919 (March
12, 1996) (establishing emission
guidelines for municipal solid waste
landfills, with a 2.5-year compliance
563 If we finalize one of these variations, the state
plan requirements may change accordingly.
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lotter on DSK11XQN23PROD with PROPOSALS2
timeframe); 62 FR 48348, 48381
(September 15, 1997) (establishing
emission guidelines for hospital/
medical/infectious waste incinerators,
with up to 3 years after State plan
approval for facilities to install control
equipment). Section XI.B provides
background information concerning the
composition of the current fossil fuelfired stationary combustion turbine fleet
and how it is expected to change in the
near future. In section XI.C, the EPA
proposes an approach for units covered
in this rulemaking and in section XI.D,
the EPA summarizes the key topics for
which we are soliciting comment
relative to existing combustion turbines.
Finally, section XI.E, outlines a
potential approach for units covered in
a second rulemaking
B. The Existing Stationary Combustion
Turbine Fleet
In 2021, existing combustion turbines
represented 37 percent of the GHG
emissions from the power sector and 40
percent of the generation from the
power sector. In the EPA’s updated
baseline projections for the power
sector, they represent 74 percent of the
GHG emissions and 25 percent of the
generation in 2035. In EPA’s modeling
of the 2035 control case, in which both
existing fossil fuel-fired EGUs and new
stationary combustion turbine EGUs are
subject to the emissions limitations
proposed in this action but existing
combustion turbine EGUs are left
uncontrolled, load shifting from those
two categories of sources to the existing
combustion turbines results in an
increase in the share of the emissions
from existing combustion turbines
(including combined cycle and simple
cycle combustion turbines) to 82
percent while their share of generation
remains 25 percent. Moreover, in that
control case, existing combined cycle
combustion turbines are responsible for
71 percent of the CO2 emissions from
the power sector.
In the EPA’s modeling in support of
these rules, we see two trends that are
important relative to existing
combustion turbines. First, the EPA’s
analysis of the reference case (which
includes the impacts of IRA without
considering the GHG limitation
requirements proposed in these rules)
projects a long-term decline in
generation and emissions from existing
combustion turbines relative to current
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generation and emissions. In this
reference case, combined cycle
generation falls in each model run year
from 2028 through 2050, and it falls by
more than 50 percent between 2030 and
2045. Generation from existing simple
cycle combustion turbines is projected
to peak in 2030 before declining by
more than 70 percent by 2045. While
generation falls from turbines, this is
primarily caused by declining capacity
factors, not through retirements.
Historical data shows a wide range of
variation in both the heat rate and the
GHG emission rates among both existing
combined cycle combustion turbines
and existing simple cycle combustion
turbines. The GHG emission rates for
existing combined cycle units range
from as low as 644 lb CO2/MWh-gross
to as high as 1,891 lb CO2/MWh-gross,
and annual capacity factors range from
as low as 1 percent to as high as 85
percent. While there is some correlation
between units with low-GHG emission
rates (e.g., more efficient units) and
utilization, some low efficiency
combined cycle units have historically
operated at very high capacity factors.
For instance, two of the highest
operating units (at 85 percent capacity
utilization) have GHG emission rates of
nearly 1,200 lb/MWh-gross.
C. BSER for Base Load Turbines Over
300 MW
As noted earlier, the EPA is adopting
an approach in which existing
combustion turbines would be regulated
in two segments. The proposed
emission guidelines presented in this
document focus on the first segment,
which comprises the base load units
(e.g., those operated at capacity factors
of greater than 50 percent) over 300
MW. The EPA intends to undertake a
separate rulemaking to address the
second segment, comprising the
remainder of the existing fossil fuelfired stationary combustion fleet, as
expeditiously as practicable.
Because the first segment would be
focused on the largest most frequently
used units, the EPA is proposing that
the BSER for these units would be CCS
or a BSER based upon burning low-GHG
hydrogen. As is the case for new base
load combustion turbines, each of these
sets of controls is adequately
demonstrated, of reasonable cost, and
consistent with the other criteria to
qualify as the BSER.
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Because the second segment would
include both smaller more frequently
used units and less frequently used
units, in that action, the EPA anticipates
considering a broader range of
technologies including heat rate
improvements. This approach
recognizes the imperatives (the urgent
need to reduce greenhouse gases), the
opportunities (including the availability
of IRC section 45Q tax credits
incentivizing CCS installation as long as
sources commence construction by
January 1, 2033), and the need for
infrastructure for CCS and co-firing lowGHG hydrogen to be deployed at a
broader scale if these BSER technologies
are to be deployed broadly at smaller
and less frequently operated existing
combustion turbines.
The EPA is proposing emission
guidelines for units with a capacity
factor greater than 50 percent and a
capacity of greater than 300 MW, but is
also taking comment on whether that
capacity factor threshold or capacity
threshold should be lower (for instance
40 percent for the capacity factor and
200 MW or 100 MW for the capacity).
The EPA is proposing that 300 MW is
the appropriate threshold for
applicability because it focuses on the
units with the highest emissions where
CCS is likely to be most cost effective.
As an important first step towards
abating emissions from the existing
turbine fleet and recognizing that at
least some project developers are
considering the use of clean hydrogen in
base load turbines 564 and recognizing
that there are likely limits to the clean
hydrogen supply in the mid-term, the
EPA believes that it is appropriate to
also propose a clean hydrogen BSER for
the same set of units. Table 6 provides
information from IPM detailing the
amount of capacity and generation from
the 2035 IPM projected control case that
would be covered under various
capacity thresholds.
564 As one developer notes, ‘‘the plant will be
capable of supporting a balanced and diverse power
generation portfolio in the future; from energy
storage capable of accommodating seasonal
fluctuations from renewable energy, to cost
effective, dispatchable intermediate and baseload
power.’’ https://www.longridgeenergy.com/news/
2020-10-13-long-ridge-energy-terminal-partnerswith-new-fortress-energy-and-ge-to-transitionpower-plant-to-zero-carbon-hydrogen.
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TABLE 6—KEY CHARACTERISTICS FOR BASELOAD COMBINED CYCLE UNITS OF VARIOUS CAPACITIES
NGCC units projected to run at a capacity factor of greater than 50 percent and at a capacity size
greater than
100
200
300
400
500
MW
MW
MW
MW
MW
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
...................................................................................................................................................
The EPA believes this approach
would ensure that GHG emissions
limitations are implemented first at the
subset of existing fossil fuel-fired
combustion turbines that contributes the
most to GHG emissions, and where the
benefits of implementing GHG controls
would be greatest.
The EPA believes there are three sets
of controls that could potentially qualify
as the BSER for the group of large and
frequently-operated combustion
turbines covered in the first rulemaking.
Those controls are heat rate/efficiency
improvements, co-firing low-GHG
hydrogen, and use of CCS. We discuss
each of these below, and in the course
of each discussion explain why we are
proposing that the following controls
qualify as the BSER: co-firing with lowGHG hydrogen in the amounts of 30
percent (by volume) by 2032 and 96
percent (by volume) by 2038, and the
use of CCS with 90 percent capture by
2035.
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1. Heat-Rate Improvements
The EPA believes that heat rate
improvements for existing combustion
turbines are broadly applicable today.
Heat rate/efficiency improvements can
be divided into two types. The first type
involves smaller scale improvements to
existing combustion turbines. The
second type involves more
comprehensive upgrades of the
combustion turbines.
Smaller scale efficiency
improvements can include measures
such as inlet fogging and inlet cooling.
Both of these techniques can achieve
about 2 percent improvements in heat
rate. Inlet chilling costs approximately
$19/kW and is also accompanied by a
capacity increase of 11 percent. Inlet
fogging is approximately $0.93/kW and
is accompanied by a capacity increase of
6 percent.565 These small-scale
efficiency improvements would likely
result in an average 2 percent
565 https://www.andovertechnology.com/wpcontent/uploads/2021/03/C_18_EDF_FINAL.pdf.
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improvement in the heat rate of affected
existing combustion turbines.
More comprehensive efficiency
upgrades to combustion turbines are
also possible. An upgrade to the
combustion turbine can result in a heat
rate improvement of 3.0 percent and a
capacity increase of 13 percent for $172/
kW, while an upgrade to the steam
turbine can result in a heat rate
improvement of 3.2 percent with a
capacity increase of 3 percent for $130/
kW. These more comprehensive
efficiency improvements would likely
result in an average efficiency
improvement of 6 percent for affected
existing stationary combustion turbines.
The EPA is not proposing HRI
improvements for units greater than 300
MW because they achieve significantly
less emission reductions than either
CCS or co-firing hydrogen, but believes
that some units may choose to make
these upgrades as part of their response
to installing CCS and/or co-firing
hydrogen. The EPA is taking comment
on whether HRI should be considered
BSER (or a component of BSER) for
combined cycle units with a capacity
factor of greater than 50 percent and a
capacity of less than 300 MW as part of
this initial rulemaking.
2. Co-Firing Low-GHG Hydrogen
a. Overview
The EPA is proposing that for existing
combined cycle combustion turbines
that operate at capacity factors of greater
than 50 percent and that are greater than
300 MW, co-firing 30 percent low-GHG
hydrogen by 2032 and 96 percent by
2038 qualifies as the BSER, for largely
the same reasons that apply to new
combined cycle turbines, as discussed
in section VII.F.3.c.vii of this preamble.
Co-firing hydrogen at these levels is
adequately demonstrated, as indicated
by announced plans of manufacturers
and generators to undertake retrofit
projects for hydrogen co-firing. These
plans also indicate that the costs of
retrofitting are reasonable. The analysis
concerning the costs of low-GHG
hydrogen for existing turbines is
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Capacity
(GW)
134
85
37
12
6
Percentage
of total
NGCC
capacity
(%)
Percentage
of total
NGCC
generation
(%)
49
31
14
4
2
78
51
23
10
7
comparable to the analysis for new
turbines. See section VII.F.3.c.vii.(B) of
this preamble. Co-firing with low-GHG
hydrogen at existing turbines also has
comparable non-air quality
environmental impacts and energy
requirements, and comparable
emissions reductions as co-firing with
low-GHG hydrogen at new turbines. See
sections VII.F.3.c.vii.(C)–(D) of this
preamble. For these reasons, the EPA is
proposing that co-firing with low-GHG
hydrogen qualifies as the BSER. The fact
that doing so will also advance the
development and deployment of this
low-emitting technology further
supports this proposal.
b. Adequately Demonstrated
Co-firing with low-GHG hydrogen is
feasible in combustion turbines that are
currently being produced.
Manufacturers have developed retrofits
to allow existing combustion turbines to
combust up to 100 percent hydrogen,
and some companies have announced
plans to retrofit their existing turbines to
combust hydrogen. In section VII.F.3.c
of this preamble, the EPA proposes cofiring of low-GHG hydrogen as BSER for
certain new base load combustion
turbines. A number of the examples that
the EPA cites as evidence that
companies are developing combined
cycle turbines to co-fire hydrogen either
are existing turbines that companies are
planning to retrofit to burn hydrogen or
are already under construction, and
would, therefore, be classified as
existing turbines under this rule.
Because new combined cycle turbines
that operate at capacity factors of greater
than 50 percent are similar to existing
combined cycle turbines that operate at
capacity factors of greater than 50
percent, the EPA is proposing a similar
BSER pathway for existing combustion
turbines, based upon co-firing 30
percent (by volume) low-GHG hydrogen
in 2032 and ramping up thereafter to 96
percent (by volume) low-GHG hydrogen
in 2038.
There are two key questions related to
whether co-firing low-GHG hydrogen in
existing combustion turbines is
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i. Capability of Existing Turbines To CoFire Hydrogen
There are at least three lines of
evidence that demonstrate that co-firing
low-GHG hydrogen in existing turbines
is possible today (with a number of
them already able to fire 100 percent
hydrogen) and that by approximately
2030, many additional turbine models
will have the capability to co-fire 100
percent hydrogen. First, information
from turbine vendors indicates that they
already have significant experience in
operating turbines with hydrogen; some
of their existing turbine models can cofire hydrogen; and/or they are currently
engaged in projects to upgrade existing
turbines to co-fire hydrogen. Second,
test burns have been completed on
several existing utility turbines. Third,
several utilities have indicated plans to
retrofit existing turbines to co-fire
hydrogen.
Existing turbine vendors including
GE, Mitsubishi, and Siemens have
indicated that their turbines can
currently co-fire some amounts of
hydrogen; and, they have plans to
expand those capabilities. GE has
indicated that most of their product line
can currently be configured to co-fire
significant amounts of hydrogen.566
Siemens is currently offering retrofit
packages for many of its existing
turbines that will allow them to
combust up to 75 percent hydrogen.567
Mitsubishi also offers retrofit packages
that could allow for up to 100 percent
firing of hydrogen.568
Section VII.F.3.c.vii(A) of this
preamble includes discussion of how
retrofitting existing turbines to co-fire
with increasing amounts of hydrogen is
adequately demonstrated. Several
turbines currently in operation have the
capability to co-fire hydrogen up to 30
percent without modifications. Other
existing turbine models would need
modifications to enable co-firing
between 50 and 100 percent.
Moreover, several existing combined
cycle turbines have demonstrated the
ability to co-fire some amounts of
hydrogen. The Long Ridge Energy
Terminal tested 5 percent hydrogen cofiring at the 485–MW combined cycle
plant on a GE HA-class (GE 7HA.02) in
2022. The turbine is designed to enable
a transition to 100 percent hydrogen
fuel. This example is particularly salient
given the large capacity of the unit. No
modifications should be required for
this turbine model, which has been
available since 2017, to operate with
between 5 and 20 percent hydrogen cofiring. Higher hydrogen co-firing
concentrations will require some
modification.569
Southern Company has also
demonstrated hydrogen co-firing on a
Mitsubishi, M501G turbine. The
demonstration involved co-firing 20
percent hydrogen (by volume), was
successful at both full and partial load,
and demonstrated compliance with
emissions requirements without
impacting maintenance intervals.570
Other test burns have demonstrated the
ability to fire up to 80 percent hydrogen
without emissions excursions.571
Several utilities are exploring the use
of hydrogen in their existing turbine
fleet. For example, Constellation Energy,
which owns a fleet of 23 gas-fired
turbines with a combined total capacity
of 8.6 GW, asserts that retrofitting
existing turbines to co-fire hydrogen is
technically feasible with existing
turbine models: ‘‘Based on our
assessments, retrofits using available
technology can allow hydrogen
blending at 50–100 percent by volume
in select generators. These retrofits,
which include burner and additional
balance-of-plant modifications, allow
for more substantial CO2 emissions
reductions.’’ 572 Florida Power and Light
(FPL) intends to convert 16 GW of
existing turbine capacity to run on 100
percent hydrogen by 2045.573 They are
566 https://www.ge.com/gas-power/future-ofenergy/hydrogen-fueled-gas-turbines?utm_
campaign=h2&utm_medium=cpc&utm_
source=google&utm_content=eta&utm_term=Ge
%20gas%20turbine%20hydrogen&
gad=1&gclid=EAIaIQobChMIqMaL6IXG_
gIVhsjjBx2gPgb-EAAYASAAEgK61PD_BwE and
https://www.ge.com/content/dam/gepower-new/
global/en_US/downloads/gas-new-site/future-ofenergy/hydrogen-overview.pdf.
567 https://assets.siemens-energy.com/siemens/
assets/api/uuid:66b2b6a3-7cdc-404d-9ab0-ddc
fbe4adf02/hydrogenflyer.pdf?ste_sid=81945e06dd
4f27fd626614f9b954e3f4.
568 https://solutions.mhi.com/clean-fuels/
hydrogen-gas-turbine/.
569 https://www.powermag.com/first-hydrogenburn-at-long-ridge-ha-class-gas-turbine-markstriumph-for-ge/.
570 https://www.powermag.com/southern-co-gasfired-demonstration-validates-20-hydrogen-fuelblend/.
571 https://www.ccj-online.com/real-worldexperience-firing-hydrogen-natural-gas-mixtures/.
572 Constellation Energy Corporation’s Comments
on EPA Draft White Paper: Available and Emerging
Technologies for Reducing Greenhouse Gas
Emissions from Combustion Turbine Electric
Generating Units.
573 https://cleanenergy.org/blog/nextera-sets-goalto-decarbonize-proposes-big-transition-for-floridapower-light/.
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adequately demonstrated. The first
question is whether existing combustion
turbines are capable of co-firing
significant amounts of hydrogen and/or
if they can be retrofitted to do so. The
second question is whether there will be
an adequate supply of low-GHG
hydrogen. These points are discussed
below.
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currently developing a 25 MW
electrolyzer project at the Cavendish
Energy Center.574
One concern with hydrogen co-firing
is that, because it burns at a higher
temperature, it has the potential to
generate more thermal NOx. The most
commonly used NOX combustion
control for base load combined cycle
turbines is dry low NOX (DLN)
combustion. Even though the ability to
co-fire hydrogen in combustion turbines
that are using DLN combustors to
reduce emissions of NOX is currently
more limited, all major combustion
turbine manufacturers have developed
DLN combustors for utility EGUs that
can co-fire hydrogen.575 Moreover, the
major combustion turbine
manufacturers are designing combustion
turbines that will be capable of
combusting 100 percent hydrogen by
approximately 2030, with DLN designs
that assure acceptable levels of NOX
emissions.576 577
ii. Availability of Low-GHG Hydrogen
The EPA is proposing that the BSER
for existing combustion turbines
includes co-firing 30 percent (by
volume) low-GHG hydrogen by 2032
and 96 percent (by volume) by 2038.
The EPA is proposing to define lowGHG hydrogen as hydrogen that is
produced with overall carbon emissions
of less than 0.45 kg CO2e/kgH2 from
well-to-gate. Electrolytic hydrogen
produced using zero-carbon emitting
energy sources is the most likely, but
not the only, form of hydrogen
anticipated to meet this proposed
definition.578
Suitable volumes of low-GHG
hydrogen are expected to be produced
by the 2032 and 2038 timeframes to
satisfy the demand driven by this
proposed rule. As referenced throughout
this proposal, DOE’s clean hydrogen
production estimates are 10 MMT
annually of clean hydrogen by 2030,
and 20 MMT annually by 2040. There
is reason to believe actual produced
574 https://dailyenergyinsider.com/news/34040florida-power-light-taps-cummins-for-its-greenhydrogen-facility/.
575 Siemens Energy (2021). Overcoming technical
challenges of hydrogen power plants for the energy
transition. NS Energy. https://
www.nsenergybusiness.com/news/overcomingtechnical-challenges-of-hydrogen-power-plants-forenergy-transition/.
576 Simon, F. (2021). GE eyes 100% hydrogenfueled power plants by 2030. https://
www.euractiv.com/section/energy/news/ge-eyes100-hydrogen-fuelled-power-plants-by-2030/.
577 Patel, S. (2020). Siemens’ Roadmap to 100%
Hydrogen Gas Turbines. https://
www.powermag.com/siemens-roadmap-to-100hydrogen-gas-turbines/.
578 DOE, Pathways to Commercial Liftoff: Clean
Hydrogen (March 2023).
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low-GHG hydrogen will exceed those
levels. Announced clean hydrogen
production projects total 12 MMT
annually for 2030.579 In fact, hydrogen
production could outpace DOE’s
projections if demand markets across
sectors, including the power sector,
grow rapidly and emerge
simultaneously with cost declines
across the value chain.580 Over time, the
emergence of the self-sustaining lowGHG hydrogen markets are predicted to
be established as demand for low-GHG
solidifies and anchors the market,
ensuring low-GHG production even
after the PTC sunsets. Given the
magnitude of the PTC for low-GHG
hydrogen, $3/kg, electrolytic hydrogen
production is expected to accelerate,
accounting for between 70 and 95
percent of hydrogen production in 2030,
and between 30 and 50 percent in
2040.581
Further, multiple utilities are
pursuing projects to secure supplies of
electrolyzer-based hydrogen for their
power projects. As mentioned earlier in
this proposal, Intermountain Power is
working with partners to develop an
integrated hydrogen turbine, a hydrogen
production facility, and a hydrogen
storage facility in Delta, Utah. All three
components of the project are under
construction and are scheduled to be
operational by 2025, with the turbine
combusting 30 percent (by volume) lowGHG hydrogen at startup.582 FPL has
announced plans to build 30 GW of
excess solar to supply clean hydrogen
production to power its turbines and to
sell to other customers.583 Entergy has
entered into multiple agreements to
579 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf. Figure 8 of the
Liftoff Report represents compiled clean hydrogen
projects with aggregated 2030 production exceeding
12 MMT annually.
580 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf. Figure 13
presents modeling of hydrogen production volumes
under various scenarios, including projections of
20MMT in 2030, and 42 MMT in 2040 based on
high end of ranges for end use demand which
assumes additional ramp up in policy support for
decarbonization—which is consistent with this
proposal to reduce emissions from the power sector,
as well as EPA’s proposed Greenhouse Gas
Emissions Standards for Heavy-Duty Vehicle.
581 DOE Pathways to Commercial Liftoff: Clean
Hydrogen, March 2023. https://liftoff.energy.gov/
wp-content/uploads/2023/03/20230320-LiftoffClean-H2-vPUB-0329-update.pdf. Figure 14 of the
Liftoff report projects the split of hydrogen
production in future years between electrolytic and
SMR.
582 https://www.ipautah.com/ipp-renewed/.
583 https://cleanenergy.org/blog/nextera-sets-goalto-decarbonize-proposes-big-transition-for-floridapower-light/.
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explore the use of existing and new
renewable generating assets and
transmission to supply zero GHG
electricity to developers of hydrogen
production plants.584 Multiple US
utilities are collaborating to develop
hydrogen hubs.585
c. Costs
The fact that existing sources are
already planning to combust low-GHG
hydrogen, even in the absence of a
regulatory requirement, is an indication
that the costs of co-firing are reasonable.
The EPA has also developed a more
specific description of the costs, which
follows. It incorporates some
components of the analysis of costs of
co-firing low-GHG hydrogen for new
turbines, as discussed in section
VII.F.3.c.vii(B) of this preamble.
There are three sets of potential costs
associated with retrofitting combustion
turbines to co-fire hydrogen: (1) Capital
costs of retrofitting combustion turbines
to have the capability of co-firing
hydrogen; (2) pipeline infrastructure to
deliver hydrogen; and (3) the fuel costs
related to production of low-GHG
hydrogen. While many combustion
turbines are able to fire lower volume
blends of hydrogen with natural gas, not
all have the capacity or on-site
infrastructure necessary to blend higher
volumes of hydrogen. The primary costs
that combustion turbines would incur
would be the fuel costs for low-GHG
hydrogen, along with limited capital
retrofit costs, in order to co-fire
hydrogen at the 30 percent and 96
percent levels that the EPA is proposing
as the BSER.
One company, Constellation Energy
Corporation, has estimated the costs to
retrofit existing plants to co-fire
hydrogen and has indicated that they
are reasonable: ‘‘We expect $10–$60/kW
in retrofit costs to achieve 30–60%
hydrogen blending by volume at our
power plants. At blend levels in the
range of 60–100%, OEMs have
suggested pricing of roughly $100/
kW.’’ 586 The EPA estimates that if lowGHG hydrogen is available at a
584 https://www.entergynewsroom.com/news/
entergy-texas-new-fortress-energy-partner-advancehydrogen-economy-in-southeast-texas/ and https://
www.entergynewsroom.com/news/entergy-texasmonarch-energy-collaborate-advance-southeasttexas-energy-infrastructure-1323187465/.
585 https://news.duke-energy.com/releases/majorsoutheast-utilities-establish-hydrogen-hubcoalition.
586 Constellation Energy Corporation’s Comments
on EPA Draft White Paper: Available and Emerging
Technologies for Reducing Greenhouse Gas
Emissions from Combustion Turbine Electric
Generating Units Docket ID No. EPA–HQ–OAR–
2022–0289, June 6, 2022).
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delivered price of $1/kg,587 co-firing 30
percent hydrogen in a combined cycle
EGU operating at a capacity factor of 65
percent would increase the levelized
cost of electricity (LCOE) by $2.9/MWh
and a 96 percent co-firing rate would
increase the LCOE by $21/MWh.588
Regardless of the level of hydrogen cofiring, the CO2 abatement cost is $64/ton
($70/metric ton) at the affected
facility.589 For an aeroderivative simple
cycle combustion turbine operating at a
capacity factor of 40 percent, the EPA
estimates co-firing 30 percent low-GHG
hydrogen would increase the LCOE by
$4.1/MWh, and a 96 percent co-firing
rate would increase the LCOE by $30/
MWh. At a delivered price of $0.75/kg,
the CO2 abatement costs for co-firing
hydrogen would be $32/ton ($35/metric
ton). For a combined cycle EGU, the
EPA estimates the LCOE increase would
be $1.4/MWh and $11/MWh for the 30
percent and 96 percent cases,
respectively. For a simple cycle EGU,
the EPA estimates the LCOE increase
would be $2.1/MWh and $15/MWh for
the 30 percent and 96 percent cases,
respectively.
The EPA is soliciting comment on
what additional costs would be required
to ensure that combustion turbines are
able to co-fire between 30 to 96 percent
low-GHG hydrogen and if there are
efficiency impacts from co-firing
hydrogen. Retrofits to add the capacity
to combust higher volumes of hydrogen
could include retrofitting the
combustor, increasing the size of the
fuel piping, and upgrades to minimize
fuel leakage, hydrogen storage and
blending equipment, upgraded control
systems, modification to the continuous
emissions monitoring system, safety
upgrades and leakage detectors,
modification of the HRSG to accept
higher temperature exhaust, and NOX
control modifications (e.g., upgraded
premix combustion technologies).590
According to model plant estimates in
EPRI’s US-REGEN model, the heat rate
of a hydrogen-fired combustion turbine
is 5 percent higher than a comparable
natural gas-fired combustion turbine.
Furthermore, for hydrogen-fired
combustion turbines relative to a
comparable natural gas-fired
combustion turbine, the capital costs are
587 The delivered price includes the purchase cost
of the fuel and its transportation costs and the 45V
tax credit.
588 The EIA long-term natural gas price for
utilities is $3.69/MMBtu.
589 The abatement cost of co-firing low-GHG
hydrogen is determined by the relative delivered
cost of the low-GHG hydrogen and natural gas.
590 Simon, Nima, Retrofitting Gas Turbine
Facilities for Hydrogen Blending. November 2,
2022. https://www.icf.com/insights/energy/
retrofitting-gas-turbines-hydrogen-blending.
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approximately $70/kW higher, the fixed
operating costs are approximately $1/
year per kW higher, and the non-fuel
variable operating costs are
approximately $0.5/MWh higher.591
While these costs are for new
combustion turbines, the amounts could
be higher for retrofits to combustion
turbines. To the extent it is appropriate
to account for additional costs
associated with a hydrogen co-firing
BSER for existing combustion turbines,
the EPA is soliciting comment on
whether capital and fixed costs should
be increased by 9 percent, consistent
with the NETL estimated retrofit costs of
CCS relative to new combustion
turbines.
The EPA is proposing to determine
that the increase in operating costs from
a BSER based on low-GHG hydrogen is
reasonable.
d. Non-Air Quality Health and
Environmental Impact and Energy
Requirements
The co-firing of hydrogen in
combustion turbines in the amounts that
the EPA proposes as the BSER would
not have adverse non-air quality health
and environmental impacts. It would
potentially result in increased
production of NOX, but those NOX
emissions can be controlled, as
described in sections VII.F.3.c.vii.(A)
and XI.C.2.b.i of this preamble.
In addition, co-firing hydrogen in the
amounts proposed would not have
adverse impacts on energy
requirements, including either the
requirements of the combustion turbines
to obtain fuel or on the energy sector
more broadly, particularly with respect
to reliability. As discussed in sections
VII.F.3.c.vii.(A)–(B) and XI.C.2.b.–c. of
this preamble, combustion turbines can
be constructed to co-fire high volumes
of hydrogen in lieu of natural gas, and
the EPA expects that low-GHG hydrogen
will be available in sufficient quantities
and at reasonable cost. Any impact on
the energy sector would be further
mitigated by the large amounts of
existing generation that would not be
subject to requirements in this rule and
the projected new capacity in the base
case modeling.
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e. Extent of Reductions in CO2
Emissions
The site-specific reduction in CO2
emissions achieved by a combustion
turbine co-firing hydrogen is dependent
on the volume of hydrogen blended into
the fuel system. Due to the lower energy
591 https://us-regen-docs.epri.com/v2021a/
assumptions/electricity-generation.html#newgeneration-capacity.
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density by volume of hydrogen
compared to natural gas, an affected
source that combusts 30 percent by
volume hydrogen with natural gas
would achieve approximately a 12
percent reduction in CO2 emissions
versus firing 100 percent natural gas.592
A source combusting 100 percent
hydrogen would have zero CO2 stack
emissions because hydrogen contains no
carbon, as previously discussed. A
source co-firing 96 percent by volume
hydrogen (approximately 89 percent by
heat input) would achieve an
approximate 90 percent CO2 emission
reduction, which is roughly equivalent
to the emission reduction achieved by
sources utilizing 90 percent CCS.
f. Promotion of the Development and
Implementation of Technology
Determining co-firing 30 percent (by
volume) low-GHG hydrogen by 2032
and co-firing 96 percent (by volume) to
be components of the BSER would
generally advance technology
development in both the production of
low-GHG hydrogen and the use of
hydrogen in combustion turbines, for
the same reasons discussed with respect
to new combustion turbines in section
VII.F.3.c.vii.(E) of this preamble.
g. Summary
The EPA proposes that co-firing 30
percent low-GHG hydrogen by 2032 and
96 percent by 2038 qualify as a BSER
pathway for large and frequently-used
existing combustion turbines. For the
reasons discussed above, the EPA
proposes that co-firing low-GHG
hydrogen on that pathway is adequately
demonstrated in light of the capability
of combustion turbines to co-fire
hydrogen and the EPA’s reasonable
expectation that adequate quantities of
low-GHG hydrogen will be available by
2032 and 2038 and at reasonable cost.
Moreover, combusting hydrogen will
achieve reductions because it does not
produce GHG emissions and will not
have adverse non-air quality health or
environmental impacts or energy
requirements, including on the
nationwide energy sector. Primarily
because the production of low-GHG
hydrogen generates the fewest GHG
emissions, the EPA proposes that cofiring low-GHG hydrogen, and not other
types of hydrogen, qualify as the ‘‘best’’
system of emission reduction. See
section VII.F.3.c.vii(F) of this preamble.
The fact that co-firing low GHG
hydrogen creates market demand for,
and advances the development of, lowGHG hydrogen, a fuel that is useful for
592 The energy density by volume of hydrogen is
lower than natural gas.
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reducing emissions in the power sector
and other industries, provides further
support for this proposal.
Similar to new base load combined
cycle turbines, the EPA is also taking
comment on an alternative approach in
which the BSER for these units would
be based on CCS with 90 percent
capture, for the reasons discussed next,
but units could follow a pathway that
would enable them to achieve the same
reductions using low-GHG hydrogen.
3. CCS
a. Overview
The EPA believes that CCS is an
effective mitigation measure for existing
combustion turbines and that it would
be most cost-effective for units that are
frequently operating. As discussed in
section VII.F.3.b.iii.(A) of this preamble,
multiple companies are considering
adding CCS to existing fossil fuel-fired
power plants and multiple companies
have performed FEED studies evaluating
the feasibility of installing CCS on an
existing combined cycle unit. As also
discussed there, CO2 pipelines are
available and their network is
expanding in the U.S., the safety of
existing and new supercritical CO2
pipelines is comprehensively regulated
by PHMSA, and areas without
reasonable access to pipelines for
geologic sequestration can transport CO2
to sequestration sites via other
transportation modes. As also discussed
there, geologic sequestration of CO2 is
well proven, broadly available
throughout the U.S., and there is a
detailed set of regulatory requirements
to ensure the security of sequestered
CO2. For these reasons, the EPA
proposes that CCS with 90 percent
capture is adequately demonstrated for
existing combustion turbines.
The EPA further proposes that CCS is
cost-reasonable for existing turbines that
are greater than 300 MW and operate at
greater than 50 percent capacity. The
EPA believes that many existing
combined cycle units are likely to be
able to install and operate CCS within
the costs that the EPA found to be
reasonable for new stationary
combustion turbines and existing coalfired steam generating units. Certain
parts of the cost calculation should be
much the same as for new sources,
including the costs for transportation
and sequestration as well as the
availability of the IRC section 45Q tax
credit, although the costs for retrofitting
capture equipment may in some cases
be higher. See section VII.F.3.b.iii.(B) of
this preamble. NETL estimates that the
capital cost of CCS retrofits on
combined cycle EGUs is 9 percent
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higher than for new combined cycle
EGUs.593 The additional capital costs
increase the LCOE of the retrofit CCS by
an additional $1.5/MWh compared to an
installation at a new combined cycle
EGU, which is consistent with control
costs that EPA has found to be
reasonable in other rulemakings, as
noted in section VII.F.3.b.iii.(B)(5).
The ability to cost-effectively apply
CCS was a significant consideration in
the EPA’s selection of proposed capacity
and utilization thresholds to determine
which existing turbines would be
covered by these proposed emission
guidelines. The EPA considered two
primary factors in evaluating an
appropriate capacity threshold. The first
is emission reduction potential. As the
capacity threshold decreases a larger
amount of the existing fleet is covered
and overall emission reduction potential
increases. For instance, at a 500 MW
threshold, only 2 percent of the capacity
and 7 percent of the emissions are
covered. The second factor the EPA
considered was capacity to build CCS.
In 2030, the EPA projects that
approximately 12 GW of coal-fired
generation will likely install CCS
(including both CCS being installed to
meet requirements of this rule and CCS
that EPA projects would occur even
without the requirements proposed
here). There are likely to also be a
number of other CCS projects for other
industries developed in the 2023
through 2030 timeframe. Multiple
industries including the ethanol
industry and the hydrogen production
sector have announced post combustion
CCS projects in response to the IRA.
The EPA believes it is reasonable to
assume therefore that by 2035 there will
be a larger capability to build CCS
retrofits than in 2030. Had the EPA
proposed capacity thresholds of 400
MW or 500 MW, they would have only
resulted in the need for a maximum of
12 GW or 6 GW of CCS capacity
respectively by 2035 for existing gas
turbines covered by this proposal,
which is less than the CCS capacity the
EPA projects in 2030 to meet the
existing coal BSER. That would likely
mean foregoing feasible, cost-effective
emissions reductions. By contrast, the
300 MW cutpoint that EPA is proposing
would require up to 37 GW of CCS in
2035. While this is approximately 3
times the amount of CCS that the EPA
is projecting for coal-fired units in 2030,
the EPA believes that 300 MW is a
reasonable threshold primarily because
593 Tommy Schmitt, Sally Homsy, National
Energy Technology Laboratory, Cost and
Performance of Retrofitting NGCC Units for Carbon
Capture—Revision 3, March 17, 2023 (DOE/NETL–
2023/3848).
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there will be significant time to deploy
the needed infrastructure, a total of
eleven years from the likely finalization
of these guidelines. In addition, it is
unlikely that all of the units that EPA
projects would be affected in 2035
would choose to install CCS; some
would likely choose to co-fire low-GHG
hydrogen.594 For these reasons, the EPA
believes that there will be adequate
capability to build enough CCS for the
existing combustion turbine EGUs
subject to a CCS BSER at a capacity
threshold of 300 MW, given the amount
of time provided.
The EPA also considered a capacity
threshold of 200 MW and of 100 MW.
According to the EPA’s projections, a
threshold of 200 MW would affect a
total of 85 GW, and a threshold of 100
MW would affect 134 GW of existing
combustion turbine capacity. While the
EPA believes that it is possible that the
industry could install that amount of
CCS on this timeline, the EPA believes
it is important to gather more
information on the question of how
quickly CCS can be deployed and is
therefore taking comment on, but not
proposing, a lower capacity threshold of
200 MW or 100 MW, and taking
comment on whether it would be
feasible to install CCS and or co-fire
hydrogen for the 85 GW or 134 GW of
units it projects would be covered under
those thresholds and a capacity factor of
greater than 50 percent.
Historical rates of emission control
technology retrofits at existing coal-fired
power plants, such as flue gas
desulfurization (FGD), indicate that
rapid deployments of such technologies
in response to regulatory requirements
have proven feasible historically in the
United States and elsewhere. FGD was
rapidly deployed in the United States in
response to various regulatory
requirements, including the 1971 NSPS
addressing SO2 emissions. Although
other compliance options were
available, FGD—a wholly new
technology—was installed on 48 GW of
coal-fired power plants between 1973
and 1984,595 while the number of
technology vendors went from 1 to
16.596 Similarly, Germany subsequently
594 Approximately 6 GW of the capacity projected
to operate at a capacity factor of greater than 50
percent in the EPA’s modeling is owned by
NextERA who has already announced intentions to
convert much of their combined cycle turbines to
co-fire increasing amounts of hydrogen.
595 Van Ewijk, S., McDowall, W. Diffusion of flue
gas desulfurization reveals barriers and
opportunities for carbon capture and storage. Nat
Commun 11, 4298, Figure 1 and Source Data (2020),
available at https://doi.org/10.1038/s41467-02018107-2.
596 Taylor, et al., Regulation as Mother of
Innovation, 27 Law & Pol’y 348, 356 (2005).
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increased its share of FGD from 10 to 79
percent in four years.597 598 It should be
noted that as FGD became a more
familiar technology, installation rates
accelerated, reaching nearly 30 GW a
year in the United States.599 A very
rapid ramp up happened after the Clean
Air Interstate Rule, for example, where
the installed capacity increased from
131 GW in 2007 to 200 GW in under
four years.600 There are many
differences between FGD and CCS, but
the history of the rapid build-out of FGD
generally supports the EPA’s view that
companies with the expertise to install
complex emission control equipment
can rapidly ramp up capacity in
response to a regulatory driver.
The EPA seeks comment on the
feasibility of setting a threshold of 100
or 200 MW and a 40 percent capacity
factor in light of these examples and
other relevant considerations. As further
described below, the EPA further
proposes that CCS with 90 percent
capture for existing combustion turbines
greater than 300 MW and operating at
more than 50 percent capacity meets the
other criteria to qualify as the BSER, for
the same reasons as it does for new
combustion turbines in the baseload
subcategory:
b. Adequately Demonstrated
Section VII.F.3.b of this preamble
includes discussion of how CCS with a
90 percent capture rate has been
adequately demonstrated and is
technically feasible based on the
demonstration of the technology at
existing coal-fired steam generating
units and industrial sources in addition
to combustion turbines. Notably, the
function, design, and operation of postcombustion CO2 capture equipment is
similar, although not identical, for both
steam generating units and combustion
turbines. As a result, application of CO2
capture at existing coal-fired steam
generating units helps show that it is
adequately demonstrated for
combustion turbines as well.
597 Van Ewijk, S., McDowall, W. Diffusion of flue
gas desulfurization reveals barriers and
opportunities for carbon capture and storage. Nat
Commun 11, 4298 (2020). https://doi.org/10.1038/
s41467-020-18107-2.
598 Similarly, in response to regulatory
requirements over 100 GW of coal-fired generation
installed selective catalytic reduction (SCR)
between 1999 and 2009, ramping from very low
levels. Healey, Scaling and Cost Dynamics of
Pollution Control Technologies, at 7, Figure 3
(2013). https://core.ac.uk/download/pdf/
44737055.pdf.
599 Markussan, Scaling up and Deployment of
FGD in the US (CCS—Releasing the Potential)
(2012) at v, 24.
600 Electric Power Annual 2015, https://
www.eia.gov/electricity/annual/archive/pdf/
03482015.pdf.
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In the retrofit context, SaskPower’s
Boundary Dam Unit 3, a 110 MW
lignite-fired unit in Saskatchewan,
Canada, has demonstrated CO2 capture
rates of 90 percent using an amine-based
post-combustion capture system
retrofitted to the existing steam
generating unit. The capture plant,
which began operation in 2014, was the
first full-scale CO2 capture system
retrofit on an existing coal-fired power
plant.601 Other references detailed in
section VII.F.3.b.iii.(A).(2) provide
additional support for the
demonstration of CO2 capture retrofits.
Moreover, section VII.F.3.b.iii.(A)(3)
of this preamble describes how CCS has
been successfully applied to a combined
cycle EGU (the Bellingham Energy
Center in south central Massachusetts)
and how several other projects are in
development. Both section
VII.F.3.b.iii.(A)(3) of this preamble and
the TSD on GHG Mitigation Measures—
Carbon Capture and Storage for
Combustion Turbines discuss several
CCS projects under development
involving retrofits to existing NGCC
units.
In addition to CO2 capture, the CO2
transport and geologic storage aspects of
CCS systems are also adequately
demonstrated, as discussed in section
VII.F.3.b and section X.D.1.a of this
preamble and in the GHG Mitigation
Measures for Steam Generating Units
TSD. Geologic sequestration potential
for CO2 is widespread and available
throughout the U.S. Nearly every State
in the U.S. has or is in close proximity
to formations with geologic
sequestration potential, including areas
offshore. These areas include deep
saline formation, unmineable coal
seams, and oil and gas reservoirs.
Additionally, the U.S. CO2 pipeline
network has steadily expanded (with
5,339 miles in operation in 2021, a 13
percent increase in CO2 pipeline miles
since 2011), and appears primed to
continue expanding, with several major
projects recently announced across the
country. Areas without reasonable
access to pipelines for geologic
sequestration can transport CO2 to
sequestration sites via other
transportation modes such as ship, road
tanker, or rail tank cars.
c. Costs
The EPA is proposing that the costs of
CCS are reasonable for existing
601 Giannaris, S., et al., Proceedings of the 15th
International Conference on Greenhouse Gas
Control Technologies (March 15–18, 2021).
SaskPower’s Boundary Dam Unit 3 Carbon Capture
Facility—The Journey to Achieving Reliability.
https://papers.ssrn.com/sol3/papers.cfm?abstract_
id=3820191.
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combustion turbines that are large and
frequently used. As further discussed in
the Regulatory Impact Analysis and the
GHG Mitigation Measures—Carbon
Capture and Storage for Combustion
Turbines TSD, the EPA’s approach
relies on cost and performance
assumptions consistent with the IPM
post-IRA 2022 reference case.602 The
EPA’s baseline shows that 7 GW of
existing natural gas combined cycle
capacity retrofits with CCS in 2030,
rising to 10 GW in 2035. The significant
deployment of CCS on combined cycle
natural gas EGUs in the absence of
emission standards reinforces the cost
reasonableness and feasibility of the
proposed standards.
Section VII.F.3.b.iii.(B) and section
X.D.1.a.ii of this preamble discuss the
cost-reasonableness of CCS technology
in the context of new combustion
turbines and existing coal-fired steam
generating units. Additionally, a March
2023 NETL report estimates that the
capital cost of CCS retrofits on
combined cycle EGUs is 9 percent
higher than for installation of CCS
equipment on new greenfield combined
cycle EGUs.603 The higher retrofit costs
account for the cost premium for design,
construction, and tie-in constraints
imposed by existing plant layout and
operation. The additional capital costs
increase the LCOE of the retrofit CCS by
an additional $2.2/MWh compared to an
installation at a new combined cycle
EGU.604 Assuming the same model
plant, a 90 percent-capture retrofit
amine-based post combustion CCS
system increases the LCOE by $8.6/
MWh and has overall CO2 abatement
costs of $26/ton ($28/metric ton).
Similar to NETL estimates for greenfield
CCS projects, costs at a specific plant
would be expected to vary somewhat
from this estimate, as it does not include
site and plant-specific considerations
such as seismic conditions, local labor
costs, or local environmental
regulations.
602 These assumptions are detailed at: https://
www.epa.gov/system/files/documents/2023-03/
Chapter%206%20-%20CO2%20
Capture%2C%20Storage%2C%20and%20
Transport.pdf.
603 Cost and Performance of Retrofitting NGCC
Units for Carbon Capture—Revision 3 (DOE/NETL–
2023/3848, March 17, 2023). https://
www.netl.doe.gov/projects/files/
CostandPerformanceofRetrofitting
NGCCUnitsforCarbonCaptureRevision3_
031723.pdf.
604 These calculations use the NETL F-Class
turbine, a service life of 12 years, an interest rate
of 7.0 percent, a natural gas price of $3.69/MMBtu,
a capacity factor of 75 percent, a transport, storage,
and monitoring cost of $10/metric ton, and a 45Q
tax credit of $85/metric ton.
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d. Non-Air Quality Health and
Environmental Impact and Energy
Requirements
As in the context of new NGCC units
and existing coal-fired steam generating
units (discussed in section
VII.F.3.b.iii.(C) and section X.D.1.a.iii of
this preamble), the EPA does not expect
the use of CCS at large, frequently used
existing combustion turbines to have
unreasonable adverse consequences
related to non-air quality health and
environmental impact or to energy
requirements.
Regarding energy requirements, upon
retrofitting an NGCC plant with CCS, a
derate in the net plant electrical output
will be incurred due to the parasitic/
auxiliary energy demand required to run
the CCS system, as well as steam
extraction from the steam cycle to
satisfy the CCS reboiler duty.605 As
discussed in the TSD on GHG Mitigation
Measures—Carbon Capture and Storage
for Combustion Turbines, a recent NETL
report has estimated that the resulting
derates for 90 percent CO2 capture
retrofits range from an 11.5 to 11.8
percent loss of net MWe.
Despite decreases in efficiency, IRC
section 45Q tax credits provide an
incentive for increased generation with
full operation of CCS because the credits
are proportional to the amount of
captured and sequestered CO2 emissions
and not to the amount of electricity
generated. The EPA is proposing that
the energy penalty is relatively minor
compared to the GHG benefits of CCS.
The EPA does not believe that
determining CCS to be BSER for large,
frequently operated combustion
turbines will cause reliability concerns.
This is because of the limited increase
in costs and energy penalty due to CCS,
coupled with the amounts of smaller or
lower capacity generation that would
not be subject to these requirements and
the projected new capacity in the base
case modeling. For the estimated 37 GW
of facilities that would face
requirements under this proposal, if
they all installed CCS retrofit the
reduction in available capacity would
be approximately 4.3 GW, or less than
1% of the total modeled available
natural gas capacity in 2035. Grid
planners, operators, and market
participants can address the potential,
marginal impact, through development
of a similarly small increment of
accredited capacity, whether from new
natural gas simple cycle turbine
605 Cost and Performance of Retrofitting NGCC
Units for Carbon Capture—Revision 3. (DOE/
NETL—2023/3848, March 17, 2023). https://
www.osti.gov/biblio/1961845.
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deployment, new energy storage, or new
sources of clean energy.
Regarding non-air quality health and
environmental impact, criteria or
hazardous air pollutant emissions
would in general be mitigated or
adequately controlled by equipment
needed to meet other CAA
requirements, and the EPA’s assessment
is that the additional cooling water
requirements from CCS at NGCC units
are reasonable, as discussed in section
VII.F.3.v.iii.(C). The EPA is committed
to working with its fellow agencies to
foster meaningful engagement with
communities and protect communities
from pollution. This can be facilitated
through the existing detailed regulatory
framework for CCS projects and further
supported through robust and
meaningful public engagement early in
the technological deployment process.
CCS projects undertaken pursuant to
these emission guidelines will, if the
EPA finalizes proposed revisions to the
CAA section 111 implementing
regulations,606 be subject to
requirements for meaningful
engagement as part of the State plan
development process. See section
XII.F.1.b of this preamble for additional
details.
lotter on DSK11XQN23PROD with PROPOSALS2
e. Extent of Reductions in CO2
Emissions
Designating CCS with 90 percent
capture as a component of the BSER for
large and frequently-operated
combustion turbines prevents large
amounts of CO2 emissions. According to
the NETL baseline report, adding a 90
percent CO2 capture system increases
the EGU’s gross heat rate by 7 percent
and the unit’s net heat rate by 13
percent. Since more fuel would be
consumed in the CCS case, the gross
and net emissions rates are reduced by
89.3 percent and 88.7 percent
respectively.
f. Promotion of the Development and
Implementation of Technology
The EPA also considered whether
determining CCS to be a component of
the BSER for existing large and
frequently operated combustion
turbines will advance the technological
development of CCS and concluded that
this factor supports our BSER
determination. Combined with the
availability of 45Q tax credits and
investments in supporting CCS
infrastructure from the IIJA, this
requirement should incentivize
additional use of CCS, which should, in
turn, incentivize cost reductions
through the development and use of
606 87
FR 79176, 79190–92 (December 23, 2022).
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better performing solvents or sorbents.
While solvent-based CO2 capture has
been adequately demonstrated at the
commercial scale, a determination of the
BSER for certain existing combustion
turbines (along with new baseload
combustion turbines and long term coalfired steam generating units) is the use
of CCS will also likely incentivize the
deployment of alternative CO2 capture
techniques at scale. Moreover, as noted
above, the cost of CCS has fallen in
recent years and is expected to continue
to fall; and further implementation of
the technology can be expected to lead
to additional cost reductions, due to
added experience and cost efficiencies
through scaling.
The EPA seeks comment on the
feasibility of setting a threshold for
inclusion in the existing combustion
turbine segment to be addressed by the
emission guidelines proposed here of
100 or 200 MW and a 40 percent
capacity factor in light of the examples
of other historic deployment of
pollution controls and other relevant
considerations. DOE recently released a
report discussing the State of carbon
management technology.607 In that
report, DOE states that with policy
support (either via regulation or
incentives) or technology premiums for
low-carbon products (e.g., low
embodied carbon steel and concrete) the
scale up of CCS technologies and
pipeline and storage infrastructure
would proceed much faster for the
power sector than will proceed absent
additional policy support or market
demand.608 In the report, DOE states
that regulatory developments, in
particular, could play a dramatic role in
accelerating the pathways described for
industries with lower-purity CO2
streams such as power plants. The
report states that absent additional
incentives, CCS technology for the
power sector is likely to significantly
scale between 2030–2040 with pilot and
demonstration technologies occurring
now. As detailed in the report, several
incentives have recently become
available or been significantly increased
that will accelerate the deployment of
CCS for the power sector. The 45Q tax
credit for CCS is a strong incentive, and
DOE is already investing heavily
through the Bipartisan Infrastructure
Law at further demonstrating lowerpurity CCS technologies such as those
used in the power sector, which will
607 DOE Carbon Management Demonstration and
Deployment Pathway, April 2023, https://
liftoff.energy.gov/
608 The Federal Buy Clean Task Force and the
First Mover’s Coalition are both seeking to provide
a clear demand signal for low embodied emissions
products.
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help to decrease costs and establish
repeatable commercial arrangements.
As the DOE report discusses, CO2
pipelines also need to be further built
out for CCS technologies to scale. CO2
pipelines are the most mature, and often
the most cost-effective CO2 transport
technology for high volumes and will
likely form the backbone of CO2
transport. PHMSA reported that 5,339
miles of CO2 pipelines were in
operation in 2021.609 Analogous
historical build out of inter- and
intrastate natural gas transmission
pipelines demonstrates that similar
levels of CO2 pipeline deployment are
feasible. Data reported by EIA indicates
that from 1997 to 2008 over 25,000
miles of natural gas transmission
pipeline was constructed, averaging
over 2,000 miles per year.610 Other
analyses indicate that the size of CO2
pipeline network necessary to capture
over 1,000 million metric tons per year
of CO2 emissions from large, frequently
operated coal and natural gas EGUs
ranges from 20,000 miles to 25,000
miles.611 This is in line with the
historical maximum deployment of
natural gas transmission pipelines, and
also does not account for any economies
of scale from pipeline systems
developed for capture from other nonpower CO2 sources.
D. Areas That the EPA Is Seeking
Comment on Related to Existing
Combustion Turbines
The EPA is seeking comment on four
general areas related to selecting the
BSER for existing combustion turbines.
First, the EPA is soliciting comment on
general assumptions about potential
future utilization of combustion
turbines. Second, the EPA is soliciting
comment on assumptions about the
appropriate group of existing
combustion turbine units to be
addressed in this rulemaking. Third, the
EPA is requesting comment on the
appropriate BSER for those turbines.
Fourth, the EPA is requesting comment
609 U.S. Department of Transportation, Pipeline
and Hazardous Material Safety Administration,
‘‘Hazardous Annual Liquid Data.’’ 2021. https://
www.phmsa.dot.gov/data-and-statistics/pipeline/
gas-distribution-gas-gathering-gas-transmissionhazardous-liquids.
610 https://www.eia.gov/naturalgas/pipelines/EIANaturalGasPipelineProjects.xlsx.
611 Middleton, Richard and Bennett, Jeffrey and
Ellett, Kevin and Ford, Michael and Johnson, Peter
and Middleton, Erin and Ogland-Hand, Jonathan
and Talsma, Carl, Reaching Zero: Pathways to
Decarbonize the US Electricity System with CCS
(August 30, 2022). Proceedings of the 16th
Greenhouse Gas Control Technologies Conference
(GHGT–16) 23–24 Oct 2022. https://ssrn.com/
abstract=4274085 or https://dx.doi.org/10.2139/
ssrn.4274085.
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on the timing of BSER requirements for
existing combustion turbines.
The EPA is seeking comment on a
number of issues related to how its
consideration of projected future
utilization of combined cycles informed
its consideration of a potential BSER for
existing combustion turbines. First, the
EPA is taking comment on its
projections of how combustion turbines
will operate in the future and the key
factors that influence those changes in
operation. While the EPA modeling
shows that there is some increase in
emissions from these units in all years
following imposition of CAA section
111 standards on existing coal-fired
steam generating units and new
stationary combustion turbines, that
increase is much smaller in the later
years. The EPA believes the magnitude
of these trends is significantly impacted
by the rate at which new low emitting
generation comes on-line, in part
incentivized by IRA and IIJA. The EPA
is taking comment on all aspects of
these assumptions including: the speed
at which new low-emitting generation
will come on-line and the impact that it
has on likely capacity factors for
combined cycle units (in particular the
projection that capacity factors will
grow in the 2028/30 timeframe but
decrease in later years).
With regard to the size and definition
of the category to be covered in a first
rulemaking covering only part of the
existing turbine category, the EPA is
also taking comment on how its
assumptions about the potential
operation of combustion turbines in
future years coupled with
considerations about the availability of
infrastructure should inform which
units should be covered in a first
rulemaking. More specifically, the EPA
is requesting comment on how to
consider the rate of CCS (and potentially
hydrogen) infrastructure development
in determining a BSER that could
potentially impact hundreds of sources.
If, for instance, increased renewable
generation and storage capacity were to
lead to a smaller number of units
operating at capacity factors of greater
than 50 percent, the proposed BSER
would not affect as many units and a
smaller size threshold might be possible
without expanding the amount of
infrastructure needed. Conversely, if
more units were likely to operate at a
higher capacity factor, a higher capacity
threshold might be appropriate. If the
number of units likely to be covered by
a 50 percent threshold were sufficiently
small, it might be reasonable to include
units in the intermediate category (e.g.,
units with capacity factors of between
20 percent and 50 percent) in a first
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rulemaking addressing the existing
fossil fuel-fired turbine category. The
EPA is also taking comment on a lower
capacity factor threshold (e.g., 40
percent) and a lower capacity threshold
(200 MW or 100 MW, and capacities
between 100 and 300 MW). With
regards to units with a capacity factor of
greater than 50 percent that are under
300 MW and units with a capacity factor
of 50 percent or less the EPA is taking
comment on the appropriateness of CCS
and/or hydrogen as a BSER. With
regards to hydrogen, the EPA is taking
comment on the appropriate level of
and timing for hydrogen co-firing. More
generally, EPA is requesting comment
on any feasibility issues related to
broader CCS deployment should those
thresholds be adjusted such that more
coal capacity is affected, and how such
issues could be addressed.
With regards to the BSER itself, the
EPA is soliciting comment on the
applicability of CCS retrofits to existing
combustion turbines and its focus on
base load turbines (e.g., those with a
capacity factor of greater than 50
percent). This solicitation includes
comment on whether particular plants
would be unable to retrofit CCS,
including details of the circumstances
that might make retrofitting with CCS
unreasonable or infeasible.
The EPA is also taking comment on
the role of low-GHG hydrogen as part of
BSER. More specifically, the EPA is
requesting comment on the
appropriateness of low-GHG hydrogen
as a BSER for combustion turbines
larger than 300 MW with capacity
factors of greater than 50 percent. While,
as has been noted earlier in this section,
a number of turbines already exist or are
under construction that owners of
combustion turbines have indicated
may burn large amounts of hydrogen in
a base load mode, the EPA is also aware
that other proponents of low-GHG
hydrogen use in turbines focus on it
primarily as an energy storage device,
storing renewable energy to provide
electricity in times where renewable
energy was not available. The EPA is
interested in the question of whether, in
this case, it would be likely that a
combined cycle turbine burning lowGHG hydrogen would operate near base
load, and whether it be prudent to have
an alternative BSER or an alternative
compliance pathway for units
combusting low-GHG hydrogen and
solicits comments on these questions.
Similar to the NSPS for base load
combustion turbines, the EPA is also
taking comment on whether to finalize
both the proposed low-GHG hydrogen
BSER and the proposed CCS with 90
percent capture BSER, or finalize a
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BSER with a single pathway, such as
based on application of CCS with 90
percent capture, which could also be
met by co-firing with low-GHG
hydrogen.
With regard to the timing for BSER,
the EPA is taking comment on a 2035
CCS based BSER standard and whether
that standard could reasonably be
applied earlier. Similarly, the EPA is
taking comment on the timing of a lowGHG hydrogen based BSER and whether
a 30 percent low-GHG hydrogen
standard could be implemented earlier
than 2032, or if low-GHG hydrogen
supply infrastructure development
suggests it should be later. The EPA is
taking comment on the same questions
with regard to a 96 percent low-GHG
hydrogen co-firing BSER in 2038.
E. BSER for Remaining Combustion
Turbines
While the EPA believes that emission
guidelines for units covered in the first
rulemaking, proposed above, can
achieve important emission reductions
from the most frequently operating
combustion turbines, the EPA believes
that limits to infrastructure and
capability to build carbon capture
systems or co-fire large amounts of
hydrogen caution against a first
rulemaking addressing emissions from
existing turbines covering all
combustion turbines. In this section, the
EPA discusses how developing a BSER
for units in a second rulemaking could
address units that do not meet the
applicability requirements for the first
rulemaking.
As noted above, the EPA is taking
comment on what units should be part
of whatever action the EPA finalizes as
a result of the proposal. Based on the
units that the EPA has proposed be
included, units that might remain
uncovered include smaller baseload
units (e.g., those less than or equal to
300 MW) and all units operating less
than or equal to a capacity factor of 50
percent. Particularly for the remainder
of the baseload units, the EPA is
interested in whether any other units
should have a BSER based on CCS. The
EPA is also interested in the timing of
such a requirement recognizing the
tensions between an earlier requirement
that would both achieve earlier
reductions and the need to allow time
for infrastructure to develop to support
growing amounts of CCS.
For intermediate turbines, the EPA is
taking comment on a BSER similar to
that for new turbines. In particular, the
EPA is interested in comment about an
appropriate pathway and timing for a
BSER that would ultimately require 96
percent low-GHG hydrogen by volume.
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Finally, for peaking turbines, the EPA is
interested in comment about whether a
clean hydrogen BSER would be
appropriate, what the timing of such a
requirement should be and whether
there should be any phasing.
The EPA is also interested in any
comments related to: potential changes
in operational patterns for turbines,
particularly as more renewables and
storage enter the grid. For instance, the
EPA is interested in comments as to
whether improvements in energy
storage will reduce reliance on
intermediate and peaking turbines. The
EPA is also interested in comments on
any potential technology developments
that could impact its determination of
BSER. For instance, the EPA is aware
that in addition to electrolyzer based
hydrogen and natural gas based
hydrogen, there are other means of
hydrogen production receiving
significant attention such as naturally
occurring hydrogen, and solicits
comments on whether any of these
potential technology developments
should impact the EPA’s consideration
of the appropriate BSER for the
remaining turbines.
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XII. State Plans for Proposed Emission
Guidelines for Existing Fossil FuelFired EGUs
A. Overview
State plan submissions under these
emission guidelines are governed by the
requirements of 40 CFR part 60, subpart
Ba (subpart Ba).612 The EPA proposed to
revise certain aspects of 40 CFR part 60,
subpart Ba, in its December 2022
proposal, ‘‘Adoption and Submittal of
State Plans for Designated Facilities:
Implementing Regulations Under Clean
Air Act Section 111(d)’’ (proposed
subpart Ba).613 The Agency intends to
finalize revisions to 40 CFR part 60,
subpart Ba, before promulgating these
emission guidelines. Therefore, State
plan development and State plan
submissions under these proposed
emission guidelines would be subject to
the requirements of subpart Ba as
revised in that future final action,
including any changes the EPA makes to
the proposal in response to public
comments. To the extent the EPA is
proposing to add to, supersede, or
otherwise vary the requirements of
subpart Ba for the purposes of these
particular emission guidelines, those
proposals are explicitly addressed in
this section of the preamble. Unless
612 40
CFR 60.20a–60.29a.
87 FR 79176 (December 23, 2022); see also
id., Docket ID No. EPA–HQ–OAR–2021–0527–0002
(memorandum to docket containing proposed
revisions to 40 CFR part 60, subpart Ba).
613 See
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expressly amended or superseded in
these proposed emission guidelines, the
provisions of subpart Ba, as revised by
the EPA’s forthcoming final rule, would
apply.
This section provides information on
several aspects of State plan
development, including compliance
deadlines, a presumptive methodology
for establishing standards of
performance for affected EGUs,
compliance flexibilities, and State plan
components and submission. In sections
X and XI of this preamble, the EPA is
soliciting comment on ranges for dates
and values for defining subcategories,
BSER, and degrees of emission
limitation; those solicitations for
comment extend to the proposed values
and dates discussed in this section of
the preamble. In section XII.B, the EPA
proposes and explains its reasoning for
compliance deadlines for affected steam
generating units and affected
combustion turbines. In section XII.C,
the EPA describes its requirement that
State plans achieve equivalent
stringency to the EPA’s BSER. Section
XII.D proposes a presumptive
methodology for calculating the
standards of performance for affected
EGUs based on subcategory as well as
requirements related to invoking
RULOF to apply a less stringent
standard of performance than results
from the EPA’s presumptive
methodology. Section XII.D also
describes proposed requirements for
increments of progress for affected EGUs
in certain subcategories and milestones
for affected EGUs, as well as testing and
monitoring requirements. In section
XII.E, the EPA proposes that States
would be permitted to include trading
and averaging as compliance measures
for affected EGUs in their State plans, so
long as plans demonstrate equivalence
to the stringency that would result if
each affected EGU was individually
achieving its standard of performance.
Finally, section XII.F describes what
must be included in State plans,
including plan components specific to
these emission guidelines and
requirements for conducting meaningful
engagement.
In this section of the preamble, the
term ‘‘affected EGU’’ means any existing
fossil fuel-fired steam generating unit or
existing fossil fuel-fired combustion
turbine EGU that meets the applicability
criteria described in sections X and XI
of this preamble. Affected EGUs would
be covered by the proposed emission
guidelines under 40 CFR part 60 subpart
UUUUb.
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B. Compliance Deadlines
The EPA is proposing a compliance
date of January 1, 2030, for affected
steam generating units. The proposed
compliance date for the CCS
combustion turbine subcategory is
January 1, 2035. The proposed
compliance dates for the first phase and
second phase for the affected hydrogen
co-fired combustion turbine subcategory
are January 1, 2032, and January 1,
2038, respectively. This means that
starting on the applicable compliance
date, affected EGUs would be subject to
standards of performance and other
State plan requirements under these
emission guidelines and would be
required to start demonstrating
compliance with those requirements.
The EPA is proposing that January 1,
2030, is the soonest that affected steam
generating units could reasonably
commence compliance with standards
of performance given the proposed State
plan submission timeline (24 months;
see section XII.F.2 of this preamble) and
the amount of time affected EGUs in the
long-term and medium-term coal-fired
steam generating unit subcategories will
need to install CCS or natural gas cofiring, respectively. For consistency, the
EPA is also proposing a January 1, 2030,
compliance date for imminent- and
near-term coal-fired units as well as the
different subcategories of natural gasand oil-fired steam generating units.
However, the EPA recognizes that the
BSERs for some subcategories of
affected steam-generating EGUs are
routine methods of operation and
maintenance, which do not require the
installation of any or significant control
equipment and can thus be applied
earlier.614 Therefore, the EPA is
soliciting comment on compliance dates
defined by the date of approval of the
State plan or January 1, 2030, whichever
is earlier, for imminent-term coal-fired
steam generating units, near-term coalfired steam generating units, and the
different subcategories of natural gasand oil-fired steam generating units.
The proposed compliance timeframe
for affected steam-generating EGUs in
these proposed emission guidelines is
based on the amount of time the EPA
believes is needed to comply with
standards of performance based on
implementation of natural gas co-firing
or CCS. Each of these systems would
require several years to plan, permit,
and construct. However, as explained
further in section XII.F.2 of this
preamble, the EPA is proposing to
614 The EPA is also taking comment in section
X.D.3.b.ii on potential BSER options for imminentand near-term affected coal-fired steam generating
units based on low levels of natural gas co-firing.
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adjust the State plan submission
deadline so that certain necessary
planning and design steps for natural
gas co-firing or CCS implementation can
take place as part of the State plan
development process. That is, we expect
that some of the planning and design
steps described below would take place
prior to State plan submission. The EPA
believes that coordinating State plan
development, submission, and
implementation in this manner reflects
how the owners/operators of affected
EGUs and States would actually
undertake the steps leading to ultimate
deployment of a control technology and
compliance with a standard of
performance.
The GHG Mitigation Measures for
Steam Generating Units TSD discusses
the timeframes for implementation of
natural gas co-firing and CCS at existing
coal-fired steam generating EGUs. Based
on this analysis, it is clear that the time
needed to design and implement CCS is
an important aspect for setting a
compliance date under these emission
guidelines. CCS projects will include
planning, design, and construction of
both the carbon capture system and the
transport and storage system; the EPA
believes that all of these steps can be
completed within roughly 5 years.615
Deployment of a carbon capture
system starts with a technical and
economic feasibility evaluation,
including a Front End Engineering
Design (FEED) study. The owner/
operator of an affected EGU would then
proceed to making technical and
commercial arrangements, including
arranging project financing and
permitting. These initial steps do not
need to be undertaken sequentially and
may be completed in 3 years or less. As
noted above, the EPA also believes that
at least some of these project design and
development steps, including feasibility
evaluations and FEED studies, can and
will be completed prior to State plan
submission. The EPA believes that the
commencement of CCS project
implementation activities, including
more detailed engineering work and
procurement, construction of the carbon
capture system, and startup and testing,
will overlap with the final steps of the
initial project design and development
phase. These project implementation
steps take approximately 3 years to
complete.
In addition to planning and
implementing a carbon capture system,
the owners/operators of affected EGUs
615 GHG Mitigation Measures for Steam
Generating Units TSD, chapter 4.7.1. See Table 5 in
chapter 4.7.1 for visual representation of the CCS
and co-firing project timelines described in this
section.
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will also have to design and construct
a system for transporting and storing
captured CO2. The necessary steps for
implementing transport and storage of
captured CO2 can be undertaken
simultaneously with development of the
CO2 capture system, and some of the
steps necessary for transport and storage
can additionally overlap with each
other. The EPA thus believes design and
implementation of CO2 transport and
storage can be completed within 5 years.
The EPA believes that the initial
phases of planning and design for CO2
transport and storage, including site
characterization and pipeline feasibility
and design activities, can and will occur
prior to State plan submission, i.e., as
part of the State plan development
process. First, the owner/operator of an
affected EGU would undertake a
feasibility analysis associated with CO2
transport and storage, as well as site
characterization and permitting of
potential storage areas. These steps can
overlap with each other and the EPA
anticipates that, in total, feasibility
analyses, site characterization, and
permitting of potential storage areas will
take 2–3 years to complete. The EPA
believes there is significant opportunity
to overlap the design and planning
phase for CO2 transport and storage with
the engineering and construction phase
for transport and storage, which is
anticipated to take 2–3 years. Based on
the potential to conduct many of the
design, planning, permitting,
engineering, and construction steps, the
EPA thus believes that affected EGUs
will need approximately 5 years, from
start to finish, to be ready to implement
CO2 transport and storage.
The EPA expects that implementation
of natural gas co-firing projects for
affected coal-fired steam-generating
EGUs, including any necessary
construction of natural gas pipelines,
can be completed in approximately 3.5
years. As discussed in the GHG
Mitigation Measures for Steam
Generating Units TSD,616 any necessary
boiler modifications to accommodate
natural gas co-firing can be completed
within 3 years. The process of planning,
permitting, and construction for boiler
modifications can occur simultaneously
with the steps that owners/operators of
affected EGUs would need to undertake
if construction of a new natural gas
pipeline is needed. The time required to
develop and construct natural gas
laterals can be broken into three phases:
planning and design; permitting and
approval; and construction. It is
616 GHG Mitigation Measures for Steam
Generating Units TSD, chapters 3.2.1.4, 3.2.2.3, and
4.7.1.
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reasonable to assume that the planning
and design phase can typically be
completed in a matter of months and
will often be finalized in less than a
year. The time required to complete the
permitting and approval phase can vary.
Based on a review of recent FERC data,
the average time for pipeline projects
similar in scope to the projects
considered in this TSD is about 1.5
years and would likely not exceed 4
years. The EPA notes that these data
may not reflect that pipeline projects
may be completed more expeditiously
in the presence of a regulatory deadline.
Finally, the actual construction could
likely be completed in less than 1 year.
Based on a sum of these estimates, the
EPA believes that 3.5 years is a
reasonable timeframe for pipeline
projects.
The EPA expects that final emission
guidelines will be published in June
2024 and is proposing a State plan
submission deadline that is 24 months
from publication, which would be June
2026. The proposed compliance date for
affected steam generating units is
January 1, 2030. The EPA requests
comment on whether using a period of
3.5 years after State plan submission is
appropriate for establishing a
compliance deadline for these emission
guidelines. As explained above, the EPA
is basing this proposed timeframe on the
expectation that some of the initial
evaluation and planning steps for both
natural gas co-firing and CCS would
take place as part of State plan
development, i.e., before the State plan
submission deadline. The EPA is also
requesting comment on potential
compliance dates between 1.5 and 5.5
years after State plan submission (i.e.,
January 1, 2028, to January 1, 2032),
including on the feasibility of
completing all the steps to implement
natural gas co-firing and CCS within a
shorter or longer timeframe. To the
extent that commenters believe more or
less time after State plan submission is
more appropriate than the proposed 3.5
years, the EPA requests that commenters
provide information supporting the
provision of a different compliance date.
Additionally, the proposed State plan
submission date and proposed
compliance date are based on the EPA’s
anticipation that it will publish final
emission guidelines for affected EGUs in
June 2024. Should the actual date of
publication of the final emission
guidelines differ from this target, the
EPA will adjust the State plan
submission and compliance dates
accordingly.
As discussed in section XI.C of this
preamble, the EPA is proposing to
subcategorize affected existing,
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frequently used combustion turbines
that are covered under these emission
guidelines into two subcategories: one
subcategory for affected combustion
turbine EGUs that adopt the pathway
with a standard of performance based
on CCS, referred to as the ‘‘CCS
subcategory’’ and one subcategory for
affected combustion turbine EGUs that
adopt the pathway with a standard of
performance based on hydrogen cofiring, referred to as the ‘‘hydrogen cofired subcategory.’’ For affected
combustion turbines in the CCS
subcategory, the EPA is proposing a
compliance date of January 1, 2035,
which is the soonest the Agency
believes these sources can comply with
standards of performance based on
installation and operation of CCS, given
the timeframes for planning and
construction of carbon capture and CO2
transport and storage systems along
with other demands on the
infrastructure and resources needed to
implement CCS throughout the power
sector and the broader economy. For
affected combustion turbines in the
hydrogen co-fired subcategory, the EPA
is proposing a two-phase standard of
performance, with a proposed
compliance date for the first phase of
January 1, 2032, and for the second
phase of January 1, 2038.
For combustion turbine EGUs in the
CCS subcategory, the same timeframes
and considerations discussed for the
planning and construction of CCS for
affected coal-fired steam generating
units apply. That is, the EPA expects
that the owners or operators of affected
combustion turbines will be able to
complete the design, planning,
permitting, engineering, and
construction steps for the carbon
capture and transport and storage
systems within 5 years. As with affected
coal-fired steam generating units, the
EPA believes that States and owners or
operators can and would take several of
the initial steps in the design and
planning processes for combustion
turbine EGUs as part of State plan
development, i.e., prior to the proposed
State plan submission deadline in
approximately June 2026.
However, as noted in section XI.C of
this preamble, the EPA is projecting
approximately 12 GW of coal-fired
generation will likely retrofit with CCS
in order to meet the proposed January
1, 2030, compliance date for affected
long-term coal-fired steam generating
units. These and other CCS projects that
are likely to be occurring in response to
the IRA may take up a significant
amount of the capacity to plan and
build CCS between 2023 and 2030. The
EPA anticipates that additional pipeline
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capacity will be constructed ahead of
January 1, 2030, for CO2 transport as
well as for natural gas pipeline laterals
that may be needed for affected coalfired steam generating units that will cofire with natural gas as a control
strategy. Due to these and other
overlapping demands on the capacity to
design, construct, and operate carbon
systems as well as pipeline systems, the
EPA is proposing to find that a January
1, 2030, compliance date for affected
combustion turbine EGUs in the CCS
subcategory, although feasible for an
individual unit, would not be the most
reasonable deadline for all of the units
that would need to install CCS.
Therefore, the EPA is proposing to
provide a compliance date for affected
combustion turbine EGUs in the CCS
subcategory that is 5 years after the
compliance date for long-term coal-fired
steam generating units, or January 1,
2035. The EPA requests comment on its
proposed compliance deadline for
combustion turbine EGUs in the CCS
subcategory, including on whether an
earlier or later compliance date would
be more reasonable given the time
needed to analyze, design, and construct
carbon capture and CO2 transport and
storage systems and the overlapping
timeframes for installation of CCS on
EGUs under the proposed CAA section
111(b) standards of performance for new
combustion turbines and on existing
coal-fired steam generating units under
these proposed emission guidelines.
For affected combustion turbine EGUs
in the hydrogen co-fired subcategory,
the EPA is proposing a compliance
deadline for the first phase of January 1,
2032. As discussed in sections
VII.F.3.c.v and vi of this preamble,
currently the vast majority of hydrogen
is not low-GHG hydrogen. Midstream
infrastructure limitations and the
adequacy and availability of hydrogen
storage facilities currently present
obstacles and increase prices for
delivered low-GHG hydrogen. However,
given the growth in the hydrogen sector
and Federal funding for DOE’s H2Hubs,
which will explicitly explore and
incentivize hydrogen distribution, the
EPA believes hydrogen distribution and
storage infrastructure will not present a
barrier to access for new combustion
turbines opting to co-fire 30 percent
hydrogen by volume in 2032. Legislative
actions including the IIJA and IRA,
utility initiatives, and industrial sector
production and infrastructure projects
indicate that sufficient low-GHG
hydrogen and sufficient distribution
infrastructure can reasonably be
expected to be available by this time. On
this basis, the EPA is proposing that
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compliance with the first phase of the
standard, which is based on an affected
EGU co-firing 30 percent (by volume)
low-GHG hydrogen, will commence on
January 1, 2032.
The proposed compliance date of
January 1, 2038, for the second phase of
the standard of performance for
combustion turbine EGUs in the
hydrogen co-fired subcategory, which is
based on a proposed BSER of 96 percent
(by volume) co-firing low-GHG
hydrogen, is also based on an
assessment of when sufficient quantities
of such hydrogen will be available, as
well as when turbine vendors are
anticipated to have the equipment
necessary for higher percentages of
hydrogen co-firing available. As
discussed in section VII.F.3 of this
preamble, the EPA expects that based on
technology advances, growing demand
for low-GHG hydrogen, and the
hydrogen production tax credits
available under IRC 45V(b)(2), there will
be continued expansion of the hydrogen
production and transmission network
between 2032 and 2038. The EPA also
notes that, based on the current ages of
the existing combustion turbine fleet,
the number of units that would be
expected to meet their standards of
performance in 2038 by co-firing 96
percent hydrogen (by volume) is likely
to decline. Therefore, the EPA believes
it is reasonable to expect that there will
be sufficient low-GHG hydrogen in 2038
to provide the quantities needed for
both new and affected existing
combustion turbines in the hydrogen cofired subcategory to meet their
applicable standards of performance.
The EPA requests comment on this
assessment, as well as on whether
compliance dates other that January 1,
2032, and January 1, 2038, would be
more reasonable for the first and second
phases of the standards for affected
units in the hydrogen co-fired
subcategory, and why.
C. Requirement for State Plans To
Maintain Stringency of the EPA’s BSER
Determination
As explained in section V.C of this
preamble, CAA section 111(d)(1)
requires the EPA to establish
requirements for State plans that, in
turn, must include standards of
performance for existing sources. Under
CAA section 111(a)(1), a standard of
performance is ‘‘a standard for
emissions of air pollutants which
reflects the degree of emission
limitation achievable through the
application of the best system of
emission reduction which . . . the
Administrator determines has been
adequately demonstrated.’’ That is, the
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EPA has the responsibility to determine
the best system of emission reduction
for a given category or subcategory of
sources and to determine the degree of
emission limitation achievable through
application of the BSER to affected
sources.617 The level of emission
performance required under CAA
section 111 is reflected in the EPA’s
presumptive standards of performance.
States use the EPA’s presumptive
standards of performance as the basis
for establishing requirements for
affected sources in their State plans. In
order for the EPA to find a State plan
‘‘satisfactory,’’ that plan must address
each affected source within the State
and achieve the level of emission
performance that would result if each
affected source was achieving its
presumptive standard of performance,
after accounting for any application of
RULOF.618 That is, while States have
the discretion to establish the applicable
standards of performance for affected
sources in their State plans, the
structure and purpose of CAA section
111 require that those plans achieve
equivalent stringency as applying the
EPA’s presumptive standards of
performance to each of those sources
(again, after accounting for any
application of RULOF).
The EPA’s December 2022 proposed
revisions to the CAA section 111
implementing regulations (40 CFR part
60, subpart Ba) would provide that
States are permitted, in appropriate
circumstances, to adopt compliance
measures that allow their sources to
meet their standards of performance in
the aggregate.619 As with the
establishment of standards of
performance for affected sources, CAA
section 111 requires that State plans that
include such flexibilities for complying
with standards of performance
demonstrate equivalent stringency as
would be achieved if each affected
617 See, e.g., West Virginia v. EPA, 142 S. Ct.
2587, 2607 (2022) (‘‘In devising emissions limits for
power plants, EPA first ‘determines’ the ‘best
system of emission reduction’ that—taking into
account cost, health, and other factors—it finds ‘has
been adequately demonstrated.’ The Agency then
quantifies ‘the degree of emission limitation
achievable’ if that best system were applied to the
covered source.’’) (internal citations omitted).
618 As explained in section XI.D.2 of this
preamble, States may invoke RULOF to apply a less
stringent standard of performance to a particular
affected EGU when the state demonstrates that the
EGU cannot reasonably apply the BSER to achieve
the degree of emission limitation determined by the
EPA. In this case, the state plan may not necessarily
achieve the same stringency as each source
achieving the EPA’s presumptive standards of
performance because affected EGUs for which
RULOF has been invoked would have standards of
performance less stringent than the EPA’s
presumptive standards.
619 87 FR 79176, 79207–08 (December 23, 2015).
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source was achieving its standard of
performance.
The requirement that State plans
achieve equivalent stringency to the
EPA’s BSER and degree of emission
limitation is borne out of the structure
and purpose of CAA section 111, which
is to mitigate air pollution that is
reasonably anticipated to endanger
public health or welfare. It achieves this
purpose by requiring source categories
that cause or contribute to dangerous air
pollution to operate more cleanly.
Unlike the Clean Air Act’s NAAQSbased programs, section 111 is not
designed to reach a level of emissions
that has been deemed ‘‘safe’’ or
‘‘acceptable’’; there is no air-quality
target that tells States and sources when
emissions have been reduced ‘‘enough.’’
Rather, CAA section 111 requires
affected sources to reduce their
emissions to the level that the EPA has
determined is achievable through
application of the best system of
emission reduction, i.e., to achieve
emission reductions consistent with the
applicable presumptive standard of
performance. Consistent with the
statutory purpose of requiring affected
sources to operate more cleanly, the
EPA typically expresses presumptive
standards of performance as rate-based
emission limitations.
In the course of complying with a
rate-based standard of performance
under a State plan, an affected source
may take an action that removes it from
the source category, e.g., by
permanently ceasing operations. In this
case, the source is no longer subject to
the emission guidelines. An affected
source may also choose to change its
operating characteristics in a way that
impacts its overall emissions, e.g., by
changing its utilization; however, the
source is still required to meet its ratebased standard. In either instance, the
changes to one affected source do not
implicate the obligations of other
affected sources. Although such changes
may reduce emissions from the source
category, they do not absolve the
remaining affected EGUs from the
statutory obligation to improve their
emission performance consistent with
the level that the EPA has determined
is achievable through application of the
BSER. This fundamental statutory
requirement applies regardless of
whether a standard of performance is
expressed or implemented as a rate- or
mass-based emission limitation, or
whether standards of performance are
achieved on a source-specific or
aggregate basis.
In sum, consistent with the respective
roles of the EPA and States under CAA
section 111, States have discretion to
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establish standards of performance for
affected sources in their State plans, and
to provide flexibilities for affected
sources to use in complying with those
standards. However, State plans must
demonstrate that they ultimately
provide for equivalent stringency as
would be achieved if each affected
source was achieving the applicable
presumptive standard of performance,
after accounting for any application of
RULOF.
D. Establishing Standards of
Performance
CAA section 111(d)(1)(A) provides
that ‘‘each State shall submit to the
Administrator a plan which establishes
standards of performance for any
existing source’’; that plan must also
‘‘provide[ ] for the implementation and
enforcement of such standards of
performance.’’ That is, States must use
the BSER and stringency in the EPA’s
emission guidelines to establish
standards of performance for each
existing affected EGU through a State
plan.
To assist States in developing State
plans that achieve the level of
stringency required by the statute, it has
been the EPA’s longstanding practice to
provide presumptively approvable
standards of performance or a
methodology for establishing such
standards. For the purpose of these
emission guidelines, the EPA is
proposing a methodology for States to
use in establishing presumptively
approvable standards of performance for
affected existing EGUs. Per CAA section
111(a)(1), the basis of this methodology
is the degree of emission limitation the
EPA has determined is achievable
through application of the BSER to each
subcategory. The EPA anticipates and
intends for most States to apply the
presumptive standards of performance
to affected EGUs.
Additionally, CAA section
111(d)(1)(B) permits States to take into
consideration a particular affected
EGU’s RULOF when applying a
standard of performance to that source.
The EPA’s proposed revisions to the
CAA section 111 implementing
regulations at 40 CFR part 60, subpart
Ba provide that a State would be able to
apply a less stringent standard of
performance to an affected EGU when
the State can demonstrate that the
source cannot reasonably apply the
BSER to achieve the degree of emission
limitation determined by the EPA.
Proposed subpart Ba describes the
conditions that would warrant
application of a less stringent RULOF
standard under these emission
guidelines and how a RULOF standard
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would be determined. Further detail
about how the EPA proposes to
implement the RULOF provision in the
context of this rulemaking is provided
in section XII.D.2 of this preamble.
States also have the authority to apply
standards of performance to affected
EGUs that are more stringent than the
EPA’s presumptively approvable
standards of performance.620
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1. Application of Presumptive
Standards
This section of the preamble describes
the EPA’s approach to providing
presumptive standards of performance
for each of the subcategories of affected
EGUs under these emission guidelines,
including establishing baseline emission
performance. Under this proposal, each
subcategory with a proposed BSER and
degree of emission limitation would
have a corresponding methodology for
establishing presumptively approvable
standards of performance (also referred
to as ‘‘presumptive standards of
performance’’ or ‘‘presumptive
standards’’).
A State, when establishing standards
of performance for affected EGUs in its
plan, would identify each affected EGU
in the State and specify into which
subcategory each EGU falls. The EPA is
proposing that the State would then use
the corresponding methodology for the
given subcategory to calculate and apply
the presumptively approvable standard
of performance for each affected EGU.
States also have the authority to
deviate from the methodology for
presumptively approvable standards, in
order to apply a more stringent standard
of performance through increasing the
degree of emission limitation beyond
what the EPA has determined to be
achievable for units as a general matter
(e.g., a State decides that an EGU in the
medium-term coal-fired subcategory
should co-fire 50 percent natural gas
instead of 40 percent). Deviations to
increase stringency do not trigger use of
the RULOF mechanism, which requires
States to demonstrate that an affected
EGU cannot reasonably apply the BSER
to achieve the degree of emission
limitation determination by the EPA.621
The EPA proposes to presume that
standards of performance that are more
stringent than the EPA’s presumptive
standards are ‘‘satisfactory’’ for the
purposes of CAA section 111(d).
620 40 CFR 60.24a(f). The EPA has proposed to
revise this provision to clarify that it has the
obligation and authority to review and approve
state plans that contain the more stringent
requirements. 87 FR 79176, 79204 (December 23,
2022).
621 87 FR 79176, 79199 (December 23, 2022).
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a. Establishing Baseline Emission
Performance for Presumptive Standards
For each subcategory, the proposed
methodology to calculate a standard of
performance entails establishing a
baseline of CO2 emissions and
corresponding electricity generation for
an affected EGU and then applying the
degree of emission limitation achievable
through the application of the BSER (as
established in section X.D and XI.C of
this preamble). The methodology for
establishing baseline emission
performance for an affected EGU is
identical in each of the subcategories
but will result in a value that is unique
to each affected EGU. To establish
baseline emission performance for an
affected EGU, the EPA is proposing that
a State will use the CO2 mass emissions
and corresponding electricity generation
data for a given affected EGU from any
continuous 8-quarter period from 40
CFR part 75 reporting within the 5 years
immediately prior to the date the final
rule is published in the Federal
Register. This proposed period is based
on the NSR program’s definition of
‘‘baseline actual emissions’’ for existing
electric steam generating units. See 40
CFR 52.21(b)(48)(i). Eight quarters of 40
CFR part 75 data corresponds to a 2-year
period, but the EPA is proposing 8
quarters of data as that corresponds to
quarterly reporting according to 40 CFR
part 75. Functionally, the EPA expects
States to utilize the most representative
8-quarter period of data from the 5 years
immediately preceding the date the final
rule is published in the Federal
Register. For the 8 quarters of data, the
EPA is proposing that a State would
divide the total CO2 emissions (in the
form of pounds) over that continuous
time period by the total gross electricity
generation (in the form of MWh) over
that same time period to calculate
baseline CO2 emission performance in
lb CO2 per MWh. As an example, a State
establishing baseline emission
performance in the year 2023 would
start by evaluating the CO2 emissions
and electricity generation data for each
of its affected EGUs for 2018 through
2022 and choosing, for each affected
EGU, a continuous 8-quarter period that
it deems to be the best representation of
the operation of that affected EGU.
While the EPA will evaluate the choice
of baseline periods chosen by States
when reviewing State plan submissions,
the EPA intends to defer to a State’s
reasonable exercise of discretion as to
which 8-quarter period is
representative.
The EPA is proposing to require the
use of 8 quarters during the 5-year
period prior to the date the final rule is
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published in the Federal Register as the
relevant period for the baseline
methodology for a few reasons. First,
each affected EGU has unique
operational characteristics that affect the
emission performance of the EGU (load,
geographic location, hours of operation,
coal rank, unit size, etc.), and the EPA
believes each affected EGU’s emission
performance baseline should be
representative of the source-specific
conditions of the affected EGU and how
it has typically operated. Additionally,
allowing a State to choose (likely in
consultation with the owners or
operators of affected EGUs) the 8-quarter
period for assessing baseline
performance can avoid situations in
which a prolonged period of atypical
operating conditions would otherwise
skew the emissions baseline. Relatedly,
the EPA believes that by using total
mass CO2 emissions and total electric
generation for an affected EGU over an
8-quarter period, any relatively shortterm variability of data due to seasonal
operations or periods of startup and
shutdown, or other anomalous
conditions, will be averaged into the
calculated level of baseline emission
performance. The baseline-setting
approach of using total CO2 mass
emissions and total electric generation
over an 8-quarter period also aligns with
the reporting and compliance
requirements. The EPA is proposing that
compliance would be demonstrated
annually based on the lb CO2/MWh
emission rate derived by dividing the
total reported CO2 mass emissions by
the total reported electric generation for
an affected EGU during the compliance
year, which is consistent with the
expression of the degree of emission
limitation proposed for each
subcategory in sections X.D.4, X.E.2,
and XI.C. The EPA believes that using
total mass CO2 emissions and total
electric generation provides a simple
and streamlined approach for
calculating baseline emission
performance without the need to sort
and filter non-representative data; any
minor amount of non-representative
data will be subsumed and accounted
for through implicit averaging over the
course of the 8-quarter period.
Moreover, this approach, by not sorting
or filtering the data, eliminates any need
for discretion in assessing whether the
data is appropriate to use.
The EPA is soliciting comment on the
proposed baseline-setting approach and
specifically on the applicability of such
an approach for each of the different
subcategories. The EPA is proposing a
continuous 8-quarter period to better
average out operating variability but
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solicits comment on whether a different
time period would be more appropriate
for assessing baseline emission
performance, as well as on the 5-year
window from which the period for
baseline emission performance is
chosen. The EPA also solicits comment
on the use of total mass CO2 emissions
and total electric generation over a
consecutive 8-quarter time period as
representative and on whether the
EPA’s proposed approach is
appropriate.
The EPA believes that using the
proposed baseline-setting approach as
the basis for establishing presumptively
approvable standards of performance
will provide certainty for States, as well
as transparency and a streamlined
process for State plan development.
While this approach is specifically
designed to be flexible enough to
accommodate unit-specific
circumstances, States retain the ability
to deviate from the methodologies the
EPA is proposing for establishing
baselines of emission performance for
affected EGUs. The EPA believes that
the instances in which a State may need
to use an alternate baseline-setting
methodology will be limited to
anticipated changes in operation, i.e.,
circumstances in which historical
emission performance is not
representative of future emission
performance. The EPA is proposing that
States wishing to vary the baseline
calculation for an affected EGU based on
anticipated changes in operation, when
those changes result in a less stringent
standard of performance, must use the
RULOF mechanism, which is designed
to address such contingencies.
b. Presumptive Standards for Steam
Generating Units
As described in section X.C of this
preamble, the EPA is proposing to first
subcategorize affected existing steam
generating units by fuel type: coal-fired
and oil- or natural gas-fired steam
generating units. The EPA is proposing
further subcategorization into four
subcategories for coal-fired steam
generating units and seven
subcategories for oil- and natural gasfired steam generating units. As
explained in section X.C.3, the EPA is
proposing that an affected coal-fired
steam generating unit’s operating
horizon determines the applicable
subcategory in three of the four
subcategories; in the case of the nearterm subcategory, the operating horizon
and load level establish applicability.
The EPA notes that, as explained in
section X.C.3 of this preamble, where
the owners or operators of affected coalfired steam-generating units have
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elected to commit to permanently cease
operation (and, in the case of near-term
operating horizon units, to limit their
capacity factor) and have also elected to
make any such commitments federally
enforceable through inclusion in a State
plan, a State may rely on such
commitments to subcategorize coal-fired
steam generating units under these
emission guidelines. To be included in
a State plan a commitment to cease
operations or to limit capacity factor
must be enforceable by the State,
whether through State rule, agreed
order, permit, or other legal
instrument.622 Upon EPA approval of
the State plan, that commitment will
become federally enforceable.
For affected oil- and natural gas-fired
steam generating units, subcategories
are defined by load level and the type
of fuel fired, as well as locality (i.e.,
continental and non-continental U.S.).
There are four subcategories for oil-fired
steam generating units based on
different combinations of load level
(base load, intermediate load, and low
load) and locality, and three
subcategories for natural gas-fired steam
generating units based on load level
(base load, intermediate, and low).
i. Long-Term Coal-Fired Steam
Generating Units
This section describes the EPA’s
proposed methodology for establishing
presumptively approvable standards of
performance for long-term coal-fired
steam generating units. Affected coalfired steam generating units that have
either (1) Elected to commit to
permanently cease operations on
January 1, 2040, or later, or (2) that have
not elected to commit to permanently
cease operations as part of the State’s
plan submission, fall within this
subcategory and have a proposed BSER
of CCS with 90 percent capture and a
proposed degree of emission limitation
of 90 percent capture of the mass of CO2
in the flue gas (i.e., the mass of CO2 after
the boiler but before the capture
equipment) over an extended period of
time and an 88.4 percent reduction in
emission rate on a gross basis over an
extended period of time. The EPA is
proposing that where States use the
methodology described here to establish
standards of performance for an affected
EGU in this subcategory, those
established standards would be
presumptively approvable when
included in a State plan submission. In
section X of this preamble, for the longterm coal-fired subcategory, the EPA is
soliciting comment on a capture rate of
90 to 95 percent and a degree of
622 40
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emission limitation defined by a
reduction in emission rate on a gross
basis from 75 to 90 percent.
Establishing a standard of
performance for an affected coal-fired
EGU in this subcategory consists of two
steps: establishing a source-specific
level of baseline emission performance
(as described above); and applying the
level of stringency, based on the
application of the BSER, to that level of
baseline emission performance.
Implementation of CCS with a capture
rate of 90 precent translates to a level of
stringency of an 88.4 percent reduction
in CO2 emission rate (see section X.D.4.a
of this preamble) compared to the
baseline level of emission performance.
Using the complement of 88.4 percent
(i.e., 11.6 percent) and multiplying it by
the baseline level of emission
performance results in the
presumptively approvable standard of
performance. For example, if a longterm coal-fired EGU’s level of baseline
emission performance is 2,000 lbs per
MWh, it will have a presumptively
approvable standard of performance of
232 lbs per MWh (2,000 lbs per MWh
multiplied by 0.116).
The EPA is also proposing that
affected coal-fired EGUs in the longterm subcategory comply with federally
enforceable increments of progress,
which are described in section XII.D.3.a
of this preamble.
The EPA solicits comments on this
proposed methodology for calculating
presumptively approvable standards of
performance for long-term coal-fired
steam generating units.
ii. Medium-Term Coal-Fired Steam
Generating Units
This section describes the EPA’s
proposed methodology for establishing
presumptively approvable standards of
performance for medium-term coal-fired
steam generating units. Affected coalfired steam generating units that have
elected to commit to permanently cease
operations after December 31, 2031, and
before January 1, 2040, have a proposed
BSER of 40 percent co-firing of natural
gas. The EPA is proposing that where
States use the methodology described
here to establish standards of
performance for an affected EGU in this
subcategory, those established standards
of performance would be presumptively
approvable when included in a State
plan submission.
Establishing a standard of
performance for an affected EGU in this
subcategory consists of two steps:
establishing a source-specific level of
baseline emission performance (as
described earlier in this preamble); and
applying the level of emission reduction
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stringency, based on the application of
the BSER, to that level of baseline
emission performance. Implementation
of natural gas co-firing at a level of 40
percent of total annual heat input
translates to a level of stringency of a 16
percent reduction in CO2 emissions (see
section X.D.4.b of this preamble)
compared to the baseline level of
emission performance. Using the
complement of 16 percent (i.e., 84
percent) and multiplying it by the
baseline level of emission performance
results in the presumptively approvable
standard of performance for the affected
EGU. For example, if a medium-term
coal-fired EGU’s level of baseline
emission performance is 2,000 lbs per
MWh, it will have a presumptively
approvable standard of performance of
1,680 lbs per MWh (2,000 lbs per MWh
multiplied by 0.84). In section X of this
preamble, for the medium-term coalfired subcategory, the EPA is soliciting
comment on a natural gas co-firing level
of 30 to 50 percent and a degree of
emission limitation from 12 to 20
percent.
For medium-term coal-fired steam
generating units that have an amount of
co-firing that is reflected in the baseline
operation, the EPA is proposing that
States account for such preexisting cofiring in adjusting the degree of
emission limitation. If, for example, an
EGU co-fires natural gas at a level of 10
percent of the total annual heat input
during the applicable 8-quarter baseline
period, the corresponding degree of
emission limitation would be adjusted
to 12 percent (i.e., an additional 30
percent of natural gas by heat input) to
reflect the preexisting level of natural
gas co-firing. This results in a standard
of performance based on the degree of
emission limitation achieving an
additional 30 percent co-firing beyond
the 10 percent that is accounted for in
the baseline. The EPA believes this
approach is a more straightforward
mathematical adjustment than adjusting
the baseline to appropriately reflect a
preexisting level of co-firing. However,
the EPA solicits comment on whether
the adjustment of a standard of
performance based on preexisting levels
of natural gas co-firing should be done
through the baseline. To adjust the
baseline to account for preexisting
natural gas co-firing, the State would
need to calculate a baseline of emission
performance for an EGU that removes
the mass emissions and electric
generation that are attributable to the
natural gas portion of the fuel. With this
adjusted baseline that removes the
natural gas-fired portion, the
presumptive standard of performance
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would be calculated by multiplying the
adjusted baseline by the degree of
emission limitation factor that reflects
40 percent co-firing. The EPA is not
proposing this methodology, because
parsing the attributable emissions and
electric generation associated with
natural gas co-firing from the
attributable emissions and electric
generation associated with coal-fired
generation requires manipulation of the
emissions and electric generation data.
However, the EPA solicits comment on
whether baseline adjustment is more
appropriate and also why that may be
so.
The standard of performance for the
medium-term coal-fired subcategory is
based on the degree of emission
limitation that is achievable through
application of the BSER to the affected
EGUs in the subcategory and consists
exclusively of the rate-based emission
limitation. However, to qualify for
inclusion in the subcategory an affected
coal-fired steam generating unit must
have elected to commit to permanently
cease operations prior to January 1,
2040. If a State decides to rely on such
a commitment to place an affected EGU
into the medium-term coal-fired
subcategory by making it an enforceable
element of its State plan, the
commitment to cease operations will
become federally enforceable upon EPA
approval of the plan.
The EPA is proposing that affected
coal-fired EGUs that elect to commit to
dates to permanently cease operations
for subcategory applicability, including
EGUs in the medium-term coal-fired
subcategory, have corresponding
federally enforceable milestones with
which they must comply. The EPA
intends these milestones to assist
affected EGUs in ensuring they are
completing the necessary steps to
comply with their State plan and
commitments to dates to permanently
cease operations. These milestones are
described in detail in section XII.D.3.b
of this preamble. Affected EGUs in this
subcategory would also be required to
comply with the federally enforceable
increments of progress described in
section XII.D.3.a of this preamble.
The EPA solicits comment on the
proposed methodology for calculating
presumptively approvable standards of
performance for medium-term coal-fired
steam generating units, including on the
proposed approach for adjusting a
presumptively approvable standard of
performance to accommodate
preexisting natural gas co-firing.
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iii. Imminent-Term Coal-Fired Steam
Generating Units
This section describes the EPA’s
proposed methodology for establishing
presumptively approvable standards of
performance for imminent-term coalfired steam generating units. Affected
coal-fired steam generating units that
elect to commit to permanently cease
operations before January 1, 2032, have
a proposed BSER of routine methods of
operation and maintenance. Therefore,
the proposed presumptively approvable
standard of performance is not to exceed
the baseline emission performance of
the affected EGU (as described in
section XII.D.1.a of this preamble).
Unlike the proposed standards of
performance for the long-term and
medium-term coal-fired steam
generating units, establishing a standard
of performance for an affected EGU in
the imminent-term subcategory consists
of just one step. The EPA is proposing
that where States use the methodology
described in section XII.D.1.a of this
preamble to establish the baseline level
of emission performance for an affected
EGU, the emission rate described by that
baseline would constitute the
presumptively approvable standard of
performance. This standard of
performance reflects that the proposed
BSER for these affected EGUs is routine
methods of operation and maintenance
and a degree of emission limitation
equivalent to no increase in emission
rate from the baseline level of emission
performance. This also ensures that the
affected EGU will not backslide in its
emission performance.
Although the EPA believes that the
baseline performance level adequately
accounts for variability in annual
emission rate, the EPA is also soliciting
comment on a methodology for a
presumptive standard above the
baseline emission performance. For the
imminent-term coal-fired subcategory,
the EPA is soliciting comment on a
presumptive standard that is defined by
0 to 2 standard deviations in annual
emission rate (using the 5-year period of
data) above the baseline emission
performance, or that is 0 to 10 percent
above the baseline emission
performance.
Because the EPA is soliciting
comment on a potential BSER for this
subcategory based on low levels of
natural gas co-firing, as described in
section X.D.3.b.ii, comment is also being
solicited on the presumptively
approvable standards for that potential
BSER. The BSER is based on the
maximum hourly heat input of natural
gas fired in the unit (MMBtu/hr) relative
to the maximum hourly heat input the
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unit is capable of (i.e., the nameplate
capacity on an MMBtu/hr basis). The
EPA is soliciting comment on the
baseline natural gas co-firing level being
determined from the 5 years of data
preceding the publication of the final
rule, or based on engineering limitations
(i.e., extent of startup guns or size of
pipeline to unit). That percent of heat
input results in percent reductions from
the emission performance baseline
equivalent to the percent of heat input
times 0.4. Adjustments relative to
current co-firing levels may be
accounted for in a manner consistent
with section XII.D.1.b.ii. Alternatively,
the EPA is soliciting comment on a
degree of emission limitation on a fuel
heat input basis. For a potential BSER
of low levels of natural gas co-firing, the
EPA is therefore also soliciting comment
on a presumptively approvable standard
defined on a heat input basis.
The standard of performance for the
imminent-term coal-fired subcategory is
based on the degree of emission
limitation that is achievable through
application of the BSER to the affected
EGUs in the subcategory and consists
exclusively of the rate-based emission
limitation. However, to qualify for
inclusion in the subcategory an affected
coal-fired EGU must have elected to
commit to permanently cease operations
prior to January 1, 2032. If a State
decides to rely on such a commitment
to place an affected EGU into the
imminent-term coal-fired subcategory
by making it an enforceable element of
its State plan, the commitment to cease
operations will become federally
enforceable upon EPA approval of the
plan.
The EPA is also proposing that
affected coal-fired steam generating
units that have elected to commit to
dates to permanently cease operations
for subcategory applicability, including
EGUs in the imminent-term coal-fired
subcategory, have corresponding
federally enforceable milestones with
which they must comply. The EPA
intends these milestones to assist
affected EGUs in ensuring they are
completing the necessary steps to
comply with these dates in their State
plan. These milestones are described in
detail in section XII.D.3.b of this
preamble.
The EPA solicits comment on the
proposed methodology for establishing
presumptively approvable standards of
performance for imminent-term coalfired steam generating units.
iv. Near-Term Coal-Fired Steam
Generating Units
Similar to the proposed approach for
establishing presumptively approvable
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standards of performance for affected
EGUs in the imminent-term coal-fired
subcategory, the EPA is proposing that
affected EGUs in the near-term coalfired subcategory have a presumptively
approvable standard of performance
based on the baseline emission
performance of the affected EGU (as
described in section XII.D.1.a of this
preamble). The near-term subcategory
includes affected coal-fired steam
generating units that have elected to
commit to permanently cease operations
after December 31, 2031, and before
January 1, 2035, and that have elected
to adopt an annual capacity factor
limitation of 20 percent.
The EPA is proposing that where
States use the methodology described in
section XII.D.1.a of this preamble to
establish the baseline level of emission
performance for an affected EGU, the
emission rate described by that baseline
would constitute the presumptively
approvable standard of performance.
This standard of performance reflects
the proposed BSER of routine methods
of operation and maintenance and a
degree of emission limitation equivalent
to no increase in emission rate. This
also ensures that the affected EGU will
not backslide in its emission
performance.
For the near-term coal-fired
subcategory, the EPA is soliciting
comment on a presumptive standard
that is defined by 0 to 2 standard
deviations in annual emission rate
(using the 5-year period of data) above
the baseline emission performance, or
that is 0 to 10 percent above the baseline
emission performance.
Because the EPA is soliciting
comment on a potential BSER for this
subcategory based on low levels of
natural gas co-firing, as described in
section X.D.3.b.ii, comment is also being
solicited on the presumptively
approvable standards for that potential
BSER. The BSER is based on the
maximum hourly heat input of natural
gas fired in the unit (MMBtu/hr) relative
to the maximum hourly heat input the
unit is capable of (i.e., the nameplate
capacity on an MMBtu/hr basis). The
EPA is soliciting comment on the
baseline natural gas co-firing level being
determined from the 5 years of data
preceding the publication of the final
rule, or based on engineering limitations
(i.e., extent of startup guns or size of
pipeline to unit). That percent of heat
input results in percent reductions from
the emission performance baseline
equivalent to the percent of heat input
times 0.4. Adjustments relative to
current co-firing levels may be
accounted for in a manner consistent
with section XII.D.1.b.ii. Alternatively,
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the EPA is soliciting comment on a
degree of emission limitation on a fuel
heat input basis. For a potential BSER
of low levels of natural gas co-firing, the
EPA is therefore also soliciting comment
on a presumptively approvable standard
defined on a heat input basis.
The standard of performance for the
near-term coal-fired subcategory is
based on the degree of emission
limitation that is achievable through
application of the BSER to the affected
EGUs in the subcategory and consists
exclusively of the rate-based emission
limitation. However, to qualify for
inclusion in the subcategory an affected
coal-fired EGU must have elected to
commit to permanently cease operations
after December 31, 2031, and before
January 1, 2035, and must have elected
to adopt an annual capacity factor
limitation of 20 percent. If a State
decides to rely on such commitments to
place an affected EGU into the near-term
coal-fired subcategory by making them
enforceable elements of its State plan,
the commitments to cease operations
and to limit its capacity factor will
become federally enforceable upon EPA
approval of the plan.
The EPA is also proposing that
affected coal-fired EGUs that have
elected to commit to dates to
permanently cease operations for
subcategory applicability, including
EGUs in the near-term coal-fired
subcategory, have corresponding
federally enforceable milestones with
which they must comply. The EPA
intends these milestones to assist
affected EGUs in ensuring they are
completing the necessary steps to
comply with these dates in their State
plan. These milestones are described in
detail in section XII.D.3.b of this
preamble.
The EPA solicits comment on the
proposed methodology for establishing
presumptively approvable standards of
performance for near-term coal-fired
steam generating units.
v. Natural Gas-Fired Steam Generating
Units and Continental Oil-Fired Steam
Generating Units
This section describes the EPA’s
proposed methodology for
presumptively approvable standards of
performance for affected natural gasfired and continental oil-fired steam
generating units: low load natural gasfired steam generating units,
intermediate load natural gas- fired
steam generating units, base load
natural gas-fired steam generating units,
low load oil-fired steam generating
units, intermediate load continental oilfired steam generating units, and base
load continental oil-fired steam
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generating units. It does not address
non-continental intermediate oil-fired
and non-continental base load oil-fired
steam generating units, which are
described in section XII.D.1.b.vi of this
preamble. The proposed definitions of
these subcategories are discussed in
section X.C.2 of this preamble. The
proposed presumptive standards of
performance are based on degrees of
emission limitation that units are
currently achieving, consistent with the
proposed BSER of routine methods of
operation and maintenance, which
amounts to a proposed degree of
emission limitation of no increase in
emission rate.
Unlike the approach to establishing
presumptive standards of performance
for coal-fired EGUs in these proposed
emission guidelines, the EPA is
proposing presumptive standards of
performance for affected natural gasfired and continental oil-fired steam
generating units in lieu of
methodologies that States would use to
establish presumptive standards of
performance. This is largely because the
low variability in emissions data at
intermediate and base load for these
units and relatively consistent
performance between these units at
those load levels, as discussed in
section X.E of this preamble and
detailed in the Natural Gas- and Oilfired Steam Generating Unit TSD,
allows for the identification of a
generally applicable standard of
performance.
However, for natural gas- or oil-fired
steam generating units with low annual
capacity factors, annual emission rates
can be high (greater than 2,500 lb CO2/
MWh-gross) and can vary considerably
across units and from year to year.
Despite their relatively high emission
rates, though, overall emissions from
these units are low. Based on these
considerations, the EPA is not
proposing a BSER or that States
establish standards of performance for
these units at this time. However, as
noted above, the EPA is soliciting
comment on determining a BSER of
uniform fuels for these units. In
addition, the EPA is soliciting comment
on a presumptive standard of
performance for these units based on
heat input. Specifically, the EPA is
soliciting comment on a range of
presumptive standards of performance
from 120 to 130 lb CO2/MMBtu for low
load natural gas-fired steam generating
units, and from 160 to 170 lb CO2/
MMBtu for low load oil-fired steam
generating units.
For intermediate load natural gasfired units (annual capacity factors
greater than or equal to 8 percent and
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less than 45 percent), annual emission
rates are less than 1,500 lb CO2/MWhgross for about 90 percent of the units.
Therefore, the EPA is proposing the
presumptive standard of performance of
an annual calendar-year emission rate of
1,500 lb CO2/MWh-gross for these units.
For base load natural gas-fired units
(annual capacity factors greater than or
equal to 45 percent), annual emission
rates are less than 1,300 lb CO2/MWhgross for about 80 percent of units.
Therefore, the EPA is proposing the
presumptive standard of performance of
an annual calendar-year emission rate of
1,300 lb CO2/MWh-gross for these units.
In the continental U.S., there are few
if any oil-fired steam generating units
that operate with intermediate or high
utilization. Liquid-oil-fired steam
generating units with 24-month capacity
factors less than 8 percent do qualify for
a work practice standard in lieu of
emission requirements under the
Mercury and Air Toxics Standards rule
(MATS) (40 CFR 63, subpart UUUUU).
If oil-fired units operated at higher
annual capacities, it is likely they would
do so with substantial amounts of
natural gas firing and have emission
rates that are similar to steam generating
units that fire only natural gas at those
levels of utilization. There are a few
natural gas-fired steam generating units
that are near the threshold for qualifying
as oil-fired units (i.e., firing more than
15 percent oil in a given year) but that
on average fire more than 90 percent of
their heat input from natural gas.
Therefore, the EPA is proposing the
same presumptive standards of
performance for oil-fired steam
generating units as for natural gas-fired
units, noted above.
The EPA is also taking comment on a
range of presumptive standards of
performance for natural gas- and oilfired steam generating units.
Specifically, the EPA is soliciting
comment on standards between (1)
1,400 and 1,600 lb CO2/MWh-gross for
intermediate load natural gas-fired
units, (2) 1,250 and 1,400 lb CO2/MWhgross for base load natural gas-fired
units, (3) 1,400 and 2,000 lb CO2/MWhgross for intermediate load oil-fired
units, and (4) 1,250 and 1,800 lb CO2/
MWh-gross for base load oil-fired units.
The upper end of the ranges for oil-fired
units is higher because of the limited
data available for oil-fired units that
operate at those annual capacity factors.
vi. Non-Continental Oil-Fired Steam
Generating Units
The EPA is proposing that for affected
EGUs in the non-continental
intermediate oil-fired and noncontinental base load oil-fired
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subcategory, a presumptively
approvable standard of performance
would be based on baseline emission
performance, consistent with the EPA’s
proposed BSER determination of routine
methods of operation and maintenance
and the proposed degree of emission
limitation of no increase in emission
rate. The EPA is proposing that where
States use the methodology described in
section XII.D.1.a of the preamble to
establish unit-specific baseline levels of
emission performance for affected EGUs
in this subcategory, those emission rates
would constitute presumptively
approvable standards of performance
when included in a State plan
submission. This standard of
performance would ensure no increase
in the unit-specific emission rate from
the baseline level of emission
performance.
For the intermediate and base load
non-continental oil-fired subcategory,
the EPA is soliciting comment on a
presumptive standard that is defined by
0 to 2 standard deviations in annual
emission rate (using the 5-year period of
data) above the baseline emission
performance, or that is 0 to 10 percent
above the baseline emission
performance.
The EPA solicits comment on the
proposed methodology for establishing
presumptively approvable standards of
performance for non-continental oilfired steam generating units in the
intermediate and base load
subcategories.
c. Presumptive Standards for
Combustion Turbines
As described in section XI.C, the EPA
is proposing to define affected existing
combustion turbines under these
emission guidelines as units with a
capacity greater than 300 MW and an
annual capacity factor of greater than 50
percent. Within this set of units, the
EPA is proposing two subcategories
based on the type of fuel used: existing
combustion turbines that adopt the
pathway with a standard of performance
based on CCS, referred to as the ‘‘CCS
subcategory’’ and existing combustion
turbines that adopt the pathway with a
standard of performance based on
hydrogen co-firing, referred to as the
‘‘hydrogen co-fired subcategory.’’ States,
in their State plan submissions, would
be required to assign existing
combustion turbine EGUs with
capacities greater than 300 MW and the
ability to operate at an annual capacity
factor of greater than 50 percent to one
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subcategory or the other.623 States
would then be required to include in
their plans the presumptive standard of
performance corresponding to the
appropriate subcategory for each
affected existing combustion turbine
EGU. As discussed in section XII.D.2 of
this preamble, States, in applying a
standard of performance to a particular
affected existing combustion turbine
EGU, also have discretion to consider
that EGU’s remaining useful life and
other factors.
However, the EPA anticipates that
some existing combustion turbine EGUs
that are greater than 300 MW do not
intend to operate at an annual capacity
factor of greater than 50 percent starting
in 2032 (the first proposed compliance
date for affected existing combustion
turbine EGUs under these emission
guidelines). Such an EGU may elect to
commit to an enforceable annual
capacity factor limitation of less than or
equal to 50 percent. If a State elects to
include such an enforceable
commitment in its State plan, the State
would not be required to have a
standard of performance for that
particular combustion turbine EGU in
its plan. Otherwise, each affected
existing combustion turbine that is
greater than 300 MW and that has the
ability to operate at an annual capacity
factor of greater than 50 percent must
have a subcategory designation and
standard of performance in the State
plan.
The EPA is proposing that States may
structure the requirements for affected
combustion turbine EGUs in their State
plans so that the applicable standard of
performance must be met for years in
which the unit operates above the 50
percent annual capacity factor
threshold. States and the owners or
operators of affected EGUs that have
such contingent standards of
performance would be required to
ensure that an affected EGU has
complied with its standard of
performance for each calendar year in
which it has operated at an annual
capacity factor of greater than 50
percent. The EPA expects that if the
owner or operator of an affected
combustion turbine EGU that has a
standard of performance believes there
is a chance the EGU will operate at an
annual capacity factor of greater than 50
623 As explained in section XI.D of this preamble,
the EPA is soliciting comment on, inter alia,
whether to finalize both the CCS and hydrogen cofired pathways for existing combustion turbines or
whether to finalize a BSER determination with a
single pathway. If the EPA does not finalize the
proposed two-pathway approach, the state plan
requirements for existing combustion turbines in
this section XII of the preamble will be updated
accordingly for the final rule.
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percent in the upcoming compliance
period, it will plan to meet that
standard. Given this practical reality,
the EPA is taking comment on whether
it should require that once an affected
existing combustion turbine EGU has
exceeded the 50 percent annual capacity
factor threshold and triggered
application of its standard of
performance for a given compliance
period, that EGU must continue to meet
its standard in subsequent compliance
periods.
i. Carbon Capture and Storage Existing
Combustion Turbine Generating Units
This section describes the EPA’s
proposed methodology for establishing
presumptively approvable standards of
performance for existing combustion
turbine EGUs that adopt the pathway
with a standard of performance based
on CCS. Affected EGUs that are assigned
to this subcategory have a proposed
BSER of CCS with 90 percent capture
and a proposed degree of emission
limitation of 90 percent capture of the
mass of CO2 in the flue gas (i.e., the
mass of CO2 after the turbine but before
the capture equipment) over an
extended period of time and an 89
percent reduction in emission rate on a
gross basis over an extended period of
time. The EPA is proposing that where
States use the methodology described
here to establish standards of
performance for an affected EGU in this
subcategory, those established standards
would be presumptively approvable
when included in a State plan
submission.
Establishing a standard of
performance for an affected combustion
turbine EGU in this subcategory consists
of two steps: establishing a sourcespecific level of baseline emission
performance (as described above); and
applying the level of stringency, based
on the application of the BSER, to that
level of baseline emission performance.
Implementation of CCS with a capture
rate of 90 precent translates to a level of
stringency of an 89 percent reduction in
CO2 emission rate (see section XI.C of
this preamble) compared to the baseline
level of emission performance. Using
the complement of 89 percent (i.e., 11
percent) and multiplying it by the
baseline level of emission performance
results in the presumptively approvable
standard of performance. For example,
if a combustion turbine EGU in this
subcategory has a baseline level of
emission performance of 1,000 lbs per
MWh, it will have a presumptively
approvable standard of performance of
110 lbs per MWh (1,000 lbs per MWh
multiplied by 0.11).
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The EPA is also proposing that
affected combustion turbines in this
subcategory comply with federally
enforceable increments of progress,
which are described in section XII.D.3.a
of this preamble.
The EPA solicits comments on this
proposed methodology for calculating
presumptively approvable standards of
performance for existing combustion
turbines in the CCS subcategory.
ii. Hydrogen Co-Fired Existing
Combustion Turbine Generating Units
This section describes the EPA’s
proposed methodology for establishing
presumptively approvable standards of
performance for existing combustion
turbines that adopt the pathway with a
standard of performance based on
hydrogen co-firing. Affected combustion
turbine EGUs in this subcategory have a
proposed BSER of hydrogen co-firing
with two phases of stringency. In the
first phase, affected EGUs in this
subcategory co-fire hydrogen at a level
of 30 percent by volume with a
proposed degree of emission limitation
of 12 percent reduction in emission rate
on a gross basis over an extended period
of time. In the second phase, affected
EGUs in this subcategory co-fire
hydrogen at a level of 96 percent by
volume with a proposed degree of
emission limitation of 88.4 percent
reduction in emission rate on a gross
basis over an extended period of time.
As described in section XII.B,
compliance with the first phase
commences on January 1, 2032, and
compliance with the second phase
commences on January 1, 2038. The
EPA is proposing that where States use
the methodology described here to
establish standards of performance for
this subcategory, those established
standards of performance would be
presumptively approvable when
included in a State plan submission.
Establishing a standard of
performance for an affected EGU in this
subcategory consists of three steps: first,
establishing a source-specific level of
baseline emission performance (as
described earlier in this preamble); and
second, applying the level of emission
reduction stringency for the first phase,
based on the application of the first
phase BSER, to that level of baseline
emission performance; and third,
applying the level of emission reduction
stringency for the second phase, based
on the application of the second phase
BSER, to that level of baseline emission
performance.
Implementation of hydrogen co-firing
at a level of 30 percent by volume
translates to a level of stringency of a 12
percent reduction in CO2 emissions (see
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section XI.C of this preamble) compared
to the baseline level of emission
performance. Using the complement of
12 percent (i.e., 88 percent) and
multiplying it by the baseline level of
emission performance results in the
presumptively approvable standard of
performance for the affected EGU. For
example, if a combustion turbine EGU
that co-fires 30 percent hydrogen (by
volume) has a baseline level of emission
performance of 1,000 lbs per MWh, it
will have a presumptively approvable
standard of performance of 880 lbs per
MWh (1,000 lbs per MWh multiplied by
0.88) for the first phase.
Implementation of hydrogen co-firing
at a level of 96 percent by volume
translates to a level of stringency of an
88.4 percent reduction in CO2 emissions
(see section XI.C of this preamble)
compared to the baseline level of
emission performance. Using the
complement of 88.4 percent (i.e., 11.6
percent) and multiplying it by the
baseline level of emission performance
results in the presumptively approvable
standard of performance for the affected
EGU. For example, if a combustion
turbine EGU that co-fires 96 percent
hydrogen (by volume) has a baseline
level of emission performance of 1,000
lbs per MWh, it will have a
presumptively approvable standard of
performance of 116 lbs per MWh (1,000
lbs per MWh multiplied by 0.116) for
the second phase.
The EPA is proposing that affected
combustion turbine EGUs in this
subcategory that meet their standards of
performance using hydrogen co-firing
must co-fire with low-GHG hydrogen.
States must make this an enforceable
part of their State plans, as described in
further detail in section XII.F.1.b.i.
The EPA is also proposing that
affected combustion turbines in this
subcategory comply with federally
enforceable increments of progress,
which are described in section XII.D.3.a
of this preamble.
The EPA solicits comment on the
proposed methodology for calculating
presumptively approvable standards of
performance for existing combustion
turbine EGUs in the hydrogen co-fired
subcategory.
2. Remaining Useful Life and Other
Factors
Under CAA section 111(d), the EPA is
required to promulgate regulations
under which States submit plans
applying standards of performance to
affected EGUs. While States establish
the standards of performance, there is a
fundamental obligation under CAA
section 111(d) that such standards
reflect the degree of emission limitation
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achievable through the application of
the BSER, as determined by the EPA.624
The EPA identifies this degree of
emission limitation as part of its
emission guideline. 40 CFR 60.22a(b)(5).
Thus, as described in section X.D of this
preamble, the EPA is providing
proposed methodologies for States to
follow in determining and applying
presumptively approvable standards of
performance to affected EGUs in each of
the subcategories covered by these
emission guidelines.
While standards of performance must
generally reflect the degree of emission
limitation achievable through
application of the BSER as determined
by the EPA, CAA section 111(d)(1) also
requires that the EPA regulations permit
the States, in applying a standard of
performance to a particular designated
facility, to ‘‘take into consideration,
among other factors, the remaining
useful life of the existing sources to
which the standard applies.’’ The EPA’s
implementing regulations under 40 CFR
60.24a thus allow a State to consider a
particular designated facility’s
remaining useful life and other factors
in applying to that facility a standard of
performance that is less stringent than
the presumptive level of stringency
given in an emission guideline.
In December 2022, the EPA proposed
to clarify the existing requirements in
subpart Ba governing what a State must
demonstrate in order to invoke RULOF
and provide a less stringent standard of
performance when submitting a State
plan.625 Specifically, the EPA proposed
to require the State to demonstrate that
a particular facility cannot reasonably
achieve the degree of emission
limitation achievable through
application of the BSER based on one or
more of three delineated circumstances,
and proposed to clarify those three
circumstances. The EPA also proposed
additions and further clarifications to
the process of invoking RULOF and
determining a standard of performance
based on RULOF, to ensure that use of
the provision does not undermine the
overall presumptive level of stringency
of the BSER, as well as to provide a
clear analytical framework for States
and the regulated community as they
624 West Virginia v. EPA, 142 S. Ct. 2587, 2607
(2022) (‘‘In devising emissions limits for power
plants, EPA first ‘determines’ the ‘best system of
emission reduction’ that—taking into account cost,
health, and other factors—it finds ‘has been
adequately demonstrated.’ The Agency then
quantifies ‘the degree of emission limitation
achievable’ if that best system were applied to the
covered source.’’) (internal citations omitted).
625 87 FR 79176, 79196–79206 (December 23,
2022).
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seek to craft satisfactory plans that the
EPA can ultimately approve.626
The EPA is not soliciting comment in
this rulemaking on the proposed
revisions to the RULOF provisions in
subpart Ba, which are subject to a
separate rulemaking process. As noted
in section XII.A of this preamble, the
EPA intends to finalize revisions to
subpart Ba prior to finalizing these
emission guidelines. Those revised
RULOF provisions, including any
changes made in response to public
comments, will apply to these emission
guidelines. While the EPA is not taking
comment on the proposed provisions of
subpart Ba themselves, the EPA is
requesting comment on how each of the
RULOF provisions that the EPA
proposed in December 2022 would be
implemented in the context of these
particular emission guidelines.
The remainder of this section of the
preamble addresses how the
requirements associated with RULOF, as
the EPA has proposed to revise them,
would apply to States and State plans
under these emission guidelines. First,
it addresses the threshold requirements
for considering RULOF and how those
requirements would apply to an affected
EGU under these emission guidelines.
Second, it addresses how, if a State has
appropriately invoked RULOF for a
particular affected EGU under the
previous step, it would be required to
determine a source-specific BSER and
calculate a standard of performance for
that affected EGU. Third, it discusses
the proposed requirement for plans that
apply less stringent standards of
performance pursuant to RULOF to
consider the potential pollution impacts
and benefits of control to communities
most affected by and vulnerable to
emissions from the affected EGU.
Fourth, this section addresses the
proposed provisions for the standard for
EPA review of State plans that include
RULOF standards of performance. And,
finally, it discusses the EPA’s proposed
interpretation of the Clean Air Act as
laid out in the proposed revisions to
subpart Ba that the Act allows states to
adopt and enforce standards of
performance more stringent than
required by an applicable emission
guideline, and that the EPA has the
ability and authority to approve such
standards of performance into State
plans.
a. Threshold Requirements for
Considering RULOF
As discussed earlier in this preamble,
CAA section 111(d)(1) expressly
626 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002.
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requires the EPA to permit states to
consider RULOF when applying a
standard of performance to a particular
affected EGU. The EPA’s proposed
revisions to the regulations governing
states’ use of RULOF would provide a
clear analytical framework to ensure
that its use to apply less stringent
standards of performance for particular
sources is consistent across states. The
proposed revisions would also ensure
that the use of RULOF does not
undermine the overall presumptive
level of stringency and the emission
reduction benefits of an emission
guideline, or undermine and render
meaningless the EPA’s BSER
determination. Such a result would be
contrary to the overarching purpose of
CAA section 111(d), which is generally
to achieve meaningful emission
reductions from designated facilities, in
this case affected EGUs, based on the
BSER in order to mitigate pollution that
endangers public health and welfare.
To this end, proposed subpart Ba
would provide that a State may apply a
less stringent standard of performance
to a particular facility, taking into
consideration remaining useful life and
other factors, provided that the State
demonstrates with respect to that
facility (or class of facilities) that it
cannot reasonably apply the BSER to
achieve the degree of emission
limitation determined by the EPA.
Invocation of RULOF would be required
to be based on one or more of three
circumstances: (1) Unreasonable cost of
control resulting from plant age,
location, or basic process design, (2)
physical impossibility or technical
infeasibility of installing necessary
control equipment, or (3) other
circumstances specific to the facility
that are fundamentally different from
the information considered in the
determination of the BSER in the
emission guidelines.627
A State wishing to invoke RULOF in
order to apply a less stringent standard
to a particular affected EGU would be
required to demonstrate that there are
fundamental differences between that
EGU and the EPA’s BSER
determination, based on consideration
of the BSER factors that the EPA
considered in its analysis. In
determining the BSER and the degree of
emission reductions achievable through
application of the BSER in these
proposed emission guidelines, the EPA
considered whether a system of
emission reduction is adequately
627 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (containing
proposed revisions to RULOF provisions at 40 CFR
60.24a(e)–(n)).
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demonstrated for the subcategory based
on the physical possibility and technical
feasibility of applying that system, the
costs of a system of emission reduction,
the non-air quality health and
environmental impacts and energy
requirements associated with a system
of emission reduction, and the extent of
emission reductions from a system.628
For each subcategory, the EPA
evaluated certain metrics related to each
of these BSER factors. For example,629
in evaluating the costs associated with
CCS and natural gas co-firing for
existing coal-fired steam generating
units, the EPA considered both $/ton
CO2 reduced and increases in levelized
costs expressed as dollars per MWh
electricity generation. A State wishing
to invoke RULOF for a particular
affected EGU in the long-term coal-fired
subcategory based on unreasonable cost
of control would also be required to
consider the cost as $/ton of CO2
reduced and $/MWh electricity
generated. The State would further have
to demonstrate that the costs, as
represented by these two metrics, for the
particular affected EGU are
fundamentally different, i.e.,
significantly higher, than costs the EPA
determines to be reasonable due to that
EGU’s age, location, or basic process
design.
The RULOF provision, currently and
as the EPA has proposed to revise it,
also allows states to invoke RULOF
based on other circumstances specific to
an affected EGU. As an illustrative
example, a State may wish to invoke
RULOF for a medium-term coal-fired
steam generating unit that is extremely
isolated (e.g., on a small island more
than 200 miles offshore) such that it
would require construction of an LNG
terminal and shipping of LNG by barge
to have natural gas available to fire at
the unit. In the EPA’s evaluation of
natural gas co-firing as the potential
BSER for medium-term coal-fired steam
generating units, the EPA considered
the distance and cost of lateral pipeline
builds in proposing natural gas co-firing
as BSER. If a State can demonstrate that
something unique to the source’s being
on a remote island—something that the
EPA did not consider in evaluating the
BSER—results in the affected EGU not
being able to reasonably achieve the
628 The EPA also considered impacts on the
energy sector as part of its BSER determinations.
However, because this consideration does not apply
at the level of a particular affected EGU, it would
not be appropriate basis for invoking RULOF.
629 The examples are only for illustrative
purposes and should not be interpreted to represent
the difference that must exist to demonstrate a
fundamental difference between the EPA’s BSER
determination and a particular affected EGU’s
circumstances.
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standard of performance, then it may be
reasonable to invoke RULOF for that
source.
Under the EPA’s proposed approach,
states would not be able to invoke
RULOF based on minor, nonfundamental differences between a
particular affected EGU and what the
EPA determined was reasonable for the
BSER. There could be instances in
which an affected EGU may not be able
to implement the presumptively
approvable standard of performance in
accordance with the precise metrics
(e.g., at exactly the same $/ton CO2
reduced or exactly the same distance
from a pipeline connection) of the BSER
determination but is able to do so
within a reasonable margin. In such
instances, it would not be reasonable for
a State to apply a less stringent standard
of performance.
Many of the factors the EPA considers
in its BSER determination, and therefore
many of the factors states might
consider in determining whether to
invoke RULOF for any particular source,
are reflected in the cost consideration.
As noted previously in this section, the
EPA is providing a range of cost
evaluations for CCS and natural gas cofiring based on different assumptions
regarding amortization period and
capacity factor. For example, the EPA is
proposing to determine that the cost of
CCS for long-term coal-fired steam
generating units is reasonable based on
the following calculations: for a
reference unit with a 12-year
amortization period and 50 percent
capacity factor the cost is $14/ton CO2
reduced or $12/MWh, and that the
average cost for the fleet under the same
assumptions is $8/ton CO2 or $7/MWh.
For natural gas co-firing for mediumterm coal-fired steam generating units,
the EPA is proposing to find the
following costs are reasonable: for a
reference unit with a 50 percent
capacity factor and an amortization
period ranging from 6 to 10 years, a cost
of $53–$66/ton CO2 or $9–$12/MWh.
The average cost for the fleet under the
same assumptions is $64–$78/ton CO2
or $11–$14/MWh.
Any costs associated with any BSER
for affected EGUs that the EPA
determines are reasonable under these
emission guidelines cannot be a basis
for invoking RULOF. Additionally, costs
that are not fundamentally different
from costs that the EPA has determined
are or could be reasonable for sources
cannot be a basis for invoking RULOF.
Thus, costs that are not fundamentally
different from, e.g., $29/MWh (the cost
for installation of wet-FGD on a 300 MW
coal-fired steam generating unit, used
for cost comparison in section X.D.1.a.ii
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of this preamble and detailed in section
VII.F.3.b.iii(B)(5) of this preamble) are
not a basis for invoking RULOF under
these emission guidelines. On the other
hand, costs that constitute outliers, e.g.,
that are greater than the 95th percentile
of costs on a fleetwide basis (assuming
a normal distribution) or that are the
same as costs the EPA has determined
are unreasonable elsewhere under these
emission guidelines would likely
represent a valid demonstration of a
fundamental difference and could be the
basis of invoking RULOF.
Importantly, the costs evaluated in the
BSER determination are, in general, for
representative, average units or are
based on average values across the fleet
of steam generating units. Those BSER
cost analysis values represent the
average of a distribution of costs
including costs that are above or below
the average representative value. On
that basis, implicit in the proposed
determination that those average
representative values are reasonable is a
proposed determination that a
significant portion of the unit-specific
costs around those average
representative values are also
reasonable, including some portion of
those unit-specific costs that are above
but not significantly different than the
average representative values.
Another example of a fundamental
difference between the EPA’s BSER
determination and a particular affected
EGU’s circumstances could be a
difference based on physical
impossibility or technical infeasibility.
In making BSER determinations, the
EPA must find that a system is
adequately demonstrated; among other
things, this means that the BSER must
be technically feasible for the source
category. For long-term coal-fired steam
generating units and combustion turbine
EGUs in the CCS subcategory, the EPA
determined that CCS is adequately
demonstrated because its components
can be and have been applied to the
source category and because it is
generally geographically available to
affected EGUs. However, it may be
possible that a particular affected EGU
is physically unable to implement CCS
due to, e.g., the impossibility of
constructing a pipeline or establishing
other means for CO2 transport. If a State
can demonstrate that it is physically
impossible or technically infeasible for
this affected EGU to apply CCS because
there are no other options to transport
captured CO2, there is a fundamental
difference between the EPA’s BSER
determination and the circumstances of
this particular affected EGU and the
State may invoke RULOF.
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The EPA has proposed under 40 CFR
part 60, subpart Ba that states may
invoke RULOF if they can demonstrate
that a source cannot apply the BSER to
achieve the degree of emission
limitation determined by the EPA based
on one or more of the three
circumstances discussed earlier in this
preamble.630 It thus follows that states
would be able to invoke RULOF under
these emission guidelines if they can
demonstrate that an affected EGU can
apply the BSER but cannot achieve the
degree of emission limitation that the
EPA determined is possible for the
source category generally.
However, the EPA has also proposed
in subpart Ba 631 that a State may not
invoke RULOF to provide a less
stringent standard of performance for a
particular source if that source cannot
apply the BSER but can reasonably
implement a different system of
emission reduction to achieve the
degree of emission limitation required
by the EPA’s BSER determination.
While a State may be able to
demonstrate that the source cannot
reasonably apply the BSER based on one
of the three circumstances, it would be
inappropriate to invoke RULOF to apply
a less stringent standard of performance
because the source can still reasonably
achieve the presumptive degree of
emission limitation. In this instance,
providing a less stringent standard of
performance would be inconsistent with
the purpose of CAA section 111(d) and
these emission guidelines.
States’ consideration of the remaining
useful life of a particular source for
affected coal-fired EGUs, in particular,
will also be informed by the structure of
the EPA’s proposed subcategories, each
of which has its own BSER
determination under these emission
guidelines. Under CAA section
111(d)(1) and the EPA’s proposed
RULOF provisions, states may consider
an affected EGU’s remaining useful life
in determining whether application of
the BSER to achieve the presumptive
level of stringency would result in
unreasonable cost resulting from plant
age.632 In determining the BSER, the
EPA considers costs and, in many
instances, specifically considers
annualized costs associated with
payment of the total capital investment
630 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(e)).
631 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(g)).
632 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(e)(1)).
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33383
of the technology associated with the
BSER. However, plant age can have
considerable variability within a source
category and the annualized costs can
change significantly based on an
affected EGU’s remaining useful life and
associated length of the capital recovery
period. Thus, the costs of applying the
BSER to an affected EGU with a short
remaining life may differ fundamentally
from the costs that the EPA found were
reasonable in making its BSER
determination.
As explained in section X of this
preamble, these proposed emission
guidelines include BSER determinations
and presumptive standards of
performance for affected coal-fired
EGUs in four subcategories: imminentterm, near-term, medium-term, and
long-term. Owing to the basis of these
subcategories, the EPA’s proposed BSER
determinations for each of these
subcategories already consider costs
amortized consistent with the operating
horizons of sources within each
subcategory. The EPA therefore does not
anticipate that states would be likely to
demonstrate the need to invoke RULOF
based on a particular coal-fired EGU’s
remaining useful life, although doing so
is not prohibited under these emission
guidelines. The proposed requirements
for states and affected EGUs invoking
RULOF based on remaining useful life
are addressed in the next subsection.
Conversely, the proposed
subcategories for existing combustion
turbines do not consider affected EGUs’
operating horizons. The useful life of a
combined cycle unit is approximately
25 to 30 years.633 More than 151 GW of
combined cycle units came on-line in
the 2000 to 2010 timeframe,634 meaning
that many of these units could
potentially be at or nearing the end of
their remaining useful lives in the 2035
to 2040 timeframe. If an affected
combustion turbine EGU has decided to
cease operations and elects to make that
cessation enforceable, the period over
which controls would be amortized,
depending on what that period of time
is, may be short enough to invoke
RULOF based on unreasonable cost of
control.
The EPA is proposing to allow states
to use the RULOF mechanism to
provide a different compliance deadline
for a source that can meet the
presumptive standard of performance
633 https://sargentlundy.com/wp-content/
uploads/2017/05/Combined-Cycle-PowerPlantLifeAssessment.pdf.
634 U.S. Environmental Protection Agency.
National Electric Energy Data System (NEEDS) v6.
October 2022. https://www.epa.gov/power-sectormodeling/national-electric-energy-data-systemneeds-v6.
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for the applicable subcategory but
cannot do so by the final compliance
date under these emission guidelines. In
such cases, a State may be able to
demonstrate that there are ‘‘other
circumstances specific to the facility
. . . that are fundamentally different
from the information considered in the
determination of the best system of
emission reduction in the emission
guidelines’’ 635 that make timely
compliance impossible. However, given
the relatively long lead times and
compliance timeframes proposed in
these emission guidelines, the EPA
anticipates that these circumstances will
be rare. Under the proposed revisions to
subpart Ba, RULOF demonstrations,
including those in support of extending
a compliance deadline, would have to
be based on information from reliable
and adequately documented sources
and be applicable to and appropriate for
the affected facility.636
Additionally, as discussed in section
XII.D.1.a of this preamble, the EPA is
proposing a methodology for calculating
an affected EGU’s baseline emissions as
part of determining its presumptively
approvable standard of performance.
The EPA explained that while the
proposed methodology should be
flexible enough to accommodate most
unit-specific circumstances, it may not
be appropriate to use recent historical
emissions data to represent baseline
emission performance when an affected
EGU anticipates that its future operating
conditions will change significantly.
Consistent with the proposed subpart
Ba, the EPA is proposing that states
wishing to rely on an affected EGU’s
anticipated change in operating
conditions as the basis for using a
different methodology to set an
emissions baseline would be required to
use the RULOF mechanism described in
this section of the preamble.
The EPA solicits comment on the
application of the RULOF provisions of
proposed subpart Ba, both in sum and
as individual, segregable pieces, to these
emission guidelines. In particular, the
EPA requests comment on factual
circumstances in which it may or may
not be appropriate for states to invoke
RULOF for affected EGUs, given the
proposed BSER determinations and
presumptive standards of performance,
and the EPA’s proposed ‘‘fundamental
difference’’ standard in the subpart Ba
rulemaking. For the consideration of
635 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(e)(3)).
636 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(j)).
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cost, the EPA requests comment on
whether it should provide further
guidance or requirements for
determining when the costs of a control
technology for a particular source are
‘‘fundamentally different’’ from the
Agency’s BSER determination and thus
a basis for invoking RULOF. The EPA
additionally seeks comment on any
source category-specific considerations
for invoking RULOF for affected EGUs,
including any additional or different
requirements that might be necessary to
ensure that use of RULOF does not
undermine the presumptive stringency
of these emission guidelines.
b. Calculation of a Standard That
Accounts for RULOF
Subpart Ba, both the presently
applicable requirements and as the EPA
has proposed to revise them, provides
that, if a State has demonstrated that
accounting for RULOF is appropriate for
a particular affected EGU, the State may
then apply a less stringent standard to
that EGU. The EPA’s proposed revisions
to subpart Ba would require that, in
doing so, the State must determine a
source-specific BSER by identifying all
the systems of emission reduction
available for the source and evaluating
each system using the same factors and
evaluation metrics that the EPA
considered in determining the BSER for
the applicable subcategory.637 As part of
determining source-specific BSER, the
State would also have to determine the
degree of emission limitation that can be
achieved by applying this sourcespecific BSER to the particular source.
The State would then calculate and
apply the standard of performance that
reflects this degree of emission
limitation.638
Consistent with these proposed
requirements in subpart Ba, the EPA is
proposing that states invoking RULOF
would be required to evaluate certain
controls as appropriate for subcategories
of affected EGUs. The EPA believes
these proposed requirements are
necessary to ensure that states
reasonably consider the controls that
may qualify as the best system of
emission reduction. Additionally, the
EPA is proposing to provide the order
in which states must evaluate controls.
A list of controls, ordered from more to
less stringent, can provide useful
637 To the extent that a state seeks to apply
RULOF to a class of affected EGUs that the state can
demonstrate are similarly situated in all meaningful
ways, the EPA proposes to permit the state to
conduct an aggregate analysis of the BSER factors
for the entire class of EGUs for which RULOF has
been invoked.
638 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(f)).
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streamlining as states may reasonably
choose to conduct a less in-depth
evaluation of controls further down the
list if they determine a more stringent
control is the best system of emission
reduction for a particular source. The
EPA also believes that providing a list
of controls for evaluation will provide
states with clarity and certainty about
what the Agency will find is a
satisfactory source-specific BSER
analysis pursuant to the RULOF
mechanism. However, the EPA is also
requesting comment on whether to
provide lists of controls to be evaluated
in a source-specific BSER analysis as a
presumptively approvable approach, as
opposed to requirements. Regardless of
how the EPA finalizes the approach to
controls for source-specific analyses,
states would retain discretion to
evaluate additional types of controls as
part of a source-specific BSER
determination for sources pursuant to
RULOF.
The EPA is proposing to require states
invoking RULOF for affected coal-fired
EGUs in the long-term subcategory to
evaluate natural gas co-firing as a
potential source-specific BSER.
Additionally, if an EGU in the long-term
subcategory can implement CCS but
cannot achieve the degree of emission
limitation prescribed by the
presumptive standard of performance,
the EPA is proposing that the State
evaluate CCS with a source-specific
degree of emission limitation as a
potential BSER. The EPA is also
proposing that states invoking RULOF
for affected long-term and medium-term
coal-fired EGUs must evaluate different
levels of natural gas co-firing. For
example, for a source in the mediumterm subcategory that cannot reasonably
co-fire 40 percent natural gas, the State
must then evaluate lower levels of
natural gas co-firing unless it has
demonstrated that natural gas co-firing
at any level is physically impossible or
technically infeasible at the source.
Similarly, if a State invoking RULOF for
an affected EGU in the long-term
subcategory demonstrates that the EGU
cannot co-fire with natural gas at 40
percent, the EPA is proposing that the
State must then evaluate lower levels of
co-firing as potential BSERs for the
source, unless the State can demonstrate
that it is physically impossible or
technically infeasible for the source to
co-fire natural gas. States may also
consider additional potential sourcespecific BSERs for affected EGUs in
either subcategory.
For states invoking RULOF for
affected existing combustion turbine
EGUs, the EPA is similarly proposing a
requirement to evaluate certain control
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strategies as part of a source-specific
BSER analysis. As a preliminary step,
for sources in either the CCS
combustion turbine subcategory or the
hydrogen co-fired combustion turbine
subcategory, the EPA is proposing that
a State would first have to demonstrate
why the affected EGU cannot reasonably
participate in the other subcategory and
meet that other subcategory’s
presumptive standard of performance. If
a unit can reasonably comply with the
presumptive standard of performance
for the alternate source category, it must
do so.
For combustion turbines in the CCS
subcategory that cannot reasonably
comply with the presumptive standards
of performance for either that
subcategory or the hydrogen co-fired
subcategory, the EPA is proposing that,
unless a State has demonstrated that it
is physically impossible or technically
infeasible for a unit to implement CCS,
the State must evaluate CCS with lower
rates of carbon capture as a potential
BSER. If CCS with lower rates of capture
is not the BSER, the State would then
be required to consider comprehensive
turbine upgrades, and finally smaller
scale efficiency improvements. For
hydrogen co-fired combustion turbines
that cannot reasonably comply with the
presumptive standards of performance
for either subcategory, a State would
first analyze lower percentages of
hydrogen co-firing, followed by
comprehensive turbine upgrades, and
lastly smaller scale efficiency
improvements. States would also be free
to analyze additional potential sourcespecific BSERs for affected combustion
turbine EGUs in either subcategory.
The EPA requests comment on the
proposed requirement to consider
certain control technologies as part of
source-specific BSER determinations,
and specifically on whether the Agency
should require this approach as
proposed or, in the alternative, provide
it as a presumptively approvable
approach to conducting a sourcespecific BSER analysis.
The EPA notes again that, under both
the proposed subpart Ba and CAA
section 111(d),639 an affected EGU that
cannot reasonably apply the EPA’s
BSER but can achieve the degree of
emission limitation for the applicable
subcategory through other reasonable
systems of emission reduction cannot be
639 As discussed earlier in this preamble,
permitting a state to apply a less stringent standard
to an affected EGU that can achieve the degree of
emission limitation the EPA determined is required
would be inconsistent with CAA section 111(d). See
also 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(g)).
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given a less stringent standard of
performance. In this case, the affected
EGU’s standard of performance would
still reflect the degree of emission
limitation achievable through
application of the EPA’s BSER.
The EPA has proposed in its revisions
to subpart Ba that specific requirements
would apply when invoking RULOF
based on an affected source’s remaining
useful life.640 Among other
requirements, the EPA in an emission
guideline would have to either identify
the outermost date to cease operations
for the relevant source category that
qualifies for consideration of remaining
useful life or provide a methodology
and considerations for states to use in
establishing such an outermost date.
Proposed subpart Ba also provides that
an affected source with a date to cease
operations that is both imminent and
prior to the outermost date could be
eligible for a standard of performance
that reflects that source’s BAU. The EPA
is proposing to supersede the
application of subpart Ba for coal-fired
steam generating units with respect to
the proposed requirements to establish
outermost and imminent dates to cease
operations for invoking RULOF based
on an affected EGU’s remaining useful
life. As explained earlier in this section
of the preamble, the EPA has designed
the subcategories for coal-fired affected
EGUs under these emission guidelines
to accommodate sources’ self-identified
operating horizons. This approach to
subcategorization obviates the need to
establish an outermost date to cease
operations to guide states’ and affected
EGUs’ consideration of remaining useful
life. Additionally, the EPA is proposing
to establish an imminent-term
subcategory with a proposed BSER
determination of routine operation and
maintenance, which serves the same
purpose as establishing an imminent
date to cease operations under the
RULOF provision. Although it is not
anticipated that states will have a reason
to invoke RULOF due to a coal-fired
EGU’s imminent date to cease
operations based on the structure of the
subcategories under these emission
guidelines, states are not precluded
from doing so based on unit-specific
circumstances.
Because of the small number of
sources in the oil- and natural gas-fired
steam generating unit subcategories and
the diversity of circumstances in which
they operate, the EPA is not proposing
to establish outermost or imminent
640 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(h),
(i)).
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33385
dates to cease operations for the purpose
of considering remaining useful life for
these sources. Regardless, because the
proposed BSER determinations for these
EGUs is routine methods of operation
and maintenance (other than for lowload oil- and natural gas-fired steam
generating units), the EPA does not
anticipate that states will find it
necessary to invoke RULOF for these
sources.
The EPA is also proposing to
supersede the requirement in subpart Ba
to establish imminent and outermost
dates for the consideration of remaining
useful life for affected combustion
turbine EGUs. While, as discussed
above in this section of the preamble, it
is likely that some portion of the
existing combustion turbine fleet will be
reaching the end of its remaining useful
life in the 2035 to 2040 timeframe, the
structure of the proposed subcategories,
the length of time between State plan
submission and the compliance dates
for the subcategories, and the staggered
compliance dates for the two
subcategories make it difficult to set a
widely-applicable date or dates that
represent an imminent cessation of
operations. States would not be
precluded from demonstrating that an
affected combustion turbine EGU’s
remaining useful life is so short that it
qualifies for a business-as-usual
standard of performance (i.e., that its
remaining useful life is so short that the
cost of any control would be
unreasonably high). Similarly, based on
the proposed BSERs for the
subcategories and the staggered nature
of the proposed compliance dates for
combustion turbine EGUs, the EPA does
not believe it is helpful to set an
outermost date for the considering of
remaining useful life for these units.
The EPA requests comment on its
proposal to supersede the requirements
in subpart Ba to set imminent and
outermost dates for the consideration of
remaining useful life for affected
combustion turbine EGUs. If
commenters believe such dates would
be useful to guide states’ consideration
of remaining useful life for affected
existing combustion turbines, the EPA
further requests input on what those
dates could be, and why.
The proposed subpart Ba would
require that any plan that applies a less
stringent standard to a particular
affected EGU based on remaining useful
life must include the date by which the
EGU commits to permanently cease
operations as an enforceable
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requirement.641 The plan would also
have to include measures that provide
for the implementation and enforcement
of such a commitment. The EPA is not
proposing to supersede this proposed
requirement for the purpose of this
emission guideline; states that include a
RULOF standard based on an affected
EGU’s remaining useful life must make
the source’s voluntary commitment to
permanently cease operations by a date
certain enforceable in the State plan.
Similarly, subpart Ba would require
that if a State seeks to rely on a source’s
operating conditions, such as its
restricted capacity, as the basis for
invoking RULOF and setting a less
stringent standard, the State plan must
include that operating condition as an
enforceable requirement.642 This
requirement would apply to operating
conditions that are within an affected
EGU’s control and is necessary to ensure
that a source’s standard of performance
matches what that source can
reasonably achieve and does not
undermine the stringency of these
emission guidelines.
The proposed presumptively
approvable standards of performance for
affected EGUs in these emission
guidelines are expressed in the form of
rate-based emission limitations,
specifically, as lb CO2/MWh. Therefore,
to ensure transparency and to enable the
EPA, states, and stakeholders to ensure
that RULOF standards do not
undermine the presumptive stringency
of these emission guidelines, the EPA is
proposing to require that standards of
performance determined through this
RULOF mechanism be in the same form
of rate-based emission limitations.643
The EPA seeks comment on
implementation of the proposed subpart
Ba requirements pertaining to
determining a source-specific BSER and
calculating a less stringent standard for
sources invoking RULOF under these
emission guidelines. It also seeks
comment on the proposed requirements
that are specific to these emission
guidelines, including but not limited to
the proposed requirement that states
evaluate certain control options for
affected coal-fired steam generating
units in the long-term and medium-term
subcategories and for affected
641 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(h),
(i)(3)).
642 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(h)).
643 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(f)(3)).
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combustion turbine EGUs as part of
their source-specific BSER
determination, the proposal to not
provide outermost or imminent dates to
cease operations for the consideration of
remaining useful life, and the proposal
to require RULOF standards of
performance to be in the form of lb CO2/
MWh emission limitations.
c. Consideration of Impacted
Communities
While the consideration of RULOF
may warrant application of a less
stringent standard of performance to a
particular affected EGU, such standards
have the potential to result in disparate
health and environmental impacts to
communities most affected by and
vulnerable to impacts from those EGUs.
Those communities could be put in the
position of bearing the brunt of the
greater health and environmental
impacts resulting from an affected EGU
implementing a less stringent standard
of performance than would otherwise
have been required pursuant to the
emission guidelines. A lack of
consideration of such potential
outcomes would be antithetical to the
public health and welfare goals of CAA
section 111(d).
Therefore, the proposed subpart Ba
revisions would require that states
applying less stringent standards of
performance consider the potential
pollution impacts and benefits of
control to communities most affected by
and vulnerable to emissions from the
affected EGU in determining sourcespecific BSERs and the degree of
emission limitation achievable through
application of such BSERs.644 The State
will have identified these communities
as pertinent stakeholders in the process
of meaningful engagement, which is
discussed in section XII.F.1.b of this
preamble.
If the EPA finalizes the requirement
under subpart Ba to consider the
potential pollution impacts and benefits
of control to the communities most
affected by and vulnerable to emissions
from a RULOF source communities as
proposed, State plan submissions under
these emission guidelines would have to
demonstrate that the State considered
such impacts and benefits in applying a
less stringent standard of performance
to such a source. The EPA expects that
states’ meaningful engagement with
pertinent stakeholders on the State plan
development generally will include
engagement on any potential use of
RULOF to apply less stringent standards
644 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(k)).
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of performance. The proposed
requirement that states consider the
potential pollution impacts and benefits
of control in the context of a sourcespecific BSER analysis for a particular
source is intended to provide for states’
consideration of health and
environmental effects on the
communities that are most affected by
and vulnerable to emissions from that
particular source. As an example, the
State plan submission could include a
comparative analysis assessing potential
BSER options for an affected EGU and
the corresponding potential benefits to
the identified communities under each
option. If the comparative analysis
shows that emissions from an affected
EGU could be controlled at a higher cost
but that such control benefits the
communities that would otherwise be
adversely impacted by a less stringent
standard of performance, the State could
balance these considerations and
determine that a higher cost is
warranted for the source-specific BSER.
The plan submission under these
emission guidelines must clearly
identify the communities most affected
by and vulnerable to emissions from the
designated facility. The EPA is
proposing that, in evaluating potential
source-specific BSERs, a State must
document any health or environmental
impacts and benefits of control options
and describe how it considered those
impacts on the identified communities.
Pursuant to the proposed meaningful
engagement requirements discussed in
section XII.F.1.b of this preamble, states’
plan submissions would also be
required to include a summary of the
meaningful engagement the State
conducted and a summary of
stakeholder input received, including
any engagement and input on RULOF
sources and the calculation of lessstringent standards of performance.
The EPA solicits comments on
additional ways in which states might
consider potential pollution impacts
and benefits of control to communities
most affected by and vulnerable to
emissions from affected EGUs when
determining a less-stringent standard
pursuant to RULOF. In particular, the
Agency is requesting comment on
metrics or information concerning
health and environmental impacts from
affected EGUs that states can consider in
source-specific RULOF determinations.
As discussed in section XII.F.1.b, the
EPA is also requesting comment on
tools and methodologies for identifying
communities that are most affected by
and vulnerable to emissions from
affected EGUs under these emission
guidelines.
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d. The EPA’s Standard of Review of
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Under CAA section 111(d)(2), the EPA
has the obligation to determine whether
a State plan submission is
‘‘satisfactory.’’ This obligation extends
to all aspects of a State plan, including
the application of less stringent
standards of performance that account
for RULOF. Pursuant to CAA section
111(d) and the proposed subpart Ba
provisions,645 states carry the burden of
making the demonstrations required
under the RULOF mechanism and have
the obligation to justify any accounting
for RULOF in support of standards of
performance that are less stringent than
the proposed presumptively approvable
standards in these emission guidelines.
While the EPA has the discretion to
supplement a State’s demonstration, the
EPA may also find that inadequacies in
a State plan’s demonstration are a basis
for concluding that the plan is not
‘‘satisfactory’’ and may therefore
disapprove the plan.
As a general matter, a less stringent
standard of performance pursuant to
RULOF must meet all other applicable
requirements of subpart Ba and these
emission guidelines.646
In determining whether a State has
met its burden in providing a less
stringent standard of performance based
on RULOF, the EPA will consider,
among other things, the applicability
and appropriateness of the information
on which the State relied. Both a
demonstration that a particular affected
EGU meets the threshold requirements
to invoke RULOF and the determination
of a source-specific standard of
performance entail the use of technical,
cost, engineering, and other
information. The proposed subpart Ba
revisions would require states to use
information that is applicable to and
appropriate for the particular source at
issue.647 This means that, when
available, the State must use source- and
site-specific information. This is
consistent with the premise that
invoking RULOF is appropriate for a
particular source when there are
fundamental differences between the
EPA’s BSER and that source’s specific
circumstances.
645 CAA section 111(d)(2), 87 FR 79176
(December 23, 2022), Docket ID No. EPA–HQ–
OAR–2021–0527–0002 (proposed revisions to
RULOF provisions at 40 CFR 60.24a(j)).
646 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR 60.24a(l)).
647 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(j)(1)).
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In some instances, site-specific
information may not be available. In
such cases, it may be reasonable for a
State to use information from, e.g., cost,
engineering, and other analyses the EPA
has provided to support this
rulemaking. The EPA is proposing that
states using non-site-specific
information must explain why that
information is reasonable to rely on to
determine a less stringent standard of
performance based on RULOF.
Regardless of the information used, it
must come from reliable and adequately
documented sources, which the
proposed subpart Ba revisions explain
presumptively include sources
published by the EPA, permits,
environmental consultants, control
technology vendors, and inspection
reports.648
The EPA solicits comment on the
types of source-specific and other
information that states should be
required to provide to support the
inclusion of standards of performance
based on RULOF in State plans, as well
as on any additional sources of
information that may be appropriate for
states to use in this context.
e. Authority To Apply More Stringent
Standards as Part of State Plans
As explained in the subpart Ba notice
of proposed rulemaking, the EPA
reevaluated its interpretation of CAA
sections 111(d) and 116 and, consistent
with its revised interpretation, has
proposed revisions to subpart Ba to
clarify that states may consider RULOF
to include more stringent standards of
performance in their State plans.649 The
allowance in CAA section 111(d)(1) that
states may consider ‘‘other factors’’ does
not limit states to considering only
factors that may result in a less stringent
standard of performance; other factors
that states may wish to account for in
applying a more stringent standard than
provided in these emission guidelines
include, but are not limited to, effects
on local communities, the availability of
control technologies that allow a
particular source to achieve greater
emission reductions, and local or State
policies and requirements.
Pursuant to proposed subpart Ba,
states seeking to apply a more stringent
standard of performance based on other
factors would have to adequately
demonstrate that the standard is in fact
648 87
FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(j)(2)).
649 87 FR 79176, 79204 (December 23, 2022),
Docket ID No. EPA–HQ–OAR–2021–0527–0002
(proposed revisions to RULOF provisions at 40 CFR
60.24a(m), (n)).
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33387
more stringent than the presumptively
approvable standard of performance for
the applicable subcategory. However, a
State would not be required to conduct
a source-specific BSER evaluation for
the purpose of applying a more stringent
standard of performance, so long as the
standard will achieve equivalent or
better emission reductions. In this case,
the EPA believes it is appropriate to
defer to the State’s discretion to impose
a more stringent standard on an
individual source because such a
standard does not have the potential to
undermine the presumptive stringency
of these emission guidelines.
More stringent standards of
performance must meet all applicable
statutory and regulatory requirements,
including that they are adequately
demonstrated.650 As for all standards of
performance, the State plan must
include requirements that provide for
the implementation and enforcement of
a more stringent standard. The EPA has
the ability and authority to review more
stringent standards of performance and
to approve them provided that the
minimum requirements of subpart Ba
and these emission guidelines are met,
rendering them federally enforceable.
The EPA requests comment on the
implementation of the proposed subpart
Ba provisions pertaining to more
stringent standards of performance in
the context of these particular emission
guidelines.
3. Increments of Progress and
Milestones for Affected EGUs That Have
Elected To Commit To Cease Operations
The EPA’s long-standing CAA section
111 implementing regulations at 40 CFR
part 60, subpart Ba 651 provide that State
plans must include legally enforceable
increments of progress to achieve
compliance for each designated facility
when the compliance schedule extends
more than a specified length of time
from the State plan submission date.652
The EPA’s December 2022 proposed
revisions to subpart Ba would require
increments of progress when the
compliance date is more than 16 months
after the State plan submission
deadline.653 Under these proposed
emission guidelines, the State plan
submission date would be 24 months
(see section XII.F.2 of this preamble)
from promulgation of the emission
650 87 FR 79176, 79204 (December 23, 2022),
Docket ID No. EPA–HQ–OAR–2021–0527–0002
(proposed revisions to RULOF provisions at 40 CFR
60.24a(m)).
651 See also 40 CFR 60.21(h).
652 40 CFR 60.24a(d).
653 87 FR 79176, 79204 (December 23, 2022),
Docket ID No. EPA–HQ–OAR–2021–0527–0002
(proposed revisions at 40 CFR 60.24a(d)).
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guidelines, which the EPA is currently
anticipating will be June 2026. The
proposed compliance dates for affected
EGUs within the proposed subcategories
all fall on or after January 1, 2030,
which is more than 16 months after the
State plan submission deadline. The
EPA is therefore proposing to require
that State plans include increments of
progress as discussed in this section.
For the purpose of these emission
guidelines, the EPA refers to precompliance date, federally enforceable
requirements associated with the
planning, construction, and operation of
natural gas or hydrogen co-firing
infrastructure and CCS as increments of
progress. The EPA is also proposing
separate, federally enforceable
‘‘milestones’’ associated with activities
surrounding enforceable dates to
permanently cease operations for steam
generating EGUs in the imminent-term,
near-term, and medium-term
subcategories. These additional State
plan requirements are intended to
ensure that affected coal-fired steam
generating units can complete the steps
necessary to qualify for a subcategory
with a less stringent BSER and to
provide the public assurance that those
steps will be concluded in a timely
manner.
a. Increments of Progress
The EPA is proposing to adopt
emission guideline-specific
implementation of the five generic
increments specified in the CAA section
111(d) implementing regulations at 40
CFR 60.21a(h). These five increments of
progress are: (1) Submittal of a final
control plan for the designated facility
to the appropriate air pollution control
agency; (2) Awarding of contracts for
emission control systems or for process
modifications, or issuance of orders for
the purchase of component parts to
accomplish emission control or process
modification; (3) Initiation of on-site
construction or installation of emission
control equipment or process change;
(4) Completion of on-sites construction
or installation of emission control
equipment or process change; and (5)
Final compliance. To this end, the EPA
is proposing that State plans must
include specified enforceable
increments of progress as required
elements for coal-fired EGUs that use
natural gas co-firing to meet the
standard of performance for the
medium-term existing coal-fired steam
generating subcategory and for natural
gas-fired combustion turbine EGUs that
use hydrogen co-firing to meet the
standard of performance for hydrogen
co-fired combustion turbine
subcategory. The EPA is additionally
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proposing that State plans must include
enforceable increments of progress for
units that use CCS to meet the standard
of performance for the long-term
existing coal-fired steam generating
subcategory or for the CCS combustion
turbine subcategory.
Some increments have been adjusted
to more closely align with planning,
engineering, and construction steps
anticipated for designated facilities that
will be complying with standards of
performance with natural gas or
hydrogen co-firing or CCS, but they
retain the basic structure and substance
of the increments in the general
implementing regulations. In addition,
consistent with 40 CFR 60.24a(d), the
EPA is proposing similar additional
increments of progress for the long-term
and medium-term coal-fired
subcategories as well as both
combustion turbine subcategories to
ensure timely progress on the planning,
permitting, and construction activities
related to pipelines that may be required
to enable full compliance with the
applicable standard of performance. The
EPA is also proposing an additional
increment of progress related to the
identification of an appropriate
sequestration site for the long-term coalfired subcategory and the CCS
combustion turbine subcategory.
Finally, the proposed emission
guidelines include an additional
increment of progress that that applies
solely to the hydrogen co-fired
combustion turbine subcategory related
to securing sufficient hydrogen contract
capacity to meet the standard of
performance.
The EPA notes that affected EGUs do
not necessarily have to implement the
EPA’s BSER technology to comply with
their applicable standards of
performance. For example, affected
EGUs in the medium- and long-term
coal-fired steam generating unit
subcategories may meet their standards
of performance using approaches other
than natural gas co-firing and CCS,
respectively. Where the owners or
operators of affected EGUs select
compliance approaches that deviate
from the BSER technology associated
with a subcategory requiring increments
of progress, the EPA proposes that the
State plan would be required to specify
increments of progress for the relevant
affected EGUs that are consistent with
the increments in 40 CFR 60.21a(h), as
well as dates for achieving each
increment.
The EPA is proposing that final
compliance with the applicable
standard of performance, also defined as
the final increment of progress at 40
CFR 60.21a(h)(5), must occur no later
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than January 1, 2030 for steam
generating units in the medium-term
and long-term subcategories, no later
than January 1, 2035 for combustion
turbine EGUs in the CCS subcategory,
and no later than January 1, 2032 for
combustion turbine EGUs in the
hydrogen co-fired subcategory.654 For
the remaining increments, the EPA is
not proposing date-specific deadlines
for achieving increments of progress.
Instead, the EPA proposes that states
must assign calendar day deadlines for
each of the remaining increments for
each affected EGU in their State plan
submissions. The first increment of
progress listed at 40 CFR 60.21a(h)(1),
submittal of a final control plan to the
air pollution control agency, must be
assigned the earliest calendar date
deadline among the increments. The
EPA believes that allowing states to
schedule sources’ increments of
progress would provide them with
flexibility to tailor compliance timelines
to individual facilities, allow
simultaneous work toward separate
increments, and still ensure full
performance by the compliance date.
The EPA solicits comment on this
approach as well as whether the EPA
should instead finalize date-specific
deadlines or more general timeframes
for achieving increments of progress
rather than leaving the timing for most
increments to State discretion. The EPA
also seeks comment on the specific
deadlines or timeframes that the EPA
could assign to each increment under a
more prescriptive approach.
The EPA is not proposing increments
of progress for either the imminent- or
near-term subcategories for coal-fired
steam generating units, or for oil- or
natural gas-fired steam generating units.
The proposed BSERs for these affected
EGUs are routine operation and
maintenance, which does not require
the installation of significant new
emission controls or operational
changes. Because there is no need for
the types of increments of progress
specified in 40 CFR 60.21a(h) to ensure
that affected EGUs in the imminent and
near-term coal-fired and oil- and natural
gas-fired subcategories can achieve full
compliance by the compliance date, the
EPA is proposing that the requirement
654 The EPA is proposing that the second phase
of the standard of performance for existing
hydrogen co-fired combustion turbines, which
corresponds to co-firing 96 percent by volume lowGHG hydrogen, would start on January 1, 2038.
However, the EPA is not proposing an increment of
progress associated with this second phase because
the Agency anticipates the relevant planning,
design, and construction steps will have occurred
ahead of the January 1, 2032 compliance date.
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for increments of progress in 40 CFR
60.24a(d) does not apply to these units.
For coal-fired steam generating units
falling within the medium-term
subcategory and combustion turbine
EGUs within the hydrogen co-fired
subcategory (i.e., units with proposed
BSERs of co-firing clean fuels), the EPA
proposes the following increments of
progress as enforceable elements
required to be included in a State plan:
(1) Submission of a final control plan for
the affected EGU to the appropriate air
pollution control agency. The final
control plan must be consistent with the
subcategory declaration in the State
plan and must include supporting
analysis for the affected EGU’s control
strategy, including the design basis for
modifications at the facility, the
anticipated timeline to achieve full
compliance, and the benchmarks the
facility anticipates along the way. (2)
Awarding of contracts for boiler or
turbine modifications, or issuance of
orders for the purchase of component
parts to accomplish such modifications.
Affected EGUs can demonstrate
compliance with this increment by
submitting sufficient evidence that the
appropriate contracts have been
awarded. (3) Initiation of onsite
construction or installation of any boiler
or turbine modifications necessary to
enable natural gas co-firing at a level of
40 percent on an annual average basis
or hydrogen co-firing at 30 percent on
an annual average basis, as appropriate
for the applicable subcategory. (4)
Completion of onsite construction of
any boiler or turbine modifications
necessary to enable natural gas co-firing
at a level of 40 percent on an annual
average basis or hydrogen co-firing at 30
percent on an annual average basis, as
appropriate for the applicable
subcategory. (5) Final compliance with
the standard of performance by January
1, 2030 for coal-fired steam generating
units and by January 1, 2032 for
combustion turbine EGUs.
In addition to the five increments of
progress derived from the CAA section
111(d) implementing regulations, the
EPA is proposing an additional
increment of progress for affected EGUs
with proposed BSERs based on co-firing
clean fuels (natural gas co-firing for
medium-term coal-fired steam
generating EGUs and hydrogen co-firing
for hydrogen co-fired combustion
turbine EGUs) to ensure timely
completion of any pipeline
infrastructure needed to transport
natural gas or hydrogen to designated
facilities within each subcategory.
Affected EGUs would be required to
demonstrate that all permitting actions
related to pipeline construction have
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commenced by a date specified in the
State plan. Evidence in support of the
demonstration must include pipeline
planning and design documentation that
informed the permitting application
process, a complete list of pipelinerelated permitting applications,
including the nature of the permit
sought and the authority to which each
permit application was submitted, an
attestation that the list of pipelinerelated permit applications is complete
with respect to the authorizations
required to operate the facility at full
compliance with the standard of
performance, and a timeline to complete
all pipeline permitting activities.
Affected EGUs within the hydrogen
co-fired combustion turbine subcategory
must meet an additional increment of
progress to demonstrate they have
secured access to hydrogen supplies
sufficient to meet their anticipated 2032
fuel needs. This increment can be met
by a capacity contract for hydrogen at
volumes in 2032 consistent with the
information provided in the final
control plan and the pipeline
specification included in the pipeline
construction increment of progress.
For coal-fired EGUs falling within the
long-term subcategory and for
combustion turbine EGUs falling within
the CCS subcategory (i.e., units with
proposed BSERs of CCS), the EPA
proposes the following increments of
progress as required, enforceable
elements to be included in a State plan
submission: (1) Submission of a final
control plan for the affected EGU to the
appropriate air pollution control agency.
The final control plan must be
consistent with the subcategory
declaration in the State plan and must
include supporting analysis for the
affected EGU’s control strategy,
including a feasibility and/or FEED
study. (2) Awarding of contracts for
emission control systems or for process
modifications, or issuance of orders for
the purchase of component parts to
accomplish emission control or process
modification. Affected EGUs can
demonstrate compliance with this
increment by submitting sufficient
evidence that the appropriate contracts
have been awarded. (3) Initiation of
onsite construction or installation of
emission control equipment or process
change required to achieve 90 percent
CO2 capture on an annual basis. (4)
Completion of onsite construction or
installation of emission control
equipment or process change required
to achieve 90 percent CO2 capture on an
annual basis. (5) Final compliance with
the standard of performance by January
1, 2030 for coal-fired steam generating
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33389
units and by January 1, 2035 for
combustion turbine EGUs.
In addition to the five increments of
progress derived from the CAA section
111(d) implementing regulations, the
EPA is proposing two additional
increments for affected EGUs that adopt
CCS to meet the standard of
performance for the long-term coal-fired
steam generating unit and CCS
combustion turbine subcategories. The
first mirrors the proposed approach for
the co-firing subcategories to ensure
timely completion of pipeline
infrastructure and the second is
designed to ensure timely selection of
an appropriate sequestration site. As the
first additional increment, the EPA
proposes that affected EGUs using CCS
to comply with their standards of
performance would be required to
demonstrate that all permitting actions
related to pipeline construction have
commenced by a date specified in the
State plan. Evidence in support of the
demonstration must include pipeline
planning and design documentation that
informed the permitting process, a
complete list of pipeline-related
permitting applications, including the
nature of the permit sought and the
authority to which each permit
application was submitted, an
attestation that the list of pipelinerelated permits is complete with respect
to the authorizations required to operate
the facility at full compliance with the
standard of performance, and a timeline
to complete all pipeline permitting
activities.
The second proposed additional
increment of progress for affected EGUs
using CCS to comply with their
standards of performance is formulated
to ensure timely completion of site
selection for geologic sequestration of
captured CO2 from the facility. Affected
EGUs within this subcategory must
submit a report identifying the
geographic location where CO2 will be
injected underground, how the CO2 will
be transported from the capture location
to the storage location, and the
regulatory requirements associated with
the sequestration activities, as well as an
anticipated timeline for completing
related permitting activities.
The EPA requests comment on the
substance of each of the six proposed
increments of progress for coal-fired
steam generating units falling within the
medium-term subcategory, the seven
increments of progress for units within
the hydrogen co-fired combustion
turbine subcategory, and the seven
increments of progress proposed for
both subcategories that anticipate CCS
adoption. The EPA seeks comment on
whether the increments contain an
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appropriate level of specificity to
establish clear, verifiable criteria to
ensure that states and affected EGUs are
taking the steps necessary to reach full
compliance. If commenters believe they
do not, the EPA requests comment on
the appropriate level of specificity for
each increment. Additionally, as
discussed in section XII.F.1.b.ii of this
preamble, the EPA is proposing a
requirement that each State plan
provide for the establishment of Carbon
Pollution Standards for EGUs websites
by the owners or operators of affected
EGUs. The EPA is further proposing that
State plans must require affected EGUs
with increments of progress to post
those increments, the schedule required
in the State plan for achieving them,
and any documentation necessary to
demonstrate that they have been
achieved to this website in a timely
manner.
b. Milestones for Affected EGUs That
Have Elected To Commit To Cease
Operations
The EPA is proposing that State plans
must include legally enforceable
milestones for affected EGUs within the
imminent-term, near-term, and mediumterm coal-fired steam generating unit
subcategories. As described in section X
of this preamble, the applicability
criteria for each of the subcategories of
coal-fired steam generating units
include an affected EGU’s intended
operating horizon; where owners or
operators of affected EGUs have elected
to commit to permanently cease
operations by a date certain before
January 1, 2040, and, where a State
further elects to include such
commitments as an enforceable element
in a State plan, such EGUs will fall into
one of these three subcategories.
Accordingly, affected EGUs in the
imminent-term, near-term, and mediumterm subcategories have BSERs that are
specifically tailored to and dependent
on their shorter operating horizons. The
EPA is aware that there are many
processes an affected EGU must
complete in order to permanently cease
operation. Therefore, to ensure that
affected EGUs can complete the steps
necessary to qualify for a subcategory
with a less stringent standard of
performance and to provide the public
assurance that those steps will be
concluded in a timely manner, the EPA
is proposing additional State plan
requirements, referred to as
‘‘milestones,’’ for EGUs in the
imminent-term, near-term, and mediumterm subcategories.
The proposed milestone reporting
requirements count backward from an
affected EGU’s date to permanently
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cease operations to ensure timely
progress toward that date. Five years
before any date used to determine the
applicable subcategory under these
emission guidelines or 60 days after
State plan submission, whichever is
later, designated facilities must submit
an Initial Milestone Report to the
applicable State administering authority
that includes the following: (1) A
summary of the process steps required
for the affected EGU to permanently
cease operation by the date included in
the State plan, including the
approximate timing and duration of
each step. (2) A list of key milestones,
metrics that will be used to assess
whether each milestone has been met,
and calendar day deadlines for each
milestone. These milestones must
include at least the following: notice to
the official reliability authority of the
retirement date; submittal of an official
suspension filing (or equivalent filing)
made to the affected EGU’s reliability
authority; and submittal of an official
retirement filing with the unit’s
reliability authority. (3) An analysis of
how the process steps, milestones, and
associated timelines included in the
Milestone Report compare to the
timelines of similar units within the
State that have permanently ceased
operations within the 10 years prior to
the date of promulgation of these
emission guidelines. (4) Supporting
regulatory documents, including
correspondence and official filings with
the relevant regional transmission
organization, balancing authority,
public utility commission, or other
applicable authority, as well as any
filings with the SEC or notices to
investors in which the plans for the
EGU are mentioned and any integrated
resource plan.
For each of the remaining years prior
to the date to permanently cease
operations that is used to determine the
applicable subcategory, affected EGUs
must submit an annual Milestone Status
Report that addresses the following: (1)
Progress toward meeting all milestones
and related metrics identified in the
Milestone Report; and (2) supporting
regulatory documents, including
correspondence and official filings with
the relevant regional transmission
organization, balancing authority,
public utility commission, or other
applicable authority to demonstrate
compliance with or progress toward all
milestones.
The EPA is also proposing that
affected EGUs with reporting milestones
associated with commitments to
permanently cease operations would be
required to submit a Final Milestone
Status Report no later than 6 months
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following its federally enforceable date.
This report would document any
actions that the unit has taken
subsequent to ceasing operation to
ensure that such cessation is permanent,
including any regulatory filings with
applicable authorities or
decommissioning plans. The EPA
requests input on whether 6 months
after the federally enforceable date is an
appropriate period of time to capture
any actions affected EGUs taken
following cessation of operations.
The EPA is proposing that affected
EGUs with reporting milestones for
commitments to permanently cease
operations would be required to post
their Initial Milestone Report, annual
Milestone Status Reports, and Final
Milestone Status Report, including the
schedule for achieving milestones and
any documentation necessary to
demonstrate that milestones have been
achieved, on the Carbon Pollution
Standards for EGUs website, as
described in section XII.F.1.b, within 30
business days of being filed.
The EPA recognizes that applicable
regulatory authorities, retirement
processes, and retirement approval
criteria will vary across states and
affected EGUs. The proposed milestone
requirements are intended to establish a
general framework flexible enough to
account for significant differences
across jurisdictions while assuring
timely planning toward the dates by
which affected EGUs permanently cease
operations. The EPA requests comment
on this proposed approach, specifically
whether any jurisdictions present
unique State circumstances that should
be considered when defining milestones
and the required reporting elements.
4. Testing and Monitoring Requirements
The EPA is proposing to require states
to include in their plans a requirement
that affected EGUs monitor and report
hourly CO2 mass emissions emitted to
the atmosphere, total heat input, and
total gross electricity output, including
electricity generation and, where
applicable, useful thermal output
converted to gross MWh, in accordance
with the 40 CFR part 75 monitoring and
reporting requirements. Under this
proposal, affected EGUs would be
required to use a 40 CFR part 75
certified monitoring methodology and
report the hourly data on a quarterly
basis, with each quarterly report due to
the Administrator 30 days after the last
day in the calendar quarter. The
monitoring requirements of 40 CFR part
75 require most fossil fuel-fired boilers
to use a CO2 CEMS, including a CO2
concentration monitor and stack gas
flow monitor, although some oil- and
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natural gas-fired boilers may have
options to use alternative measurement
methodologies (e.g., fuel flow meters). A
CO2 CEMS is the most technically
reliable method of emission
measurement for EGUs that burn solid
fuels, as it provides a measurement
method that is performance based rather
than equipment specific and is verified
based on NIST traceable standards. A
CEMS provides a continuous
measurement stream that can account
for variability in the fuels and the
combustion process. Reference methods
have been developed to ensure that all
CEMS meet the same performance
criteria, which helps to ensure
consistent, accurate data. Natural gasfired combustion turbines have options
under appendices D and G of 40 CFR
part 75 to use fuel flowmeters in lieu of
a CO2 CEMS. The flue flowmeter data,
paired with fuel quality data, is used to
determine CO2 mass emissions and heat
input.
The majority of EGUs will generally
have no changes to their monitoring and
reporting requirements and will
continue to monitor and submit
emissions reports under 40 CFR part 75
as they have under existing programs,
such as the Acid Rain Program (ARP)
and the Regional Greenhouse Gas
Initiative (RGGI)—a cooperative of
several states formed to reduce CO2
emissions from EGUs. The majority of
coal- and oil-fired EGUs not subject to
the ARP or RGGI are subject to the
MATS program and, therefore, will have
installed stack gas flow monitors and/or
CO2 concentration monitors necessary
to comply with the MATS. Similarly,
the majority of natural gas-fired
combustion turbines that may be
affected by this rule already use fuel
flowmeters to monitor and report CO2
mass emissions and heat input under
appendices D and G of 40 CFR part 75.
Relying on the same monitors that are
certified and quality-assured in
accordance with 40 CFR part 75 ensures
cost efficient, consistent, and accurate
data that may be used for different
purposes for multiple regulatory
programs.
The EPA requests comment on
monitoring and reporting requirements
for captured CO2 mass emissions and
net electricity output, and on allowable
testing methods for stack gas flow rate.
The CCS process is also subject to
monitoring and reporting requirements
under the EPA’s GHGRP (40 CFR part
98). The GHGRP requires reporting of
facility-level GHG data and other
relevant information from large sources
and suppliers in the U.S. The ‘‘suppliers
of carbon dioxide’’ source category of
the GHGRP (GHGRP subpart PP)
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requires those affected facilities with
production process units that capture a
CO2 stream for purposes of supplying
CO2 for commercial applications or that
capture and maintain custody of a CO2
stream in order to sequester or
otherwise inject it underground to
report the mass of CO2 captured and
supplied. Facilities that inject a CO2
stream underground for long-term
containment in subsurface geologic
formations report quantities of CO2
sequestered under the ‘‘geologic
sequestration of carbon dioxide’’ source
category of the GHGRP (GHGRP subpart
RR). In 2022, to complement GHGRP
subpart RR, the EPA proposed the
‘‘geologic sequestration of carbon
dioxide with enhanced oil recovery
(EOR) using ISO 27916’’ source category
of the GHGRP (GHGRP subpart VV) to
provide an alternative method of
reporting geologic sequestration in
association with EOR.655 656 657
The EPA is proposing that any
affected unit that employs CCS
technology that captures enough CO2 to
meet the proposed standard and injects
the captured CO2 underground must
report under GHGRP subpart RR or
proposed GHGRP subpart VV. If the
emitting EGU sends the captured CO2
offsite, it must assure that the CO2 is
managed at a facility subject to the
GHGRP requirements, and the facility
injecting the CO2 underground must
report under GHGRP subpart RR or
proposed GHGRP subpart VV. This
proposal does not change any of the
requirements to obtain or comply with
a UIC permit for facilities that are
subject to the EPA’s UIC program under
the Safe Drinking Water Act.
The EPA also notes that compliance
with the standard is determined
exclusively by the tons of CO2 captured
by the emitting EGU. The tons of CO2
sequestered by the geologic
sequestration site are not part of that
calculation, though the EPA anticipates
that the quantity of CO2 sequestered
655 87
FR 36920 (June 21, 2022).
Standards Organization (ISO)
standard designated as CSA Group (CSA/American
National Standards Institute (ANSI) ISO
27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage—Carbon
Dioxide Storage Using Enhanced Oil Recovery
(CO2—EOR) (referred to as ‘‘CSA/ANSI ISO
27916:2019’’).
657 As described in 87 FR 36920 (June 21, 2022),
both subpart RR and proposed subpart VV (CSA/
ANSI ISO 27916:2019) require an assessment and
monitoring of potential leakage pathways;
quantification of inputs, losses, and storage through
a mass balance approach; and documentation of
steps and approaches used to establish these
quantities. Primary differences relate to the terms in
their respective mass balance equations, how each
defines leakage, and when facilities may
discontinue reporting.
656 International
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will be substantially similar to the
quantity captured. However, to verify
that the CO2 captured at the emitting
EGU is sent to a geologic sequestration
site, we are leveraging regulatory
requirements under the GHGRP. The
BSER is determined to be adequately
demonstrated based solely on geologic
sequestration that is not associated with
EOR. However, EGUs also have the
compliance option to send CO2 to EOR
facilities that report under GHGRP
subpart RR or proposed GHGRP subpart
VV. We also emphasize that this
proposal does not involve regulation of
downstream recipients of captured CO2.
That is, the regulatory standard applies
exclusively to the emitting EGU, not to
any downstream user or recipient of the
captured CO2. The requirement that the
emitting EGU assure that captured CO2
is managed at an entity subject to the
GHGRP requirements is thus exclusively
an element of enforcement of the EGU
standard. This will avoid duplicative
monitoring, reporting, and verification
requirements between this proposal and
the GHGRP, while also ensuring that the
facility injecting and sequestering the
CO2 (which may not necessarily be the
EGU) maintains responsibility for these
requirements. Similarly, the existing
regulatory requirements applicable to
geologic sequestration are not part of the
proposed rule.
The EPA requests comment on the
following questions related to additional
monitoring and reporting of hourly
captured CO2 under 40 CFR part 75: (a)
should EGUs with carbon capture
technologies be required to monitor and
report the hourly captured CO2 mass
emissions under 40 CFR part 75, (b) if
EGUs with carbon capture technologies
are not required to monitor and report
the hourly captured CO2 mass
emissions, the calculation procedures
for total heat input and NOX rate in
appendix F to 40 CFR part 75 may no
longer provide accurate results;
therefore, what changes might be
necessary to accurately determine total
heat input and NOX rate, (c) to ensure
accurate and complete accounting of
CO2 mass emissions emitted to the
atmosphere and captured for use or
sequestration, at what locations should
CO2 concentration and stack gas flow be
monitored, and should other values also
be monitored at those locations, (d) are
there quality assurance activities
outside of those required under 40 CFR
part 75 for CO2 concentration monitors
and stack gas flow monitors that should
be required of the monitors to accurately
and reliably measure captured CO2 mass
emissions, and (e) what monitoring
plan, quality assurance, and emissions
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data should be reported to the EPA to
support evaluation and ensure
consistent and accurate data as it relates
to CO2 emissions capture.
The 40 CFR part 75 monitoring and
reporting provisions require hourly
reporting of total gross electricity
output, including useful thermal output,
but do not require the reporting of net
electricity output. The EPA requests
comment on the following questions
related to reporting of net electricity
output: (a) should EGUs be required to
measure and report total net electricity
output, including useful thermal output,
under 40 CFR part 75, (b) what guidance
should the EPA provide on how to
measure and apportion net electricity
output, (c) should EGUs measure and
report net electricity output at the unit
or facility level, and (d) what
monitoring plan, quality assurance, and
output data should be reported to the
EPA to support evaluation and ensure
consistent and accurate data as it relates
to total net electricity output.
To calculate CO2 mass emissions at a
fossil fuel-fired boiler, the EGU typically
measures CO2 concentration and flue
gas flow rate as the exhaust gases from
combustion pass through the stack (or
duct). Under 40 CFR part 75, EGUs must
complete regular performance tests on
the flue gas flow monitor based on EPA
Reference Method 2 or its allowable
alternatives that are provided in 40 CFR
part 60, appendices A–1 and A–2. In
general, the allowable alternative
measurement methods reduce or
eliminate the potential overestimation
of stack gas flow rate that results from
the use of EPA Reference Method 2
when the specific flow conditions (e.g.,
angular flow) are present in the stack.
However, EGUs with stack gas flow
monitors are not required to use the
allowable alternative measurement
methods and EGUs may change
methods at any time. The EPA requests
comment on the following questions
related to the use of EPA Reference
Method 2 and its allowable alternatives
for stack gas flow monitors under 40
CFR part 75: (a) should or under what
conditions should EGUs be required to
conduct a flow study and choose the
appropriate EPA reference method for
each stack gas flow monitor based on
the results of the study, (b) once an EGU
selects the use of an EPA reference
method for a stack gas flow monitor,
regardless of the basis for that selection,
should the EGU be required to continue
using the same EPA reference method
until a flow study or other engineering
justification is made to change the EPA
reference method, and (c) what
additional monitoring plan, quality
assurance, and emissions data should be
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reported to the EPA to support
evaluation and ensure consistent and
accurate data as it relates stack gas flow
rate and performance of the stack gas
flow monitor.
E. Compliance Flexibilities
In developing these proposed
emission guidelines, the EPA has heard
from stakeholders seeking flexibility in
complying with standards of
performance under these emission
guidelines. In particular, stakeholders
have requested that the EPA allow states
to include flexibilities such as averaging
and market-based mechanisms in their
State plans, as has been permitted under
prior EPA rules. The EPA is proposing
to allow states to incorporate averaging
and emission trading into their State
plans, provided that states ensure that
use of these compliance flexibilities will
result in a level of emission
performance by the affected EGUs that
is equivalent to each source
individually achieving its standard of
performance. As discussed below, the
EPA also recognizes that the structure of
the proposed subcategories and
associated degrees of emission
limitation, as well as the unique
characteristics of the existing sources in
the relevant source categories, will
likely require that certain limitations or
conditions be placed on the
incorporation of averaging and trading
in order to ensure that such standards
are at least as stringent as the EPA’s
BSER. This section discusses
considerations related to such
compliance flexibilities in the context of
this particular rule and set of regulated
sources—existing steam generating units
and existing combustion turbine
EGUs—and solicits comment on
whether certain types of averaging and
trading maintain the stringency of the
EPA’s BSER.
1. Overview
In the proposed subpart Ba revisions,
‘‘Adoption and Submittal of State Plans
for Designated Facilities: Implementing
Regulations Under Clean Air Act
Section 111(d)’’ (87 FR 79176; December
23, 2022), the EPA explained that under
its proposed interpretation of CAA
section 111, each State is permitted to
adopt measures that allow its sources to
meet their emission limits in the
aggregate when the EPA determines, in
any particular emission guideline, that
it is appropriate to do so given, inter
alia, the pollutant, sources, and
standards of performance at issue. Thus,
the EPA has proposed to return to its
longstanding position that CAA section
111(d) authorizes the EPA to approve
State plans that achieve the requisite
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emission limitation through aggregate
reductions from their sources, including
through trading or averaging, where
appropriate for a particular emission
guideline and consistent with the
intended environmental outcomes of the
BSER.658 See 87 FR 79208 (December
23, 2022).
Consistent with the return to this
longstanding position, the EPA is
proposing to allow states to incorporate
trading and averaging in their State
plans under these emission guidelines.
States would not be required to allow
for such compliance mechanisms in
their State plans but could provide for
trading and averaging for existing steam
generating units and/or existing
combustion turbines at their
discretion.659 As discussed in section
XII.C of this preamble, State plans must
demonstrate that they achieve a level of
emission performance by affected EGUs
that is consistent with the application of
the BSER. The EPA is therefore
proposing that, in order to find that a
State plan that includes trading or
averaging is ‘‘satisfactory,’’ it must
demonstrate that it maintains the level
of emission performance for the source
category that would be achieved if each
affected EGU was individually
achieving its presumptive standard of
performance, after allowing for any
application of RULOF. In the case of
averaging, discussed in section XII.E.3
of this preamble, an equivalence
demonstration would be relatively
straightforward. For emission trading
programs, ensuring equivalent emission
658 The EPA has authorized trading or averaging
as compliance methods in several emission
guidelines. See, e.g., 40 CFR 60.33b(d)(2) (emission
guidelines for municipal waste combustors permit
state plans to establish trading programs for NOX
emissions); 70 FR 28606, 28617 (May 18, 2005)
(Clean Air Mercury Rule authorized trading)
(vacated on other grounds); 40 CFR 60.24(b)(1)
(subpart B CAA section 111 implementing
regulations promulgated in 2005 allow States’
standards of performance to be based on an
‘‘allowance system’’); 80 FR 64662, 64840 (October
23, 2015) (CPP authorizing trading or averaging as
a compliance strategy). In the recent supplemental
proposal to promulgate emission guidelines for the
oil and natural gas industry, the EPA has also
proposed to allow States to permit sources to
demonstrate compliance in the aggregate. 87 FR
74702, 74812 (December 6, 2022).
659 The EPA notes that these flexibilities, trading
and averaging, would be used to comply with
standards of performance, rather than to establish
standards of performance in the first instance. In
contrast to the RULOF mechanism, which, as
described in section XI.D.2 of this preamble, States
may use to establish different standards of
performance than those described by the EPA’s
BSER, trading or averaging may be used to
demonstrate compliance with already established
standards of performance. That is, States
incorporating trading or averaging would not need
to undergo a RULOF demonstration for sources
participating in trading or averaging programs.
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performance in the aggregate may be
more difficult.
Section XII.E.2 of this preamble
discusses considerations related to the
appropriateness of trading and
averaging for affected EGUs in certain
circumstances, e.g., affected EGUs with
proposed BSERs based on routine
methods of operation and maintenance.
Section XII.E.2 of this preamble also
discusses program design examples as
well as potential design elements and
takes comment on whether these or
other designs or design elements could
ensure that use of emission trading or
averaging does not undermine the
stringency of the EPA’s BSER. However,
the Agency is not proposing a
presumptively approvable averaging or
trading approach at this time.
The EPA also notes that States that
incorporate trading or averaging into
their State plans would need to conduct
meaningful engagement on this aspect
of their plans with pertinent
stakeholders, just as they would need to
do for any other part of a plan. As
discussed in greater detail in section
XII.F.1.b of this preamble, meaningful
engagement provides an opportunity for
communities most affected by and
vulnerable to the impacts of a plan to
provide input, including input on any
impacts resulting from the use of trading
or averaging for compliance.
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2. Emission Trading
The EPA is proposing to allow State
plans to include emission trading
programs as a compliance flexibility for
affected existing EGUs under these
emission guidelines and is taking
comment on whether certain types of
trading programs could satisfy the
requirement to maintain equivalence
with source-specific application of
standards of performance. This section
discusses considerations related to
affected EGUs under these emission
guidelines and how a State could
potentially incorporate a rate-based
trading program or a mass-based trading
program in a way that preserves the
stringency of the BSER.
a. Considerations for Emission Trading
in State Plans
Emission trading has been used to
achieve required emission reductions in
the power sector for nearly 3 decades.
In Title IV of the Clean Air Act
Amendments of 1990, Congress
specified the design elements for the
Acid Rain Program, a 48-State
allowance trading program to reduce
SO2 emissions and the resulting acid
precipitation. Building on the success of
that first allowance trading program as
a tool for addressing multi-State air
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pollution issues, the EPA has
promulgated and implemented multiple
allowance trading programs since 1998
for SO2 or NOX emissions to address the
requirements of the CAA’s good
neighbor provision with respect to
successively more stringent NAAQS for
fine particulate matter and ozone. The
EPA currently administers eight power
sector emission trading programs that
differ in pollutants, geographic regions,
covered time periods, and levels of
stringency.660 Annual progress reports
demonstrate that EPA trading programs
have been successful in mitigating the
problems they were designed to address,
exhibiting significant emission
reductions and extraordinarily high
levels of compliance.661 In addition,
several states have implemented
regional or intrastate CO2 emissions
trading programs to address GHG
emissions from the power sector (the
RGGI and California trading programs,
respectively).
In general, emission trading programs
provide flexibility for EGUs to secure
emission reductions at a lower cost
relative to more prescriptive forms of
regulation. Emission trading can allow
the owners and operators of EGUs to
prioritize emission reduction actions
where they are the quickest or cheapest
to achieve while still meeting electricity
demand and broader environmental and
economic performance goals. These
benefits are heightened where there is a
diverse set of emission sources (e.g.,
variation in technology, fuel type, age,
and operating parameters) included in
an emission trading program. This
diversity of sources is typically
accompanied by differences in marginal
emission abatement costs and operating
parameters, resulting in heterogeneity in
economic emission reduction
opportunities that can be optimized
through the compliance flexibility
provided through emission trading. In
addition, the EPA has observed, with
the support of multiple independent
analyses, that there is significant
660 The six current CSAPR trading programs are
the CSAPR NOX Annual Trading Program, CSAPR
NOX Ozone Season Group 1 Trading Program,
CSAPR SO2 Group 1 Trading Program, CSAPR SO2
Group 2 Trading Program, CSAPR NOX Ozone
Season Group 2 Trading Program, and CSAPR NOX
Ozone Season Group 3 Trading Program. The
regulations for the six CSAPR programs are set forth
at subparts AAAAA, BBBBB, CCCCC, DDDDD,
EEEEE, and GGGGG, respectively, of 40 CFR part
97. The regulations for the Texas SO2 Trading
Program are set forth at subpart FFFFF of 40 CFR
part 97. The Acid Rain Program SO2 trading
program is set forth in Title IV of the Clean Air Act
Amendments of 1990.
661 Environmental Protection Agency (2021).
Power Sector Programs—Progress Report. EPA.
https://www3.epa.gov/airmarkets/progress/reports/
index.html.
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evidence that implementation of trading
programs prompted greater innovation
and deployment of clean technologies
that reduce emissions and control
costs.662
Emission trading may also provide
important benefits. Having flexibility to
prioritize the most cost effective
emission reductions among affected
EGUs may reduce the cost of
compliance as well as provide flexibility
for fleet management, while achieving
the requisite level of emission
performance. In particular, emission
trading may provide some short-term
operational flexibility.
At the same time, there may be
challenges for implementing an
emission trading program, especially in
the context of the emission guidelines
that the EPA is proposing here. The EPA
notes that while the proposed emission
guidelines include both steam
generating units and combustion
turbines, the fleet of affected steam
generating units is expected to shrink
under BAU projections (see section IV.F
of this preamble), and the number of
existing combustion turbines subject to
these emission guidelines is limited (see
section XI.C of this preamble) given the
subcategory applicability thresholds. As
a result, there is unlikely to be as much
diversity in cost and emission
performance among affected emission
sources (resulting in less diversity in
emission reduction opportunities and
marginal abatement costs) as seen in
prior emission trading programs for the
electric power sector.
The utility of trading under these
emission guidelines may also be
obviated somewhat by the subcategories
that the EPA has proposed to establish
for existing coal-fired steam generating
units and existing gas combustion
turbines. The specific subcategories
proposed under these emission
guidelines for steam generating units are
designed to provide for much of the
same operational flexibility as would be
provided through trading; as a result,
the EPA believes that it would not be
appropriate to allow affected EGUs in
certain subcategories—imminent-term
and near-term coal-fired steam
generating units and natural gas- and
oil-fired steam generating units—to
comply with their standards of
performance through trading. Similarly,
the EPA believes it would not be
662 LaCount, M.D., Haeuber, R.A., Macy, T.R., &
Murray, B.A. (2021). Reducing Power Sector
Emissions under the 1990 Clean Air Act
Amendments: A Retrospective on 30 Years of
Program Development and Implementation.
Atmospheric Environment (Oxford, England: 1994),
245, 1–10. https://doi.org/10.1016/
j.atmosenv.2020.118012.
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appropriate to allow affected EGUs with
less-stringent, source-specific standards
based on RULOF to comply with those
standards of performance through
trading. As discussed in section X.D.3 of
this preamble, the proposed BSER
determinations for the imminent- and
near-term coal-fired steam generating
unit subcategories are designed to take
into account factors such as operating
horizon and load level (expressed as
annual capacity factor) and, as a result,
are based on routine methods of
operation and maintenance. Natural gasand oil-fired steam generating units also
have proposed BSER determinations
based on routine methods of operation
and maintenance. An emission trading
program that includes affected EGUs
that have BSERs and resulting standards
of performance based on limited
expected emission reduction potential—
or, in the case of affected EGUs for
which states have invoked RULOF, less
stringent standards of performance—
may introduce the risk of undermining
the intended stringency of the BSER for
other facilities.
The EPA also believes that emission
trading may be inappropriate for some
subcategories of affected EGUs based on
other, subcategory-specific reasons.
Affected EGUs that receive the IRC
section 45Q tax credit for permanent
sequestration of CO2 may have an
overriding incentive to maximize both
the application of the CCS technology
and total electric generation, leading to
source behavior that may be nonresponsive to the economic incentives
of a trading program. This consideration
may be relevant for affected EGUs in the
long-term coal-fired steam generating
unit subcategory and the CCS
combustion turbine subcategory that
comply with their standards of
performance using CCS. Additionally,
the utilization applicability criterion for
existing combustion turbines creates a
barrier to emission trading under these
emission guidelines. Specifically,
existing combustion turbines that are
greater than 300 MW qualify as affected
EGUs and thus have applicable
standards of performance only when
they operate at an annual capacity factor
of greater than 50 percent. When they
operate at an annual capacity factor of
50 percent or less, they are not subject
to standards of performance. The EPA
believes that the fact that units may fall
in or out of a trading program from year
to year very likely precludes their
inclusion in any such program as a
practical matter.
The EPA requests comment on these
challenges and on whether, in light of
these and other considerations,
emission trading should be permitted
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for certain subcategories and not
permitted for others, and on whether
emission trading should be limited to
within certain subcategories, and why.
In the following sections, the EPA
discusses potential rate-based and massbased emission trading program
approaches that could potentially be
included in a State plan and solicits
comment on applied implementation
issues in the context of these proposed
emission guidelines and the
considerations discussed in this
subsection XII.E.2.a of the preamble.
b. Rate-Based Emission Trading
A rate-based trading program allows
affected EGUs to trade compliance
instruments that are generated based on
their emission performance. This
section describes one method of how
states could establish a rate-based
trading program as part of a State plan.
The EPA requests comment on whether
this or another method of rate-based
trading could demonstrate equivalent
stringency as would be achieved if each
affected EGU was achieving its standard
of performance.
In this example, affected EGUs that
perform at a lower emission rate (lb
CO2/MWh) than their standard of
performance would be issued
compliance instruments that are
denominated in one ton of CO2. A
tradable instrument denominated in
another unit of measure, such as a
MWh, is not fungible in the context of
a rate-based emission trading program.
A compliance instrument denominated
in MWh that is awarded to one affected
EGU may not represent an equivalent
amount of emissions credit when used
by another affected EGU to demonstrate
compliance, as the CO2 emission rates
(lb CO2/MWh) of the two affected EGUs
are likely to differ. This may pose a
challenge for states trying to
demonstrate equivalence with the
intended stringency of the BSER.
These compliance instruments could
be transferred among affected EGUs,
making them ‘‘tradable.’’ Compliance
would be demonstrated for an affected
EGU based on a combination of its
reported CO2 emission performance (in
lb CO2/MWh) and, if necessary, the
surrender of an appropriate number of
tradable compliance instruments, such
that the demonstrated lb CO2/MWh
emission performance is equivalent to
the rate-based standard of performance
for the affected EGU.
Specifically, each affected EGU would
have a particular standard of
performance, based on the degree of
emission limitation achievable through
application of the BSER, with which it
would have to demonstrate compliance.
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Under a rate-based trading program,
affected EGUs performing at a CO2
emission rate below their standard of
performance would be awarded
compliance instruments at the end of
each control period denominated in
tons of CO2. The number of compliance
instruments awarded would be equal to
the difference between their standard of
performance CO2 emission rate and
their actual reported CO2 emission rate
multiplied by their generation in MWh.
Affected EGUs performing worse than
their standard of performance would be
required to obtain and surrender an
appropriate number of compliance
instruments when demonstrating
compliance, such that their
demonstrated CO2 emission rate is
equivalent to their rate-based standard
of performance. Transfer and use of
these compliance instruments would be
accounted for with a rate adjustment as
each affected EGU performs its
compliance demonstration.
In general, rate-based emission
trading can by design assure
achievement of the requisite level of
emission performance for affected
sources, because reduced utilization and
retirements are automatically accounted
for in the award of the compliance
instrument. By default, only operating
affected EGUs could receive or
participate in the trading of compliance
instruments.
The EPA is seeking comment on
whether rate-based emission trading
might be appropriate under these
emission guidelines, taking into
consideration the discussion of the
appropriateness of trading for certain
subcategories in section XII.E.2.a of this
preamble. In particular, the EPA
requests comment on whether and how
a rate-based emission trading program
could be designed to ensure equivalent
stringency as would be achieved if each
participating affected EGU was
achieving its source-specific standard of
performance, given the structure of the
proposed subcategories and their
proposed BSERs. The EPA also requests
comment on any other methods of ratebased trading that would preserve the
stringency of the BSER.
c. Mass-Based Emission Trading
A mass-based trading program
establishes a budget of allowable mass
emissions for a group of affected EGUs,
with tradable instruments (typically
referred to as ‘‘allowances’’) issued to
affected EGUs in the amount equivalent
to the emission budget. Each allowance
would represent a tradable permit to
emit one ton of CO2, with affected EGUs
required to surrender allowances in a
number equal to their reported CO2
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emissions during each compliance
period. This section describes one
method of how states could establish a
mass-based trading program as part of a
State plan. The EPA requests comment
on whether this or another method of
mass-based trading could ensure
equivalent stringency as would be
achieved if each participating affected
EGU was achieving its source-specific
standard of performance.
As previously discussed, mass-based
emission trading has been used in the
power sector at the Federal, regional,
and State levels for nearly 3 decades.
Owners and operators of EGUs, utilities,
and State agencies thus have extensive
familiarity with mass-based emission
trading, which could make the design
and implementation of a mass-based
trading program as part of a State plan
relatively straightforward. However, this
familiarity comes with an awareness on
the part of states and the EPA of the
need to tailor the design of a mass-based
emission trading program to the
situation in which it is applied. Past
experience shows that emission budgets
have often been overestimated when set
many years in advance of the start of a
program, as economic and technological
conditions have changed significantly
between the time the program was
adopted and when compliance
obligations begin. Projecting affected
EGU fleet composition and utilization
beyond the relative near term has
become increasingly challenging, driven
by factors including changes in relative
fuel prices and continued rapid
improvement in the cost and
performance of wind and solar
generation, along with new incentives
for technology deployment provided by
the IIJA and the IRA. Critically, if
affected EGUs reduce utilization or exit
the source category, the remaining
affected EGUs face a reduced or
eliminated obligation to improve their
emission performance. In this case, the
emission budget would be established at
a level such that the sources would not
be collectively meeting the required
level of emission performance
commensurate with each source
achieving its rate-based standard of
performance.
One program design states might
employ to ensure that affected EGUs
participating in a mass-based trading
program continue to meet the level of
emission performance prescribed by
category-wide, source-specific
implementation of the rate-based
standards of performance includes
regularly adjusting emission budgets to
account for sources that cease
operations or change their utilization.
One budget adjustment method that the
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EPA has developed is dynamic
budgeting, as applied in the Good
Neighbor Plan,663 in which budgets are
updated annually based on recent
historical generation. States could apply
a similar dynamic budgeting process to
mass-based trading implemented under
these emission guidelines. In this
context, states could establish an
emission budget based on the unitspecific standards of performance of the
participating affected EGUs, as
described in section XII.D of this
preamble, multiplied by each affected
EGU’s recent historical generation. The
emission budget would be updated
regularly to account for units that
reduce utilization or cease operation.
This is one way that states could assure
achievement of the requisite level of
emission performance for affected EGUs
through mass-based trading, though the
EPA acknowledges that existing State or
regional mass-based trading programs
may have developed other regular
emission budget adjustment methods
that could potentially provide similar
assurance and might provide a model
that could be applied for trading under
these emission guidelines.
The EPA also acknowledges that other
methods could be used to establish an
emission budget that, in conjunction
with the aforementioned dynamic
budget approach, could achieve at least
the requisite level of emission
performance consistent with application
of the BSER. States could use a single
rate at the level of the subcategory or
source category that is, for example, as
stringent as the most controlled unit in
the group (based on unit-specific
standards of performance as defined in
section XII.D.1) to establish the
emission budget.
The EPA is seeking comment on
whether mass-based emission trading
might be appropriate under these
emission guidelines, taking into
consideration the discussion of the
appropriateness of trading for certain
subcategories in section XII.E.2.a of this
preamble. In particular, the EPA
requests comment on whether and how
a mass-based emission trading program
could be designed to ensure equivalent
stringency as each participating affected
EGU achieving its source-specific
standard of performance, given the
structure of the proposed subcategories
and their proposed BSERs. The EPA is
also seeking comment on whether the
method of mass-based emission trading
using dynamic budgeting, as discussed
663 The final Good Neighbor Plan was signed by
the Administrator on March 15, 2023. At this time,
the final action has not yet been published in the
Federal Register.
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in this section, might be appropriate
under these emission guidelines. The
EPA is also seeking comment on other
approaches or features that could ensure
that emission budgets reflect the
stringency that would be achieved
through unit-specific application of ratebased standards of performance.
d. General Emission Trading Program
Implementation Elements
The EPA notes that states would need
to establish procedures and systems
necessary to implement and enforce an
emission trading program, whether it is
rate-based or mass-based, if they elect to
incorporate emission trading into their
State plans. This would include, but is
not limited to, establishing compliance
timeframes and the mechanics for
demonstrating compliance under the
program (e.g., surrender of compliance
instruments as necessary based on
monitoring and reporting of CO2
emissions and generation); establishing
requirements for continuous monitoring
and reporting of CO2 emissions and
generation; and developing a tracking
system for tradable compliance
instruments. Additionally, for states
implementing a mass-based emission
trading program, State plans would
need to specify how allowances would
be distributed to participating affected
EGUs.
The EPA acknowledges that the
proposed dates as of which standards of
performance would apply for sources
covered by these emission guidelines
differ by subcategory: January 1, 2030,
for all steam generating units; January 1,
2032, for the hydrogen co-fired
combustion turbine subcategory; and
January 1, 2035, for the CCS combustion
turbine subcategory. If trading is
permitted for two or more of these sets
of sources, this difference could
potentially pose an implementation
challenge where a trading program
includes these sources. To address this
issue, a program could, for example,
begin in 2030 for steam generating units
and bring in combustion turbine EGUs
later, or states could delay
implementation of a trading program to
coincide with the later combustion
turbine date. The Agency requests
comment on potential ways to address
this implementation issue in the context
of a State plan, and whether this issue
impacts the utility or feasibility of
trading across subcategories.
The EPA is also requesting comment
on whether and to what extent there
would be a desire to capitalize on the
EPA’s existing reporting and
compliance tracking infrastructure to
support State implementation of an
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e. Banking of Compliance Instruments
The EPA requests comment on
whether State plans should be allowed
to provide for banking of tradable
compliance instruments (hereafter
referred to as ‘‘allowance banking,’’
although it is relevant for both massbased and rate-based trading programs).
Allowance banking has potential
implications for a trading program’s
ability to maintain the requisite
stringency of the standards of
performance. The EPA recognizes that
allowance banking—that is, permitting
allowances that remain unused in one
control period to be carried over for use
in future control periods—may provide
incentives for early emission reductions,
promote operational flexibility and
planning, and facilitate market liquidity.
However, the EPA has observed that
unrestricted allowance banking from
one control period to the next (absent
provisions that adjust future control
period budgets to account for banked
allowances) may result in a long-term
allowance surplus that has the potential
to undermine a trading program’s ability
to ensure that, at any point in time, the
affected sources are achieving the
required level of emission performance.
In addition to requesting comment on
whether the EPA should permit
allowance banking, the EPA requests
comment on the treatment of banked
allowances, specifically whether all or
only some portion of an allowance bank
could be carried over for use in future
control periods or if additional program
design elements would be necessary to
accommodate allowance banking.
f. Interstate Emission Trading
The EPA is requesting comment on
whether, and under what circumstances
or conditions, to allow interstate
emission trading under these emission
guidelines. Given the
interconnectedness of the power sector
and given that many utilities operate in
multiple states, interstate emission
trading may increase compliance
flexibility. For interstate emission
trading programs to function
successfully, all participating states
would need to, at a minimum, use the
same form of trading and have identical
trading program requirements. There are
many requirements for program
reciprocity and approvability that
would need to be established in the
emission guidelines, in addition to
providing mechanisms for submission
and EPA review of State plans that
include interstate trading mechanisms.
Given the increased level of program
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complexity that would be necessary to
accommodate interstate trading and the
operational flexibilities already
provided by the structure of the
proposed subcategories and their
proposed BSERs, the EPA requests
comment on whether there is utility in
providing for it under these emission
guidelines. In addition, the EPA
requests comment on the information,
guidance, and requirements the EPA
would need to provide for states to
implement successful interstate
emission trading programs.
3. Rate-Based Averaging
The EPA is proposing to allow State
plans to include rate-based averaging as
a compliance flexibility for affected
EGUs under these emission guidelines.
This section discusses how states could
potentially incorporate a rate-based
averaging program in a way that
preserves the stringency of the EPA’s
BSER as well as some considerations
related to incorporating averaging in
State plans. The EPA is seeking
comment on one potential method,
described in this section, as well as
other methods that could maintain the
required level of emission performance
equivalent to each source individually
achieving its standard of performance.
Averaging allows multiple affected
EGUs to jointly meet a rate-based
standard of performance. Affected EGUs
participating in averaging could, for
example, demonstrate compliance
through an effective CO2 emission rate
that is based on a gross generation-based
weighted average of the required
standards of performance of the affected
EGUs that participate in averaging. The
scope of such averaging could apply at
the facility level or the owner or
operator level. This method for
calculating a composite rate could
demonstrate equivalence with sourcespecific standards of performance.
Averaging can provide potential
benefits. First, it offers some flexibility
for sources to target cost effective
reductions at any affected EGU. For
example, owners or operators of affected
EGUs might target installation of
emission control approaches at units
that operate more. Second, averaging at
the facility level provides greater ease of
compliance accounting for affected
EGUs with a complex stack
configuration (such as a common- or
multi-stack configuration). In such
instances, unit-level compliance
involves apportioning reported
emissions to individual affected EGUs
that share a stack based on electricity
generation or other parameters.
However, the EPA notes that the
subcategory approach in these emission
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guidelines already provides significant
operational flexibility for affected EGUs,
potentially making the provision of
further flexibility through averaging
redundant or inappropriate, especially
at the owner or operator level.
The EPA is seeking comment on the
utility of rate-based averaging as a
compliance flexibility, as well as on the
illustrative method for developing a
composite standard of performance for
the purposes of rate-based averaging.
The EPA is also seeking comment on
any other considerations related to ratebased averaging, including whether the
scope of averaging should be limited to
a certain level of aggregation (e.g., to
facility-level rate-based averaging) or to
certain subcategories.
4. Relationship to Existing State
Programs
The EPA recognizes that many states
have adopted binding policies and
programs (with both a supply-side and
demand-side focus) under their own
authorities that have significantly
reduced CO2 emissions from EGUs, that
these policies will continue to achieve
future emission reductions, and that
states may continue to adopt new power
sector policies addressing GHG
emissions. States have exercised their
power sector authorities for a variety of
purposes, including economic
development, energy supply and
resilience goals, conventional and GHG
pollution reduction, and generating
allowance proceeds for investments in
communities disproportionately
impacted by environmental harms. The
scope and approach of EPA’s proposed
emission guidelines differs significantly
from the range of policies and programs
employed by states to reduce power
sector CO2 emissions, and this proposal
operates more narrowly to improve the
CO2 emission performance of a subset of
EGUs within the broader electric power
sector. The Agency recognizes the
importance of State programs and their
potential to reduce power sector CO2
emissions through a range of strategies
broader than those proposed here
pursuant to CAA section 111(d). The
EPA seeks comment on whether there
are any elements of the proposed
emission guidelines that might interfere
with the implementation of State
requirements that limit CO2 emissions
from EGUs that may be subject to the
proposed emission guidelines.
F. State Plan Components and
Submission
This section describes the proposed
requirements for the contents of State
plans, the proposed timing of State plan
submissions, and the EPA’s review of
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and action on State plan submissions.
This section also discusses issues
related to the applicability of a Federal
plan and timing for the promulgation of
a Federal plan.
As explained earlier in this preamble,
the requirements of 40 CFR part 60,
subpart Ba, govern State plan
submissions under these emission
guidelines. Where the EPA is proposing
to add to, supersede, or otherwise vary
the requirements of subpart Ba for the
purposes of State plan submissions
under these particular emission
guidelines,664 those proposals are
addressed explicitly in section XII.F.1.b
on specific State plan requirements and
throughout this preamble. Unless
expressly amended or superseded in
these proposed emission guidelines, the
provisions of subpart Ba would apply.
1. Components of a State Plan
Submission
The EPA is proposing that a State
plan must include a number of discrete
components. These proposed plan
components include those that apply for
all State plans pursuant to 40 CFR part
60, subpart Ba. The EPA is also
proposing additional plan components
that are specific to State plans submitted
pursuant to these emission guidelines.
For example, the EPA is proposing plan
components that are necessary to
implement and enforce the specific
types of standards of performance for
affected EGUs that would be adopted by
a State and incorporated into its State
plan.
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a. General Components
The CAA section 111 implementing
regulations at 40 CFR part 60 subpart Ba
provide separate lists of administrative
and technical criteria that must be met
in order for a State plan submission to
be deemed complete. The EPA’s
proposed revisions to subpart Ba would
add one item to the list of
administrative criteria related to
meaningful engagement (element 9 in
the list below).665 If that criterion is
finalized as proposed, the complete list
of applicable administrative
completeness criteria for State plan
submissions would be: (1) A formal
letter of submittal from the Governor or
the Governor’s designee requesting EPA
approval of the plan or revision thereof;
(2) Evidence that the State has adopted
the plan in the State code or body of
regulations; or issued the permit, order,
or consent agreement (hereafter
664 40
CFR 60.20a(a)(1).
FR 79176, 79204 (December 23, 2022),
Docket ID No. EPA–HQ–OAR–2021–0527–0002
(proposed revisions at 40 CFR 60.27a(g)(2)).
665 87
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‘‘document’’) in final form. That
evidence must include the date of
adoption or final issuance as well as the
effective date of the plan, if different
from the adoption/issuance date; (3)
Evidence that the State has the
necessary legal authority under State
law to adopt and implement the plan;
(4) A copy of the official State
regulation(s) or document(s) submitted
for approval and incorporated by
reference into the plan, signed, stamped,
and dated by the appropriate State
official indicating that they are fully
adopted and enforceable by the State.
The effective date of the regulation or
document must, whenever possible, be
indicated in the document itself. The
State’s electronic copy must be an exact
duplicate of the hard copy. For revisions
to the approved plan, the submission
must indicate the changes made to the
approved plan by redline/strikethrough;
(5) Evidence that the State followed all
applicable procedural requirements of
the State’s regulations, laws, and
constitution in conducting and
completing the adoption/issuance of the
plan; (6) Evidence that public notice
was given of the plan or plan revisions
with procedures consistent with the
requirements of 40 CFR 60.23, including
the date of publication of such notice;
(7) Certification that public hearing(s)
were held in accordance with the
information provided in the public
notice and the State’s laws and
constitution, if applicable and
consistent with the public hearing
requirements in 40 CFR 60.23; (8)
Compilation of public comments and
the State’s response thereto; and (9)
Evidence of meaningful engagement,
including a list of pertinent
stakeholders, a summary of the
engagement conducted, and a summary
of stakeholder input received.
Pursuant to subpart Ba, the technical
criteria required for all plans must
include each of the following: 666 (1)
Description of the plan approach and
geographic scope; (2) Identification of
each designated facility (i.e., affected
EGU); identification of standards of
performance for each affected EGU; and
monitoring, recordkeeping, and
reporting requirements that will
determine compliance by each
designated facility; (3) Identification of
compliance schedules and/or
increments of progress; (4)
Demonstration that the State plan
submission is projected to achieve
emission performance under the
applicable emission guidelines; (5)
Documentation of State recordkeeping
and reporting requirements to determine
666 40
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the performance of the plan as a whole;
and (6) Demonstration that each
standard is quantifiable, permanent,
verifiable, enforceable, and nonduplicative.
b. Specific State Plan Requirements
To ensure that State plans submitted
pursuant to these emission guidelines
are consistent with the requirements of
subpart Ba, the EPA is proposing
regulatory requirements that would
apply to all affected EGUs subject to a
standard of performance under a State
plan pursuant to these proposed
emission guidelines, as well as
requirements that apply to affected
EGUs within specific subcategories.
Standards of performance for affected
EGUs included in a State plan must be
quantifiable, verifiable, permanent,
enforceable, and non-duplicative.
Additionally, per CAA section 302(l),
standards of performance must be
continuous in nature. Additional
proposed State plan requirements
include:
• Identification of affected EGUs and
the subcategory to which each affected
EGU is assigned;
• Identification of standards of
performance for each affected EGU in lb
CO2/MWh-gross basis, including
provisions for implementation and
enforcement of such standards;
• Identification of enforceable
increments of progress and milestones,
as required for affected EGUs within the
applicable subcategory, included as
enforceable elements of a State plan;
• If relevant, identification of
applicable enforceable requirements
that are prerequisites for inclusion of an
affected EGU in a specific subcategory,
such as enforceable commitments to
cease operations by a specified date or
to limit annual capacity factor, where a
State and the owner or operator of an
affected EGU have chosen to rely on
such commitments in order for the
affected EGU to be included in a
specific subcategory, included as
enforceable elements of a State plan;
and
• Identification of applicable
monitoring, reporting, and
recordkeeping requirements for affected
EGUs.
The proposed emission guidelines
include requirements pertaining to the
methodologies states must use for
establishing a presumptively approvable
standard of performance for an affected
EGU within a respective subcategory.
These proposed methodologies are
specified for each of the subcategories of
affected EGUs in section XII.D.1 of this
preamble.
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The EPA notes that standards of
performance for affected EGUs in a State
plan must be representative of the level
of emission performance that results
from the application of the BSER in
these emission guidelines. As discussed
in section XII.C of this preamble, in
order for the EPA to find a State plan
‘‘satisfactory,’’ that plan must achieve
the level of emission performance that
would result if each affected source was
achieving its presumptive standard of
performance, after accounting for any
application of RULOF. That is, while
states have the discretion to establish
the applicable standards of performance
for affected sources in their State plans,
the structure and purpose of CAA
section 111 require that those plans
achieve an equivalent level of emission
performance as applying the EPA’s
presumptive standards of performance
to those sources (again, after accounting
for any application of RULOF).
The proposed emission guidelines
also include requirements that apply to
states when they invoke RULOF in
applying a less stringent standard of
performance for an affected EGU than
the presumptively approvable standard
of performance. Such requirements
include a demonstration by the State of
why an affected EGU for which the State
invokes RULOF cannot reasonably
apply the BSER. The State would also
be required to demonstrate where and
how it considered the potential
pollution impacts and benefits of
control to communities most affected by
and vulnerable to emissions from the
designated facility. The EPA expects
that states would identify these
communities, gather information about
the potential pollution impacts and
benefits of control, and document how
they have considered that information
in setting source-specific standards of
performance for RULOF sources through
their meaningful engagement processes.
In addition to consideration of
impacts on and benefits to affected
communities in the context of invoking
RULOF for particular sources, the
proposed revisions to the CAA section
111 subpart Ba implementing
regulations include requirements for
public engagement on overall State plan
development. These requirements are
intended to ensure robust and
meaningful public involvement in the
plan development process and to ensure
that those who are most affected by and
vulnerable to the impacts of a plan will
share in the benefits of the plan and are
protected from being adversely
impacted. The proposed requirements
are in addition to the existing public
notice requirements under subpart Ba
and, if finalized, would apply to State
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plan development in the context of
these emission guidelines.
The fundamental purpose of CAA
section 111 is to reduce emissions from
categories of stationary sources that
cause, or significantly contribute to, air
pollution which may reasonably be
anticipated to endanger public health or
welfare. Therefore, a key consideration
in the State’s development of a State
plan is the potential impact of the
proposed plan requirements on public
health and welfare. Meaningful
engagement is a corollary to the
longstanding requirement for public
participation, including through public
hearings, in the course of State plan
development under CAA section 111.667
A robust and meaningful engagement
process is critical to ensuring that the
entire public has an opportunity to
participate in the State plan
development process and that states
understand and consider the full range
of impacts of a proposed plan.
In the subpart Ba revisions of
December 2022, the EPA proposed to
define meaningful engagement as:
[T]timely engagement with pertinent
stakeholder representation in the plan
development or plan revision process. Such
engagement must not be disproportionate in
favor of certain stakeholders. It must include
the development of public participation
strategies to overcome linguistic, cultural,
institutional, geographic, and other barriers
to participation to assure pertinent
stakeholder representation, recognizing that
diverse constituencies may be present within
any particular stakeholder community. It
must include early outreach, sharing
information, and soliciting input on the State
plan.668
The EPA proposed to define that
pertinent stakeholders ‘‘include but are
not limited to, industry, small
businesses, and communities most
affected by and/or vulnerable to the
impacts of the plan or plan revision.’’ 669
The preamble to the proposed revisions
to subpart Ba notes that ‘‘increased
vulnerability of communities may be
attributable, among other reasons, to
both an accumulation of negative and
lack of positive environmental, health,
economic, or social conditions within
these populations or communities.’’ 670
In the context of these emission
guidelines, the air pollutant of concern
is greenhouse gases and the air
pollution is elevated concentrations of
these gases in the atmosphere, which
667 40
CFR 60.23(c)–(g); 40 CFR 60.23a(c)–(h).
FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.21a(k)).
669 87 FR 79176, 79191 (December 23, 2022),
Docket ID No. EPA–HQ–OAR–2021–0527–0002
(proposed revisions at 40 CFR 60.21a(l)).
670 87 FR 79176, 79191 (December 23, 2022).
668 87
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result in warming temperatures and
other changes to the climate system that
are leading to serious and lifethreatening environmental and human
health impacts. Thus, one set of impacts
on communities that states should
consider in identifying pertinent
stakeholders is climate change impacts,
including increased incidence of
drought and flooding, damage to crops
and disruption of associated food, fiber,
and fuel production systems, increased
incidence of pests, increased incidence
of heat-induced illness, and impacts on
water availability and water quality.
These and other such climate changerelated impacts can have a
disproportionate impact on
communities and populations
depending on, inter alia, accumulation
of negative and lack of positive
environmental, health, economic, or
social conditions. The Agency therefore
expects states’ pertinent stakeholders to
include not only owners and operators
of affected EGUs but also communities
within the State that are most affected
by and/or vulnerable to the impacts of
climate change, including those exposed
to more extreme drought, flooding, and
other severe weather impacts, including
extreme heat and cold (states should
refer to section III of this preamble, on
climate impacts, to assist them in
identifying their pertinent stakeholders).
Additionally, communities near
affected EGUs may also be affected by
a State plan or plan revision due to
impacts associated with implementation
of that plan. For example, communities
located near affected EGUs may be
impacted by construction and operation
of infrastructure required under a State
plan. Activities related to the
construction and operation of new
natural gas, CCS, and hydrogen
pipelines may impact individuals and
communities both locally and at larger
distances from affected EGUs but near
any associated pipelines. Thus,
communities near affected EGUs and
communities near pipelines constructed
pursuant to State plan requirements
should be considered pertinent
stakeholders and included in
meaningful engagement.
The EPA also acknowledges that
employment at affected EGUs (including
employment in operation and
maintenance as well as in construction
for installation of pollution control
technology) is impacted by power sector
trends on an ongoing basis, and states
may choose to take energy communities
into consideration as part of meaningful
engagement. A variety of Federal
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programs are available to support these
communities.671
In some cases, an affected EGU may
be located near State or Tribal borders
and impact communities in neighboring
states or Tribal lands. In such cases, the
EPA believes it could be reasonable for
a State to identify pertinent stakeholders
in the neighboring State or Tribal land
and to work with the relevant air
pollution control authority to conduct
meaningful engagement that addresses
cross-border impacts. The EPA solicits
comment on how meaningful
engagement should apply to pertinent
stakeholders outside a State’s borders.
It is important for states to recognize
and engage the communities most
affected by and/or vulnerable to the
impacts of a State plan, particularly as
these communities may not have had a
voice when the affected EGUs were
originally constructed. Consistent with
the long-standing requirements for
public engagement in State plan
development, states should design
meaningful engagement to ensure that
all pertinent stakeholders are able to
provide input on how affected EGUs in
their State comply with their State plan
requirements pursuant to these emission
guidelines. Because these emission
guidelines address air pollution that
becomes well mixed and is long-lived in
the atmosphere, the EPA expects states
will consider communities and
populations within the State that are
both most impacted by particular
affected EGUs and associated pipelines
and that will be most affected by the
overall stringency of State plans. (Note
that the EPA addresses consideration of
impacts of particular sources in the
context of RULOF in section XII.D.2.c of
this preamble.)
During the Agency’s pre-proposal
outreach, some environmental justice
organizations and community
representatives raised strongly held
concerns about the potential health,
671 An April 2023 report of the Federal
Interagency Working Group on Coal and Power
Plant Communities and Economic Revitalization
(Energy Communities IWG) summarizes how the
Bipartisan Infrastructure Law, CHIPS and Science
Act, and Inflation Reduction Act have greatly
increased the amount of Federal funding relevant to
meeting the needs of energy communities, as well
as how the Energy Communities IWG has launched
an online Clearinghouse of broadly available
Federal funding opportunities relevant for meeting
the needs and interests of energy communities, with
information on how energy communities can access
Federal dollars and obtain technical assistance to
make sure these new funds can connect to local
projects in their communities. Interagency Working
Group on Coal and Power Plant Communities and
Economic Revitalization. ‘‘Revitalizing Energy
Communities: Two-Year Report to the President’’
(April 2023). https://energycommunities.gov/wpcontent/uploads/2023/04/IWG-Two-Year-Report-tothe-President.pdf.
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environmental, and safety impacts of
CCS. The EPA believes that any
deployment of CCS can and should take
place in a manner that is protective of
public health, safety, and the
environment, and that includes early
and meaningful engagement with
affected communities and the public. As
stated in the Council on Environmental
Quality’s (CEQ) February 2022 Carbon
Capture, Utilization, and Sequestration
Guidance, ‘‘the successful widespread
deployment of responsible CCUS will
require strong and effective permitting,
efficient regulatory regimes, meaningful
public engagement early in the review
and deployment process, and measures
to safeguard public health and the
environment.’’ 672
As discussed in section V.C.3 of this
preamble, the EPA is required to
consider nonair quality health and
environmental impacts, along with
other considerations, in determining the
BSER for both new and existing affected
EGUs. In developing this proposed
rulemaking, the EPA heard and
carefully considered concerns expressed
by affected communities regarding the
possible impacts of CCS and hydrogen
infrastructure in the context of selecting
the proposed BSER. After weighing any
adverse nonair quality health and
environmental impacts of CCS and
hydrogen co-firing along with the other
BSER considerations, including the
significant amount of emission
reductions that can be achieved, and the
reasonableness of the control costs, the
EPA decided to propose that CCS and
hydrogen co-firing meet the
qualifications for the BSER for certain
subcategories of sources. See, for
example, section X.D.1.a.iii of this
preamble.
The EPA recognizes, however, that
facility- and community-specific
circumstances, including the existence
of cumulative impacts affecting a
community’s resilience or where
infrastructure buildout would
necessarily occur in an already
vulnerable community, may also exist.
The meaningful engagement process is
designed to identify and enable
consideration of these and other facilityand community-specific circumstances.
This includes consideration of facilityand community-specific concerns with
emissions control systems, including
CCS and hydrogen co-firing. States
should design meaningful engagement
to elicit input from pertinent
stakeholders on facility- and
672 Carbon Capture, Utilization, and Sequestration
Guidance, 87 FR 8808, 8809 (February 16, 2022),
https://www.govinfo.gov/content/pkg/FR-2022-0216/pdf/2022-03205.pdf.
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community-specific issues related to
implementation of emissions control
systems generally, as well as on any
considerations for particular systems.
If the revisions to subpart Ba are
finalized as proposed, states would need
to demonstrate in their State plans how
they provided meaningful engagement
with the pertinent stakeholders. This
includes providing a list of the pertinent
stakeholders, a summary of engagement
conducted, and a summary of the
stakeholder input provided, including
information about the potential
pollution impacts and benefits of
control. As previously noted, the State
must allow for balanced participation,
including communities most vulnerable
to the impacts of the plan. States must
consider the best way to reach affected
communities, which may include but
should not be limited to notification
through the internet. Other channels
may include notice through
newspapers, libraries, schools,
hospitals, travel centers, community
centers, places of worship, gas stations,
convenience stores, casinos, smoke
shops, Tribal Assistance for Needy
Families offices, Indian Health Services,
clinics, and/or other community health
and social services as appropriate. The
State should also consider any
geographic, linguistic, or other barriers
to participation in meaningful
engagement for members of the public.
If a State plan submission does not meet
the required elements for notice and
opportunity for public participation,
including requirements for meaningful
engagement, this may be grounds for the
EPA to find the submission incomplete
or to disapprove the plan. As discussed
in section XII.F.2 of this preamble, the
EPA is proposing to provide 24 months
from the date of publication of final
emission guidelines for State plan
submission, which should allow states
adequate time to conduct meaningful
engagement.
The EPA is requesting comment on
what assistance states and pertinent
stakeholders may need in conducting
meaningful engagement with affected
communities to ensure that there are
adequate opportunities for public input
on decisions to implement emissions
control technology (including but not
limited to CCS or low-GHG hydrogen).
The EPA is also requesting comment on
any tools or methodologies that states
may find helpful for identifying
communities that are most affected by
and vulnerable to emissions from
affected EGUs under these emission
guidelines. The EPA is also requesting
comment on whether it would be useful
for the Agency to promulgate minimum
approvability requirements for
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meaningful engagement that are specific
to these emission guidelines and, if so,
what those requirements should be.
i. Specific State Plan Requirements for
Existing Combustion Turbines Co-Firing
Low-GHG Hydrogen
As discussed in section XI.C of this
preamble, the EPA is proposing that the
BSER for affected combustion turbine
EGUs in the hydrogen co-fired
subcategory is co-fired 30 percent lowGHG hydrogen by volume starting
January 1, 2032, and 96 percent lowGHG hydrogen by volume starting
January 1, 2038. Therefore, as discussed
in section XII.D.1.c.ii of this preamble,
the EPA is proposing a rate-based
presumptive standard of performance
for the hydrogen co-fired subcategory
based on co-firing low-GHG hydrogen at
these levels. However, CAA section 111
does not require that sources meet their
applicable standards of performance by
implementing the BSER. Therefore,
affected combustion turbine EGUs in the
hydrogen co-fired subcategory do not
necessarily have to meet their standards
of performance by co-firing hydrogen.
However, should they choose to comply
in this manner, the hydrogen that they
co-fire to meet their standards of
performance must be low-GHG
hydrogen. Thus, the EPA is proposing
that State plans require that affected
EGUs in the hydrogen co-fired
subcategory that meet their standards of
performance by co-firing hydrogen
demonstrate that they are co-firing lowGHG hydrogen. The EPA discusses its
rationale for requiring low-GHG
hydrogen to be used for compliance and
its proposed definition of low-GHG
hydrogen in sections VII.F.3.c.vi and
VII.F.3.c.vii(F) of this preamble.
Section VII.K.3 of this preamble
discusses the EPA’s proposal to closely
follow Department of Treasury
protocols, which are currently under
development, in determining how
affected EGUs demonstrate compliance
with the requirement to use low-GHG
hydrogen. In the context of the proposed
CAA section 111(b) rule for new
combustion turbines, the EPA is taking
comment on what forms of acceptable
mechanisms and documentary evidence
should be required for EGUs to
demonstrate compliance with the
obligation to co-fire low-GHG hydrogen,
including proof of production pathway,
overall emissions calculations or
modeling results and input, purchasing
agreements, contracts, and attribute
certificates. The EPA is also taking
comment, in the context of the CAA
section 111(b) rule, on whether EGUs
should be required to make fully
transparent their sources of low-GHG
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hydrogen and the corresponding
quantities procured, as well as on
whether the EPA should require EGUs
to demonstrate that their hydrogen is
exclusively from facilities that produce
only low-GHG hydrogen, as a means of
reducing burden and opportunities for
double counting. The EPA proposed to
mirror the requirements it finalizes for
verification of low-GHG hydrogen for
new combustion turbine EGUs, as
discussed in section VII.K.3 of this
preamble, in the State plan
requirements for affected existing
combustion turbine EGUs in the
hydrogen co-fired subcategory under
these emission guidelines. The EPA
therefore requests comment on the
proposed approaches for verifying that
low-GHG hydrogen is used for
complying with an applicable standard
of performance discussed in section
VII.K.3 of this preamble. Additionally,
the EPA requests comment on any
unique considerations regarding the
implementation of such verification
requirements through State plans,
including whether any additional or
different requirements may be necessary
to ensure that affected existing
combustion turbine EGUs in the
hydrogen co-firing subcategory that cofire hydrogen to meet their standards of
performance co-fire with low-GHG
hydrogen.
ii. Specific State Plan Requirements for
Transparency and Compliance
Assurance
The EPA is proposing or requesting
comment on several requirements
designed to help states ensure
compliance by affected EGUs with
standards of performance, as well as to
assist the public in tracking increments
of progress toward the final compliance
date.
First, the EPA is requesting comment
on whether to require that an affected
EGU’s enforceable commitment to
permanently cease operations, when a
State relies on that commitment for
subcategory applicability (e.g., a State
elects to rely on an affected coal-fired
steam-generating unit’s commitment to
permanently cease operations by
December 31, 2034, to meet the
applicability requirements for the nearterm subcategory), must be in the form
of an emission limit of 0 lb CO2/MWh
that applies on the relevant date.673
Such an emission limit would be
included in a State regulation, permit,
order, or other acceptable legal
instrument and submitted to the EPA as
part of a State plan. If approved, the
affected EGU would have a federally
enforceable emission limit of 0 lb CO2/
MWh that would become effective as of
the date that the EGU permanently
ceases operations. The EPA is
requesting comment on whether such an
emission limit would have any
advantages or disadvantages for
compliance and enforceability relative
to the alternative, which is an
enforceable commitment in a State plan
to cease operation by a date certain.
Second, the EPA is proposing that
State plans that cover affected coal-fired
steam generating units within any
subcategory that is based on the date by
which a source elects to permanently
cease operations (i.e., imminent-term,
near-term, medium-term) must include,
in conjunction with an enforceable date,
the requirement that each source
comply with applicable State and
Federal requirements for permanently
ceasing operation of the EGU, including
removal from its respective State’s air
emissions inventory and amending or
revoking all applicable permits to reflect
the permanent shutdown status of the
EGU.
Third, the EPA is proposing that each
State plan must require owners and
operators of affected EGUs to establish
publicly accessible websites, referred to
here as a ‘‘Carbon Pollution Standards
for EGUs website,’’ to which all
reporting and recordkeeping
information for each affected EGU
subject to the State plan would be
posted. Although this information will
also be required to be submitted directly
to the EPA and the relevant State
regulatory authority, the EPA is
interested in ensuring that the
information is made accessible in a
timely manner to all pertinent
stakeholders. The EPA anticipates that
the owners or operators of a portion of
the affected EGUs may already be
posting comparable reporting and
recordkeeping information to publicly
available websites under the EPA’s
April 2015 Coal Combustion Residuals
Rule,674 such that the burden of this
website requirement for these units
could be minimal.
In particular, the EPA is proposing
that the owners or operators of affected
EGUs would be required to post to their
websites their subcategory designations
and compliance schedules, including
for increments of progress and
milestones, leading up to full
673 As explained in section X of this preamble, an
affected EGU’s federally enforceable commitment to
cease operations is not part of that EGU’s standard
of performance but is rather a prerequisite
condition for subcategory applicability.
674 See https://www.epa.gov/coalash/list-publiclyaccessible-internet-sites-hosting-compliance-dataand-information-required for a list of websites for
facilities posting Coal Combustion Rule compliance
information.
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compliance with the applicable
standards of performance. Owners or
operators would also be required to post
to their websites any information or
documentation needed to demonstrate
that an increment of progress or
milestone has been achieved. Similarly,
the EPA is proposing that emissions
data and other information needed to
demonstrate compliance with a
standard of performance would also be
required to be posted to the Carbon
Pollution Standards for EGUs website
for an affected EGU in a timely manner.
The EPA is proposing that all
information required to be made
publicly available on the Carbon
Pollution Standards for EGUs website be
posted within 30 business days of the
information becoming available to or
reported by the owner or operator of an
affected EGU. Information would have
to remain on the website for a minimum
of 10 years. The EPA solicits comment
on these timeframes for posting and
information retention, as well as on any
concerns related to confidential
business information.
The EPA proposes that owners or
operators of affected EGUs that are also
subject to similar website reporting
requirements for the Coal Combustion
Residuals Rule may use an already
established website to house the
reporting and recordkeeping
information necessary to satisfy its
Carbon Pollution Standards for EGUs
website requirements. The EPA solicits
comment on other ways to reduce
redundancy and burden while satisfying
the objective of making it easier for
pertinent stakeholders to access affected
EGUs’ reporting and recordkeeping
information.
To make it easier for the public to find
the relevant Carbon Pollution Standards
for EGUs websites, the EPA is also
proposing that a State must establish a
website that displays the links to the
websites for all affected EGUs in its
State plan.
Fourth, to promote transparency and
to assist the EPA and the public in
assessing increments of progress under
a State plan, the EPA is proposing that
State plans must include a requirement
that the owner or operator of each
affected EGU must report any deviation
from any federally enforceable State
plan increment of progress or milestone
within 30 business days after the owner
or operator of the affected EGU knew or
should have known of the event. In the
report, the owner or operator of the
affected EGU would be required to
explain the cause or causes of the
deviation and describe all measures
taken or to be taken by the owner or
operator of the EGU to cure the reported
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deviation and to prevent such
deviations in the future, including the
timeframes in which the owner or
operator intends to cure the deviation.
The owner or operator of the EGU must
submit the report to the State regulatory
agency and post the report to the
affected EGU’s Carbon Pollution
Standards for EGUs website.
Fifth, to aid all affected parties and
stakeholders in implementing these
emission guidelines, the EPA is
explaining its intended approach to
exercising its enforcement authorities to
ensure compliance while addressing
genuine risks to electric system
reliability. In these emission guidelines,
the EPA has included subcategories for
coal-fired steam generating units that
take into account the operating horizons
of these units and has provided
relatively long planning and compliance
timeframes. The EPA’s proposed
emission guidelines for existing
combustion turbines likewise provide
extensive lead time to meet the
proposed degrees of emission limitation
and apply only to a portion of the fleet
that exceeds certain capacity and
utilization thresholds. The Agency
therefore does not anticipate that either
the need for certain coal-fired steam
generating units and existing
combustion turbines to install controls,
or affected EGUs’ preexisting decisions
to permanently cease operations, will
result in resource constraints that would
adversely affect electric reliability.
Nonetheless, the EPA believes it is
appropriate to provide accommodations
for potential isolated instances in which
unanticipated factors beyond an owner
or operator’s control, and ability to
predict and plan for, could have an
adverse, localized impact on electric
reliability. In such instances, affected
EGUs could find themselves in the
position of either operating in
noncompliance with approved,
federally enforceable State plan
requirements or halting operations and
thereby potentially impacting electric
reliability.
CAA section 113 authorizes the EPA
to bring enforcement actions against
sources in violation of CAA
requirements, seeking injunctive relief,
civil penalties and, in certain
circumstances, other appropriate relief.
The EPA also has the discretion to agree
to negotiated resolutions, including
administrative compliance orders
(‘‘ACOs’’) for achieving compliance
with CAA requirements, that include
expeditious compliance schedules with
enforceable compliance milestones. The
EPA does not generally speak to the
intended scope of its enforcement
efforts, particularly in advance of a
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violation actually occurring. However,
the EPA is explaining its intended
approach to ACOs here to provide
confidence both with respect to electric
reliability and that emission reductions
under these emission guidelines will
occur as required under CAA section
111(d).
The EPA would evaluate each request
for an ACO for an affected EGU that is
required to run in violation of a State
plan requirement for reliability
purposes on a case-by-case basis.
However, as a general matter, the EPA
anticipates that to qualify for an ACO,
the owner/operator would need to
demonstrate, as a minimum, that the
following conditions have been
satisfied: 675
• The owner/operator of the affected
EGU requesting an ACO has requested,
in writing and in a timely manner, an
enforceable compliance schedule in an
ACO.
• The owner/operator of the affected
EGU requesting an ACO has provided
the EPA written analysis and
documentation of reliability risk if the
unit were not in operation, which
demonstrates that operation of the unit
in noncompliance is critical to
maintaining electric reliability and that
failure to operate the unit would result
in violation of the established reliability
criteria for the relevant control area/
balancing authority, or cause reserves to
fall below the required system reserve
margin.
• The owner/operator of the affected
EGU requesting an ACO has provided
the EPA with written concurrence with
the reliability analysis from the relevant
electric planning authority for the area
in which the affected EGU is located.
• The owner/operator of the affected
EGU requesting an ACO has
demonstrated that the need to continue
operating for reliability purposes is due
to factors beyond the control of the
owner/operator and that the owner/
operator of the affected EGU has not
contributed to the purported need for an
ACO.
• The owner/operator of the affected
EGU requesting an ACO demonstrates
that it has met all applicable increments
of progress and milestones in the State
plan.
• It can be demonstrated that there is
insufficient time to address the
reliability risk and potential
noncompliance through a State plan
revision.
If deemed appropriate to do so, the
EPA would issue an ACO that includes
675 This is a nonexclusive list of conditions. The
EPA may choose to consider additional factors
when deciding whether to enter an ACO in any
given situation.
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a compliance schedule and milestones
to achieve compliance as expeditiously
as practicable. The ACO would also
include any operational limits,
including limits on utilization reflecting
the extent to which the unit is needed
for grid reliability, and/or work
practices necessary to minimize or
mitigate any emissions to the maximum
extent practicable during any operation
of the affected EGU before it has
achieved full compliance. The EPA
reiterates that it would not be
appropriate to request an ACO to
address reliability risk and anticipated
noncompliance in circumstances in
which a State plan revision is possible.
The EPA requests comment on
whether to promulgate requirements in
the final emission guidelines pertaining
to the demonstrations, analysis, and
information the owner or operator of an
affected EGU would have to submit to
the EPA in order to be considered for an
ACO.
2. Timing of State Plan Submissions
The EPA’s proposed subpart Ba
revisions would require states to submit
State plans within 15 months after
publication of the final emission
guidelines.676 For the purpose of these
particular emission guidelines, the EPA
is proposing to supersede that timeline
and is proposing a State plan
submission deadline that is 24 months
from the date of publication of the final
emission guidelines. Crucially, these
proposed emission guidelines apply to a
relatively large and complex source
category—existing fossil fuel-fired steam
generating units and existing fossil fuelfired combustion turbines. Making the
decisions necessary for State plan
development will require significant
analysis, consultation, and coordination
between states, utilities, ISOs or RTOs,
and the owners or operators of
individual affected EGUs. The power
sector is subject to many layers of
regulatory and other requirements under
many authorities, and the decisions
states make under these emission
guidelines will necessarily have to
accommodate many overlapping
considerations and processes. States’
plan development may be additionally
complicated by the fact that, unlike
some other source sectors to which the
general CAA section 111 implementing
regulations apply, decision-making
regarding control strategies and
operations for affected EGUs may not be
solely within the purview of the owners
or operators of those sources; at the very
676 87 FR 79182 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.23a(a)).
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least, affected EGUs often must obtain
permission before making significant or
permanent changes. The EPA does not
believe it is reasonable to expect states
and affected EGUs to undertake the
coordination and planning necessary to
ensure that their plans for implementing
these emission guidelines are consistent
with the broader needs and trajectory of
the power sector in the space of 15
months.
Additionally, prior to an owner or
operator providing a suggestion for a
subcategory and standard of
performance for an affected EGU to a
State, that owner or operator will likely
need to analyze options for complying
with the applicable BSER for the
subcategory. The EPA anticipates that
some owners or operators of affected
coal-fired steam generating units and
affected combustion turbines will do
feasibility and FEED studies for CCS
prior to committing to it as a control
strategy in a State plan. As discussed in
section XII.B of this preamble and in the
GHG Mitigation Measures for Steam
Generating Units TSD, FEED studies
take approximately 12 months to
complete,677 after which additional time
is necessary to allow the conclusions
from that study to be integrated into a
State’s planning process for certain
affected EGUs. For other coal-fired
steam generating units, there may also
be planning, design, and permitting
exercises that will be necessary for
utilities to undertake prior to
committing to a subcategory based on
natural gas co-firing. While any boiler
modifications required for affected
EGUs that intend to co-fire natural gas
are relatively straightforward, the
owners or operators of EGUs in the
medium-term subcategory may also be
required to construct new pipelines to
enable co-firing of 40 percent natural
gas. Pipeline projects also require an
initial planning and design process to
determine feasibility and, in some cases,
could involve FERC approval. Similar
considerations apply for affected
combustion turbine EGUs in the
hydrogen co-fired subcategory with
regard to any turbine upgrades that may
be necessary to co-fire higher
percentages of hydrogen and/or to the
construction of any pipeline laterals that
are necessary to supply the EGU with
low-GHG hydrogen. Based on the
approximately 12-month period that
states and the owners or operators of
affected EGUs will likely take to assess
control strategies for these units, the
EPA does not believe it is reasonable to
require State plans to be submitted 15
677 GHG Mitigation Measures for Steam
Generating Units TSD, chapter 4.7.1.
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months after promulgation of these
emission guidelines.
In the proposed subpart Ba timelines
for State plan submission, the EPA
justified the generally applicable
timelines in the context of public health
and welfare impacts by proposing
timelines that are as quick as is
reasonably feasible for a generic set of
emission guidelines under CAA section
111(d). The EPA is proposing 24 months
for State plan timelines for these
emission guidelines because 24 months
is the quickest time that the EPA
believes to be reasonably feasible for a
State to submit a State plan based on the
work and evaluation needed to establish
which compliance strategy (such as CCS
or co-firing) will be appropriate at a
given EGU. Additionally, the EPA does
not believe providing a longer timeline
for the submission of State plans in this
particular instance would ultimately
impact how quickly the affected EGUs
can comply with their standards of
performance. As explained in section
XII.B of this preamble and in the GHG
Mitigation Measures for Steam
Generating Units TSD, the EPA
anticipates that CCS projects will take
roughly 5 years to complete, assuming
some steps are undertaken concurrently.
If the EPA were to promulgate these
emission guidelines in June 2024 and
require State plan submissions in
September 2025, the EPA anticipates
that the soonest compliance could
commence is in the third quarter of
2029. However, in this case, it is likely
that at least some owners/operators of
affected EGUs would have to commit to
subcategories or control technologies
before completing feasibility and FEED
studies, which could result in the need
for plan revisions and delayed emission
reductions. In contrast, providing 24
months for State plan submission would
mean that although plans would be due
June 2026, owners or operators of
affected EGUs would have had time to
complete their feasibility and FEED
studies and some initial planning steps
before then. The EPA anticipates that
owners or operators would need
approximately another 3.5 years to
reach full compliance, meaning that
emission reductions would commence
in the first quarter of 2030. The EPA
does not believe that a difference of
three months will adversely impact
public health or welfare, especially
when it is considered that providing
more time for State plan development in
this instance is more likely to ultimately
result in certainty and timely emission
reductions. The EPA solicits comment
on the 24-month State planning period.
The EPA specifically requests comments
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from owners and operators of affected
EGUs regarding the steps, and amount
of time needed for each step, that they
would have to undertake to determine
the applicable subcategories and to plan
and implement the associated control
strategies for each of their affected
EGUs. Additionally, the EPA requests
comment on the 24-month planning
period from states, including on any
unique characteristics of the fossil fuelfired EGU source category that they
believe merit planning timeframes
longer than 15 months. Through
outreach, many states have expressed a
need for longer planning periods and
the EPA solicits comment on whether
this 24-month planning period
accommodates that need. The EPA also
requests comment from potentially
impacted communities and other
pertinent stakeholders on any
considerations related to providing a
longer State plan submission timeframe
under these emission guidelines.
The EPA is additionally requesting
comment on a potential bifurcated
approach to State plan submissions for
affected steam generating units and
affected combustion turbine EGUs. In
contrast to the proposed compliance
deadline for steam generating units, the
EPA is proposing compliance deadlines
for combustion turbine EGUs in the CCS
subcategory and combustion turbine
EGUs in the hydrogen co-fired
subcategory of January 1, 2035, and
January 1, 2032 (with a second phase
commencing on January 1, 2038),
respectively. Despite the longer period
between the anticipated promulgation of
these emission guidelines and the
proposed compliance deadlines for
affected combustion turbine EGUs, the
EPA is proposing that State plan
submissions containing standards of
performance and other applicable
requirements for these units would be
due 24 months after promulgation.
Based on many of the same
considerations regarding power sector
planning and coordination discussed
above, the EPA believes that states;
owners and operators of affected EGUs;
RTOs, ISOs, or other balancing
authorities; and the public may benefit
from considering the control strategies
for all affected EGUs under these
emission guidelines on the same
timeline. Additionally, the EPA is
cognizant of the need to achieve
emission reductions and thus the public
health and welfare benefits as soon as
reasonably practicable.
However, the EPA also acknowledges
that the compliance timeframes for
combustion turbine EGUs are likely to
be longer than those for steam
generating units under these emission
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guidelines due to, inter alia, the need to
phase installation of CCS across the
power sector and the continued rampup in production and transmission
capacity for low-GHG hydrogen. The
EPA is therefore requesting comment on
an approach in which states would
submit two different plans on different
timelines: a State plan addressing
affected steam-generating units due 24
months after promulgation of these
emission guidelines and a second State
plan addressing affected combustion
turbine EGUs due 36 months after
promulgation of these emission
guidelines. The EPA solicits comment
on this staggered approach and on
whether 36 months, or a longer or
shorter period, could be an appropriate
State plan submission deadline for
combustion turbine EGUs, and why.
The EPA requests that commenters
explain if and how a longer State plan
submission timeline for affected
combustion turbine EGUs would be
consistent with achieving the emission
reductions under these emission
guidelines as quickly as reasonably
practicable, as well as on the potential
interactions between the State plan
submission time frame and the
proposed compliance deadlines for
combustion turbine EGUs. The EPA also
solicits comment from potentially
impacted communities and other
pertinent stakeholders on any
considerations related to providing a
longer State plan submission timeframe
for combustion turbine EGUs under
these emission guidelines.
3. State Plan Revisions
The EPA expects that the State plan
submission deadline proposed under
these emission guidelines would give
states, utilities and independent power
producers, and stakeholders sufficient
time to determine in which subcategory
each of the affected EGUs falls and to
formulate and submit a State plan
accordingly. However, the EPA also
acknowledges that, despite states’ best
efforts to accurately reflect the plans of
owners or operators with regard to
affected EGUs at the time of State plan
submission, such plans may
subsequently change. In general, states
have the authority and discretion to
submit revised State plans to the EPA
for approval.678 State plan revisions are
generally subject to the same
requirements as initial State plan
submissions under these emission
guidelines and the subpart Ba
implementation regulations, including
meaningful engagement, and the EPA
reviews State plan revisions against the
678 40
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33403
applicable requirements of these
emission guidelines in the same manner
in which it reviews initial State plan
submissions pursuant to 40 CFR 60.27a.
Approved State plan requirements
remain federally enforceable unless and
until the EPA approves a plan revision
that supersedes such requirements.
States and affected EGUs should plan
accordingly to avoid noncompliance.
The EPA is proposing a State plan
submission date that is 24 months after
the publication of final emission
guidelines and is proposing that the first
compliance date for a portion of affected
EGUs would be on January 1, 2030. A
State may choose to submit a plan
revision prior to compliance with its
existing State plan requirements;
however, the EPA reiterates that any
already approved federally enforceable
requirements, including milestones,
increments of progress, and standards of
performance, will remain in place
unless and until the EPA approves the
plan revision. The EPA requests
comment on whether it would be
helpful to states to impose a cut-off date
for the submission of plan revisions
ahead of the January 1, 2030,
compliance date for coal-fired steam
generating affected EGUs or ahead of the
separate compliance dates for achieving
the CCS-based or hydrogen co-firingbased standards for existing combustion
turbines. Such a cut-off date, e.g.,
January 1, 2028, would in effect
establish a temporary moratorium on
plan submissions in order to provide a
sufficient window for the EPA to act on
them and effectuate any changes to
existing State plan requirements ahead
of the final compliance date. State plan
revisions would again be permitted after
the final compliance date. As an
alternative to a cut-off date for State
plan revisions ahead of the compliance
date, the EPA requests comment on the
dual-path standards of performance
approach discussed in section XII.F.4 of
this preamble.
Under the proposed emission
guidelines for existing coal-fired steam
generating units, states would place
their affected coal-fired steam
generating units into one of four
subcategories based on the time
horizons over which those EGUs elect to
operate. These subcategories are static—
affected EGUs would not be able move
between subcategories absent a plan
revision.679 However, the EPA
679 If the EPA finalizes an option for States to
include dual paths for an affected coal-fired EGU or
EGUs in their state plans, those affected EGUs
would be able to choose between two subcategories
prior to the final compliance date without the
state’s needing to revise its plan.
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acknowledges that there may be
instances in which a change in
subcategory will be necessary. For
affected coal-fired steam generating
EGUs that are switching into the
imminent-term, near-term, or mediumterm subcategories, the EPA proposes to
require that the State include in its State
plan revision documentation of the
affected EGU’s submission to the
relevant RTO or balancing authority of
the new date it intends to permanently
cease operations, any responses from
and studies conducted by the RTO or
balancing authority addressing
reliability and any other considerations
related to ceasing operations, any filings
with the SEC or notices to investors in
which the plans for the EGU are
mentioned, any integrated resource
plan, and any other relevant information
in support of the new date. This
documentation must be published on
the Carbon Pollution Standards for
EGUs website. These proposed
requirements are modeled on the
proposed milestones for sources electing
to commit to permanently cease
operations and are intended to help
states, stakeholders, and the EPA ensure
that the affected EGU’s change in
circumstances is sufficiently certain to
warrant a State plan revision. Because of
the long lead times for planning and
implementation of control systems for
affected EGUs, revising a State plan after
the submission deadline has the
potential to significantly disrupt states’
and affected EGUs’ compliance
strategies. The EPA therefore believes it
is reasonable to require affected EGUs
and states to provide evidence that a
source’s circumstances have in fact
changed, in order for the EPA to
approve a plan revision. Affected EGUs
switching into the imminent-term, nearterm, or medium-term subcategories
would also be required to comply with
the proposed enforceable milestones
applicable to those subcategories.
Some changes between subcategories
of affected coal-fired steam generating
EGUs, including from the long-term into
the medium-term subcategory and from
the imminent-term or near-term into the
medium-term or long-term subcategory,
would entail new standards of
performance reflecting a different addon control strategy than initially
anticipated. In order to avoid
undermining the stringency of these
proposed emission guidelines, the EPA
expects affected EGUs changing
subcategories before the January 1, 2030,
compliance deadline to make every
reasonable effort to meet that
compliance deadline. However, the EPA
acknowledges that, in some
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circumstances, it may not be possible to
complete the necessary planning and
construction within a shortened
timeframe. Additionally, unforeseen
circumstances could require some
affected EGUs to change subcategories
after the final compliance deadline has
passed (e.g., to ensure reliability).
In these circumstances, the EPA is
proposing that states may use the
RULOF mechanism described in section
XII.D.2 of this preamble to adjust the
compliance deadlines for affected EGUs
that cannot comply with their
applicable standards of performance by
the January 1, 2030, deadline. The EPA
expects that states may be able to
demonstrate that the change in
subcategory constitutes an ‘‘other
circumstance[ ] specific to the facility
. . . that [is] fundamentally different
from the information considered in the
determination of the best system of
emission reduction in the emission
guidelines.’’ 680 In order to invoke
RULOF to change a compliance
deadline for an affected EGU that has
switched subcategories, the EPA
proposes that the State must first
demonstrate that the affected EGU
cannot meet the applicable presumptive
standard of performance by the
compliance deadline in these emission
guidelines. As part of this
demonstration the State would be
required to provide evidence supporting
the affected EGU’s need to switch
subcategories. The State would also be
required to demonstrate that the need to
invoke RULOF and to provide a
different compliance deadline or less
stringent standard of performance was
not caused by self-created impossibility.
Like subcategorization for affected
coal-fired steam-generating units, states
would place their affected combustion
turbine EGUs into one of the two
subcategories in their State plans, along
with the corresponding standard of
performance. These subcategory
designations are static—affected EGUs
would not be able to move between
subcategories absent a plan revision.
The EPA expects that situations
necessitating a change in subcategory
for combustion turbine EGUs will be far
less likely than for coal-fired steamgenerating units. However, should the
need arise for an affected combustion
turbine EGU to change subcategories in
a State plan, the same considerations
discussed above for coal-fired steam
generating units would apply. If a
combustion turbine EGU changes
680 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions to RULOF provisions at 40 CFR
60.24a(e)(3)).
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subcategories in a manner that entails a
new standard of performance that is
based on a different control technology
than initially anticipated, the EPA
expects the owner or operator of that
EGU to make every reasonable effort to
meet the original compliance deadline
for the newly applicable subcategory.
For situations in which this is
impossible, the EPA is proposing that
states could use the RULOF mechanism
as described above to provide a revised
compliance deadline. As part of its
RULOF demonstration, a State would be
required to provide evidence supporting
the affected combustion turbine’s need
to switch subcategories, as well as a
demonstration that the need to invoke
RULOF and to provide a different
compliance deadline was not caused by
the owner or operator’s self-created
impossibility.
Documentation related to these
demonstrations must also be posted to
the Carbon Pollution Standards for
EGUs website. For example, it would
not be reasonable for a State that has
been notified that an RTO requires an
affected EGU to switch subcategories to
wait to revise its SIP until the remaining
useful life of that EGU is so short as to
preclude otherwise reasonable systems
of emission reduction. To this end, the
EPA is proposing to consider when a
State knew or should have known that
an affected EGU would need to switch
subcategories when evaluating the
approvability of State plans that include
RULOF demonstrations. The EPA is
additionally proposing to consider
whether an affected EGU has been
complying with its applicable
milestones and increments of progress
when evaluating RULOF
demonstrations. The EPA encourages
states to consult with their EPA
Regional Offices as early as possible if
they believe it may become necessary
for an affected EGU to switch
subcategories. The EPA requests
comment on whether to set a deadline
for states to provide plan revisions
within a certain timeframe of knowing
that an affected EGU needs to switch
subcategories and on what timeframe
would be appropriate.
The EPA is proposing that states
invoking RULOF because an affected
EGU cannot comply with its newly
applicable presumptive standard of
performance by the final compliance
deadline first evaluate whether the
affected EGU is able to comply with that
standard by a different, later-in-time
deadline. If a State can demonstrate that
an affected EGU cannot reasonably
comply with the applicable presumptive
standard of performance under any
reasonable compliance deadline, it may
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then evaluate different systems of
emission reduction according to the
proposed RULOF mechanism described
in section XII.D.2 of this preamble.
4. Dual-Path Standards of Performance
for Affected EGUs
Under the structure of these emission
guidelines as proposed, states would
assign affected coal-fired steam
generating units to subcategories in their
State plans and an affected EGU would
not be able to change its applicable
subcategory without a State plan
revision. This is because, due to the
nature of the BSERs for coal-fired steam
generating units, an affected EGU that
switches between subcategories may not
be able to meet compliance obligations
for a new and different subcategory
without considerable lag time and thus
the switch would result in
noncompliance and a loss of emission
reductions. Similarly, states would be
required to assign their affected
combustion turbine EGUs to either the
CCS or hydrogen co-fired subcategory in
their State plans, at which point a unit
could not switch between subcategories
without a plan revision. Therefore, as a
general matter, states must assign each
affected EGU to a subcategory and have
in place all the legal instruments
necessary to implement the
requirements for that subcategory by the
time of State plan submission.
However, the EPA acknowledges that
there may be circumstances in which
the owner or operator of a coal-fired
steam generating unit has not yet
finalized its future operating plans and
wishes to retain the option to choose
between two different subcategories
ahead of the proposed January 1, 2030,
compliance date. Similarly, the owner
or operator of a combustion turbine EGU
may wish to retain the ability to choose
between the CCS and hydrogen co-fired
subcategories, particularly because the
relatively long period between State
plan submission and compliance means
that a unit’s circumstances could change
materially in that time. The EPA is
therefore soliciting comment on the
following dual-path approach that may
result in an additional flexibility for
owners or operators of affected coalfired steam generating units and affected
combustion turbine EGUs that want
additional time to commit to a
particular subcategory without the need
for a State plan revision.
The EPA is soliciting comment on an
approach that allows coal-fired steam
generating units and combustion turbine
EGUs to have two different standards of
performance submitted to the EPA in a
State plan based on potential inclusion
in two different subcategories. A State
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plan would be required to have all the
associated components for each
subcategory. For example, for an
affected coal-fired steam generating unit
that wants the option to be part of either
the long-term or imminent-term
subcategory, the State plan would
include an enforceable standard of
performance based on implementation
of CCS and associated requirements,
including increments of progress; as
well as an enforceable requirement to
permanently cease operations before
January 1, 2033, and a standard of
performance based on routine operation
and maintenance. The affected EGU
would be required to meet all
compliance obligations for both
subcategories, including increments of
progress and/or milestones for
commitments to cease operations,
leading up to the compliance date of
January 1, 2030. The State and the
owner or operator of the affected EGU
would be required to choose a
subcategory for the affected EGU ahead
of that date. Specifically, the EPA is
proposing that the State must notify the
EPA of its final applicable subcategory
and standard of performance at least 6
months prior to the compliance date.
For affected coal-fired steam generating
units, the State would be required to
notify the EPA of the applicable
standard by July 1, 2029. For affected
combustion turbine EGUs, the State
would be required to notify the EPA of
the applicable standard by the earliest
compliance date, or July 1, 2031. If the
State has not notified the EPA by the
required date (July 1, 2029, or July 1,
2031) of the final applicable subcategory
for the affected EGU, the EPA is
proposing that a coal-fired steam
generating unit would automatically be
subject to the requirements of the
subcategory that corresponds to the
longer remaining life of the EGU, while
a combustion turbine EGU would
automatically be subject to the
requirements of the CCS subcategory.
Additionally, if the affected EGU misses
an enforceable increment of progress,
milestone (as described in section
XII.D.3 of this preamble), or any other
requirement for one of the two
subcategories, the EGU will
automatically be subject to the
requirements of the other subcategory. If
the EGU misses submissions for
increments of progress and/or
milestones for both subcategories, the
EGU will automatically be subject to the
requirements of the subcategory that
corresponds to the longer remaining life
of the EGU (for coal-fired steam
generating units) or the CCS subcategory
(for combustion turbine EGUs) and will
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33405
additionally be found to be out of
compliance for the increment of
progress or milestone that it has missed.
The EPA is soliciting comment on this
approach to provide flexibility to states
and affected coal-fired steam generating
units and affected combustion turbine
EGUs. In some instances, owners or
operators of affected EGUs may wish to
have additional time to evaluate future
operating plans; this proposed dual-path
approach should provide owners or
operators additional time to commit to
a subcategory. However, with this
additional time comes additional
burden on owners and operators to
demonstrate compliance with each of
the requirements associated with two
different subcategories that would be
included in a State plan. As an example,
a coal-fired steam generating unit
intends to cease operations between
2038 and 2041. The State plan is
submitted and contains two different
enforceable dates to permanently cease
operations, e.g., December 31, 2038,
with a standard of performance based
on natural gas co-firing and December
31, 2041, with a standard of
performance based on CCS, as well as
an enforceable commitment by the State
to choose one path or the other by July
1, 2029. The affected EGU would then
be required to comply with the
increments of progress for both the longterm (CCS) and medium-term (co-firing)
subcategories, until the point at which
the State decides which of the two paths
in its plan it will require for the unit.
The EPA solicits comment on whether
this proposed dual-path flexibility
would have utility and on whether it
could be implemented in a manner that
ensures that states and affected coalfired steam generating units and affected
combustion turbine EGUs would be able
to comply with applicable requirements
in a timely manner. Additionally, the
EPA solicits comment on whether
notification deadlines of July 1, 2029,
for coal-fired steam generating units,
and July 1, 2031, for combustion turbine
EGUs are the appropriate dates for a
final decision between two potential
standards of performance and why.
5. EPA Action on State Plans
Pursuant to proposed subpart Ba, the
EPA would use a 60-day timeline for the
Administrator’s determination of
completeness of a State plan
submission 681 and a 12-month timeline
681 The timeframes and requirements for state
plan submissions described in this section also
apply to state plan revisions. See generally 40 CFR
60.27a.
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for action on State plans.682 The EPA is
not proposing to supersede these
timelines; therefore, review of and
action on State plan submissions will be
governed by the requirements of revised
subpart Ba. First, the EPA would review
the components of the State plan to
determine whether the plan meets the
completeness criteria of 40 CFR
60.27a(g). The EPA must determine
whether a State plan submission has
met the completeness criteria within 60
days of its receipt of that submission. If
the EPA has failed to make a
completeness determination for a State
plan submission within 60 days of
receipt, the submission shall be deemed,
by operation of law, complete as of that
date.
Proposed subpart Ba would require
the EPA to take action on a State plan
submission within 12 months of that
submission’s being deemed complete.
The EPA will review the components of
State plan submissions against the
applicable requirements of subpart Ba
and these emission guidelines,
consistent with the underlying
requirement that State plans must be
‘‘satisfactory’’ per CAA section 111(d). If
the EPA finalizes the revisions to
subpart Ba as proposed, the
Administrator would have the option to
fully approve, fully disapprove,
partially approve, partially disapprove,
and conditionally approve a State plan
submission.683 Any components of a
State plan submission that the EPA
approves become federally enforceable.
The EPA requests comment on the use
of the timeframes provided in subpart
Ba, as the EPA has proposed to revise
it, for EPA actions on State plan
submissions and for the promulgation of
Federal plans for these particular
emission guidelines.
6. Federal Plan Applicability and
Promulgation Timing
The provisions of subpart Ba,
including any revisions the EPA
finalizes pursuant to its December 2022
proposal, will apply to the EPA’s
promulgation of any Federal plans
under these emission guidelines. The
EPA’s obligation to promulgate a
Federal plan is triggered in three
situations: where a State does not
submit a plan by the plan submission
deadline; where the EPA determines
that a State plan submission does not
meet the completeness criteria and the
time period for State plan submission
682 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.27a).
683 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.27a(b)).
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has elapsed; and where the EPA fully or
partially disapproves a State’s plan.684
Where a State has failed to submit a
plan by the submission deadline, the
proposed revisions to subpart Ba would
give the EPA 12 months from the State
plan submission due date to promulgate
a Federal plan; otherwise, the 12-month
period starts from the date the State
plan submission is deemed incomplete,
whether in whole or in part, or from the
date of the EPA’s disapproval. The EPA
may approve a State plan submission
that corrects the relevant deficiency
within the 12-month period, before it
promulgates a Federal plan, in which
case its obligation to promulgate a
Federal plan is relieved.685 As provided
by 40 CFR 60.27a(e), a Federal plan will
prescribe standards of performance for
affected EGUs of the same stringency as
required by these emission guidelines
and will require compliance with such
standards as expeditiously as
practicable but no later than the final
compliance date under these guidelines.
However, upon application by the
owner or operator of an affected EGU,
the EPA in its discretion may provide
for a less stringent standard of
performance or longer compliance
schedule than provided by these
emission guidelines, in which case the
EPA would follow the same process and
criteria in the regulations that apply to
states’ provision of RULOF standards.686
Under the proposed revisions to subpart
Ba, the EPA would also be required to
conduct meaningful engagement with
pertinent stakeholders prior to
promulgating a Federal plan.687
As described in section XII.F.2 of this
preamble, the EPA is proposing to allow
states 24 months for a State plan
submission after the promulgation of the
final emission guidelines. Therefore, the
EPA would be obligated to promulgate
a Federal plan within 36 months of the
final emission guidelines for all states
that fail to submit plans. Note that this
will be the earliest obligation for the
EPA to promulgate Federal plans for
states and that different triggers (e.g., a
disapproved State plan) will result in
later obligations to promulgate Federal
plans contingent on when the obligation
is triggered.
Under the Tribal Authority Rule
(TAR) adopted by the EPA, Tribes may
684 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.27a(c)).
685 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.27a(d)).
686 40 CFR 60.27a(e)(2).
687 87 FR 79176 (December 23, 2022), Docket ID
No. EPA–HQ–OAR–2021–0527–0002 (proposed
revisions at 40 CFR 60.27a(f)).
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seek authority to implement a plan
under CAA section 111(d) in a manner
similar to that of a State. See 40 CFR
part 49, subpart A. Tribes may, but are
not required to, seek approval for
treatment in a manner similar to that of
a State for purposes of developing a
Tribal Implementation Plan (TIP)
implementing the emission guidelines.
If a Tribe obtains approval and submits
a TIP, the EPA will generally use similar
criteria and follow similar procedures as
those described for State plans when
evaluating the TIP submission and will
approve the TIP if appropriate. The EPA
is committed to working with eligible
Tribes to help them seek authorization
and develop plans if they choose. Tribes
that choose to develop plans will
generally have the same flexibilities
available to states in this process. If a
Tribe does not seek and obtain the
authority from the EPA to establish a
TIP, the EPA has the authority to
establish a Federal CAA section 111(d)
plan for areas of Indian country where
designated facilities are located. A
Federal plan would apply to all
designated facilities located in the areas
of Indian country covered by the
Federal plan unless and until the EPA
approves an applicable TIP applicable
to those facilities.
XIII. Implications for Other EPA
Programs
A. Implications for New Source Review
(NSR) Program
CAA section 110(a)(2)(C) requires that
a SIP include a New Source Review
(NSR) program that provides for the
‘‘regulation of the modification and
construction of any stationary source
. . . as necessary to assure that [the
NAAQS] are achieved.’’ Within the NSR
program, the ‘‘major NSR’’
preconstruction permitting program
applies to new construction and
modifications of existing sources that
emit ‘‘regulated NSR pollutants’’ at or
above certain established thresholds.
New sources and modifications that
emit regulated NSR pollutants under the
established thresholds may be subject to
‘‘minor NSR’’ program requirements or
may be excluded from NSR
requirements altogether. The NSR
program for a State or local permitting
authority with an approved SIP is
implemented through 40 CFR 51.160 to
51.166, while the NSR program
applying in areas for which the EPA or
a delegated State, local or Tribal agency
is the permitting authority is
implemented through 40 CFR part 49
and 40 CFR 52.21.
NSR applicability is pollutant-specific
and, for the major NSR program, the
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permitting requirements that apply to a
source depend on the air quality
designation at the location of the source
for each of its emitted pollutants at the
time the permit is issued. Major NSR
permits for sources located in an area
that is designated as attainment or
unclassifiable for the NAAQS for its
pollutants are referred to as Prevention
of Significant Deterioration (PSD)
permits. In addition, PSD permits can
include requirements for specific
pollutants for which there are no
NAAQS.688 Sources subject to PSD
must, among other requirements,
comply with emission limitations that
reflect the Best Available Control
Technology (BACT) for ‘‘each pollutant
subject to regulation’’ as specified by
CAA sections 165(a)(4) and 169(3).
Major NSR permits for sources located
in nonattainment areas and that emit at
or above the specified major NSR
threshold for the pollutant for which the
area is designated as nonattainment are
referred to as Nonattainment NSR
(NNSR) permits. Sources subject to
NNSR must, among other requirements,
meet the Lowest Achievable Emissions
Rate (LAER) pursuant to CAA sections
171(3) and 173(a)(2) for any pollutant
subject to NNSR. For sources subject to
minor NSR, the CAA and EPA rules do
not set forth prescriptive control
technology requirements for minor NSR
programs so these permits can be less
stringent than major NSR permits. Due
to the pollutant-specific applicability of
the NSR program, it is conceivable that
a source seeking to newly construct or
modify may have to obtain multiple
types of NSR permits (i.e., NNSR, PSD,
or minor NSR) depending on the air
quality designation at the location of the
source and the types and amounts of
pollutants it emits.
A new stationary source is subject to
major NSR requirements if its potential
to emit (PTE) a regulated NSR pollutant
exceeds statutory emission thresholds,
upon which the NSR regulations define
it as a ‘‘major stationary source.’’ 689 For
PSD permitting, once a new stationary
688 For the PSD program, ‘‘regulated NSR
pollutant’’ includes any pollutant for which a
NAAQS has been promulgated (‘‘criteria
pollutants’’) and any other air pollutant that meets
the requirements of 40 CFR 52.21(b)(50). Some of
these non-criteria pollutants include fluorides,
sulfuric acid mist, hydrogen sulfide, total reduced
sulfur, and reduced sulfur compounds.
689 For PSD, the statute uses the term ‘‘major
emitting facility’’ and defines it as a stationary
source that emits, or has a PTE, at least 100 tons
per year (TPY) if the source is in one of 28 listed
source categories, or at least 250 TPY if the source
is not a listed source category. CAA section 169(1).
For NNSR, the emissions threshold for a major
stationary source is 100 TPY, and lower thresholds
apply for certain pollutants based on the severity
of the nonattainment classification.
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source is determined to be subject to
major NSR for one regulated NSR
pollutant (with the exception of
GHG),690 the source can be subject to
major NSR requirements for any other
regulated NSR pollutant if the PTE of
that pollutant is at least the
‘‘significant’’ emissions rate (‘‘SER’’), as
defined in 40 CFR 52.21(b)(23). In the
case of GHG,691 the EPA has not
promulgated a GHG SER but applies a
BACT applicability threshold of 75,000
TPY CO2e.692
For an existing source, it can be
subject to major NSR requirements if it
is a major stationary source and its
emissions increase resulting from a
modification (i.e., physical change or
change in the method of operation) are
equal to or greater than the SER for a
regulated NSR pollutant, upon which
the NSR regulations define it as a
‘‘major modification.’’ 693 As with new
sources, the one exception to this
applicability approach is GHG, which
currently applies a BACT applicability
threshold in lieu of a SER and can only
be subject to major NSR if another
pollutant is also subject to major NSR
for the modification. Generally, an
existing major stationary source
triggering major NSR requirements for a
regulated NSR pollutant would have
both a significant emissions increase
from the modification and a significant
net emissions increase at the stationary
source, and the calculation of the
significant emissions increase differs
depending on whether the modification
is to an existing emissions unit, or the
addition of a new emissions unit, or if
it involves multiple types of emission
units.694 An existing major stationary
690 As a result of the Supreme Court’s decision in
UARG v. EPA, the D.C. Circuit issued an amended
judgment in Coalition for Responsible Regulation,
Inc. v. EPA, Nos. 09–1322, 10–073, 10–1092 and
10–1167 (D.C. Cir. April 10, 2015), which, among
other things, vacated the PSD and title V regulations
under review in that case to the extent that they
require a stationary source to obtain a PSD or title
V permit solely because the construction of the
source, or a modification at the source, emits or has
the potential to emit GHGs at or above the
applicable major NSR thresholds.
691 Consistent with the 2009 Endangerment
Findings, the PSD program treats GHG as a single
air pollutant defined as the aggregate group of six
gases: CO2, N2O, CH4, HFCs, PFCs, and SF6. 40 CFR
52.21(b)(49)(i).
692 See Janet G. McCabe and Cynthia Giles, Next
Steps and Preliminary Views on the Application of
Clean Air Act Permitting Programs to Greenhouse
Gases Following the Supreme Court’s Decision in
Utility Air Regulatory Group v. Environmental
Protection Agency (July 24, 2014), https://
www.epa.gov/sites/default/files/2015-12/
documents/20140724memo.pdf.
693 Per 40 CFR 52.21(b)(1)(i)(c), a minor source
that undergoes a physical change that would itself
be considered major, is subject to major source
requirements.
694 40 CFR 52.21(a)(2)(iv); 40 CFR 52.21(b)(2)(i);
40 CFR 52.21(b)(3).
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source would trigger PSD permitting
requirements for GHGs if it undertakes
a modification and: (1) The modification
is otherwise subject to PSD for a
pollutant other than GHG; and (2) the
modification results in a GHG emissions
increase and a GHG net emissions
increase that is equal to or greater than
75,000 TPY CO2e and greater than zero
on a mass basis.
Since GHG is not a criteria pollutant,
it is regulated under the CAA’s PSD
program, but not under the NNSR or
minor NSR programs. For new sources
and modifications that are subject to
PSD, the permitting authority must
establish emission limitations based on
BACT for each pollutant that is subject
to PSD at the major stationary source or
at each emissions unit involved in the
major modification. BACT is assessed
on a case-by-case basis, and the
permitting authority, in its analysis of
BACT for each pollutant, evaluates the
emission reductions that each available
emissions-reducing technology or
technique would achieve, as well as the
energy, environmental, economic, and
other costs associated with each
technology or technique. The CAA also
specifies that BACT cannot be less
stringent than any applicable standard
of performance under the NSPS.695
Permitting authorities may determine
BACT by applying the EPA’s five-step
‘‘top down’’ approach.696 The ultimate
determination of BACT is made by the
permitting authority after a public
notice and comment period of at least
30-days on the draft permit and
supporting information.697
1. NSR Implications of a CAA Section
111(b) Standard
As noted above, BACT cannot be set
at a level that is less stringent than the
standard of performance established by
an applicable NSPS, and the EPA refers
to this minimum control level as the
‘‘BACT floor.’’ While a proposed NSPS
does not establish the BACT floor for
affected facilities seeking a PSD permit,
once an NSPS is promulgated, it then
serves as the BACT floor for any new
major stationary source or major
modification that meets the
695 42 U.S.C. 7479(3) (‘‘In no event shall
application of ‘best available control technology’
result in emissions of any pollutants which will
exceed the emissions allowed by any applicable
standard established pursuant to [CAA Section 111
or 112].’’).
696 U.S. EPA, NSR Workshop Manual (Draft
October 1990), https://www.epa.gov/sites/default/
files/2015-07/documents/1990wman.pdf; U.S. EPA,
PSD and Title V Permitting Guidance for
Greenhouse Gases (March 2011), https://
www.epa.gov/sites/default/files/2015-07/
documents/ghgguid.pdf.
697 40 CFR 124.10.
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permitting authority determines that the
action is exempt from permitting.699
Thus, there may be circumstances in
which an affected source that is
implementing a BSER requirement from
a State plan is required to obtain a major
NSR permit for one or more of its
pollutants. One scenario in which this
may occur is if an affected source
experiences greater unit availability and
reliability as a result of implementing its
BSER requirement (e.g., an efficiency
based BSER) that, in turn, lowers the
operating costs of its EGU. Since EGUs
that operate at lower costs are generally
preferred in the dispatch by the system
operator over units with higher
operational costs, the BSER
implementation could result in
improving the source’s relative
economics that would, in turn, increase
its utilization of its EGU(s). With an
increase in utilization resulting from the
source implementing the BSER, the
annual emissions from the EGU could
increase, and if the emissions increase
equals or exceeds the relevant SER for
one or more of its pollutants, the source
may be required to obtain a major NSR
permit for the modification.
However, while it may be possible for
an affected source to trigger major NSR
requirements from actions it takes to
implement a BSER requirement, we
2. NSR Implications of a CAA Section
expect this situation to not occur often.
111(d) Standard
As previously discussed in this
With respect to the proposed action
preamble, states will have considerable
for emission guidelines, should it be
flexibility in adopting varied
promulgated, states will be called upon
compliance measures as they develop
to develop a plan that establish
their plans to meet the standards of
standards of performance for each
performance of the emission guidelines.
affected EGU that meets the
One of these flexibilities is the ability
requirements in the emission
for states to establish the standards of
guidelines. In doing so, a State agency
performance in their plans in such a
may develop a plan that results in an
way so that their affected sources, in
affected source undertaking a physical
complying with those standards, in fact
or operational change. Under the NSR
would not have emission increases that
program, undertaking a physical or
trigger major NSR requirements. To
operational change may require the
achieve this, the State would need to
source to obtain a preconstruction
conduct an analysis consistent with the
permit for the proposed change, with
NSR regulatory requirements that
the type of NSR permit (i.e., NNSR, PSD,
supports its determination that as long
or minor NSR) depending on the
as affected sources comply with the
amount of the emissions increase
standards of performance, their
resulting from the change and the air
emissions would not increase in a way
quality designation at the location of the
that trigger major NSR requirements. For
source for its emitted pollutants. More
example, a State could, as part of its
specifically, any time an existing source
State plan, develop enforceable
adds equipment or otherwise makes
conditions for a source expected to
physical or operational changes to its
trigger major NSR that would effectively
facility, regardless of whether it has
limit the unit’s ability to increase its
done so to comply with a national or
emissions in amounts that would trigger
State level requirement, the source may
be required to obtain a NSR permit prior
699 The EPA sought to exempt environmentally
to making the changes unless the
beneficially pollution control projects from NSR
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applicability of the NSPS and
commences construction after the date
of the proposed NSPS in the Federal
Register.698 In the context of
combustion turbines that would be
subject to this NSPS at 40 CFR part 60,
subpart TTTTa, for any new major
stationary source or major modification
that commences construction or
reconstruction of a stationary
combustion turbine EGU after the date
of publication of this proposed NSPS,
the PSD permit should reflect a BACT
determination that is at least as stringent
as the promulgated NSPS for each of the
source’s affected EGUs.
However, the fact that a minimum
control requirement is established by an
applicable NSPS does not mean that a
permitting authority cannot select a
more stringent control level for the PSD
permit or consider technologies for
BACT beyond those that were
considered in developing the NSPS. As
explained above, BACT is a case-by-case
review that considers a number of
factors, and the review should reflect
advances in control technology,
reductions in the costs or other impacts
of using particular control strategies, or
other relevant information that may
have become available after
development of an applicable NSPS.
698 U.S.
EPA, PSD and Title V Permitting
Guidance for Greenhouse Gases (March 2011), p.
25.
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requirements in a 2002 rule that codified
longstanding EPA policy, but this rule was struck
down in court. New York v. EPA, 413 F.3d 3, 40–
42 (D.C. Cir. 2005) (New York I).
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major NSR (effectively establishing a
synthetic minor limitation).700
B. Implications for Title V Program
Title V is implemented through 40
CFR parts 70 and 71. Part 70 defines the
minimum requirements for State, local
and Tribal (state) agencies to develop,
implement and enforce a title V
operating permit program; these
programs are developed by the State and
the State submits a program to the EPA
for a review of consistency with part 70.
There are about 117 approved part 70
programs in effect, with about 14,000
part 70 permits currently in effect. (See
Appendix A of 40 CFR part 70 for the
approval status of each State program.)
Part 71 is a Federal permit program run
by the EPA, primarily where there is no
part 70 program in effect (e.g., in Indian
country, the Federal Outer Continental
Shelf, and for offshore Liquified Natural
Gas terminals).701 There are about 100
part 71 permits currently in effect (most
are in Indian country).
The title V regulations require each
permit to include emission limitations
and standards, including operational
requirements and limitations that assure
compliance with all applicable
requirements. Requirements resulting
from these rules that are imposed on
EGUs or other potentially affected
entities that have title V operating
permits are applicable requirements
under the title V regulations and would
need to be incorporated into the
source’s title V permit in accordance
with the schedule established in the
title V regulations. For example, if the
permit has a remaining life of three
years or more, a permit reopening to
incorporate the newly applicable
requirement shall be completed no later
than 18 months after promulgation of
the applicable requirement. If the permit
has a remaining life of less than three
700 Certain stationary sources that emit or have
the potential to emit a pollutant at a level that is
equal to or greater than specified thresholds are
subject to major source requirements. See, e.g., CAA
sections 165(a)(1), 169(1), 501(2), 502(a). A
synthetic minor limitation is a legally and
practicably enforceable restriction that has the
effect of limiting emissions below the relevant level
and that a source voluntarily obtains to avoid major
stationary source requirements, such as the PSD or
title V permitting programs. See, e.g., 40 CFR
52.21(b)(4), 51.166(b)(4), 70.2 (definition of
‘‘potential to emit’’).
701 In some circumstances, the EPA may delegate
authority for part 71 permitting to another
permitting agency, such as a Tribal agency or a
state. The EPA has entered into delegation
agreements for certain part 71 permitting activities
with at least one Tribal agency. There are currently
no States that do not have an approved part 70
program; thus, there is no need for the EPA to
delegate part 71 delegated authority to any state at
this time.
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years, the newly applicable requirement
must be incorporated at permit renewal.
If a State needs to include provisions
related to the State plan in a source’s
title V permit before submitting the plan
to the EPA, these limits should be
labeled as ‘‘state-only’’ or ‘‘not federally
enforceable’’ until the EPA has
approved the State plan. The EPA
solicits comment on whether, and under
what circumstances, states might use
this mechanism.
XIV. Impacts of Proposed Actions
In accordance with E.O. 12866 and
13563, the guidelines of OMB Circular
A–4 and the EPA’s Guidelines for
Preparing Economic Analyses, the EPA
prepared an RIA for these proposed
actions. This RIA presents the expected
economic consequences of the EPA’s
proposed rules, including analysis of
the benefits and costs associated with
the projected emission reductions for
three illustrative scenarios. The first
scenario represents the proposed CAA
111(b) combustion turbine phase 1 and
phase 2 standards and 111(d) steam
generating turbine proposals in
combination. The second and third
scenarios represent different
stringencies of the combined policies.
All three illustrative scenarios are
compared against a single baseline. For
detailed descriptions of the three
illustrative scenarios and the baseline,
see section 1 of the RIA, which is titled
‘‘Regulatory Impact Analysis for the
Proposed New Source Performance
Standards for Greenhouse Gas
Emissions from New, Modified, and
Reconstructed Fossil Fuel-Fired Electric
Generating Units; Emission Guidelines
for Greenhouse Gas Emissions from
Existing Fossil Fuel-Fired Electric
Generating Units; and Repeal of the
Affordable Clean Energy Rule.’’
The three scenarios detailed in the
RIA, including the proposal scenario,
are illustrative in nature and do not
represent the plans that states may
ultimately pursue. As there are
considerable flexibilities afforded to
states in developing their State plans,
the EPA does not have sufficient
information to assess specific
compliance measures on a unit-by-unit
basis. Nonetheless, the EPA believes
that such illustrative analysis can
provide important insights.
In the RIA, the EPA evaluates the
potential impacts of the three
illustrative scenarios using the present
value (PV) of costs, benefits, and net
benefits, calculated for the years 2024 to
2042 from the perspective of 2024, using
both a three percent and seven percent
discount rate. In addition, the EPA
presents the assessment of costs,
benefits, and net benefits for specific
snapshot years, consistent with the
Agency’s historic practice. These
specific snapshot years are 2028, 2030,
2035, and 2040. In addition to the core
benefit-cost analysis, the RIA also
includes analyses of anticipated
economic and energy impacts,
environmental justice impacts, and
employment impacts.
The analysis presented in this
preamble section summarizes key
results of the illustrative policy
scenario. For detailed benefit-cost
results for the three illustrative
scenarios and results of the variety of
impact analysis just mentioned, please
see the RIA, which is available in the
docket for this action. The EPA also
seeks comment on all aspects of the
analysis, including modeling
assumptions.
A. Air Quality Impacts
For the analysis of the proposed
standards for new combustion turbines
and for existing steam generating EGUs,
which do not include the impact of the
proposed standards for existing
combustion turbines and the third phase
of the proposed standards for new
combustion turbines, total cumulative
power sector CO2 emissions between
2028 and 2042 are projected to be 617
million metric tons lower under the
illustrative proposal scenario than
under the baseline. Table 7 shows
projected aggregate annual electricity
sector emission changes for the
illustrative proposal scenario, relative to
the baseline.
TABLE 7—PROJECTED ELECTRICITY SECTOR EMISSION IMPACTS FOR THE ILLUSTRATIVE PROPOSAL SCENARIO, RELATIVE
TO THE BASELINE
CO2 (million
metric tons)
2028
2030
2035
2040
.....................................................................................
.....................................................................................
.....................................................................................
.....................................................................................
Annual NOX
(thousand
short tons)
¥10
¥89
¥37
¥24
Ozone Season
NOX
(thousand
short tons)
¥7
¥64
¥21
¥13
¥3
¥22
¥7
¥4
Annual SO2
(thousand
short tons)
¥12
¥107
¥41
¥30
Direct PM2.5
(thousand
short tons)
¥1
¥6
¥1
¥1
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Note: Ozone season is the May through September period in this analysis.
The emissions changes in these tables
do not account for changes in HAP that
are likely to occur as a result of this
action.
For the analysis of the proposed
standards for existing combustion
turbines and for the third phase of the
proposed standards for new natural gasfired EGUs, total cumulative power
sector CO2 emissions between 2028 and
2042 are estimated to be between 215–
409 million metric tons lower than
under the illustrative proposal scenario.
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TABLE 8—ESTIMATED ELECTRICITY
SECTOR EMISSION IMPACTS FROM
EXISTING GAS STANDARD AND
THIRD PHASE OF LOW-GHG HYDROGEN CO-FIRING STANDARD FOR
NEW BASE LOAD COMBUSTION TURBINES
CO2 (million metric
tons)
Low
2028
2030
2035
2040
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B. Compliance Cost Impacts
The power industry’s compliance
costs are represented in this analysis as
the change in electric power generation
costs between the baseline and
illustrative scenarios, including the cost
of monitoring, reporting, and
recordkeeping. In simple terms, these
costs are an estimate of the increased
power industry expenditures required to
comply with the proposed actions.
The compliance assumptions—and,
therefore, the projected compliance
costs—set forth in this analysis are
illustrative in nature and do not
represent the plans that states may
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ultimately pursue. The illustrative
proposal scenario is designed to reflect,
to the extent possible, the scope and
nature of the proposed guidelines.
However, there is uncertainty with
regards to the precise measures that
states will adopt to meet the
requirements because there are
flexibilities afforded to the states in
developing their State plans.
The impact of the IRA is to accelerate
the ongoing shift towards lower emitting
technology. In particular, tax credits for
low-emitting technology results in
growing generation share for renewable
resources and the deployment of 11 GW
of CCS retrofits on existing coal fired
EGUs, and 10 GW of CCS retrofits on
existing combined cycle EGUs by 2035.
New combined cycle builds are 22 GW
by 2030, and existing coal capacity
continues to decline, falling to 69 GW
by 2030 and 35 GW by 2040. As a result,
the compliance cost of the proposed
rules is lower than it would be absent
the IRA.
We estimate the present value (PV) of
the projected compliance costs for the
analysis of the proposed standards for
new combustion turbines and for
existing steam-generating EGUs, which
do not include the impact of the
proposed standards for existing
combustion turbines EGUs and the third
phase of the proposed standards for new
combustion turbines over the 2024 to
2042 period, as well as estimate the
equivalent annual value (EAV) of the
flow of the compliance costs over this
period. The EAV represents a flow of
constant annual values that, had they
occurred annually, would yield a sum
equivalent to the PV. All dollars are in
2019 dollars. Consistent with Executive
Order 12866 guidance, we estimate the
PV and EAV using 3 and 7 percent
discount rates. The PV of the
compliance costs, discounted at the 3percent rate, is estimated to be about
$14 billion, with an EAV of about $0.95
billion. At the 7-percent discount rate,
the PV of the compliance costs is
estimated to be about $10 billion, with
an EAV of about $0.98 billion.
The EPA has developed a separate
estimate of the projected compliance
costs for the proposed standards for
existing combustion turbines and third
phase of the proposed standards for new
natural gas-fired EGUs over the 2024 to
2042 period. The PV of these
compliance costs, discounted at the 3percent rate, is estimated to be between
about $5.7 to 10 billion, with an EAV of
between about $0.4 to 0.7 billion. At the
7 percent discount rate, the PV of these
compliance costs is estimated to be
between about $3.5 to 6.2 billion, with
an EAV of about $0.34 to 0.6 billion.
Sections 3 and 8 of the RIA present
detailed discussions of the compliance
cost projections for the proposed
requirements, as well as projections of
compliance costs for less and more
stringent regulatory options. For a
detailed description of these compliance
cost projections, please see sections 3
and 8 of the RIA. The EPA solicits
comment on its cost estimation
generally.
C. Economic and Energy Impacts
These proposed actions have
economic and energy market
implications. The energy impact
estimates presented here reflect the
EPA’s illustrative analysis of the
proposed rules. States are afforded
flexibility to implement the proposed
rules, and thus the impacts could be
different to the extent states make
different choices than those assumed in
the illustrative analysis. Table 9
presents a variety of energy market
impact estimates for 2028, 2030, 2035,
and 2040 for the illustrative proposal
scenario, relative to the baseline. These
results pertain to the analysis of the
proposed standards for new combustion
turbines and for existing steam
generation EGUs, and do not include the
impact of the proposed standards for
existing combustion turbines and the
third phase of the proposed standards
for new combustion turbines.
TABLE 9—SUMMARY OF CERTAIN ENERGY MARKET IMPACTS FOR THE ILLUSTRATIVE PROPOSAL SCENARIO, RELATIVE TO
THE BASELINE
[Percent change]
2028
(%)
¥1
¥1
¥2
0
0
0
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Retail electricity prices .....................................................................................................................
Average price of coal delivered to power sector .............................................................................
Coal production for power sector use .............................................................................................
Price of natural gas delivered to power sector ...............................................................................
Price of average Henry Hub (spot) .................................................................................................
Natural gas use for electricity generation ........................................................................................
These and other energy market
impacts are discussed more extensively
in section 3 of the RIA.
More broadly, changes in production
in a directly regulated sector may have
effects on other markets when output
from that sector—for this rule
electricity—is used as an input in the
production of other goods. It may also
affect upstream industries that supply
goods and services to the sector, along
with labor and capital markets, as these
suppliers alter production processes in
response to changes in factor prices. In
addition, households may change their
demand for particular goods and
services due to changes in the price of
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electricity and other final goods prices.
Economy-wide models—and, more
specifically, computable general
equilibrium (CGE) models—are
analytical tools that can be used to
evaluate the broad impacts of a
regulatory action. A CGE-based
approach to cost estimation
concurrently considers the effect of a
regulation across all sectors in the
economy.
In 2015, the EPA established a
Science Advisory Board (SAB) panel to
consider the technical merits and
challenges of using economy-wide
models to evaluate costs, benefits, and
economic impacts in regulatory
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(%)
2
0
¥40
9
10
8
2035
(%)
0
2
¥23
¥2
¥2
¥1
2040
(%)
0
2
¥15
¥3
¥2
¥2
analysis. In its final report, the SAB
recommended that the EPA begin to
integrate CGE modeling into applicable
regulatory analysis to offer a more
comprehensive assessment of the effects
of air regulations.702 In response to the
SAB’s recommendations, the EPA
developed a new CGE model called
SAGE designed for use in regulatory
analysis. A second SAB panel
702 U.S. EPA. 2017. SAB Advice on the Use of
Economy-Wide Models in Evaluating the Social
Costs, Benefits, and Economic Impacts of Air
Regulations. EPA–SAB–17–012.
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performed a peer review of SAGE, and
the review concluded in 2020.703
The EPA used SAGE to evaluate
potential economy-wide impacts of
these proposed rules, and the results are
contained in an appendix of the RIA. As
presented in the RIA, annualized social
costs estimated in SAGE are
approximately 35 percent larger than
the partial equilibrium private
compliance costs (less taxes and
transfers) derived from IPM. This is
consistent with general expectations
based on the empirical literature.704
However, the social cost estimate
reflects the combined effect of the
proposed rules’ requirements and
interactions with IRA subsidies for
specific technologies that are expected
to see increased use in response to the
proposed rules. We are not able to
identify their relative roles at this time.
The EPA solicits comment on the SAGE
analysis presented in the RIA appendix.
Environmental regulation may affect
groups of workers differently, as
changes in abatement and other
compliance activities cause labor and
other resources to shift. An employment
impact analysis describes the
characteristics of groups of workers
potentially affected by a regulation, as
well as labor market conditions in
affected occupations, industries, and
geographic areas. Employment impacts
of these proposed actions are discussed
more extensively in section 5 of the RIA.
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D. Benefits
Pursuant to E.O. 12866, the RIA for
these actions analyzes the benefits
associated with the projected emission
reductions under the proposals to
inform the EPA and the public about
these projected impacts.705 These
proposed rules are projected to reduce
emissions of CO2, SO2, NOX, and PM2.5
nationwide which we estimate will
provide climate benefits and public
health benefits. The potential climate,
health, welfare, and water quality
impacts of these emission reductions are
discussed in detail in the RIA. In the
RIA, the EPA presents the projected
monetized climate benefits due to
703 U.S. EPA. 2020. Technical Review of EPA’s
Computable General Equilibrium Model, SAGE.
EPA–SAB–20–010.
704 See, for example, Marten, A.L., Garbaccio, R.,
and Wolverton, A. 2019. Exploring the General
Equilibrium Costs of Sector-Specific Environmental
Regulations. Journal of the Association of
Environmental and Resource Economists, 6(6),
1065–1104.
705 These results pertain to the analysis of the
proposed standards for new combustion turbine
EGUs and for existing steam-generating EGUs, and
do not include the impact of the proposed
standards for existing combustion turbine EGUs and
the third phase of the proposed standards for new
natural gas-fired EGUs.
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reductions in CO2 emissions and the
monetized health benefits attributable to
changes in SO2, NOX, and PM2.5
emissions, based on the emissions
estimates in illustrative scenarios
described previously. We monetize
benefits of the proposed standards and
evaluate other costs in part to enable a
comparison of costs and benefits
pursuant to E.O. 12866, but we
recognize there are substantial
uncertainties and limitations in
monetizing benefits, including benefits
that have not been quantified or
monetized.
We estimate the climate benefits from
these proposed rules using estimates of
the social cost of greenhouse gases (SC–
GHG), specifically the SC–CO2. The SC–
CO2 is the monetary value of the net
harm to society associated with a
marginal increase in CO2 emissions in a
given year, or the benefit of avoiding
that increase. In principle, SC–CO2
includes the value of all climate change
impacts (both negative and positive),
including (but not limited to) changes in
net agricultural productivity, human
health effects, property damage from
increased flood risk natural disasters,
disruption of energy systems, risk of
conflict, environmental migration, and
the value of ecosystem services. The
SC–CO2, therefore, reflects the societal
value of reducing emissions of the gas
in question by one metric ton and is the
theoretically appropriate value to use in
conducting benefit-cost analyses of
policies that affect CO2 emissions. In
practice, data and modeling limitations
naturally restrain the ability of SC–CO2
estimates to include all the important
physical, ecological, and economic
impacts of climate change, such that the
estimates are a partial accounting of
climate change impacts and will
therefore, tend to be underestimates of
the marginal benefits of abatement. The
EPA and other Federal agencies began
regularly incorporating SC–GHG
estimates in their benefit-cost analyses
conducted under E.O. 12866 since 2008,
following a Ninth Circuit Court of
Appeals remand of a rule for failing to
monetize the benefits of reducing CO2
emissions in a rulemaking process.
We estimate the global social benefits
of CO2 emission reductions expected
from the proposed rule using the SC–
GHG estimates presented in the
February 2021 TSD: Social Cost of
Carbon, Methane, and Nitrous Oxide
Interim Estimates under E.O. 13990.
These SC–GHG estimates are interim
values developed under E.O. 13990 for
use in benefit-cost analyses until
updated estimates of the impacts of
climate change can be developed based
on the best available climate science
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and economics. We have evaluated the
SC–GHG estimates in the TSD and have
determined that these estimates are
appropriate for use in estimating the
global social benefits of CO2 emission
reductions expected from this proposed
rule. After considering the TSD, and the
issues and studies discussed therein, the
EPA finds that these estimates, while
likely an underestimate, are the best
currently available SC–GHG estimates.
These SC–GHG estimates were
developed over many years using a
transparent process, peer-reviewed
methodologies, the best science
available at the time of that process, and
with input from the public. As
discussed in section 4 of the RIA, these
interim SC–CO2 estimates have a
number of limitations, including that
the models used to produce them do not
include all of the important physical,
ecological, and economic impacts of
climate change recognized in the
climate-change literature and that
several modeling input assumptions are
outdated. As discussed in the February
2021 TSD, the Interagency Working
Group on the Social Cost of Greenhouse
Gases (IWG) finds that, taken together,
the limitations suggest that these SC–
CO2 estimates likely underestimate the
damages from CO2 emissions. The IWG
is currently working on a
comprehensive update of the SC–GHG
estimates (under E.O. 13990) taking into
consideration recommendations from
the National Academies of Sciences,
Engineering and Medicine, recent
scientific literature, public comments
received on the February 2021 TSD and
other input from experts and diverse
stakeholder groups. The EPA is
participating in the IWG’s work. In
addition, while that process continues,
the EPA is continuously reviewing
developments in the scientific literature
on the SC–GHG, including more robust
methodologies for estimating damages
from emissions, and looking for
opportunities to further improve SC–
GHG estimation going forward. Most
recently, the EPA has developed a draft
updated SC–GHG methodology within a
sensitivity analysis in the regulatory
impact analysis of the EPA’s November
2022 supplemental proposal for oil and
gas standards that is currently
undergoing external peer review and a
public comment process. If EPA’s
updated SC–GHG methodology is
finalized before these rules are finalized,
the EPA intends to present monetized
climate benefits using the updated SC–
GHG estimates in the final RIA. See
section 4 of the RIA for more discussion
of this effort.
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In addition to CO2, these proposed
rules are expected to reduce emissions
of NOX and SO2 and direct PM2.5
nationally throughout the year. Because
NOX and SO2 are also precursors to
secondary formation of ambient PM2.5,
reducing these emissions would reduce
human exposure to ambient PM2.5
throughout the year and would reduce
the incidence of PM2.5-attributable
health effects. These proposed rules are
also expected to reduce ozone season
NOX emissions nationally. In the
presence of sunlight, NOX and volatile
organic compounds (VOCs) can undergo
a chemical reaction in the atmosphere to
form ozone. Reducing NOX emissions in
most locations reduces human exposure
to ozone and the incidence of ozonerelated health effects, though the degree
to which ozone is reduced will depend
in part on local concentration levels of
VOCs. The RIA estimates the health
benefits of changes in PM2.5 and ozone
concentrations. The health effect
endpoints, effect estimates, benefit unitvalues, and how they were selected, are
described in the Estimating PM2.5- and
Ozone-Attributable Health Benefits
TSD, which is referenced in the RIA for
these actions. Our approach for
updating the endpoints and to identify
suitable epidemiologic studies, baseline
incidence rates, population
demographics, and valuation estimates
is summarized in section 4 of the RIA.
The following PV and EAV estimates
reflect projected benefits over the 2024
to 2042 period, discounted to 2024 in
2019 dollars, for the analysis of the
proposed standards for new natural gasfired EGUs and for existing coal-fired
EGUs, which do not include the impact
of the proposed standards for existing
natural gas-fired EGUs and the third
phase of the proposed standards for new
natural gas-fired EGUs. We monetize
benefits of the proposed standards and
evaluate other costs in part to enable a
comparison of costs and benefits
pursuant to E.O. 12866, but we
recognize there are substantial
uncertainties and limitations in
monetizing benefits, including benefits
that have not been quantified. The
projected PV of monetized climate
benefits is about $30 billion, with an
EAV of about $2.1 billion using the SC–
CO2 discounted at 3 percent. The
projected PV of monetized health
benefits is about $68 billion, with an
EAV of about $4.8 billion discounted at
3 percent. Combining the projected
monetized climate and health benefits
yields a total PV estimate of about $98
billion and EAV estimate of $6.9 billion.
At a 7 percent discount rate, these
proposed rules are expected to generate
projected PV of monetized health
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benefits of about $44 billion, with an
EAV of about $4.3 billion discounted at
7 percent. The EPA notes that while
OMB Circular A–4, as published in
2003, recommends using 3 percent and
7 percent discount rates as ‘‘default’’
values, Circular A–4 also recognizes that
‘‘special ethical considerations arise
when comparing benefits and costs
across generations,’’ and Circular A–4
acknowledges that analyses may
appropriately ‘‘discount future costs and
consumption benefits . . . at a lower
rate than for intragenerational analysis.’’
Therefore, climate benefits remain
discounted at 3 percent in this benefits
analysis. Thus, these proposed rules
would generate a PV of total monetized
benefits of $74 billion, with an EAV of
$6.4 billion discounted at a 7 percent
rate.
The projected PV of monetized
climate benefits for the analysis of the
impact of the proposed standards for
existing combustion turbines and the
third phase of the proposed standards
for new natural gas-fired EGUs is
between about $10 to 20 billion, with an
EAV of between about $0.7 to 1.4 billion
using the SC–CO2 discounted at 3
percent.
The results presented in this section
provide an incomplete overview of the
effects of the proposals. The monetized
climate benefits estimates do not
include important benefits that we are
unable to fully monetize due to data and
modeling limitations. In addition,
important health, welfare, and water
quality benefits anticipated under these
proposed rules are not quantified. We
anticipate that taking non-monetized
effects into account would show the
proposals to be more beneficial than the
tables in this section reflect. Discussion
of the non-monetized health, climate,
welfare, and water quality benefits is
found in section 4 of the RIA.
E. Environmental Justice Analytical
Considerations and Stakeholder
Outreach and Engagement
Consistent with the EPA’s
commitment to integrating
environmental justice (EJ) in the
Agency’s actions, and following the
directives set forth in multiple
Executive Orders, the Agency has
analyzed the impacts of these proposed
rules on communities with potential
environmental justice concerns and
engaged with stakeholders representing
these communities to seek input and
feedback. The EPA evaluates, to the
extent practicable, whether proposed
GHG reductions are accompanied by
changes in other health-harming
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pollutants that may place further
burdens on these communities.706
Executive Order 12898 is discussed in
section XV.J of this preamble and
analytical results are available in section
6 of the RIA.
1. Introduction
Executive Order 12898 directs the
EPA to identify the populations of
concern who are most likely to
experience unequal burdens from
environmental harms; specifically,
minority populations, low-income
populations, and indigenous peoples.
Additionally, Executive Order 13985 is
intended to advance racial equity and
support underserved communities
through Federal government actions.
The EPA defines environmental justice
as the fair treatment and meaningful
involvement of all people regardless of
race, color, national origin, or income,
with respect to the development,
implementation, and enforcement of
environmental laws, regulations, and
policies. The EPA further defines the
term fair treatment to mean that ‘‘no
group of people should bear a
disproportionate burden of
environmental harms and risks,
including those resulting from the
negative environmental consequences of
industrial, governmental, and
commercial operations or programs and
policies’’.707 In recognizing that
minority and low-income populations
often bear an unequal burden of
environmental harms and risks, the EPA
continues to consider ways of protecting
them from adverse public health and
environmental effects of air pollution.
2. Analytical Considerations
EJ concerns for each rulemaking are
unique and should be considered on a
case-by-case basis, and the EPA’s EJ
Technical Guidance states that ‘‘[t]he
analysis of potential EJ concerns for
regulatory actions should address three
questions:
1. Are there potential EJ concerns
associated with environmental stressors
affected by the regulatory action for
population groups of concern in the
baseline?
2. Are there potential EJ concerns
associated with environmental stressors
affected by the regulatory action for
population groups of concern for the
706 These results pertain to the analysis of the
proposed standards for new combustion turbine
EGUs and for existing steam-generating EGUs, and
do not include the impact of the proposed
standards for existing combustion turbine EGUs and
the third phase of the proposed standards for new
natural gas-fired EGUs.
707 Plan EJ 2014. Washington, DC: U.S. EPA,
Office of Environmental Justice. https://
www.epa.gov/environmentaljustice/plan-ej-2014.
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regulatory option(s) under
consideration?
3. For the regulatory option(s) under
consideration, are potential EJ concerns
created or mitigated compared to the
baseline?’’
To address these questions, the EPA
developed an analytical approach that
considers the purpose and specifics of
the rulemaking, as well as the nature of
known and potential exposures and
impacts. For the rules, the EPA
quantitatively evaluates the proximity of
existing affected facilities to potentially
vulnerable and/or overburdened
populations for consideration of local
pollutants impacted by these rules but
not modeled here (RIA section 6.4), as
well as the distribution of ozone and
PM2.5 concentrations in the baseline and
changes due to the proposed
rulemakings across different
demographic groups on the basis of
race, ethnicity, poverty status,
employment status, health insurance
status, age, sex, educational attainment,
and degree of linguistic isolation (RIA
section 6.5). The EPA also qualitatively
discusses potential EJ climate impacts
(RIA section 6.3). Each of these analyses
was performed to answer separate
questions and is associated with unique
limitations and uncertainties.
Baseline demographic proximity
analyses provide information as to
whether there may be potential EJ
concerns associated with environmental
stressors emitted from sources affected
by the regulatory actions for certain
population groups of concern. The
baseline demographic proximity
analyses examined the demographics of
populations living within 5 km and 10
km of the following three sets of
sources: (1) all 140 coal plants with
units potentially subject to the proposed
rules, (2) three coal plants retiring by
January 1, 2032 with units potentially
subject to the proposed rules, and (3) 19
coal plants retiring between January 1,
2032 to January 1, 2040 with units
potentially subject to the proposed
rules. The proximity analysis of the full
population of potentially affected units
greater than 25 MW indicated that the
demographic percentages of the
population within 10 km and 50 km of
the facilities are relatively similar to the
national averages. The proximity
analysis of the 19 units that will retire
from 1/1/32 to 1/1/40 (a subset of the
total 140 units) found that the percent
of the population within 10 km that is
African American is higher than the
national average. The proximity analysis
for the 3 units that will retire by 1/1/32
(a subset of the total 140 units) found
that for both the 10 km and 50 km
populations the percent of the
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population that is Native American for
one facility is significantly above the
national average, the percent of the
population that is Hispanic/Latino for
another facility is significantly above
the national average, and all three
facilities were well above the national
average for both the percent below the
poverty level and the percent below two
times the poverty level.
Because the pollution impacts that are
the focus of these rules may occur
downwind from affected facilities,
ozone and PM2.5 exposure analyses that
evaluate demographic variables are
better able to evaluate any potentially
disproportionate pollution impacts of
these rulemakings. The baseline PM2.5
and ozone exposure analyses respond to
question 1 from EPA’s EJ Technical
Guidance document more directly than
the proximity analyses, as they evaluate
a form of the environmental stressor
primarily affected by the regulatory
actions (RIA section 6.5). Baseline ozone
and PM2.5 exposure analyses show that
certain populations, such as Hispanics,
Asians, those linguistically isolated, and
those less educated may experience
disproportionately higher ozone and
PM2.5 exposures as compared to the
national average. Black populations may
also experience disproportionately
higher PM2.5 concentrations than the
reference group, and American Indian
populations and children may also
experience disproportionately higher
ozone concentrations than the reference
group. Therefore, there likely are
potential EJ concerns associated with
environmental stressors affected by the
regulatory actions for population groups
of concern in the baseline (question 1).
Finally, the EPA evaluates how postpolicy regulatory alternatives of these
proposed rulemakings are expected to
differentially impact demographic
populations, informing questions 2 and
3 from EPA’s EJ Technical Guidance
with regard to ozone and PM2.5 exposure
changes. We infer that baseline
disparities in the ozone and PM2.5
concentration burdens are likely to
remain after implementation of the
regulatory action or alternatives under
consideration. This is due to the small
magnitude of the concentration changes
associated with these rulemakings
across population demographic groups,
relative to the magnitude of the baseline
disparities (question 2). This EJ
assessment also suggests that these
actions are unlikely to mitigate or
exacerbate PM2.5 exposures disparities
across populations of EJ concern
analyzed. Regarding ozone exposures,
while most policy options and future
years analyzed will not likely mitigate
or exacerbate ozone exposure disparities
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33413
for the population groups evaluated,
ozone exposure disparities may be
exacerbated for some population groups
analyzed in 2030 under all regulatory
options. However, the extent to which
disparities may be exacerbated is likely
modest, due to the small magnitude of
the ozone concentration changes
(question 3). Importantly, the actions
described in these proposals are
expected to lower PM2.5 and ozone in
many areas, and thus mitigate some preexisting health risks of air pollution
across all populations evaluated.
3. Outreach and Engagement
In outreach with potentially
vulnerable communities, residents have
voiced two primary concerns. First,
there is the concern that their
communities have experienced
historically disproportionate burdens
from the environmental impacts of
energy production, and second, that as
the sector evolves to use new
technologies such as CCS and hydrogen,
they may continue to face
disproportionate burdens.
With regard to CCS, the EPA is
proposing that CCS is a component of
the BSER for new base load stationary
combustion turbine EGUs, existing coalfired steam generating units that intend
to operate after 2040, and large and
frequently operated existing stationary
combustion turbine EGUs. The EPA
recognizes and has given careful
consideration to the various concerns
that potentially vulnerable communities
have raised with regard to the use of
CCS in determining that CCS is BSER
for these sources. In the following
section, the EPA discusses various
measures undertaken in this rulemaking
and elsewhere to address community
concerns on this matter.
One concern the EPA has heard from
stakeholders is that adding CCS to EGUs
can extend the life of an existing coalfired steam generating unit, subjecting
local residents who have already been
negatively impacted by the operation of
the coal-fired steam generating unit to
additional harmful pollution. There are
several important factors the EPA
considered in evaluating the emission
impact of an upgraded EGU when
determining BSER for these units that
intend to operate in the long term. First,
CCS is the most effective add-on
pollution control available for
mitigation of GHG emissions from
affected sources. Second, most CCS
technologies work much more
effectively when the EGU is emitting the
lowest levels of SO2 possible; therefore
it is likely that as part of a CCS
installation, companies will improve
their EGUs’ SO2 control. Third, a CCS
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retrofit may trigger requirements under
the major NSR program because of the
potential for an emissions increase of
one or more pollutants due to the
additional energy production by the
EGU to power the CO2 capture system.
If the source is undergoing major NSR
permitting, the permitting authority
would provide an opportunity for the
public to comment on the draft permit,
which is another avenue for affected
residents to submit input regarding
additional controls that may be needed
to meet best available control
technology requirements for non-GHG
pollutants such as NOX.708
Communities have also expressed
concerns about CO2 pipeline safety and
geologic sequestration. As discussed in
section VII.F.3.b.iii of the preamble,
supercritical CO2 pipeline safety is
regulated by PHMSA. These regulations
protect against environmental release
during transport and PHMSA has
announced steps to further strengthen
its safety oversight of supercritical CO2
pipelines, including initiating a new
rulemaking to update standards for
supercritical CO2 pipelines and solicited
research proposals to strengthen CO2
pipeline safety.709 Geologic
sequestration of CO2 is regulated by the
EPA through the UIC Program under the
Safe Drinking Water Act, and through
the GHGRP under the Clean Air Act.
UIC Class VI regulations include strong
protections for communities to prevent
contamination of underground sources
of drinking water. These regulatory
protections include a variety of
measures, including proper site
characterization and strict construction,
operating, and monitoring requirements
to ensure well and formation integrity,
proper plugging of wells, and long-term
project management and post-injection
site care to ensure leakage
prevention.710 GHGRP requirements
complement and build on UIC
regulations through air-side monitoring
and reporting requirements that provide
the EPA and communities with a
transparent means of evaluating the
effectiveness of geologic sequestration.
708 The EPA discusses the interactions between
CCS and non-GHG pollutants for existing coal-fired
steam generating units in section X.D.1.a.iii(B) of
this preamble.
709 PHMSA, ‘‘PHMSA Announces New Safety
Measures to Protect Americans From Carbon
Dioxide Pipeline Failures After Satartia, MS Leak.’’
2022. https://www.phmsa.dot.gov/news/phmsaannounces-new-safety-measures-protect-americanscarbon-dioxide-pipeline-failures.
710 See generally Administrator Michael S. Regan,
Underground Injection Control Class VI Letter to
Governors (December 9, 2022), https://
www.epa.gov/system/files/documents/2022-12/
AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
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These programs work in combination to
provide security and transparency.
The final concern the EPA has heard
from stakeholders is about a lack of
opportunity for impacted communities
to voice opinions about projects like this
that affect them. Recognizing the
important stake that local residents have
in decisions regarding EGUs in their
communities, the EPA expects that
states will address facility-specific
concerns about how to responsibly
deploy CCS and any other potential
control strategies in the course of
meaningful engagement under the
proposed emission guidelines for
existing steam generating units and
existing combustion turbines, as
discussed in section XII.F.1.b of the
preamble. State plans should
specifically ensure that community
members have an opportunity to share
their input if they reside near a fossil
fuel-fired steam generating unit that
plans to install CCS to meet the
requirements of these proposed rules
regarding how to responsibly deploy
this technology.
With regard to the decision to
construct a new combustion turbine,
most of the safeguards outlined above
for CCS retrofits apply. While
meaningful engagement applies under
emission guidelines to existing sources,
there exists an opportunity for
community engagement for new sources
as part of the major NSR permitting
process, in the event that the source
triggers major NSR requirements. While
new combustion turbines that co-fire
with hydrogen may trigger major NSR,
there are cases in which they are less
likely to trigger major NSR, such as: (1)
If the new combustion turbine is
proposed at an existing facility and the
facility is able to reduce its emissions
more than the emissions increase from
the combustion turbine (e.g., if the
combustion turbine replaces an existing
coal-fired EGU and the facility has
emission reduction credits from the
shutdown unit), or (2) if the emissions
from the new combustion turbine are
low enough to not trigger major NSR.
The EPA further notes that hydrogen
production presents a unique set of
potential issues for vulnerable
communities. During the February 27th
National Tribal Energy Roundtable
Webinar, one of the primary concerns
articulated was the potential for fossilderived hydrogen to essentially extend
the life of petrochemical industries
already creating localized pollution
loading. Since hydrogen is non-toxic,
and it does not produce carbon dioxide
when burned, the inclusion of hydrogen
in combustion turbine operations will
lower overall health risks compared
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with hydrocarbons. Perceived
community risks with hydrogen related
to storage and transportation include its
combustibility and propensity to leak
due to extremely low molecular weight.
Despite concerns about hydrogen, its
low molecular weight ensures that it
dissipates and disperses quickly when
released outdoors, reducing unintended
combustion risks compared with other
fuels.711 Adequate ventilation and leak
detection are available to ensure safety
and are important elements in the
design of hydrogen systems. Concerns
around hydrogen leaks can be mitigated
with hydrogen monitoring systems
combined with adequate ventilation and
leak detection equipment, including
special flame detectors.712 Further,
building and operational codes and
standards developed specifically for
hydrogen’s properties can minimize
risks around hydrogen usage in a
community.713
New combustion turbine models
designed to combust hydrogen, and
those potentially being retrofit to
combust hydrogen, may be co-located
with electrolyzers that produce the
hydrogen the facility will use. In such
instances, water scarcity could be
exacerbated in some areas by the
freshwater demands of electrolytic
hydrogen production, which could pose
a particular challenge for vulnerable
communities. As such, electrolyzer
siting will need to take water
availability into account. Examples for
sustainable siting for electrolyzers are
emerging in Europe, which has begun to
employ Sustainable Value Methodology
designed to be sensitive to water access
and availability and includes,
‘‘decision-making support, combining
economic, environmental and social
criteria’’.714 We also expect advances in
electrolytic technology over time to
reduce water demand, including the
potential to enabling sea-water usage in
electrolyzers.715
711 Department of Energy, Safe Use of Hydrogen
https://www.energy.gov/eere/fuelcells/safe-usehydrogen.
712 Ibid.
713 Department of Energy, Safety Codes and
Standards https://www.energy.gov/eere/fuelcells/
safety-codes-and-standards-basics.
714 Journal of Cleaner Production, Volume 315, 15
September 2021, 128124, ‘‘Water Availability and
Water Usage Solutions for Electrolysis in Hydrogen
Production’’ Simoes, Sophia et al., https://
www.sciencedirect.com/science/article/pii/
S0959652621023428.
715 Sun, F., Qin, J., Wang, Z. et al. Energy-saving
hydrogen production by chlorine-free hybrid
seawater splitting coupling hydrazine degradation.
Nat Commun 12, 4182 (2021). https://doi.org/
10.1038/s41467-021-24529-3.
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F. Grid Reliability Considerations
The requirements for sources and
states set forth in these proposed actions
were developed cognizant of concerns
about an electric grid under transition,
and related reliability considerations.
As previously stated, a variety of
important influences have led to notable
changes in the generation mix and
expectations of how the power sector
will evolve. These trends have generally
put existing high-emitting generators
under greater economic pressure and
will continue to do so even absent any
EPA action pursuant to CAA section
111, and that is manifest in various
economic projections and modeling of
the electric power system. Recent
legislation, including the IIJA, the IRA,
and State policies have amplified these
trends, with continued change expected
for the existing fleet of EGUs. Moreover,
many regions of the country have
experienced a significant increase in the
frequency and severity of extreme
weather events—events that are notably
projected to worsen if GHG emissions
are not adequately controlled. These
events have impacted energy
infrastructure and both the demand for
and supply of electricity. A wide range
of stakeholders including power
generators, grid operators and State and
Federal regulators are actively engaged
in ensuring the reliability of the electric
power system is maintained and
enhanced in the face of these changes.
As explained in this preamble, these
proposed actions take account of the
rapidly evolving power sector and
extensive input received from power
companies and other stakeholders on
the future of these regulated sources,
while ensuring that new natural gasfired combustion turbines and existing
steam EGUs achieve significant and
cost-effective reductions in GHG
emissions through the application of
adequately demonstrated control
technologies. Preserving the ability of
power companies and grid operators to
maintain system reliability has been a
paramount consideration in the
development of these proposed actions.
Accordingly, these proposed rules
include significant design elements that
are intended to allow the power sector
continued resource and operational
flexibility, and to facilitate long-term
planning during this dynamic period.
Among other things, these elements
include subcategories of new natural
gas-fired combustion turbines that allow
for the stringency of standards of
performance to vary by capacity factor;
subcategories for existing steam EGUs
that are based on operating horizons and
fuel reflecting the request of industry
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stakeholders; compliance deadlines for
both new and existing EGUs that
provide ample lead time to plan; and
proposed State plan flexibilities. In
addition, this preamble discusses EPA’s
intention to exercise its enforcement
discretion where needed to address any
potential instances in which individual
EGUs may need to temporarily operate
for reliability reasons, and to set forth
clear and transparent expectations for
administrative compliance orders to
ensure that compliance with these
proposed rules can be achieved without
impairing the ability of power
companies and grid operators to
maintain reliability. As such, these
proposed rules provide the flexibility
needed to avoid reliability concerns
while still securing the pollution
reductions consistent with section 111
of the CAA.
To support these proposed actions,
the EPA has conducted an analysis of
resource adequacy based upon power
sector modeling and projections of the
standards on existing steam generating
units, and the first two phases of the
standards on new combustion turbines,
as well as the results of the spreadsheetbased analysis of the standards on
existing combustion turbines and the
third phase of the standards on new
combustion turbines, that can be found
in the RIA. Any potential impact of
these proposed actions is dependent
upon a myriad of decisions and
compliance choices source owners and
operators may pursue. It is important to
recognize that the proposed rules
provide multiple flexibilities that
preserve the ability of responsible
authorities to maintain electric
reliability. While not explicitly modeled
using IPM, the proposed emission
guidelines for existing natural gas-fired
EGUs are estimated to have very little
incremental impact on resource
adequacy. The guidelines would affect a
subset of the total natural gas fleet, and
units that install CCS are still able to
maintain capacity accreditation values
(after accounting for capacity de-rates).
Moreover, units that operate below 50
percent capacity factor annually (and
are not subject to the CCS requirement)
would still be able to operate at higher
levels during times of greater demand,
thereby maintaining their capacity
accreditation values.
The results presented in the Resource
Adequacy Analysis TSD, which is
available in the docket, show that the
projected impacts of the proposed rules
on power system operations, under
conditions preserving resource
adequacy, are modest and manageable.
For the specific scenarios analyzed in
the RIA, the implementation of the
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proposed rules can be achieved while
maintaining resource adequacy even as
shifts in existing and new capacity
occur. Retirements are offset by
additions, along with reserve transfers
where/when needed, which
demonstrates that ample compliance
pathways exist for sources while
preserving resource adequacy.
The EPA routinely consults with the
DOE and FERC on electric reliability
and intends to continue to do so as it
develops and implements a final rule.
This ongoing engagement will be
strengthened with routine and
comprehensive communication between
the agencies under the DOE–EPA Joint
Memorandum of Understanding on
Interagency Communication and
Consultation on Electric Reliability
signed on March 8, 2023.716 The
memorandum will provide greater
interagency engagement on electric
reliability issues at a time of significant
dynamism in the power sector, allowing
the EPA and the DOE to use their
considerable expertise in various
aspects of grid reliability to support the
ability of Federal and State regulators,
grid operators, regional reliability
entities, and power companies to
continue to deliver a high standard of
reliable electric service. As the power
sector continues to change and as the
agencies carry out their respective
authorities, the agencies intend to
continue to engage and collectively
monitor, share information, and consult
on policy and program decisions to
assure the continued reliability of the
bulk power system.
In addition, the EPA observes that
power companies, grid operators, and
State public utility commissions have
well-established procedures in place to
preserve electric reliability in response
to changes in the generating portfolio,
and expects that those procedures will
continue to be effective in addressing
compliance decisions that power
companies may make over the extended
time period for implementation of these
proposed rules. In response to any
regulatory requirement, affected sources
will have to take some type of action to
reduce emissions, which will generally
have costs. Some EGU owners may
conclude that, all else being equal,
retiring a particular EGU is likely to be
the more economic option from the
perspective of the unit’s customers and/
or owners because there are better
opportunities for using the capital than
investing it in new emissions controls at
716 Joint Memorandum of Understanding on
Interagency Communication and Consultation on
Electric Reliability (March 8, 2023). https://
www.epa.gov/power-sector/electric-reliability-mou.
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the unit. Such a retirement decision will
require the unit’s owner to follow the
processes put in place by the relevant
RTO, balancing authority, or State
regulator to protect electric system
reliability. These processes typically
include analysis of the potential impacts
of the proposed EGU retirement on
electrical system reliability,
identification of options for mitigating
any identified adverse impacts, and, in
some cases, temporary provision of
additional revenues to support the
EGU’s continued operation until longerterm mitigation measures can be put in
place. In some rare instances where the
reliability of the system is jeopardized
due to extreme weather events or other
unforeseen emergencies, authorities can
request a temporary reprieve from
environmental requirements and
constraints (through DOE) in order to
meet electric demand and maintain
reliability. These proposed actions do
not interfere with these already
available provisions, but rather provides
a long-term pathway for sources to
develop and implement a proper plan to
reduce emissions while maintaining
adequate supplies of electricity.
XV. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
These actions were submitted to the
Office of Management and Budget
(OMB) for review under Section 3(f)(1)
of Executive Order 12866. Any changes
made in response to recommendations
received as part of Executive Order
12866 review have been documented in
the docket. The EPA prepared an
analysis of the potential costs and
benefits associated with these actions.
This analysis, ‘‘Regulatory Impact
Analysis for the Proposed New Source
Performance Standards for Greenhouse
Gas Emissions from New, Modified, and
Reconstructed Fossil Fuel-Fired Electric
Generating Units; Emission Guidelines
for Greenhouse Gas Emissions from
Existing Fossil Fuel-Fired Electric
Generating Units; and Repeal of the
Affordable Clean Energy Rule,’’ is
available in the docket.
Table 10 presents the estimated
present values (PV) and equivalent
annualized values (EAV) of the
projected climate benefits, health
benefits, compliance costs, and net
benefits of the proposed rule in 2019
dollars discounted to 2024. This
analysis covers the impacts of the
proposed standards for new combustion
turbines and for existing steam
generating EGUs, and does not include
the impact of the proposed standards for
existing combustion turbines and the
third phase of the proposed standards
for new combustion turbines. The
estimated monetized net benefits are the
projected monetized benefits minus the
projected monetized costs of the
proposed rules.
The projected climate benefits in table
8 are based on estimates of the social
cost of carbon (SC–CO2) at a 3 percent
discount rate and are discounted using
a 3 percent discount rate to obtain the
PV and EAV estimates in the table.
Under E.O. 12866, the EPA is directed
to consider the costs and benefits of its
actions. Accordingly, in addition to the
projected climate benefits of the
proposals from anticipated reductions
in CO2 emissions, the projected
monetized health benefits include those
related to public health associated with
projected reductions in fine particulate
matter (PM2.5) and ozone
concentrations. The projected health
benefits are associated with several
point estimates and are presented at real
discount rates of 3 and 7 percent. The
power industry’s compliance costs are
represented in this analysis as the
change in electric power generation
costs between the baseline and policy
scenarios. In simple terms, these costs
are an estimate of the increased power
industry expenditures required to
implement the proposed requirements.
These results present an incomplete
overview of the potential effects of the
proposals because important categories
of benefits—including benefits from
reducing HAP emissions—were not
monetized and are therefore not
reflected in the benefit-cost tables. The
EPA anticipates that taking nonmonetized effects into account would
show the proposals to have a greater net
benefit than this table reflects.
TABLE 10—PROJECTED MONETIZED BENEFITS, COMPLIANCE COSTS, AND NET BENEFITS OF THE PROPOSED RULES, 2024
THROUGH 2042 717
[Billions 2019$, discounted to 2024] a
3% Discount
rate
Present Value:
Climate Benefits c .............................................................................................................................................
Health Benefits d ...............................................................................................................................................
Compliance Costs ............................................................................................................................................
Net Benefits e ....................................................................................................................................................
Equivalent Annualized Value b:
Climate Benefits c .............................................................................................................................................
Health Benefits d ...............................................................................................................................................
Compliance Costs ............................................................................................................................................
Net Benefits e ....................................................................................................................................................
7% Discount
rate
$30
68
14
85
$30
44
10
64
2.1
4.8
0.95
5.9
2.1
4.3
0.98
5.4
a Values
have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding.
annualized present value of costs and benefits are calculated over the 20-year period from 2024 to 2042.
c Climate benefits are based on changes (reductions) in CO emissions. Climate benefits in this table are based on estimates of the SC–CO
2
2
at a 3 percent discount rate and are discounted using a 3 percent discount rate to obtain the PV and EAV estimates in the table. The EPA does
not have a single central SC–CO2 point estimate. We emphasize the importance and value of considering the benefits calculated using all four
SC–CO2 estimates (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). As discussed in section 4 of the RIA, consideration of climate benefits calculated using discount rates below 3 percent, including 2 percent and lower,
is also warranted when discounting intergenerational impacts.
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b The
717 This analysis pertains to the proposed
standards for new combustion turbines and for
existing steam generating EGUs and does not
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include the impact of the proposed standards for
existing combustion turbines and the third phase of
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d The EPA notes that while OMB Circular A–4, as published in 2003, recommends using 3 percent and 7 percent discount rates as ‘‘default’’
values, Circular A–4 also recognizes that ‘‘special ethical considerations arise when comparing benefits and costs across generations,’’ and Circular A–4 acknowledges that analyses may appropriately ‘‘discount future costs and consumption benefits . . . at a lower rate than for
intragenerational analysis.’’ Therefore, climate benefits remain discounted at 3 percent in this benefits analysis.
e The projected monetized health benefits include those related to public health associated with reductions in PM
2.5 and ozone concentrations.
The projected health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent.
f Several categories of benefits remain unmonetized and are thus not reflected in the table. Non-monetized benefits include important climate,
health, welfare, and water quality benefits and are described in RIA Table 4–6.
As shown in table 10, the proposed
rules are projected to reduce greenhouse
gas emissions in the form of CO2,
producing a projected PV of monetized
climate benefits of about $30 billion,
with an EAV of about $2.1 billion using
the SC–CO2 discounted at 3 percent.
The proposed rules are also projected to
reduce PM2.5 and ozone concentrations,
producing a projected PV of monetized
health benefits of about $68 billion,
with an EAV of about $4.8 billion
discounted at 3 percent.
The PV of the projected compliance
costs are $14 billion, with an EAV of
about $0.95 billion discounted at 3
percent. Combining the projected
benefits with the projected compliance
costs yields a net benefit PV estimate of
about $85 billion and EAV of about $5.9
billion at a 3 percent discount rate.
At a 7 percent discount rate, the
proposed rules are expected to generate
projected PV of monetized health
benefits of about $44 billion, with an
EAV of about $4.3 billion. Climate
benefits remain discounted at 3 percent
in this net benefits analysis. Thus, the
proposed rules would generate a PV of
monetized benefits of about $74 billion,
with an EAV of about $6.4 billion
discounted at a 7 percent rate. The PV
of the projected compliance costs are
about $10 billion, with an EAV of $0.98
billion discounted at 7 percent.
Combining the projected benefits with
the projected compliance costs yields a
net benefit PV estimate of about $64
billion and an EAV of about $5.4 billion
discounted at 7 percent.
The EPA has developed a separate
analysis of the proposed standards for
existing combustion turbines and third
phase of the proposed standards for new
natural gas-fired EGUs over the 2024 to
2042 period. This analysis includes
estimated compliance costs and climate
benefits, and is located in Section 8 of
the RIA. The PV of the compliance
costs, discounted at the 3-percent rate,
is estimated to be between about $5.7 to
10 billion, with an EAV of between
about $0.40 to 0.70 billion. At the 7
percent discount rate, the PV of the
compliance costs is estimated to be
between about $ 3.5 to 6.2 billion, with
an EAV of about $ 0.34 to 0.60 billion.
The PV of the climate benefits,
discounted at the 3-percent rate, is
estimated to be between about $10 to 20
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billion, with an EAV of between about
$0.70 to 1.4 billion.
As discussed in section XIV of this
preamble, the monetized benefits
estimates provide an incomplete
overview of the beneficial impacts of the
proposals. In particular, the monetized
climate benefits are incomplete and an
underestimate as explained in section
4.2 of the RIA. In addition, important
health, welfare, and water quality
benefits anticipated under these
proposed rules are not quantified or
monetized. The EPA anticipates that
taking non-monetized effects into
account would show the proposals to
have greater benefits than the estimates
in the preamble and RIA reflect.
Simultaneously, the estimates of
compliance costs used in the net
benefits analysis may provide an
incomplete characterization of the true
costs of the rule. The balance of
unquantified benefits and costs is
ambiguous but is unlikely to change the
result that the benefits of the proposals
exceed the costs by billions of dollars
annually.
We also note that the RIA follows the
EPA’s historic practice of using a
technology-rich partial equilibrium
model of the electricity and related fuel
sectors to estimate the incremental costs
of producing electricity under the
requirements of proposed and final
major EPA power sector rules. In
Appendix B of the RIA for these actions,
the EPA has also included an economywide analysis that considers additional
facets of the economic response to the
proposed rules, including the full
resource requirements of the expected
compliance pathways, some of which
are paid for through subsidies in the
partial equilibrium analysis. The social
cost estimates in the economy-wide
analysis and discussed in Appendix B
of the RIA are still far below the
projected benefits of the proposed rules.
B. Paperwork Reduction Act (PRA)
1. 40 CFR Part 60, Subpart TTTT
This action does not impose any new
information collection burden under the
PRA. OMB has previously approved the
information collection activities
contained in the existing regulations
and has assigned OMB control number
2060–0685.
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2. 40 CFR Part 60, Subpart TTTTa
The information collection activities
in this proposed rule have been
submitted for approval to the Office of
Management and Budget (OMB) under
the PRA. The Information Collection
Request (ICR) document that the EPA
prepared has been assigned EPA ICR
number 2771.01. You can find a copy of
the ICR in the docket for this rule, and
it is briefly summarized here.
Respondents/affected entities:
Owners and operators of fossil-fuel fired
EGUs.
Respondent’s obligation to respond:
Mandatory.
Estimated number of respondents: 2.
Frequency of response: Annual.
Total estimated burden: 110 hours
(per year). Burden is defined at 5 CFR
1320.3(b).
Total estimated cost: $14,000 (per
year), includes $0 annualized capital or
operation & maintenance costs.
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for the EPA’s regulations in 40
CFR are listed in 40 CFR part 9.
Submit your comments on the
Agency’s need for this information, the
accuracy of the provided burden
estimates and any suggested methods
for minimizing respondent burden to
the EPA using the docket identified at
the beginning of this rule. The EPA will
respond to any ICR-related comments in
the final rule. You may also send your
ICR-related comments to OMB’s Office
of Information and Regulatory Affairs
using the interface at www.reginfo.gov/
public/do/PRAMain. Find this
particular information collection by
selecting ‘‘Currently under Review—
Open for Public Comments’’ or by using
the search function. OMB must receive
comments no later than July 24, 2023.
3. 40 CFR Part 60, Subpart UUUUb
The information collection activities
in this proposed rule have been
submitted for approval to the Office of
Management and Budget (OMB) under
the PRA. The Information Collection
Request (ICR) document that the EPA
prepared has been assigned EPA ICR
number 2770.01. You can find a copy of
the ICR in the docket for this rule, and
it is briefly summarized here.
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This rule imposes specific
requirements on State governments with
existing fossil fuel-fired steam
generating units. The information
collection requirements are based on the
recordkeeping and reporting burden
associated with developing,
implementing, and enforcing a plan to
limit GHG emissions from existing
EGUs. These recordkeeping and
reporting requirements are specifically
authorized by CAA section 114 (42
U.S.C. 7414). All information submitted
to the EPA pursuant to the
recordkeeping and reporting
requirements for which a claim of
confidentiality is made is safeguarded
according to Agency policies set forth in
40 CFR part 2, subpart B.
The annual burden for this collection
of information for the states (averaged
over the first 3 years following
promulgation) is estimated to be
104,000 hours at a total annual labor
cost of $13.1 million. The annual
burden for the Federal government
associated with the State collection of
information (averaged over the first 3
years following promulgation) is
estimated to be 27,347 hours at a total
annual labor cost of $1.8 million.
Burden is defined at 5 CFR 1320.3(b).
Respondents/affected entities: States
with one or more designated facilities
covered under subpart UUUUb.
Respondent’s obligation to respond:
Mandatory.
Estimated number of respondents: 50.
Frequency of response: Once.
Total estimated burden: 104,000
hours (per year). Burden is defined at 5
CFR 1320.3(b).
Total estimated cost: $13,163,689,
includes $36,750 annualized capital or
operation & maintenance costs.
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for the EPA’s regulations in 40
CFR are listed in 40 CFR part 9.
Submit your comments on the
Agency’s need for this information, the
accuracy of the provided burden
estimates and any suggested methods
for minimizing respondent burden to
the EPA using the docket identified at
the beginning of this rule. The EPA will
respond to any ICR-related comments in
the final rule. You may also send your
ICR-related comments to OMB’s Office
of Information and Regulatory Affairs
using the interface at www.reginfo.gov/
public/do/PRAMain. Find this
particular information collection by
selecting ‘‘Currently under Review—
Open for Public Comments’’ or by using
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the search function. OMB must receive
comments no later than July 24, 2023.
4. 40 CFR Part 60, Subpart UUUUa
This proposed rule does not impose
an information collection burden under
the PRA.
C. Regulatory Flexibility Act (RFA)
I certify that these actions will not
have a significant economic impact on
a substantial number of small entities
under the RFA. The small entities
subject to the requirements of the NSPS
are private companies, investor-owned
utilities, cooperatives, municipalities,
and sub-divisions, that would seek to
build and operate stationary combustion
turbines in the future. The Agency has
determined that seven small entities
may be so impacted, and may
experience an impact of 0 percent to 0.9
percent of revenues in 2035. Details of
this analysis are presented in section 5.3
of the RIA.
The EPA started the Small Business
Advocacy Review (SBAR) panel process
prior to determining if the NSPS would
have a significant economic impact on
a substantial number of small entities
under the RFA. The EPA conducted an
initial outreach meeting with small
entity representatives on December 14,
2022. The EPA sought input from
representatives of small entities while
developing the proposed NSPS which
enabled the EPA to hear directly from
these representatives about the
regulation of GHG emissions from
EGUs. The purpose of the meeting was
to provide general background on the
NSPS rulemaking, answer questions,
and solicit input. Fifteen various small
entities that potentially would be
affected by the NSPS attended the
meeting. The representatives included
small entity municipalities,
cooperatives, and industry professional
organizations. When the EPA
determined the NSPS would not have a
significant economic impact on a
substantial number of small entities
under the RFA, the EPA did not proceed
with convening the SBAR panel.
Emission guidelines will not impose
any requirements on small entities.
Specifically, emission guidelines
established under CAA section 111(d)
do not impose any requirements on
regulated entities and, thus, will not
have a significant economic impact
upon a substantial number of small
entities. After emission guidelines are
promulgated, states establish standards
on existing sources, and it is those State
requirements that could potentially
impact small entities.
The analysis in the accompanying
RIA is consistent with the analysis of
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the analogous situation arising when the
EPA establishes NAAQS, which do not
impose any requirements on regulated
entities. As here, any impact of a
NAAQS on small entities would only
arise when states take subsequent action
to maintain and/or achieve the NAAQS
through their State implementation
plans. See American Trucking Assoc. v.
EPA, 175 F.3d 1029, 1043–45 (D.C. Cir.
1999) (NAAQS do not have significant
impacts upon small entities because
NAAQS themselves impose no
regulations upon small entities).
The EPA is aware that there is
substantial interest in the proposed
rules among small entities and invites
comments on all aspects of the
proposals and their impacts, including
potential impacts on small entities.
D. Unfunded Mandates Reform Act of
1995 (UMRA)
The proposed NSPS contain a Federal
mandate under UMRA, 2 U.S.C. 1531–
1538, that may result in expenditures of
$100 million or more for the private
sector in any one year. The proposed
NSPS do not contain an unfunded
mandate of $100 million or more as
described in UMRA, 2 U.S.C. 1531–1538
for State, local, and Tribal governments,
in the aggregate. Accordingly, the EPA
prepared, under section 202 of UMRA,
a written statement of the benefit-cost
analysis, which is in section XIV of this
preamble and in the RIA.
The proposed repeal of the ACE Rule
and emission guidelines do not contain
an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C.
1531–1538, and do not significantly or
uniquely affect small governments. The
proposed emission guidelines do not
impose any direct compliance
requirements on regulated entities, apart
from the requirement for states to
develop plans to implement the
guidelines under CAA section 111(d) for
designated EGUs. The burden for states
to develop CAA section 111(d) plans in
the 24-month period following
promulgation of the emission guidelines
was estimated and is listed in section
XV.B, but this burden is estimated to be
below $100 million in any one year. As
explained in section XII.F.6, the
proposed emission guidelines do not
impose specific requirements on Tribal
governments that have designated EGUs
located in their area of Indian country.
The proposed actions are not subject
to the requirements of section 203 of
UMRA because they contain no
regulatory requirements that might
significantly or uniquely affect small
governments.
In light of the interest in these rules
among governmental entities, the EPA
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initiated consultation with
governmental entities. The EPA invited
the following 10 national organizations
representing State and local elected
officials to a virtual meeting on
September 22, 2022: (1) National
Governors Association, (2) National
Conference of State Legislatures, (3)
Council of State Governments, (4)
National League of Cities, (5) U.S.
Conference of Mayors, (6) National
Association of Counties, (7)
International City/County Management
Association, (8) National Association of
Towns and Townships, (9) County
Executives of America, and (10)
Environmental Council of States. These
10 organizations representing elected
State and local officials have been
identified by the EPA as the ‘‘Big 10’’
organizations appropriate to contact for
purpose of consultation with elected
officials. Also, the EPA invited air and
utility professional groups who may
have State and local government
members, including the Association of
Air Pollution Control Agencies,
National Association of Clean Air
Agencies, and American Public Power
Association, Large Public Power
Council, National Rural Electric
Cooperative Association, and National
Association of Regulatory Utility
Commissioners to participate in the
meeting. The purpose of the
consultation was to provide general
background on these rulemakings,
answer questions, and solicit input from
State and local governments.
Subsequent to the September 22, 2022,
meeting, the EPA received letters from
five organizations. These letters were
submitted to the pre-proposal nonrulemaking docket. See Docket ID No.
EPA–HQ–OAR–2022–0723–0013, EPA–
HQ–OAR–2022–0723–0016, EPA–HQ–
OAR–2022–0723–0017, EPA–HQ–OAR–
2022–0723–0020, and EPA–HQ–OAR–
2022–0723–0021. For summary of the
UMRA consultation see the
memorandum in the docket titled,
Federalism Pre-Proposal Consultation
Summary.
E. Executive Order 13132: Federalism
The proposed NSPS and the proposed
repeal of the ACE Rule do not have
federalism implications. These actions
will not have substantial direct effects
on the states, on the relationship
between the national government and
the states, or on the distribution of
power and responsibilities among the
various levels of government.
The EPA has concluded that the
proposed emission guidelines may have
federalism implications, because they
may impose substantial direct
compliance costs on State or local
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governments, and the Federal
Government will not provide the funds
necessary to pay these costs.
Any potential federalism implications
arise from the provisions of CAA section
111(d)(1), which direct the EPA to
‘‘prescribe regulations . . . under which
each State shall submit to the [EPA] a
[state] plan . . .’’ establishing standards
of performance for sources in the State.
As discussed in the Supporting
Statement found in the docket for this
rulemaking, the development of State
plans will entail many hours of staff
time to develop and coordinate
programs for compliance with the
proposed emission guidelines, as well
as time to work with State legislatures
as appropriate, and develop a plan
submittal.
Although the direct compliance costs
may not be substantial, the EPA
nonetheless elected to consult with
representatives of State and local
governments in the process of
developing these actions to permit them
to have meaningful and timely input
into their development. The EPA’s
consultation regarded planned actions
for the NSPS and emission guidelines.
The EPA invited the following 10
national organizations representing
State and local elected officials to a
virtual meeting on September 22, 2022:
(1) National Governors Association, (2)
National Conference of State
Legislatures, (3) Council of State
Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6)
National Association of Counties, (7)
International City/County Management
Association, (8) National Association of
Towns and Townships, (9) County
Executives of America, and (10)
Environmental Council of States. These
10 organizations representing elected
State and local officials have been
identified by the EPA as the ‘‘Big 10’’
organizations appropriate to contact for
purpose of consultation with elected
officials. Also, the EPA invited air and
utility professional groups who may
have State and local government
members, including the Association of
Air Pollution Control Agencies,
National Association of Clean Air
Agencies, and American Public Power
Association, Large Public Power
Council, National Rural Electric
Cooperative Association, and National
Association of Regulatory Utility
Commissioners to participate in the
meeting. The purpose of the
consultation was to provide general
background on these rulemakings,
answer questions, and solicit input from
State and local governments.
Subsequent to the September 22, 2022,
meeting, the EPA received letters from
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Fmt 4701
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33419
five organizations. These letters were
submitted to the pre-proposal nonrulemaking docket. See Docket ID No.
EPA–HQ–OAR–2022–0723–0013, EPA–
HQ–OAR–2022–0723–0016, EPA–HQ–
OAR–2022–0723–0017, EPA–HQ–OAR–
2022–0723–0020, and EPA–HQ–OAR–
2022–0723–0021. For a summary of the
Federalism consultation see the
memorandum in the docket titled
Federalism Pre-Proposal Consultation
Summary. A detailed Federalism
Summary Impact Statement (FSIS)
describing the most pressing issues
raised in pre-proposal and post-proposal
comments will be forthcoming with the
final emission guidelines, as required by
section 6(b) of Executive Order 13132.
In the spirit of E.O. 13132, and
consistent with EPA policy to promote
communications between State and
local governments, the EPA specifically
solicits comment on these proposed
actions from State and local officials.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
These actions do not have Tribal
implications, as specified in Executive
Order 13175. The proposed NSPS
would impose requirements on owners
and operators of new or reconstructed
stationary combustion turbines and
emission guidelines would not impose
direct requirements on Tribal
governments. Tribes are not required to
develop plans to implement the
emission guidelines developed under
CAA section 111(d) for designated
EGUs. The EPA is aware of six fossil
fuel-fired steam generating units located
in Indian country but is not aware of
any fossil fuel-fired steam generating
units owned or operated by Tribal
entities. The EPA notes that the
proposed emission guidelines do not
directly impose specific requirements
on EGU sources, including those located
in Indian country, but before developing
any standards for sources on Tribal
land, the EPA would consult with
leaders from affected Tribes. Thus,
Executive Order 13175 does not apply
to these actions.
Because the EPA is aware of Tribal
interest in these proposed rules and
consistent with the EPA Policy on
Consultation and Coordination with
Indian Tribes, the EPA offered
government-to-government consultation
with Tribes and conducted stakeholder
engagement.
The EPA will hold additional
meetings with Tribal environmental
staff to inform them of the content of
these proposed rules as well as offer
government-to-government consultation
with Tribes. The EPA specifically
E:\FR\FM\23MYP2.SGM
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33420
Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed Rules
lotter on DSK11XQN23PROD with PROPOSALS2
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks Populations and
Low-Income Populations
Executive Order 13045 (62 FR 19885,
April 23, 1997) directs Federal agencies
to include an evaluation of the health
and safety effects of the planned
regulation on children in Federal health
and safety standards and explain why
the regulation is preferable to
potentially effective and reasonably
feasible alternatives. This action is not
subject to Executive Order 13045
because the EPA does not believe the
environmental health risks or safety
risks addressed by this action present a
disproportionate risk to children. The
EPA evaluated the health benefits of the
CO2, ozone and PM2.5 emissions
reductions and the results of this
evaluation are contained in the RIA and
are available in the docket. The EPA
believes that the PM2.5-related, ozonerelated, and CO2-related benefits
projected under these proposed rules
will improve children’s health.
Additionally, the PM2.5 and ozone EJ
exposure analyses in section 6 of the
RIA suggests that nationally, children
(ages 0–17) will experience at least as
great a reduction in PM2.5 and ozone
exposures as adults (ages 18–64) in
2028, 2030, 2035 and 2040 under all
regulatory alternatives of these
rulemakings.
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution, or Use
These actions, which are significant
regulatory actions under Executive
Order 12866, are likely to have a
significant adverse effect on the supply,
distribution or use of energy. The EPA
has prepared a Statement of Energy
Effects for these action as follows. This
analysis pertains to the proposed
standards for new combustion turbines
and for existing steam generating EGUs,
and does not include the impact of the
proposed standards for existing
combustion turbines and the third phase
of the proposed standards for new
combustion turbines. The EPA estimates
a 0.2 percent increase in retail
electricity prices on average, across the
contiguous U.S. in 2035, and a 28
percent reduction in coal-fired
electricity generation in 2035 as a result
of these actions. The EPA projects that
utility power sector delivered natural
gas prices will decrease 2.4 percent in
2035. For more information on the
estimated energy effects, please refer
VerDate Sep<11>2014
19:29 May 22, 2023
Jkt 259001
disproportionate and adverse effects on
people of color, low-income populations
and/or Indigenous peoples, because the
I. National Technology Transfer and
location and number of new sources is
Advancement Act (NTTAA) and 1 CFR
unknown.
Part 51
For existing sources of this proposed
These proposed actions involve
technical standards. Therefore, the EPA action under CAA section 111(d), the
EPA believes that the human health or
conducted searches for the New Source
environmental conditions that exist
Performance Standards for Greenhouse
Gas Emissions from New, Modified, and prior to this action result in or have the
Reconstructed Fossil Fuel-Fired Electric potential to result in disproportionate
Generating Units; Emission Guidelines
and adverse human health or
for Greenhouse Gas Emissions from
environmental effects on people of
Existing Fossil Fuel-Fired Electric
color, low-income populations, and/or
Generating Units; and Repeal of the
Indigenous peoples. The EPA believes
Affordable Clean Energy Rule through
that this proposed action is not likely to
the Enhanced National Standards
change disproportionate and adverse
Systems Network (NSSN) Database
PM2.5 exposure impacts on people of
managed by the American National
color, low-income populations,
Standards Institute (ANSI). Searches
Indigenous peoples, and/or other
were conducted for EPA Method 19 of
potential populations of concern
40 CFR part 60, appendix A. No
evaluated in the future analytical years.
applicable voluntary consensus
The EPA also believes that this
standards were identified for EPA
proposed action is not likely to change
Method 19. For additional information,
disproportionate and adverse ozone
please see the March 23, 2023,
exposure impacts on people of color,
memorandum titled, Voluntary
low-income populations, Indigenous
Consensus Standard Results for New
peoples, and/or other potential
Source Performance Standards for
populations of concern evaluated in
Greenhouse Gas Emissions from New,
2028, 2035, and 2040. However, in the
Modified, and Reconstructed Fossil
analytical year of 2030, this action is
Fuel-Fired Electric Generating Units;
Emission Guidelines for Greenhouse Gas likely to slightly increase existing
Emissions from Existing Fossil Fuelnational level disproportionate and
Fired Electric Generating Units; and
adverse ozone exposure impacts on
Repeal of the Affordable Clean Energy
Asian populations, Hispanic
Rule.
populations, and those linguistically
The EPA welcomes comments on this isolated.
aspect of the proposed rulemakings and,
The EPA believes that it is not
specifically, invites the public to
identify potentially applicable VCS and practicable to assess whether the GHG
impacts associated with this action are
to explain why such standards should
likely to result in a change in
be used in these regulations.
disproportionate and adverse effects on
J. Executive Order 12898: Federal
people of color, low-income populations
Actions To Address Environmental
and/or Indigenous peoples. However,
Justice in Minority Populations and
the EPA believes that the projected total
Low-Income Populations
cumulative power sector reduction of
Executive Order 12898 (59 FR 7629;
617 million metric tons of CO2
February 16, 1994) directs Federal
emissions between 2028 and 2042 will
agencies, to the greatest extent
have a beneficial effect on populations
practicable and permitted by law, to
at risk of climate change effects/impacts.
make environmental justice part of their Research indicates that some
mission by identifying and addressing,
communities of color, specifically
as appropriate, disproportionately high
populations defined jointly by ethnic/
and adverse human health or
racial characteristics and geographic
environmental effects of their programs, location, may be uniquely vulnerable to
policies, and activities on minority
climate change health impacts in the
populations (people of color and/or
U.S. See sections VII, X, and XIV of this
Indigenous peoples) and low-income
preamble for further information
populations.
For new sources constructed after the regarding GHG controls and emission
reductions.
date of publication of this proposed
action under CAA section 111(b), the
Michael S. Regan,
EPA believes that it is not practicable to
Administrator.
assess whether the human health or
[FR Doc. 2023–10141 Filed 5–22–23; 8:45 am]
environmental conditions that exist
BILLING CODE 6560–50–P
prior to this action result in
sections 5.1 and 8.3.3 of the RIA, which
is in the public docket.
solicits additional comment on these
proposed rules from Tribal officials.
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]]>Agencies
[Federal Register Volume 88, Number 99 (Tuesday, May 23, 2023)]
[Proposed Rules]
[Pages 33240-33420]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2023-10141]
[[Page 33239]]
Vol. 88
Tuesday,
No. 99
May 23, 2023
Part III
Environmental Protection Agency
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40 CFR Part 60
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; Proposed Rule
Federal Register / Vol. 88, No. 99 / Tuesday, May 23, 2023 / Proposed
Rules
[[Page 33240]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2023-0072; FRL-8536-02-OAR]
RIN 2060-AV09
New Source Performance Standards for Greenhouse Gas Emissions
From New, Modified, and Reconstructed Fossil Fuel-Fired Electric
Generating Units; Emission Guidelines for Greenhouse Gas Emissions From
Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the
Affordable Clean Energy Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: In this document, the Environmental Protection Agency (EPA) is
proposing five separate actions under section 111 of the Clean Air Act
(CAA) addressing greenhouse gas (GHG) emissions from fossil fuel-fired
electric generating units (EGUs). The EPA is proposing revised new
source performance standards (NSPS), first for GHG emissions from new
fossil fuel-fired stationary combustion turbine EGUs and second for GHG
emissions from fossil fuel-fired steam generating units that undertake
a large modification, based upon the 8-year review required by the CAA.
Third, the EPA is proposing emission guidelines for GHG emissions from
existing fossil fuel-fired steam generating EGUs, which include both
coal-fired and oil/gas-fired steam generating EGUs. Fourth, the EPA is
proposing emission guidelines for GHG emissions from the largest, most
frequently operated existing stationary combustion turbines and is
soliciting comment on approaches for emission guidelines for GHG
emissions for the remainder of the existing combustion turbine
category. Finally, the EPA is proposing to repeal the Affordable Clean
Energy (ACE) Rule.
DATES: Comments. Comments must be received on or before July 24, 2023.
Comments on the information collection provisions submitted to the
Office of Management and Budget (OMB) under the Paperwork Reduction Act
(PRA) are best assured of consideration by OMB if OMB receives a copy
of your comments on or before June 22, 2023.
Public Hearing. The EPA will hold a virtual public hearing on June
13, 2023 and June 14, 2023. See SUPPLEMENTARY INFORMATION for
information on registering for a public hearing.
ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2023-0072, by any of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov
(our preferred method). Follow the online instructions for submitting
comments.
Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2023-0072 in the subject line of the message.
Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2023-0072.
Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2023-0072, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to https://www.regulations.gov, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the SUPPLEMENTARY
INFORMATION section of this document.
FOR FURTHER INFORMATION CONTACT: For questions about these proposed
actions, contact Mr. Christian Fellner, Sector Policies and Programs
Division (D243-02), Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711; telephone number: (919) 541-4003; and email address:
[email protected] or Ms. Lisa Thompson, Sector Policies and
Programs Division (D243-02), Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina 27711; telephone number: (919) 541-9775; and email
address: [email protected].
SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. The public hearing will be
held via virtual platform on June 13, 2023 and June 14, 2023 and will
convene at 11:00 a.m. Eastern Time (ET) and conclude at 7:00 p.m. ET
each day. If the EPA receives a high volume of registrations for the
public hearing, the EPA may continue the public hearing on June 15,
2023. On each hearing day, the EPA may close a session 15 minutes after
the last pre-registered speaker has testified if there are no
additional speakers. The EPA will announce further details at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
The EPA will begin pre-registering speakers for the hearing no
later than 1 business day following the publication of this document in
the Federal Register. The EPA will accept registrations on an
individual basis. To register to speak at the virtual hearing, please
use the online registration form available at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power or contact the public hearing team
at (888) 372-8699 or by email at [email protected]. The last
day to pre-register to speak at the hearing will be June 6, 2023. Prior
to the hearing, the EPA will post a general agenda that will list pre-
registered speakers in approximate order at: https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearings to run either ahead of schedule or behind schedule.
Each commenter will have 4 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony by submitting the text of your oral testimony as written
comments to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will
be posted online at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power. While the EPA expects the hearing to go forward as described in
this section, please monitor our website or contact the public hearing
team at (888) 372-8699 or by email at [email protected] to
determine if there are any updates. The EPA does not intend to publish
a document in the Federal Register announcing updates.
[[Page 33241]]
If you require the services of an interpreter or a special
accommodation such as audio description, please pre-register for the
hearing with the public hearing team and describe your needs by May 30,
2023. The EPA may not be able to arrange accommodations without
advanced notice.
Docket. The EPA has established a docket for these rulemakings
under Docket ID No. EPA-HQ-OAR-2023-0072. All documents in the docket
are listed in the Regulations.gov index. Although listed in the index,
some information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only in hard
copy.
Written Comments. Direct your comments to Docket ID No. EPA-HQ-OAR-
2023-0072 at https://www.regulations.gov (our preferred method), or the
other methods identified in the ADDRESSES section. Once submitted,
comments cannot be edited or removed from the docket. The EPA may
publish any comment received to its public docket. Do not submit to the
EPA's docket at https://www.regulations.gov any information you
consider to be Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute. This type of
information should be submitted as discussed in the Submitting CBI
section of this document.
Multimedia submissions (audio, video, etc.) must be accompanied by
a written comment. The written comment is considered the official
comment and should include discussion of all points you wish to make.
The EPA will generally not consider comments or comment contents
located outside of the primary submission (i.e., on the Web, cloud, or
other file sharing system). Please visit https://www.epa.gov/dockets/commenting-epa-dockets for additional submission methods; the full EPA
public comment policy; information about CBI or multimedia submissions;
and general guidance on making effective comments.
The https://www.regulations.gov website allows you to submit your
comment anonymously, which means the EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to the EPA without going through
https://www.regulations.gov, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and
should be free of any defects or viruses.
Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the EPA, note the docket ID,
mark the outside of the digital storage media as CBI, and identify
electronically within the digital storage media the specific
information that is claimed as CBI. In addition to one complete version
of the comments that includes information claimed as CBI, you must
submit a copy of the comments that does not contain the information
claimed as CBI directly to the public docket through the procedures
outlined in Written Comments section of this document. If you submit
any digital storage media that does not contain CBI, mark the outside
of the digital storage media clearly that it does not contain CBI and
note the docket ID. Information not marked as CBI will be included in
the public docket and the EPA's electronic public docket without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 Code of Federal Regulations
(CFR) part 2.
Our preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol (FTP),
or other online file sharing services (e.g., Dropbox, OneDrive, Google
Drive). Electronic submissions must be transmitted directly to the
OAQPS CBI Office at the email address [email protected] and, as
described above, should include clear CBI markings and note the docket
ID. If assistance is needed with submitting large electronic files that
exceed the file size limit for email attachments, and if you do not
have your own file sharing service, please email [email protected] to
request a file transfer link. If sending CBI information through the
postal service, please send it to the following address: OAQPS Document
Control Officer (C404-02), OAQPS, U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina 27711, Attention Docket ID No.
EPA-HQ-OAR-2023-0072. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
Preamble acronyms and abbreviations. Throughout this document the
use of ``we,'' ``us,'' or ``our'' is intended to refer to the EPA. The
EPA uses multiple acronyms and terms in this preamble. While this list
may not be exhaustive, to ease the reading of this preamble and for
reference purposes, the EPA defines the following terms and acronyms
here:
ACE Affordable Clean Energy rule
BACT best available control technology
BSER best system of emissions reduction
Btu British thermal unit
CAA Clean Air Act
CBI Confidential Business Information
CCS carbon capture and sequestration/storage
CCUS carbon capture, utilization, and sequestration/storage
CFR Code of Federal Regulations
CHP combined heat and power
CO2 carbon dioxide
CO2e carbon dioxide equivalent
CPP Clean Power Plan
CSAPR Cross-State Air Pollution Rule
DOE Department of Energy
DOI Department of the Interior
DOT Department of Transportation
EGU electric generating unit
EIA Energy Information Administration
EJ environmental justice
E.O. Executive Order
EOR enhanced oil recovery
EPA Environmental Protection Agency
FEED front-end engineering and design
FGD flue gas desulfurization
FR Federal Register
FrEDI Framework for Evaluating Damages and Impacts
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GW gigawatt
HHV higher heating value
HRSG heat recovery steam generator
IBR incorporate by reference
ICR information collection request
IGCC integrated gasification combined cycle
IIJA Infrastructure Investment and Jobs Act
IPCC Intergovernmental Panel on Climate Change
IRC Internal Revenue Code
IRP integrated resource plan
kg kilogram
kWh kilowatt-hour
LCOE levelized cost of electricity
LHV lower heating value
LNG liquefied natural gas
MMBtu/hr million British thermal units per hour
MMst million short tons
MMT CO2e million metric tons of carbon dioxide equivalent
MW megawatt
MWh megawatt-hour
[[Page 33242]]
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NCA4 2017-2018 Fourth National Climate Assessment
NETL National Energy Technology Laboratory
NGCC natural gas combined cycle
NOX nitrogen oxides
NREL National Renewable Energy Laboratory
NSPS new source performance standards
NSR New Source Review
OMB Office of Management and Budget
PM particulate matter
PSD Prevention of Significant Deterioration
PUC public utilities commission
RIA regulatory impact analysis
RPS renewable portfolio standard
RTO Regional Transmission Organization
SCR selective catalytic reduction
SIP State Implementation Plan
U.S. United States
U.S.C. United States Code
Organization of this document. The information in this preamble is
organized as follows:
I. Executive Summary
A. Climate Change and the Power Sector
B. Overview of the Proposals
C. Recent Developments in Emissions Controls and the Electric
Power Sector
D. How the EPA Considered Environmental Justice in the
Development of These Proposals
II. General Information
A. Action Applicability
B. Where to Get a Copy of This Document and Other Related
Information
C. Organization and Approach for These Proposed Rules
III. Climate Change and Its Impacts
IV. Recent Developments in Emissions Controls and the Electric Power
Sector
A. Introduction
B. Background
C. CCS
D. Natural Gas Co-Firing
E. Hydrogen Co-Firing
F. Recent Changes in the Power Sector
G. GHG Emissions From Fossil Fuel-Fired EGUs
H. The Legislative, Market, and State Law Context
I. Projections of Power Sector Trends
V. Statutory Background and Regulatory History for CAA Section 111
A. Statutory Authority To Regulate GHGs From EGUs Under CAA
Section 111
B. History of EPA Regulation of Greenhouse Gases From
Electricity Generating Units Under CAA Section 111 and Caselaw
C. Detailed Discussion of CAA Section 111 Requirements
VI. Stakeholder Engagement
VII. Proposed Requirements for New and Reconstructed Stationary
Combustion Turbine EGUs and Rationale for Proposed Requirements
A. Overview
B. Combustion Turbine Technology
C. Overview of Regulation of Stationary Combustion Turbines for
GHGs
D. Eight-Year Review of NSPS
E. Applicability Requirements and Subcategorization
F. Determination of the Best System of Emission Reduction (BSER)
for New and Reconstructed Stationary Combustion Turbines
G. Proposed Standards of Performance
H. Reconstructed Stationary Combustion Turbines
I. Modified Stationary Combustion Turbines
J. Startup, Shutdown, and Malfunction
K. Testing and Monitoring Requirements
L. Mechanisms To Ensure Use of Actual Low-GHG Hydrogen
M. Recordkeeping and Reporting Requirements
N. Additional Solicitations of Comment and Proposed Requirements
O. Compliance Dates
VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-
Fired Steam Generating Units
A. 2018 NSPS Proposal
B. Eight-Year Review of NSPS for Fossil Fuel-Fired Steam
Generating Units
C. Projects Under Development
IX. Proposed ACE Rule Repeal
A. Summary of Selected Features of the ACE Rule
B. Developments Undermining ACE Rule's Projected Emission
Reductions
C. Developments Showing That Other Technologies are the BSER for
This Source Category
D. Insufficiently Precise Degree of Emission Limitation
Achievable From Application of the BSER
E. ACE Rule's Preclusion of Emissions Trading or Averaging
X. Proposed Regulatory Approach for Existing Fossil Fuel-Fired Steam
Generating Units
A. Overview
B. Applicability Requirements for Existing Fossil Fuel-Fired
Steam Generating Units
C. Subcategorization of Fossil Fuel-Fired Steam Generating Units
D. Determination of BSER for Coal-Fired Steam Generating Units
E. Natural Gas-Fired and Oil-Fired Steam Generating Units
F. Summary
XI. Proposed Regulatory Approach for Emission Guidelines for
Existing Fossil Fuel-fired Stationary Combustion Turbines
A. Overview
B. The Existing Stationary Combustion Turbine Fleet
C. BSER for Base Load Turbines Over 300 MW
D. Areas That the EPA is Seeking Comment on Related to Existing
Combustion Turbines
E. BSER for Remaining Combustion Turbines
XII. State Plans for Proposed Emission Guidelines for Existing
Fossil Fuel-Fired EGUs
A. Overview
B. Compliance Deadlines
C. Requirement for State Plans To Maintain Stringency of the
EPA's BSER Determination
D. Establishing Standards of Performance
E. Compliance Flexibilities
F. State Plan Components and Submission
XIII. Implications for Other EPA Programs
A. Implications for New Source Review (NSR) Program
B. Implications for Title V Program
XIV. Impacts of Proposed Actions
A. Air Quality Impacts
B. Compliance Cost Impacts
C. Economic and Energy Impacts
D. Benefits
E. Environmental Justice Analytical Considerations and
Stakeholder Outreach and Engagement
F. Grid Reliability Considerations
XV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act of 1995 (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks Populations and Low-
Income Populations
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
Executive Summary
In 2009, the EPA concluded that GHG emissions endanger our nation's
public health and welfare.\1\ Since that time, the evidence of the
harms posed by GHG emissions has only grown and Americans experience
the destructive and worsening effects of climate change every day.
Fossil fuel-fired EGUs are the nation's largest stationary source of
GHG emissions, representing 25 percent of the United States' total GHG
emissions in 2020. At the same time, a range of cost-effective
technologies and approaches to reduce GHG emissions from these sources
are available to the power sector, and multiple projects are in various
stages of operation and development--including carbon capture and
sequestration/storage (CCS) and co-firing with lower-GHG fuels.
Congress has also acted to provide funding and other incentives to
encourage the deployment of these technologies to
[[Page 33243]]
achieve reductions in GHG emissions from the power sector.
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\1\ 74 FR 66496 (December 15, 2009).
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In this document, the EPA is proposing several actions under
section 111 of the Clean Air Act (CAA) to reduce the significant
quantity of GHG emissions from new and existing fossil fuel-fired EGUs
by establishing new source performance standards (NSPS) and emission
guidelines that are based on available and cost-effective technologies
that directly reduce GHG emissions from these sources. Consistent with
the statutory command of section 111, the proposed NSPS and emission
guidelines reflect the application of the best system of emission
reduction (BSER) that, taking into account costs, energy requirements,
and other statutory factors, is adequately demonstrated.
Specifically, the EPA is proposing to update and establish more
protective NSPS for GHG emissions from new and reconstructed fossil
fuel-fired stationary combustion turbine EGUs that are based on highly
efficient generating practices, hydrogen co-firing, and CCS. The EPA is
also proposing to establish new emission guidelines for existing fossil
fuel-fired steam generating EGUs that reflect the application of CCS
and the availability of natural gas co-firing. The EPA is
simultaneously proposing to repeal the Affordable Clean Energy (ACE)
rule because the emission guidelines established in ACE do not reflect
the BSER for steam generating EGUs and are inconsistent with section
111 of the CAA in other respects. To address GHG emissions from
existing fossil fuel-fired stationary combustion turbines, the EPA is
proposing emission guidelines for large and frequently used existing
stationary combustion turbines. Further, the EPA is soliciting comment
on how the Agency should approach its legal obligation to establish
emission guidelines for the remaining existing fossil fuel-fired
combustion turbines not covered by this proposal, including smaller
frequently used, and less frequently used, combustion turbines.
Each of the NSPS and emission guidelines proposed here would ensure
that EGUs reduce their GHG emissions in a manner that is cost-effective
and improves the emissions performance of the sources, consistent with
the applicable CAA requirements and caselaw. These proposed standards
and emission guidelines, if finalized, would significantly decrease GHG
emissions from fossil fuel-fired EGUs and the associated harms to human
health and welfare. Further, the EPA has designed these proposed
standards and emission guidelines in a way that is compatible with the
nation's overall need for a reliable supply of affordable electricity.
A. Climate Change and the Power Sector
These proposals focus on reducing the emissions of GHGs from the
power sector. The increasing concentrations of GHGs in the atmosphere
are, and have been, warming the planet, resulting in serious and life-
threatening environmental and human health impacts. The increased
concentrations of GHGs in the atmosphere and the resulting warming have
led to more frequent and more intense heat waves and extreme weather
events, rising sea levels, and retreating snow and ice, all of which
are occurring at a pace and scale that threatens human welfare.
The power sector in the United States (U.S.) is both a key
contributor to the cause of climate change and a key component of the
solution to the climate challenge. In 2020, the power sector was the
largest stationary source of GHGs, emitting 25 percent of the overall
domestic emissions.\2\ These emissions are almost entirely the result
of the combustion of fossil fuels in the EGUs that are the subjects of
these proposals.
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\2\ https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
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The power sector possesses many opportunities to contribute to
solutions to the climate challenge. Particularly relevant to these
proposals are several key technologies (co-firing of low-GHG fuels and
CCS) that can allow steam generating EGUs and stationary combustion
turbines (the focus of these proposals) to provide power while emitting
significantly lower GHG emissions. Moreover, with the increased
electrification of other GHG-emitting sectors of the economy, such as
personal vehicles, heavy-duty trucks, and the heating and cooling of
buildings, a power sector with lower GHG emissions can also help reduce
pollution coming from other sectors of the economy.
B. Overview of the Proposals
As noted above, these actions include proposed BSER determinations
and accompanying standards of performance for GHG emissions from new
and reconstructed fossil fuel-fired stationary combustion turbines,
proposed repeal of the ACE Rule, proposed BSER determinations and
emission guidelines for existing fossil fuel-fired steam generating
units, proposed BSER determinations and emission guidelines for large,
frequently used existing fossil fuel-fired stationary combustion
turbines, and solicitation for comment on potential BSER options and
emission guidelines for existing fossil fuel-fired stationary
combustion turbines not otherwise covered by the proposal.
The EPA is taking these actions consistent with the process that
CAA section 111 establishes. Under CAA section 111, once the EPA has
identified a source category that emits dangerous air pollutants, it
proceeds to regulate new sources and, for GHGs and certain other air
pollutants, existing sources. The central requirement is that the EPA
must determine the ``best system of emission reduction . . . adequately
demonstrated,'' taking into account the cost of the reductions, non-air
quality health and environmental impacts, and energy requirements. CAA
section 111(a)(1). The EPA may determine that different sets of sources
have different characteristics relevant for determining the BSER and
may subcategorize sources accordingly.
Once it determines the BSER, the EPA must determine the ``degree of
emission limitation'' achievable by application of the BSER. For new
sources, the EPA determines the standard of performance with which the
sources must comply, which is a standard for emissions that reflects
the degree of emission limitation. For existing sources, the EPA
includes the information it has developed concerning the BSER and
associated degree of emission limitation into emission guidelines and
directs the states to adopt State plans that contain standards of
performance that are consistent with the emission guidelines.
Since the early 1970s, the EPA has promulgated regulations under
section 111 for more than 60 source categories, which has established a
robust regulatory history. During this period, the courts, primarily
the U.S. Court of Appeals for the D.C. Circuit and the Supreme Court,
have developed a body of caselaw interpreting section 111. As the
Supreme Court has recognized, in these CAA section 111 actions, the EPA
has determined the BSER to be ``measures that improve the pollution
performance of individual sources,'' including add-on controls and
clean fuels. West Virginia v. EPA, 142 S. Ct. 2587, 2614 (2022). For
present purposes, several of a BSER's key features include that costs
of controls must be reasonable, that the EPA may determine a control to
be ``adequately demonstrated'' even if it is new and not yet in
widespread commercial use, and, further, that the EPA may reasonably
project the development of a control system at a future time and
establish requirements that take effect at that time. The actions that
the EPA is proposing are consistent with the requirements of CAA
section 111 and its regulatory history and caselaw.
[[Page 33244]]
1. New and Reconstructed Fossil Fuel-Fired Combustion Turbines
For new and reconstructed fossil fuel-fired combustion turbines,
the EPA is proposing to create three subcategories based on the
function the combustion turbine serves: a low load (``peaking units'')
subcategory that consists of combustion turbines with a capacity factor
of less than 20 percent; an intermediate load subcategory for
combustion turbines with a capacity factor that ranges between 20
percent and a source-specific upper bound that is based on the design
efficiency of the combustion turbine; and a base load subcategory for
combustion turbines that operate above the upper-bound threshold for
intermediate load turbines. This subcategorization approach is similar
to the current NSPS for these sources, which includes separate
subcategories for base load and non-base load units; however, the EPA
is now proposing to subdivide the non-base load subcategory into a low
load subcategory and a separate intermediate load subcategory. This
revised approach to subcategories is consistent with the fact that
utilities and power plant operators are building new combustion
turbines with plans to operate them at varying levels of capacity, in
coordination with existing and expected energy sources. These patterns
of operation are important for the type of controls that the EPA is
proposing as the BSER for these turbines, in terms of the feasibility
of, emissions reductions that would be achieved by, and cost-
reasonableness of, those controls.
For the low load subcategory, the EPA is proposing that the BSER is
the use of lower emitting fuels (e.g., natural gas and distillate oil)
with standards of performance ranging from 120 lb CO2/MMBtu
to 160 lb CO2/MMBtu, depending on the type of fuel
combusted.\3\ For the intermediate load and base load subcategories,
the EPA is proposing an approach in which the BSER has multiple
components: (1) Highly efficient generation; and (2) depending on the
subcategory, use of CCS or co-firing low-GHG hydrogen.
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\3\ In the 2015 NSPS, the EPA referred to clean fuels as fuels
with a consistent chemical composition (i.e., uniform fuels) that
result in a consistent emission rate of 69 kilograms per gigajoule
(kg/GJ) (160 lb CO2/MMBtu). Fuels in this category
include natural gas and distillate oil. In this rulemaking, the EPA
refers to these fuels as both lower emitting fuels or uniform fuels.
---------------------------------------------------------------------------
These components of the BSER for the intermediate and base load
subcategories form the basis of a standard of performance that applies
in multiple phases. That is, affected facilities--which are facilities
that commence construction or reconstruction after the date of
publication in the Federal Register of this proposed rulemaking--must
meet the first phase of the standard of performance, which is based
exclusively on application of the first component of the BSER (highly
efficient generation), by the date the rule is promulgated. Affected
sources in the intermediate load and base load subcategories must also
meet the second and in some cases third and more stringent phases of
the standard of performance, which are based on the continued
application of the first component of the BSER and the application of
the second and in some cases third component of the BSER. For base load
units, the EPA is proposing two pathways as potential BSER--(1) the use
of CCS to achieve a 90 percent capture of GHG emissions by 2035 and (2)
the co-firing of 30 percent (by volume) low-GHG hydrogen by 2032, and
ramping up to 96 percent by volume low-GHG hydrogen by 2038. These two
BSER pathways both offer significant opportunities to reduce GHG
emissions but, may be available on slightly different timescales.
Depending upon the phase in periods for both CCS and hydrogen, the CCS
pathway could provide greater cumulative emission reductions than the
low GHG hydrogen pathway. The EPA seeks comment specifically upon the
percentages of hydrogen co-firing and CO2 capture as well as
the dates that meet the statutory BSER criteria for each pathway. The
EPA solicits comment on the differences in emissions reductions in both
scale and time that would result from the two standards and BSER
pathways, including how to calculate the different amounts of emission
reductions, how to compare them, and what conclusions to draw from
those differences. The EPA also seeks comment on whether the Agency
should finalize both pathways as separate subcategories with separate
standards of performance, or whether it should finalize one pathway
with the option of meeting the standard of performance using either
system of emission reduction, e.g., a single standard based on
application of CCS with 90 percent capture, which could also be met by
co-firing 96 percent (by volume) low-GHG hydrogen.
It should be noted that utilization of highly efficient generation
is a logical complement to both CCS and co-firing of low-GHG hydrogen
because, from both an economic and emissions perspective, that
configuration will provide the greatest reductions at the lowest cost.
This approach reflects the EPA's view that the BSER for the
intermediate load and base load subcategories should reflect the deeper
reductions in GHG emissions that can be achieved by implementing CCS
and co-firing low-GHG hydrogen with the most efficient stationary
combustion turbine configuration available. However, in proposing that
compliance begins in 2032 (for co-firing with low-GHG hydrogen) and
2035 (for use of CCS), the EPA recognizes that building the
infrastructure required to support wider use of CCS and qualified low-
GHG hydrogen in the power sector will take place on a multi-year time
scale.
More specifically, with respect to the first phase of the standards
of performance, the EPA is proposing that the BSER for both the
intermediate load and base load subcategories includes highly efficient
generating technology (i.e., the most efficient available turbines).
For the intermediate load subcategory, the EPA is proposing that the
BSER includes highly efficient simple cycle combustion turbine
technology with an associated first phase standard of 1,150 lb
CO2/MWh-gross. For the base load subcategory, the EPA is
proposing that the BSER includes highly efficient combined cycle
technology with an associated first phase standard of 770 lb
CO2/MWh-gross for larger combustion turbine EGUs with a base
load rating of 2,000 MMBtu/h or more. For smaller base load combustion
turbines (with a base load rating of less than 2,000 MMBtu/h), the
proposed associated standard would range from 770 to 900 lb
CO2/MWh-gross depending on the specific base load rating of
the combustion turbine. These standards would apply immediately upon
the effective date of the final rule.
With respect to the second phase of the standards of performance,
for the intermediate load subcategory, the EPA is proposing that the
BSER includes co-firing 30 percent by volume low-GHG hydrogen (unless
otherwise noted, all co-firing hydrogen percentages are on a volume
basis) with an associated standard of 1,000 lb CO2/MWh-
gross, compliance with which would be required starting in 2032. For
the base load subcategory, to elicit comment on both pathways, the EPA
is proposing to subcategorize further into base load units that are
adopting the CCS pathway and base load units that are adopting the low-
GHG hydrogen co-firing pathway. For the subcategory of base load units
that are adopting the CCS pathway, the EPA is proposing that the BSER
includes the use of CCS with 90 percent capture of CO2 with
an associated standard of 90 lb CO2/MWh-gross, compliance
with which would be
[[Page 33245]]
required starting in 2035. For the subcategory of base load units that
are adopting the low-GHG hydrogen co-firing pathway, the EPA is
proposing that the BSER includes co-firing 30 percent (by volume) low-
GHG hydrogen with an associated standard of 680 lb CO2/MWh-
gross, compliance with which would be required starting in 2032, and
co-firing 96 percent (by volume) low-GHG hydrogen by 2038, which
corresponds to a standard of performance of 90 lb CO2/MWh-
gross. In both cases, the second (and sometimes third) phase standard
of performance would be applicable to all combustion turbines that were
subject to the first phase standards of performance.
Existing and Modified Fossil Fuel-Fired Steam Generating Units and ACE
Repeal
With respect to existing coal-fired steam generating units, the EPA
is proposing to repeal and replace the existing ACE Rule emission
guidelines. The EPA recognizes that, since it promulgated the ACE Rule,
the costs of CCS have decreased due to technology advancements as well
as new policies including the expansion of the Internal Revenue Code
section 45Q tax credit for CCS in the Inflation Reduction Act (IRA);
and the costs of natural gas co-firing have decreased as well, due in
large part to a decrease in the difference between coal and natural gas
prices. As a result, the EPA considered both CCS and natural gas co-
firing as candidates for BSER for existing coal-fired steam EGUs.
Based on the latest information available to the Agency on cost,
emission reductions, and other statutory criteria, the EPA is proposing
that the BSER for existing coal-fired steam EGUs that expect to operate
in the long-term is CCS with 90 percent capture of CO2. The
EPA has determined that CCS satisfies the BSER criteria for these
sources because it is adequately demonstrated, achieves significant
reductions in GHG emissions, and is highly cost-effective.
Although the EPA considers CCS to be a broadly applicable BSER, the
Agency also recognizes that CCS will be most cost-effective for
existing steam EGUs that are in a position to recover the capital costs
associated with CCS over a sufficiently long period of time. During the
early engagement process (see Docket ID No. EPA-HQ-OAR-2022-0723-0024),
industry stakeholders requested that the EPA ``[p]rovide approaches
that allow for the retirement of units as opposed to investments in new
control technologies, which could prolong the lives of higher-emitting
EGUs; this will achieve maximum and durable environmental benefits.''
Industry stakeholders also suggested that the EPA recognize that some
units may remain operational for a several-year period but will do so
at limited capacity (in part to assure reliability), and then
voluntarily cease operations entirely (see Docket ID No. EPA-HQ-OAR-
2022-0723-0029).
In response to this industry stakeholder input and recognizing that
the cost effectiveness of controls depends on the unit's expected
operating time horizon, which dictates the amortization period for the
capital costs of the controls, the EPA believes it is appropriate to
establish subcategories of existing steam EGUs that are based on the
operating horizon of the units. The EPA is proposing that for units
that expect to operate in the long-term (i.e., those that plan to
operate past December 31, 2039), the BSER is the use of CCS with 90
percent capture of CO2 with an associated degree of emission
limitation of an 88.4 percent reduction in emission rate (lb
CO2/MWh-gross basis). As explained in detail in this
proposal, CCS with 90 percent capture of CO2 is adequately
demonstrated, cost reasonable, and achieves substantial emissions
reductions from these units.
The EPA is proposing to define coal-fired steam generating units
with medium-term operating horizons as those that (1) Operate after
December 31, 2031, (2) have elected to commit to permanently cease
operations before January 1, 2040, (3) elect to make that commitment
federally enforceable and continuing by including it in the State plan,
and (4) do not meet the definition of near-term operating horizon
units. For these medium-term operating horizon units, the EPA is
proposing that the BSER is co-firing 40 percent natural gas on a heat
input basis with an associated degree of emission limitation of a 16
percent reduction in emission rate (lb CO2/MWh-gross basis).
While this subcategory is based on a 10-year operating horizon (i.e.,
January 1, 2040), the EPA is specifically soliciting comment on the
potential for a different operating horizon between 8 and 10 years to
define the threshold date between the definition of medium-term and
long-term coal-fired steam generating units (i.e., January 1, 2038 to
January 1, 2040), given that the costs for CCS may be reasonable for
units with amortization periods as short as 8 years. For units with
operating horizons that are imminent-term, i.e., those that (1) Have
elected to commit to permanently cease operations before January 1,
2032, and (2) elect to make that commitment federally enforceable and
continuing by including it in the State plan, the EPA is proposing that
the BSER is routine methods of operation and maintenance with an
associated degree of emission limitation of no increase in emission
rate (lb CO2/MWh-gross basis). The EPA is proposing the same
BSER determination for units in the near-term operating horizon
subcategory, i.e., units that (1) Have elected to commit to permanently
cease operations by December 31, 2034, as well as to adopt an annual
capacity factor limit of 20 percent, and (2) elect to make both of
these conditions federally enforceable by including them in the State
plan. The EPA is also soliciting comment on a potential BSER based on
low levels of natural gas co-firing for units in these last two
subcategories.
The EPA is not proposing to revise the NSPS for newly constructed
or reconstructed fossil fuel-fired steam generating units, which it
promulgated in 2015 (80 FR 64510; October 23, 2015). This is because
the EPA does not anticipate that any such units will construct or
reconstruct and is unaware of plans by any companies to construct or
reconstruct a new coal-fired EGU. The EPA is proposing to revise the
standards of performance that it promulgated in the same 2015 action
for coal-fired steam generators that undertake a large modification
(i.e., a modification that increases its hourly emission rate by more
than 10 percent) to mirror the emissions guidelines, discussed below,
for existing coal-fired steam generators. This will ensure that all
existing fossil fuel-fired steam generating sources are subject to the
emission controls whether they modify or not.
The EPA is also proposing emission guidelines for existing natural
gas-fired and oil-fired steam generating units. Recognizing that
virtually all of these units have limited operation, the EPA is, in
general, proposing that the BSER is routine methods of operation and
maintenance with an associated degree of emission limitation of no
increase in emission rate (lb CO2/MWh-gross).
3. Existing Fossil Fuel-Fired Stationary Combustion Turbines
The EPA is also proposing emission guidelines for large (i.e.,
greater than 300 MW), frequently operated (i.e., with a capacity factor
of greater than 50 percent), existing fossil fuel-fired stationary
combustion turbines. Because these existing combustion turbines are
similar to new stationary combustion turbines, the EPA is proposing a
BSER that is similar to the BSER for new base load combustion turbines.
The EPA is
[[Page 33246]]
not proposing a first phase efficiency-based standard of performance;
but the EPA is proposing that BSER for these units is based on either
the use of CCS by 2035 or co-firing of 30 percent (by volume) low-GHG
hydrogen by 2032 and co-firing 96 percent low-GHG hydrogen by 2038.
For the emission guidelines for existing fossil fuel-fired steam
generating units and large, frequently operated fossil fuel-fired
combustion turbines, the EPA is also proposing State plan requirements,
including submittal timelines for State plans and methodologies for
determining presumptively approvable standards of performance
consistent with BSER. This proposal also addresses how states can
implement the remaining useful life and other factors (RULOF) provision
of CAA section 111(d) and how states can conduct meaningful engagement
with impacted stakeholders. Finally, the EPA is proposing to allow
states to include trading or averaging in State plans so long as they
demonstrate equivalent emissions reductions, and this proposal
discusses considerations related to the appropriateness of including
such compliance flexibilities.
Finally, the EPA is soliciting comment on a number of variations to
the subcategories and BSER determinations, as well as the associated
degrees of emission limitation and standards of performance, summarized
above. The EPA is soliciting comment on the capacity and capacity
factor threshold for inclusion in the subcategory of large, frequently
operated turbines (e.g., capacities between 100 MW and 300 MW for the
capacity threshold and a lower capacity factor threshold (e.g., 40
percent). The EPA is also soliciting comment on BSER options and
associated degrees of emission limitation for existing fossil fuel-
fired stationary combustion turbines for which no BSER is being
proposed (i.e., fossil fuel-fired stationary combustion turbines that
are not large, frequently operated turbines).
C. Recent Developments in Emissions Controls and the Electric Power
Sector
Several recent developments concerning emissions controls and the
state of the electric power sector are relevant for the EPA's
determination of the BSER for existing coal-fired steam generating EGUs
and natural gas-fired combustion turbines. These include developments
that have led to significant reductions in the cost of CCS; expected
increases in the availability and expected reductions in the cost of
low-GHG hydrogen; and announced and planned retirements of coal-fired
power plants.
In recent years, the cost of CCS has declined in part because of
process improvements learned from earlier deployments of CCS and other
advances. In addition, the IRA, enacted in 2022, extended and
significantly increased the tax credit for CCS under Internal Revenue
Code (IRC) section 45Q. As explained in detail in the BSER discussions
later in this preamble, these changes support the EPA's proposed
conclusion that CCS is the BSER for a number of subcategories in these
proposals.
In addition, in both the Infrastructure Investment and Jobs Act
(IIJA), enacted in 2021, and the IRA, Congress provided extensive
support for the development of hydrogen produced through low-GHG
methods. This support includes investment in infrastructure through the
IIJA and the provision of tax credits in the IRA to incentivize the
manufacture of hydrogen through low GHG-emitting methods. These changes
also support the EPA's proposal that co-firing low-GHG hydrogen is BSER
for certain subcategories of stationary combustion turbines.
The IIJA and IRA have also been part of the reason why many
utilities and power generating companies have recently announced plans
to change the mix of their generating assets. State legislation,
technology advancements, market forces, consumer demand, and the fact
that the existing fossil fuel-fired fleet is aging are also leading to,
in most cases, decreased use of the fossil fuel-fired units that are
the subjects of these proposals. Between 2010 and 2021, fossil fuel-
fired generation declined from approximately 70 percent of total net
generation to approximately 60 percent, with coal generation dropping
from 46 percent to 23 percent of net generation during the period.
Many utilities and power generating companies have announced GHG
reduction commitments as they further analyze and consider the
incentives of the IRA. These utilities and companies have also
announced their intention to permanently cease operating many of their
remaining coal-fired EGUs. Some companies are planning to install
combustion turbines with advanced technologies to limit GHG emissions,
including CCS and hydrogen co-firing \4\ (with some companies having
announced plans to ultimately move to 100 percent hydrogen firing) and
advanced energy storage technologies. As more renewables come online
and as these technologies become more widely deployed, the utilization
of natural gas-fired combustion turbine EGUs will be impacted. The
EPA's post-IRA 2022 reference case modeling projects lower utilization
relative to current levels of stationary combustion turbines.
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\4\ See section VII.F.3.b of this preamble for discussion of CCS
demonstrations and section VII.F.3.c for discussion of hydrogen co-
firing demonstrations. Also see the GHG Mitigation Measures for
Steam Generating Units TSD included in the rulemaking docket for
this proposal.
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The power sector has also been influenced by the actions of State
governments to reduce GHG emissions. More than two-thirds of states
have enacted policies to require utilities to increase the amount of
electricity generated from sources that emit no GHGs. Other states have
recently enacted significant legislation requiring the decarbonization
of their utility fleets, using devices such as carbon markets, low-GHG
emission standards, carbon capture and storage mandates, utility
planning, or mandatory retirement schedules.
Additionally, Congress has recently enacted investments in GHG
reductions. As noted earlier, Congress enacted IRC section 45Q by
section 115 of the Energy Improvement and Extension Act of 2008, to
provide a credit for the sequestration of CO2; IRC section
45Q was amended significantly by the Bipartisan Budget Act of 2018 and
most recently by the IRA. The IIJA provided more than $65 billion for
infrastructure investments and upgrades for transmission capacity,
pipelines, and low-carbon fuels (including low-GHG hydrogen, as noted
above). In addition, the Creating Helpful Incentives to Produce
Semiconductors and Science Act (CHIPS Act) authorized billions more in
funding for development of low- and non-GHG emitting energy
technologies that will provide additional low-cost options for power
companies to reduce overall GHG emissions.\5\
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\5\ https://www.congress.gov/bill/117th-congress/house-bill/4346.
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Finally, the EPA has carefully considered the importance of
maintaining resource adequacy and grid reliability in developing these
proposals and is confident that these proposed NSPS and emission
guidelines--with the extensive lead time and compliance flexibilities
they provide--can be successfully implemented in a manner that
preserves the ability of power companies and grid operators to maintain
the reliability of the nation's electric power system. The EPA has
evaluated the reliability implications of the proposal in the Resource
Adequacy Analysis TSD; conducted dispatch modeling of the proposed NSPS
and
[[Page 33247]]
proposed emission guidelines in a manner that takes into account
resource adequacy needs; and consulted with the DOE and the Federal
Energy Regulatory Commission (FERC) in the development of these
proposals. Moreover, the EPA has included in these proposals the
flexibility that power companies and grid operators need to plan for
achieving feasible and necessary reductions of GHGs from these sources
consistent with the EPA's statutory charge while ensuring grid
reliability. Furthermore, the EPA is soliciting comment on localized
impacts of these proposals on resource adequacy and reliability, and on
opportunities to enhance reliable integration of the proposals into the
power system.
D. How the EPA Considered Environmental Justice in the Development of
These Proposals
Consistent with E.O. 12898, E.O. 13985 and the EPA's commitment to
upholding environmental justice across its policies and programs, the
EPA carefully considered the impacts of these proposals on communities
with potential environmental justice concerns. As part of its pre-
proposal outreach to stakeholders, the EPA engaged on multiple
occasions with environmental justice organizations and representatives
of communities that are affected by various forms of pollution from the
power sector. The EPA took this feedback and analysis into account in
its development of these proposals. The EPA's consideration of
environmental justice in these proposals is briefly summarized here and
discussed in further detail in sections XIV.E and XV.J of the preamble
and section 6 of the RIA.
These proposals are focused on establishing NSPS and emission
guidelines for GHGs, and these proposed actions will, in conjunction
with other policies such as the IRA, play a significant role in
reducing GHGs and move us a step closer to avoiding the worst impacts
of climate change, which is already having a disproportionate impact on
EJ communities. Beyond the GHG reductions, the EPA also has conducted a
thorough evaluation of the impacts that these proposals would have on
emissions of other health-harming air pollutants from EGUs, as well as
how these changes in emissions would affect air quality and public
health, particularly for historically overburdened populations
including people of color, indigenous peoples, and people with low
incomes.
The EPA's national-level analysis of emission reduction and public
health impacts, which is documented in sections 3 and 4 of the RIA and
summarized in greater detail in section XIV.A and XIV.D of this
preamble, finds that these proposals would achieve nationwide
reductions in EGU emissions of multiple health-harming air pollutants
including nitrogen oxides (NOX), sulfur dioxide
(SO2), and fine particulate matter (PM2.5). These
reductions in health-harming pollution would result in significant
public health benefits including avoided premature deaths, reductions
in new asthma cases and incidences of asthma symptoms, reductions in
hospital admissions and emergency department visits, and reductions in
lost work and school days.
The EPA has also evaluated how the air quality impacts associated
with these proposals would be distributed, with particular focus on
potentially vulnerable populations. As discussed in section 6 of the
RIA, these proposals are anticipated to lead to modest but widespread
reductions in ambient levels of PM2.5 for a large majority
of the nation's population, as well as reductions in ambient
PM2.5 exposures that are similar in magnitude across all
racial, ethnic, income and linguistic groups. Similarly, the EPA found
that the proposed standards are anticipated to lead to modest but
widespread reductions in ambient levels of ground-level ozone for the
majority of the nation's population, and that in all but one of the
years evaluated the proposed standards would lead to reductions in
ambient ozone exposures across all demographic groups. Although these
reductions in PM2.5 and ozone exposures are small relative
to baseline levels, and although disparities in PM2.5 and
ozone exposure would continue to persist following these proposals, the
EPA's analysis indicates that the air quality benefits of these
proposals would be broadly distributed.
Where authorized under section 111 of the Clean Air Act, the EPA
has also incorporated provisions in these proposals to better address
the needs and concerns of communities with environmental justice
concerns. Specifically, the EPA's proposed emission guidelines for
existing steam EGUs as well as existing fossil fuel-fired stationary
combustion turbines would require states to undertake meaningful
engagement with affected stakeholders, including communities that are
most affected by and vulnerable to emissions from these EGUs. These
meaningful engagement requirements are intended to ensure that the
perspectives, priorities, and concerns of affected communities are
included in the process of establishing and implementing standards of
performance for existing EGUs, including decisions about compliance
strategies and compliance flexibilities that may be included in a State
plan.
In the Agency's pre-proposal outreach, some environmental justice
organizations and community representatives raised strongly held
concerns about the potential health, environmental, and safety impacts
of CCS. The EPA believes that deployment of CCS can take place in a
manner that is protective of public health, safety, and the
environment, and should include early and meaningful engagement with
affected communities and the public. As stated in the Council on
Environmental Quality's (CEQ) February 2022 Carbon Capture,
Utilization, and Sequestration Guidance, ``the successful widespread
deployment of responsible CCUS will require strong and effective
permitting, efficient regulatory regimes, meaningful public engagement
early in the review and deployment process, and measures to safeguard
public health and the environment.'' See 87 FR 8808 (February 16,
2022).
The EPA gave close consideration to these concerns as it developed
its proposed determinations on the BSER for these proposed NSPS and
emission guidelines, and addresses certain of the substantive issues
that were raised in pre-proposal discussions in sections
VII.F.3.b.iii(C) and X.D.1.a.iii of this preamble. As explained in
these sections, the EPA is proposing to determine that CCS is the BSER
for certain subcategories of new and existing EGUs based on its
consideration of all of the statutory criteria for BSER, including
emission reductions, cost, energy requirements, and non-air health and
environmental considerations. In evaluating concerns raised by
stakeholders in connection with CCS, the EPA is mindful that Federal
agencies have ``taken actions in the past decade to develop a robust
CCUS regulatory framework to protect the environment and public health
across multiple statutes.'' \6\
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\6\ Carbon Capture, Utilization, and Sequestration Guidance, 87
FR 8808, 8809 (February 16, 2022), https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf.
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This framework includes, among other things, the EPA regulation of
geologic sequestration wells under the Underground Injection Control
(UIC) program of the Safe Drinking Water Act; required reporting and
public disclosure of geologic sequestration activity, as well as
implementation of rigorous monitoring, reporting, and verification of
geologic sequestration, under the
[[Page 33248]]
EPA's Greenhouse Gas Reporting Program; and safety regulations for
CO2 pipelines administered by the Pipeline and Hazardous
Materials and Safety Administration (PHMSA). With respect to air
emissions, some CCS projects may also require pre-construction
permitting under the Clean Air Act's New Source Review (NSR) program
and the adoption of additional emission limitations for non-GHG air
pollutants based on applicable control technology requirements. The EPA
invites public comment and feedback from stakeholders on all aspects of
its proposed determination that CCS represents the BSER for certain new
and existing fossil fuel-fired EGUs, including its evaluation of the
various regulatory frameworks that apply to CCS.
CEQ's guidance, and the EPA's evaluation of BSER, recognizes that
multiple Federal agencies have responsibility for regulating and
permitting CCS projects, along with State and Tribal governments. The
EPA is committed to working with Federal, State, and Tribal partners to
ensure the responsible deployment of CCS, to protect communities from
pollution, and to foster meaningful engagement with communities. This
can be facilitated through the existing detailed regulatory framework
for CCS projects and further supported through robust and meaningful
public engagement early in the project development process.
Furthermore, the EPA is requesting comment on what assistance states
and pertinent stakeholders may need in conducting meaningful engagement
with affected communities to ensure that there are adequate
opportunities for public input on decisions to implement emissions
control technology (including but not limited to CCS or low-GHG
hydrogen).
II. General Information
A. Action Applicability
The source category that is the subject of these actions is
comprised of the fossil fuel-fired electric utility generating units
regulated under CAA section 111. The North American Industry
Classification System (NAICS) codes for the source category are 221112
and 921150. The list of categories and NAICS codes is not intended to
be exhaustive, but rather provides a guide for readers regarding the
entities that these proposed actions are likely to affect.
The proposed amendments to 40 CFR part 60, subpart TTTT, once
promulgated, will be directly applicable to affected facilities that
began construction after January 8, 2014, and affected facilities that
began reconstruction or modification after June 18, 2014. The proposed
NSPS, proposed to be codified in 40 CFR part 60, subpart TTTTa, once
promulgated, will be directly applicable to affected facilities that
begin construction or reconstruction after the date of publication of
the proposed standards in the Federal Register. Federal, State, local,
and Tribal government entities that own and/or operate EGUs subject to
40 CFR part 60, subparts TTTT or TTTTa would be affected by these
proposed amendments and standards.
The proposed emission guidelines for GHG emissions from fossil
fuel-fired EGUs proposed to be codified in 40 CFR part 60, subpart
UUUUb, once promulgated, will be applicable to states in the
development and submittal of State plans pursuant to CAA section
111(d). After the EPA promulgates a final emission guideline, each
State that has one or more designated facilities must develop, adopt,
and submit to the EPA a State plan under CAA section 111(d). The term
``designated facility'' means ``any existing facility . . . which emits
a designated pollutant and which would be subject to a standard of
performance for that pollutant if the existing facility were an
affected facility.'' See 40 CFR 60.21a(b). If a State fails to submit a
plan or the EPA determines that a State plan is not satisfactory, the
EPA has the authority to establish a Federal CAA section 111(d) plan in
such instances.
Under the Tribal Authority Rule adopted by the EPA, Tribes may seek
authority to implement a plan under CAA section 111(d) in a manner
similar to a State. See 40 CFR part 49, subpart A. Tribes may, but are
not required to, seek approval for treatment in a manner similar to a
State for purposes of developing a Tribal Implementation Plan (TIP)
implementing an emission guideline. If a Tribe does not seek and obtain
the authority from the EPA to establish a TIP, the EPA has the
authority to establish a Federal CAA section 111(d) plan for designated
facilities that are located in areas of Indian country. A Federal plan
would apply to all designated facilities located in the areas of Indian
country covered by the Federal plan unless and until the EPA approves a
TIP applicable to those facilities.
B. Where To Get a Copy of This Document and Other Related Information
In addition to being available in the docket, an electronic copy of
this action is available on the internet at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power. Following publication in the
Federal Register, the EPA will post the Federal Register version of the
proposals and key technical documents at this same website.
Memoranda showing the edits that would be necessary to incorporate
the changes to 40 CFR part 60, subpart TTTT and UUUUa and new 40 CFR
part 60, subparts TTTTa and UUUUb proposed in these actions are
available in the docket (Docket ID No. EPA-HQ-OAR-2023-0072). Following
signature by the EPA Administrator, the EPA also will post a copy of
the documents at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
C. Organization and Approach for These Proposed Rules
This rulemaking includes several proposed actions: (1) The EPA's
proposed amendments to the Standards of Performance for Greenhouse Gas
Emissions From New, Modified, and Reconstructed Stationary Sources:
Electric Utility Generating Units (80 FR 64510; October 23, 2015) (2015
NSPS) and (2) proposed requirements for GHG emissions from new and
reconstructed fossil fuel-fired stationary combustion turbine EGUs.
These actions also (3) propose to repeal the ACE Rule (84 FR 32523;
July 8, 2019), (4) propose new emission guidelines for states in
developing plans to reduce GHG emissions from existing fossil fuel-
fired steam generating EGUs, which include both coal-fired and oil- and
natural gas-fired steam generating EGUs, and (5) propose new emission
guidelines for states in developing plans to reduce GHG emissions from
existing fossil fuel-fired stationary combustion turbines. The EPA
proposes that each of these actions function independently and are
therefore severable. The EPA invites comment on the question of which
portions of these proposed rules, if any, should be severable.
Section III of this preamble provides updated information on the
impacts of climate change. In section IV, the EPA provides a summary of
recent developments in emissions controls and the electric power
sector. Section V presents a summary of the statutory background and
regulatory history. In section VI, the EPA summarizes stakeholder
outreach efforts. In section VII, the EPA describes the proposed BSERs,
standards of performance, and associated requirements for new and
reconstructed fossil fuel-fired stationary combustion turbine EGUs. In
section
[[Page 33249]]
VIII, the EPA presents proposed amendments to requirements for new,
reconstructed, and modified fossil fuel-fired steam generating units.
In section IX, the EPA provides a summary of the ACE Rule and proposes
its repeal. In section X, the EPA presents the proposed BSERs, degree
of emission limitation, and related requirements for the proposed
emission guidelines for existing fossil fuel-fired steam generating
EGUs. In section XI, the EPA presents the proposed BSERs, degree of
emission limitation, and related requirements for the proposed emission
guidelines for existing natural gas-fired combustion turbines. Section
XII presents the requirements for State plan development. In section
XIII, the EPA describes the implications for these proposals on other
EPA programs and rules. Section XIV describes the impacts of these
proposals. Finally, in section XV, the EPA provides the statutory and
executive order reviews.
III. Climate Change and Its Impacts
Elevated concentrations of GHGs are and have been warming the
planet, leading to changes in the Earth's climate including changes in
the frequency and intensity of heat waves, precipitation, and extreme
weather events; rising seas; and retreating snow and ice. The changes
taking place in the atmosphere as a result of the well-documented
buildup of GHGs due to human activities are transforming the climate at
a pace and scale that threatens human health, society, and the natural
environment. Human-induced GHGs, largely derived from our reliance on
fossil fuels, are causing serious and life-threatening environmental
and health impacts.
Extensive additional information on climate change is available in
the scientific assessments and the EPA documents that are briefly
described in this section, as well as in the technical and scientific
information supporting them. One of those documents is the EPA's 2009
Endangerment and Cause or Contribute Findings for GHGs Under section
202(a) of the CAA (74 FR 66496; December 15, 2009).\7\ In the 2009
Endangerment Findings, the Administrator found under section 202(a) of
the CAA that elevated atmospheric concentrations of six key well-mixed
GHGs--carbon dioxide (CO2), methane (CH4),
nitrous oxide (N2O), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)--
``may reasonably be anticipated to endanger the public health and
welfare of current and future generations'' (74 FR 66523; December 15,
2009), and the science and observed changes have confirmed and
strengthened the understanding and concerns regarding the climate risks
considered in the Finding. The 2009 Endangerment Findings, together
with the extensive scientific and technical evidence in the supporting
record, documented that climate change caused by human emissions of
GHGs threatens the public health of the U.S. population. It explained
that by raising average temperatures, climate change increases the
likelihood of heat waves, which are associated with increased deaths
and illnesses (74 FR 66497; December 15, 2009). While climate change
also increases the likelihood of reductions in cold-related mortality,
evidence indicates that the increases in heat mortality will be larger
than the decreases in cold mortality in the U.S. (74 FR 66525; December
15, 2009). The 2009 Endangerment Findings further explained that
compared to a future without climate change, climate change is expected
to increase tropospheric ozone pollution over broad areas of the U.S.,
including in the largest metropolitan areas with the worst tropospheric
ozone problems, and thereby increase the risk of adverse effects on
public health (74 FR 66525; December 15, 2009). Climate change is also
expected to cause more intense hurricanes and more frequent and intense
storms of other types and heavy precipitation, with impacts on other
areas of public health, such as the potential for increased deaths,
injuries, infectious and waterborne diseases, and stress-related
disorders (74 FR 66525; December 15, 2009). Children, the elderly, and
the poor are among the most vulnerable to these climate-related health
effects (74 FR 66498; December 15, 2009).
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\7\ In describing these 2009 Findings in these proposals, the
EPA is neither reopening nor revisiting them.
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The 2009 Endangerment Findings also documented, together with the
extensive scientific and technical evidence in the supporting record,
that climate change touches nearly every aspect of public welfare \8\
in the U.S. including changes in water supply and quality due to
increased frequency of drought and extreme rainfall events; increased
risk of storm surge and flooding in coastal areas and land loss due to
inundation; increases in peak electricity demand and risks to
electricity infrastructure; predominantly negative consequences for
biodiversity and the provisioning of ecosystem goods and services; and
the potential for significant agricultural disruptions and crop
failures (though offset to some extent by carbon fertilization). These
impacts are also global and may exacerbate problems outside the U.S.
that raise humanitarian, trade, and national security issues for the
U.S. (74 FR 66530; December 15, 2009).
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\8\ The CAA states in section 302(h) that ``[a]ll language
referring to effects on welfare includes, but is not limited to,
effects on soils, water, crops, vegetation, manmade materials,
animals, wildlife, weather, visibility, and climate, damage to and
deterioration of property, and hazards to transportation, as well as
effects on economic values and on personal comfort and well-being,
whether caused by transformation, conversion, or combination with
other air pollutants.'' 42 U.S.C. 7602(h).
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In 2016, the Administrator similarly issued Endangerment and Cause
or Contribute Findings for GHG emissions from aircraft under section
231(a)(2)(A) of the CAA (81 FR 54422; August 15, 2016).\9\ In the 2016
Endangerment Findings, the Administrator found that the body of
scientific evidence amassed in the record for the 2009 Endangerment
Findings compellingly supported a similar endangerment finding under
CAA section 231(a)(2)(A) and also found that the science assessments
released between the 2009 and the 2016 Findings, ``strengthen and
further support the judgment that GHGs in the atmosphere may reasonably
be anticipated to endanger the public health and welfare of current and
future generations.'' 81 FR 54424 (August 15, 2016).
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\9\ In describing these 2016 Findings in these proposals, the
EPA is neither reopening nor revisiting them.
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Since the 2016 Endangerment Findings, the climate has continued to
change, with new records being set for several climate indicators such
as global average surface temperatures, GHG concentrations, and sea
level rise. Moreover, heavy precipitation events have increased in the
Eastern U.S. while agricultural and ecological drought has increased in
the Western U.S. along with more intense and larger wildfires.\10\
These and other trends are examples of the risks discussed in the 2009
and 2016 Endangerment Findings that have already been experienced.
Additionally, major scientific assessments continue to demonstrate
advances in our understanding of the climate system and the impacts
that GHGs have on public health and welfare both for current and future
generations. These updated observations and projections document the
rapid rate of current and future climate change both
[[Page 33250]]
globally and in the U.S. These assessments include:
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\10\ See later in this section for specific examples. An
additional resource for indicators can be found at https://www.epa.gov/climate-indicators.
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U.S. Global Change Research Program's (USGCRP) 2016
Climate and Health Assessment \11\ and 2017-2018 Fourth National
Climate Assessment (NCA4).12 13
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\11\ USGCRP, 2016: The Impacts of Climate Change on Human Health
in the United States: A Scientific Assessment. Crimmins, A., J.
Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen,
N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S.
Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change
Research Program, Washington, DC, 312 pp.
\12\ USGCRP, 2017: Climate Science Special Report: Fourth
National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey,
K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)].
U.S. Global Change Research Program, Washington, DC, USA, 470 pp,
doi: 10.7930/J0J964J6.
\13\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
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Intergovernmental Panel on Climate Change (IPCC) 2018
Global Warming of 1.5 [deg]C,\14\ 2019 Climate Change and Land,\15\ and
the 2019 Ocean and Cryosphere in a Changing Climate \16\ assessments,
as well as the 2021 IPCC Sixth Assessment Report (AR6).17 18
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\14\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. Portner, D.
Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)].
\15\ IPCC, 2019: Climate Change and Land: an IPCC special report
on climate change, desertification, land degradation, sustainable
land management, food security, and greenhouse gas fluxes in
terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V.
Masson-Delmotte, H.-O. Portner, D.C. Roberts, P. Zhai, R. Slade, S.
Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S. Neogi, M.
Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E. Huntley, K.
Kissick, M. Belkacemi, J. Malley (eds.)].
\16\ IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere
in a Changing Climate [H.-O. P[ouml]rtner, D.C. Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegr[inodot][acute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama,
N.M. Weyer (eds.)].
\17\ IPCC, 2021: Summary for Policymakers. In: Climate Change
2021: The Physical Science Basis. Contribution of Working Group I to
the Sixth Assessment Report of the Intergovernmental Panel on
Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L.
Connors, C. Pe[acute]an, S. Berger, N. Caud, Y. Chen, L. Goldfarb,
M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K.
Maycock, T. Waterfield, O. Yelekci, R. Yu and B. Zhou (eds.)].
Cambridge University Press.
\18\ IPCC, 2022: Summary for Policymakers [H.-O. P[ouml]rtner,
D.C. Roberts, E.S. Poloczanska, K. Mintenbeck, M. Tignor, A.
Alegr[iacute]a, M. Craig, S. Langsdorf, S. L[ouml]schke, V.
M[ouml]ller, A. Okem (eds.)]. In: Climate Change 2022: Impacts,
Adaptation and Vulnerability. Contribution of Working Group II to
the Sixth Assessment Report of the Intergovernmental Panel on
Climate Change [H.-O. P[ouml]rtner, D.C. Roberts, M. Tignor, E.S.
Poloczanska, K. Mintenbeck, A. Alegr[iacute]a, M. Craig, S.
Langsdorf, S. L[ouml]schke, V. M[ouml]ller, A. Okem, B. Rama
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and
New York, New York, USA, pp. 3-33, doi:10.1017/9781009325844.001.
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The National Academy of Sciences (NAS) 2016 Attribution of
Extreme Weather Events in the Context of Climate Change,\19\ 2017
Valuing Climate Damages: Updating Estimation of the Social Cost of
Carbon Dioxide,\20\ and 2019 Climate Change and Ecosystems \21\
assessments.
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\19\ National Academies of Sciences, Engineering, and Medicine.
2016. Attribution of Extreme Weather Events in the Context of
Climate Change. Washington, DC: The National Academies Press.
https://dio.org/10.17226/21852.
\20\ National Academies of Sciences, Engineering, and Medicine.
2017. Valuing Climate Damages: Updating Estimation of the Social
Cost of Carbon Dioxide. Washington, DC: The National Academies
Press. https://doi.org/10.17226/24651.
\21\ National Academies of Sciences, Engineering, and Medicine.
2019. Climate Change and Ecosystems. Washington, DC: The National
Academies Press. https://doi.org/10.17226/25504.
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National Oceanic and Atmospheric Administration's (NOAA)
annual State of the Climate reports published by the Bulletin of the
American Meteorological Society,\22\ most recently in August of 2022.
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\22\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
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EPA Climate Change and Social Vulnerability in the United
States: A Focus on Six Impacts (2021).\23\
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\23\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
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The most recent information demonstrates that the climate is
continuing to change in response to the human-induced buildup of GHGs
in the atmosphere. These recent assessments show that atmospheric
concentrations of GHGs have risen to a level that has no precedent in
human history and that they continue to climb, primarily as a result of
both historic and current anthropogenic emissions, and that these
elevated concentrations endanger our health by affecting our food and
water sources, the air we breathe, the weather we experience, and our
interactions with the natural and built environments. For example, the
annual global average atmospheric concentrations of one of these GHGs,
CO2, measured at Mauna Loa in Hawaii and at other sites
around the world reached 415 parts per million (ppm) in 2020 (nearly 50
percent higher than pre-industrial levels) \24\ and has continued to
rise at a rapid rate. Global average temperature has increased by about
1.1 degrees Celsius ([deg]C) (2.0 degrees Fahrenheit ([deg]F)) in the
2011-2020 decade relative to 1850-1900.\25\ The years 2015-2021 were
the warmest 7 years in the 1880-2020 record according to six different
global surface temperature datasets.\26\ The IPCC determined with
medium confidence that this past decade was warmer than any multi-
century period in at least the past 100,000 years.\27\ Global average
sea level has risen by about 8 inches (about 21 centimeters (cm)) from
1901 to 2018, with the rate from 2006 to 2018 (0.15 inches/year or 3.7
millimeters (mm)/year) almost twice the rate over the 1971 to 2006
period and three times the rate of the 1901 to 2018 period.\28\ The
rate of sea level rise during the 20th Century was higher than in any
other century in at least the last 2,800 years.\29\ Higher
CO2 concentrations have led to acidification of the surface
ocean in recent decades to an extent unusual in the past 2 million
years, with negative impacts on marine organisms that use calcium
carbonate to build shells or skeletons.\30\ Arctic sea ice extent
continues to decline in all months of the year; the most rapid
reductions occur in September (very likely almost a 13 percent decrease
per decade between 1979 and 2018) and are unprecedented in at least
1,000 years.\31\ Human-induced climate change has led to heatwaves and
heavy precipitation becoming more frequent and more intense, along with
increases in agricultural and ecological droughts \32\ in many
regions.\33\
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\24\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021.'' Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
\25\ IPCC, 2021.
\26\ Blunden, J. and T. Boyer, Eds., 2022.
\27\ IPCC, 2021.
\28\ IPCC, 2021.
\29\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi: 10.7930/NCA4.2018.
\30\ IPCC, 2021.
\31\ IPCC, 2021.
\32\ These are drought measures based on soil moisture.
\33\ IPCC, 2021.
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The assessment literature demonstrates that modest additional
amounts of warming may lead to a climate different from anything humans
have ever experienced. The present-day CO2 concentration of
415 ppm is already higher than at any time in the last 2 million
years.\34\ If concentrations exceed 450 ppm, they would likely be
higher
[[Page 33251]]
than at any time in the past 23 million years: \35\ At the current rate
of increase of more than 2 ppm per year, this will occur in about 15
years. While buildup of GHGs is not the only factor that controls
climate, it is illustrative that 3 million years ago (the last time
CO2 concentrations were this high) Greenland was not yet
completely covered by ice and still supported forests, while 23 million
years ago (the last time concentrations were above 450 ppm) the West
Antarctic ice sheet was not yet developed, indicating the possibility
that high GHG concentrations could lead to a world that looks very
different from today and from the conditions in which human
civilization has developed.\36\
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\34\ IPCC, 2021.
\35\ IPCC, 2013.
\36\ Gulev, S.K., P.W. Thorne, J. Ahn, F.J. Dentener, C.M.
Domingues, S. Gerland, D. Gong, D.S. Kaufman, H.C. Nnamchi, J.
Quaas, J.A. Rivera, S. Sathyendranath, S.L. Smith, B. Trewin, K. von
Schuckmann, and R.S. Vose, 2021: Changing State of the Climate
System. In Climate Change 2021: The Physical Science Basis.
Contribution of Working Group I to the Sixth Assessment Report of
the Intergovernmental Panel on Climate Change [Masson-Delmotte, V.,
P. Zhai, A. Pirani, S.L. Connors, C. P[eacute]an, S. Berger, N.
Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E.
Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield, O.
Yelek[ccedil]i, R. Yu, and B. Zhou (eds.)]. Cambridge University
Press, Cambridge, United Kingdom and New York, New York, USA, pp.
287-422, doi:10.1017/9781009157896.004.
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If the Greenland and Antarctic ice sheets were to melt
substantially, for example, sea levels would rise dramatically, with
potentially severe consequences for coastal cities and infrastructure.
The IPCC estimated that during the next 2,000 years, sea level will
rise by 7 to 10 feet even if warming is limited to 1.5 [deg]C (2.7
[deg]F), from 7 to 20 feet if limited to 2 [deg]C (3.6 [deg]F), and by
60 to 70 feet if warming is allowed to reach 5 [deg]C (9 [deg]F) above
preindustrial levels.\37\ For context, almost all of the city of Miami
is less than 25 feet above sea level, and the NCA4 stated that 13
million Americans would be at risk of migration due to 6 feet of sea
level rise. Moreover, the CO2 being absorbed by the ocean
has resulted in changes in ocean chemistry due to acidification of a
magnitude not seen in 65 million years,\38\ putting many marine
species--particularly calcifying species--at risk.\39\
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\37\ IPCC, 2021.
\38\ IPCC, 2018.
\39\ IPCC, 2021.
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The NCA4 found that it is very likely (greater than 90 percent
likelihood) that by mid-century, the Arctic Ocean will be almost
entirely free of sea ice by late summer for the first time in about 2
million years.\40\ Coral reefs will be at risk for almost complete (99
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from
today (2 [deg]C or 3.6 [deg]F since preindustrial). At this
temperature, between 8 and 18 percent of animal, plant, and insect
species could lose over half of the geographic area with suitable
climate for their survival, and 7 to 10 percent of rangeland livestock
would be projected to be lost.\41\ The IPCC similarly found that
climate change has caused substantial damages and increasingly
irreversible losses in terrestrial, freshwater, and coastal and open
ocean marine ecosystems.\42\
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\40\ USGCRP, 2018.
\41\ IPCC, 2018.
\42\ IPCC, 2022.
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Every additional increment of temperature comes with consequences.
For example, the half degree of warming from 1.5 to 2 [deg]C (0.9
[deg]F of warming from 2.7 [deg]F to 3.6 [deg]F) above preindustrial
temperatures is projected on a global scale to expose 420 million more
people to frequent extreme heatwaves and 62 million more people to
frequent exceptional heatwaves (where heatwaves are defined based on a
heat wave magnitude index which takes into account duration and
intensity--using this index, the 2003 French heat wave that led to
almost 15,000 deaths would be classified as an ``extreme heatwave'' and
the 2010 Russian heatwave which led to thousands of deaths and
extensive wildfires would be classified as ``exceptional''). This half
degree temperature increase has been projected to lead to an increase
in the frequency of sea-ice-free Arctic summers from once in a hundred
years to once in a decade. It could lead to 4 inches of additional sea
level rise by the end of the century, exposing an additional 10 million
people to risks of inundation, as well as increasing the probability of
triggering instabilities in either the Greenland or Antarctic ice
sheets. Between half a million and a million additional square miles of
permafrost is projected to thaw over several centuries. Risks to food
security is projected to increase from medium to high for several lower
income regions in the Sahel, southern Africa, the Mediterranean,
central Europe, and the Amazon. In addition to food security issues,
this temperature increase is projected to have implications for human
health in terms of increasing ozone concentrations, heatwaves, and
vector-borne diseases (for example, expanding the range of the
mosquitoes which carry dengue fever, chikungunya, yellow fever, and the
Zika virus or the ticks which carry lyme, babesiosis, or Rocky Mountain
Spotted Fever).\43\ Moreover, every additional increment in warming
leads to larger changes in extremes, including the potential for events
unprecedented in the observational record. Every additional degree is
projected to intensify extreme precipitation events by about 7 percent.
The peak winds of the most intense tropical cyclones (hurricanes) are
projected to increase with warming. In addition to a higher intensity,
the IPCC found that precipitation and frequency of rapid
intensification of these storms has already increased, while the
movement speed has decreased, and elevated sea levels have increased
coastal flooding, all of which make these tropical cyclones more
damaging.\44\
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\43\ IPCC, 2018.
\44\ IPCC, 2021.
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The NCA4 also evaluated a number of impacts specific to the U.S.
Severe drought and outbreaks of insects like the mountain pine beetle
have killed hundreds of millions of trees in the Western U.S. Wildfires
have burned more than 3.7 million acres in 14 of the 17 years between
2000 and 2016, and Federal wildfire suppression costs were about a
billion dollars annually.\45\ The National Interagency Fire Center has
documented U.S. wildfires since 1983, and the 10 years with the largest
acreage burned have all occurred since 2004.\46\ Wildfire smoke
degrades air quality increasing health risks, and more frequent and
severe wildfires due to climate change would further diminish air
quality, increase incidences of respiratory illness, impair visibility,
and disrupt outdoor activities, sometimes thousands of miles from the
location of the fire. Meanwhile, sea level rise has amplified coastal
flooding and erosion impacts, leading to salt water intrusion into
coastal aquifers and groundwater, flooding streets, increasing storm
surge damages, and threatening coastal property and ecosystems,
requiring costly adaptive measures such as installation of pump
stations, beach nourishment, property elevation, and shoreline
armoring. Tens of billions of dollars of U.S. real estate could be
below sea level by 2050 under some scenarios. Increased frequency and
duration of drought will reduce agricultural productivity in some
regions, accelerate depletion of water supplies for irrigation, and
expand the distribution and incidence of pests and diseases for crops
and livestock. The NCA4 also recognized that climate change can
increase risks to national
[[Page 33252]]
security, both through direct impacts on military infrastructure, but
also by affecting factors such as food and water availability that can
exacerbate conflict outside U.S. borders. Droughts, floods, storm
surges, wildfires, and other extreme events stress nations and people
through loss of life, displacement of populations, and impacts on
livelihoods.\47\
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\45\ USGCRP, 2018.
\46\ NIFC (National Interagency Fire Center). 2022. Total
wildland fires and acres (1983-2020). Accessed November 2022.
https://www.nifc.gov/sites/default/files/document-media/TotalFires.pdf.
\47\ USGCRP, 2018.
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Some GHGs also have impacts beyond those mediated through climate
change. For example, elevated concentrations of CO2
stimulate plant growth (which can be positive in the case of beneficial
species, but negative in terms of weeds and invasive species, and can
also lead to a reduction in plant micronutrients) \48\ and cause ocean
acidification. Nitrous oxide depletes the levels of protective
stratospheric ozone.\49\ The tropospheric ozone produced by the
reaction of methane in the atmosphere has harmful effects for human
health and plant growth in addition to its climate effects.\50\
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\48\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F.
Garofalo, A.S. Khan, I. Loladze, A.A. Perez de Leon, A. Showler, J.
Thurston, and I. Walls, 2016: Ch. 7: Food Safety, Nutrition, and
Distribution. The Impacts of Climate Change on Human Health in the
United States: A Scientific Assessment. U.S. Global Change Research
Program, Washington, DC, 189-216, https://dx.doi.org/10.7930/J0ZP4417.
\49\ WMO (World Meteorological Organization), Scientific
Assessment of Ozone Depletion: 2018, Global Ozone Research and
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland,
2018.
\50\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik,
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air
Quality. In Impacts, Risks, and Adaptation in the United States:
Fourth National Climate Assessment, Volume II [Reidmiller, D.R.,
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 512-538. doi: 10.7930/NCA4. 2018.
CH13.
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Ongoing EPA modeling efforts can shed further light on the
distribution of climate change damages expected to occur within the
U.S. Based on methods from over 30 peer-reviewed climate change impact
studies, the EPA's Framework for Evaluating Damages and Impacts (FrEDI)
model has developed estimates of the relationship between future
temperature changes and physical and economic climate-driven damages
occurring in specific U.S. regions across 20 impact categories, which
span a large number of sectors of the U.S. economy.\51\ Recent
applications of FrEDI have advanced the collective understanding about
how future climate change impacts in these 20 sectors are expected to
be substantial and distributed unevenly across U.S. regions.\52\ Using
this framework, the EPA estimates that under a global emission scenario
with no additional mitigation, relative to a world with no additional
warming since the baseline period (1986-2005), damages accruing to
these 20 sectors in the contiguous U.S. occur mainly through increased
deaths due to increasing temperatures, as well as climate-driven
changes in air quality, transportation impacts due to coastal flooding
resulting from sea level rise, increased mortality from wildfire
emission exposure and response costs for fire suppression, and reduced
labor hours worked in outdoor settings and buildings without air
conditioning. The relative damages from long-term climate driven
changes in these sectors are also projected vary from region to region:
for example, the Southeast is projected to see some of the largest
damages from sea level rise, the West Coast will see higher damages
from wildfire smoke than other parts of the country, and the Northern
Plains states are projected to see a higher proportion of damages to
rail and road infrastructure. While the FrEDI framework currently
quantifies damages for 20 sectors within the U.S., it is important to
note that it is still a preliminary and partial assessment of climate
impacts relevant to U.S. interests in a number of ways. For example,
FrEDI does not reflect increased damages that occur due to interactions
between different sectors impacted by climate change or all the ways in
which physical impacts of climate change occuring abroad have spillover
effects in different regions of the U.S. See the FrEDI Technical
Documentation \53\ for more details.
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\51\ EPA. (2021). Technical Documentation on the Framework for
Evaluating Damages and Impacts (FrEDI). U.S. Environmental
Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi. Documentation has been subject to both a
public review comment period and an independent expert peer review,
following EPA peer-review guidelines.
\52\ (1) Sarofim, M.C., Martinich, J., Neumann, J.E., et al.
(2021). A temperature binning approach for multi-sector climate
impact analysis. Climatic Change 165. https://doi.org/10.1007/s10584-021-03048-6, (2) Supplementary Material for the Regulatory
Impact Analysis for the Supplemental Proposed Rulemaking,
``Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and
Natural Gas Sector Climate Review,'' Docket ID No. EPA-HQ-OAR-2021-
0317, September 2022, (3) The Long-Term Strategy of the United
States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.
Published by the U.S. Department of State and the U.S. Executive
Office of the President, Washington DC. November 2021, (4) Climate
Risk Exposure: An Assessment of the Federal Government's Financial
Risks to Climate Change, White Paper, Office of Management and
Budget, April 2022.
\53\ EPA. (2021). Technical Documentation on the Framework for
Evaluating Damages and Impacts (FrEDI). U.S. Environmental
Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi.
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These scientific assessments, EPA analyses, and documented observed
changes in the climate of the planet and of the U.S. present clear
support regarding the current and future dangers of climate change and
the importance of GHG emissions mitigation.
IV. Recent Developments in Emissions Controls and the Electric Power
Sector
A. Introduction
In this section, we discuss background information about the
electric power sector and then discuss several recent developments that
are relevant for many of the controls that the EPA is proposing to
determine qualify as the BSER for the fossil fuel-fired power plants
that are the subject of this proposed rulemaking. After giving some
general background, we first discuss CCS and explain that its cost has
fallen significantly. Lower CCS costs are central for the EPA's
proposals that CCS is the BSER for certain existing coal-fired EGUs and
certain existing and new natural gas-fired combustion turbines. Second,
we discuss natural gas co-firing for coal-fired EGUs and explain recent
reductions in cost for this approach as well as its widespread
availability and current and potential deployment within this source
category. Third, we discuss hydrogen produced through low-emitting
manufacturing, the availability of which is expected to increase
significantly and the cost of which is expected to decline
significantly in the near future. This increase in availability and
decrease in cost is central for the EPA's proposal that low-GHG
hydrogen is the BSER for certain existing and new natural gas-fired
combustion turbines. Finally, we discuss key developments in the
electric power sector that underly the expected operational methods for
existing coal-fired EGUs and new and existing natural gas-fired
combustion turbines. These key developments, in turn, are relevant for
the regulatory design.
B. Background
1. Electric Power Sector
Electricity in the U.S. is generated by a range of technologies,
and while the sector is rapidly evolving, the stationary combustion
turbines and steam generating EGUs that are the subject of these
proposed regulations still provide more than half of the electricity
generated in the U.S. These EGUs fill many roles that are important to
maintaining a reliable supply of electricity. For example, certain EGUs
generate base load power, which is the portion of electricity loads
that are continually present and typically
[[Page 33253]]
operate throughout all hours of the year. Other EGUs provide
complementary generation to balance variable supply and demand
resources. ``Peaking units'' provide capacity during hours of the
highest daily, weekly, or seasonal net demand. Some EGUs also play
important roles ensuring the reliability of the electric grid,
including facilitating the regulation of frequency and voltage,
providing ``black start'' capability in the event the grid must be
repowered after a widespread outage, and providing reserve generating
capacity \54\ in the event of unexpected changes in the availability of
other generators.
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\54\ Generation and capacity are commonly reported statistics
with key distinctions. Generation is the production of electricity
and is a measure of an EGU's actual output while capacity is a
measure of the maximum potential production of an EGU under certain
conditions. There are several methods to calculate an EGU's
capacity, which are suited for different applications of the
statistic. Capacity is typically measured in megawatts (MW) for
individual units or gigawatts (1 GW = 1,000 MW) for multiple EGUs.
Generation is often measured in kilowatt-hours (kWh), megawatt-hours
(MWh), or gigawatt-hours (1 GWh = 1 million kWh).
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In general, the EGUs with the lowest operating costs are dispatched
first, and, as a result, an inefficient EGU with high fuel costs will
typically only operate if other lower-cost plants are unavailable or
insufficient to meet demand. Units are also unavailable during both
routine and unanticipated outages, which typically become more frequent
as power plants age. These factors result in the mix of available
generating capacity types (e.g., the share of capacity of each type of
generating source) being substantially different than the mix of the
share of total electricity produced by each type of generating source
in a given season or year.
Generated electricity must be transmitted over networks \55\ of
high voltage lines to substations where power is stepped down to a
lower voltage for local distribution. Within each of these transmission
networks, there are multiple areas where the operation of power plants
is monitored and controlled by regional organizations to ensure that
electricity generation and load are kept in balance. In some areas, the
operation of the transmission system is under the control of a single
regional operator; \56\ in others, individual utilities \57\ coordinate
the operations of their generation and transmission to balance the
system across their respective service territories.
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\55\ The three network interconnections are the Western
Interconnection, comprising the western parts of both the U.S. and
Canada (approximately the area to the west of the Rocky Mountains),
the Eastern Interconnection, comprising the eastern parts of both
the U.S. and Canada (except those parts of Eastern Canada that are
in the Quebec Interconnection), and the Texas Interconnection (which
encompasses the portion of the Texas electricity system commonly
known as the Electric Reliability Council of Texas (ERCOT)). See map
of all NERC interconnections at https://www.nerc.com/AboutNERC/keyplayers/PublishingImages/NERC%20Interconnections.pdf.
\56\ For example, PJM Interconnection, LLC, New York Independent
System Operator (NYISO), Midwest Independent System Operator (MISO),
California Independent System Operator (CAISO), etc.
\57\ For example, Los Angeles Department of Power and Water,
Florida Power and Light, etc.
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2. Types of EGUs
In 2021, approximately 61 percent of net electricity was generated
from the combustion of fossil fuels with natural gas providing 38
percent, coal providing 22 percent, and petroleum products such as fuel
oil providing an additional 1 percent.\58\ Fossil fuel-fired EGUs
include the steam generating units and stationary combustion turbines
that are the subject of these proposed regulations.
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\58\ U.S. Energy Information Administration (EIA). Electric
Power Monthly, Table 1.1 and Form EIA-860M, July 2022. https://www.eia.gov/electricity/data/php.
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There are two forms of fossil fuel-fired electric utility steam
generating units: utility boilers and those that use gasification
technology (i.e., integrated gasification combined cycle (IGCC) units).
While coal is the most common fuel for fossil fuel-fired utility
boilers, natural gas can also be used as a fuel in these EGUs and many
existing coal- and oil-fired utility boilers have repowered as natural
gas-fired units. An IGCC unit gasifies fuel--typically coal or
petroleum coke--to form a synthetic gas (or syngas) composed of carbon
monoxide (CO) and hydrogen (H2), which can be combusted in a
combined cycle system to generate power. The heat created by these
technologies produces high-pressure steam that is released to rotate
turbines, which, in turn, spin an electric generator.
Stationary combustion turbine EGUs (most commonly natural gas-
fired) use one of two configurations: combined cycle or simple cycle
combustion turbines. Combined cycle units have two generating
components (i.e., two cycles) operating from a single source of heat.
Combined cycle units first generate power from a combustion turbine
(i.e., the combustion cycle) directly from the heat of burning natural
gas or other fuel. The second cycle reuses the waste heat from the
combustion turbine engine, which is routed to a heat recovery steam
generator (HRSG) that generates steam, which is then used to produce
additional power using a steam turbine (i.e., the steam cycle).
Combining these generation cycles increases the overall efficiency of
the system. Combined cycle units that fire mostly natural gas are
commonly referred to as natural gas combined cycle (NGCC) units, and,
with greater efficiency, are utilized at higher capacity factors to
provide base load or intermediate power. An EGU's capacity factor
indicates a power plant's electricity output as a percentage of its
total generation capacity. Simple cycle combustion turbines only use a
combustion turbine to produce electricity (i.e., there is no heat
recovery or steam cycle). These less-efficient combustion turbines are
generally utilized at non-base load capacity factors and contribute to
reliable operations of the grid during periods of peak demand or
provide flexibility to support increased generation from variable
energy sources.\59\
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\59\ Non-dispatchable renewable energy (electrical output cannot
be used at any given time to meet fluctuating demand) is both
variable and intermittent and is often referred to as intermittent
renewable energy. The variability aspect results from predictable
changes in electric generation (e.g., solar not generating
electricity at night) that often occur on longer time periods. The
intermittent aspect of renewable energy results from inconsistent
generation due to unpredictable external factors outside the control
of the owner/operator (e.g., imperfect local weather forecasts) that
often occur on shorter time periods. Since renewable energy
fluctuates over multiple time periods, grid operators are required
to adjust forecast and real time operating procedures. As more
renewable energy is added to the electric grid and generation
forecasts improve, the intermittency of renewable energy is reduced.
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Other generating sources produce electricity by harnessing kinetic
energy from flowing water, wind, or tides, thermal energy from
geothermal wells, or solar energy primarily through photovoltaic solar
arrays. Spurred by a combination of declining costs, consumer
preferences, and government policies, the capacity of these renewable
technologies is growing, and when considered with existing nuclear
energy, accounted for nearly 41 percent of the overall net electricity
supply in 2022. Many projections show this share growing over time. For
example, the EPA's Power Sector Modeling Platform v6 Using the
Integrated Planning Model post-IRA 2022 reference case (i.e., the EPA's
projections of the power sector, which includes representation of the
IRA absent further regulation) shows zero-emitting sources reaching 76
percent of electricity generation by 2040. (See section IV.F of this
preamble and the accompanying RIA for additional discussion of
projections for the power sector). These projections are consistent
with power company announcements. For example, as the Edison Electric
Institute (EEI) stated in pre-proposal public comments
[[Page 33254]]
submitted to the regulatory docket: ``Fifty EEI members have announced
forward-looking carbon reduction goals, two-thirds of which include a
net-zero by 2050 or earlier equivalent goal, and members are routinely
increasing the ambition or speed of their goals or altogether
transforming them into net-zero goals . . . . EEI's member companies
see a clear path to continued emissions reductions over the next decade
using current technologies, including nuclear power, natural gas-based
generation, energy demand efficiency, energy storage, and deployment of
new renewable energy--especially wind and solar--as older coal-based
and less-efficient natural gas-based generating units retire.'' \60\
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\60\ Edison Electric Institute (EEI). (November 18, 2022). Clean
Air Act Section 111 Standards and the Power Sector: Considerations
and Options for Setting Standards and Providing Compliance
Flexibility to Units and States. Pg. 5. Public comments submitted to
the EPA's pre-proposal rulemaking, Docket ID No. EPA-HQ-OAR-2022-
0723.
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C. CCS
One of the key GHG reduction technologies upon which BSER
determinations are founded in this proposal is CCS--a technology that
can capture and permanently store CO2 from EGUs. CCS has
three major components: CO2 capture, transportation, and
sequestration/storage. Generally, the capture processes most applicable
to combustion turbines and utility boilers remove CO2 from
the exhaust gas after combustion. The exhaust gases from most
combustion processes are at atmospheric pressure with relatively low
concentrations of CO2. Most post-combustion capture systems
utilize liquid solvents (most commonly amine-based) in a scrubber
column to absorb the CO2 from the flue gas.\61\ The
CO2-rich solvent is then regenerated by heating the solvent
to release the captured CO2. The high purity CO2
is then compressed and transported, generally through pipelines, to a
site for geologic sequestration (i.e., the long-term containment of
CO2 in subsurface geologic formations).\62\ Process
improvements learned from earlier deployments of CCS, the availability
of better solvents, and other advances have resulted in a decrease in
the cost of CCS in recent years. The cost of CO2 capture,
excluding any tax credits, from coal-fired power generation is
projected to fall by 50 percent by 2025 compared to 2010.\63\ In
addition, new policies such as the IRA, enacted in 2022, support the
deployment of CCS technology and will further reduce the cost of
implementing CCS by extending and increasing the tax credit for CCS
under Internal Revenue Code section 45Q.
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\61\ Post-combustion CO2 capture is most common, but
as discussed later in this preamble, there are also pre-combustion
CO2 capture options available and applicable to the power
sector.
\62\ 40 CFR 261.4(h).
\63\ Technology Readiness and Costs of CCS (2021). Global CCS
Institute. https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.
_____________________________________-
There are several examples of the application of CCS at EGUs, some
of which are noted here with further detail provided in section
VII.F.3.b.iii(A) of this preamble. These include SaskPower's Boundary
Dam Unit 3, a 110-MW lignite-fired unit in Saskatchewan, Canada, which
has achieved CO2 capture rates of 90 percent using an amine-
based post-combustion capture system retrofitted to the existing steam
generating unit.\64\ Amine-based carbon capture has also been
demonstrated at AES's Warrior Run (Cumberland, Maryland) and Shady
Point (Panama, Oklahoma) coal-fired power plants.\65\
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\64\ Giannaris, S., et al. Proceedings of the 15th International
Conference on Greenhouse Gas Control Technologies (March 15-18,
2021). SaskPower's Boundary Dam Unit 3 Carbon Capture Facility-The
Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
\65\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
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CCS has also been successfully applied to an existing combined
cycle combustion turbine EGU at the Bellingham Energy Center in south
central Massachusetts, and other projects are in different stages of
deployment. The 40-MW slipstream capture facility at the Bellingham
Energy Center operated from 1991 to 2005 and captured 85 to 95 percent
of the CO2 in the slipstream.\66\ In Scotland, the proposed
900-MW Peterhead Power Station combined cycle EGU with CCS is in the
planning stages of deployment and will have the potential to capture 90
percent of its CO2 emissions.\67\ Moreover, an 1,800-MW
combined cycle EGU that will be constructed in West Virginia and will
utilize CCS has been announced. The project is planned to begin
operation later this decade, and its economic feasibility was partially
credited to the expanded IRC section 45Q tax credit for sequestered
CO2 provided through the IRA.\68\
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\66\ U.S. Department of Energy (DOE). Carbon Capture
Opportunities for Natural Gas Fired Power Systems. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems.
\67\ Buli, N. (2021, May 10). SSE, Equinor plan new gas power
plant with carbon capture in Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/.
\68\ Competitive Power Ventures (2022). Multi-Billion Dollar
Combined Cycle Natural Gas Power Station with Carbon Capture
Announced in West Virginia. Press Release. September 16, 2022.
https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/.
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In developing these proposals, the EPA reviewed the current state
of CCS technology and costs, including the use of CCS with both steam
generating units and combustion turbines. This review is reflected in
the BSER discussions later in this preamble and is further detailed in
the accompanying RIA and technical support documents titled, GHG
Mitigation Measures for Steam Generating Units and GHG Mitigation
Measures--Carbon Capture and Storage for Combustion Turbines. The three
documents are included in the rulemaking docket.
D. Natural Gas Co-Firing
For a coal-fired steam generating unit, the substitution of natural
gas for some of the coal so that the unit fires a combination of coal
and natural gas is known as ``natural gas co-firing.'' Most existing
coal-fired steam generating units can be modified to co-fire natural
gas in any desired proportion with coal. Generally, the modification of
existing boilers to enable or increase natural gas firing typically
involves the installation of new gas burners and related boiler
modifications as well as the construction of natural gas supply
pipelines. In recent years, the cost of natural gas co-firing has
declined because the expected difference between coal and gas prices
has decreased to about $1/MMBtu and recent analyses support lower
capital costs for modifying existing boilers to co-fire with natural
gas, as discussed in section X.D.2 of this preamble.
In developing these proposals, the EPA reviewed in detail the
current state of natural gas co-firing technology and costs. This
review is reflected in the BSER discussions later in this preamble and
is further detailed in the accompanying RIA and GHG Mitigation Measures
for Steam Generating Units TSD. Both documents are included in the
rulemaking docket.
E. Hydrogen Co-Firing
Industrial combustion turbines have been burning byproduct fuels
containing large percentages of hydrogen for decades, and recently,
utility combustion turbines in the power sector have begun to co-fire
hydrogen as
[[Page 33255]]
a fuel to generate electricity. Hydrogen contains no carbon, and when
combusted in a turbine, produces zero direct CO2 emissions.
However, as discussed in section IV.F.3 of this preamble, the
manufacture of hydrogen, depending on the method of production, can
generate GHG emissions. As noted previously, there has been a growing
interest in the use of hydrogen as a fuel for combustion turbines to
generate electricity. Many models of new utility combustion turbines
have demonstrated the ability to co-fire up to 30 percent hydrogen and
developers are working toward models that will be ready to combust 100
percent hydrogen by 2030. Furthermore, several utilities are co-firing
hydrogen in test burns; and some have announced plans to move to
combusting 100 percent hydrogen in the 2035-2045 timeframe.
Specifically, the Los Angeles Department of Water and Power's (LADWP)
Scattergood Modernization project includes plans to have a hydrogen-
ready combustion turbine in place when the 346-MW combined cycle plant
(potential for up to 830 MW) begins initial operations in 2029. LADWP
foresees the plant running on 100 percent electrolytic hydrogen by
2035.\69\ In addition, LADWP also has an agreement in place to purchase
electricity from the Intermountain Power Agency project (IPA) in Utah.
IPA is replacing an existing 1.8-GW coal-fired EGU with an 840-MW
combined cycle turbine that developers expect to initially co-fire 30
percent electrolytic hydrogen in 2025 and 100 percent hydrogen by
2045.\70\ In Florida, NextEra Energy has announced plans to operate 16
GW of existing natural gas-fired combustion turbines with electrolytic
hydrogen as part of the utility's Zero Carbon Blueprint to be carbon-
free by 2045.\71\ Duke Energy Corporation, which operates 33 gas-fired
plants across the Midwest, the Carolinas, and Florida, has outlined
plans for full hydrogen capabilities throughout its future turbine
fleet: ``All natural gas units built after 2030 are assumed to be
convertible to full hydrogen capability. After 2040, only peaking units
that are fully hydrogen capable are assumed to be built.'' \72\
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\69\ https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
\70\ https://www.forbes.com/sites/mitsubishiheavyindustries/2021/07/30/eager-to-become-hydrogen-ready-power-plants-turn-to-dual-fuel-turbines/?sh=38ddea053476.
\71\ https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
\72\ https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2022.pdf.
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In addition to those three utility announcements, several merchant
generators operating in wholesale markets are also signaling their
intent to ramp up hydrogen co-firing levels after initial 30 percent
co-firing phases. The Cricket Valley Energy Center (CVEC) in New York
is retrofitting its combined cycle power plant starting in 2022 as a
first step toward the conversion to a 100 percent hydrogen fuel capable
plant. CVEC announcements did not have specific dates for 100 percent
electrolytic hydrogen firing but indicated in its announcement that New
York has mandated achieving a zero-emission electricity sector by
2040.\73\ The Long Ridge Energy Terminal in Ohio, which is has
successfully co-fired a 5 percent hydrogen blend at its 485-MW combined
cycle plant, noted its technology has the capability to transition to
100 percent hydrogen over time as its low-GHG fuel supply becomes
available.\74\ Constellation Energy, which owns 23 natural gas-fired or
dual fuel generators (8.6 GW), is exploring electrolytic hydrogen co-
firing across its fleet. It estimated costs for blend levels in the
range of 60-100 percent at approximately $100/kW for retrofits and
noted that equipment manufacturers are planning 100 percent hydrogen
combustion-ready turbines before 2030.\75\
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\73\ https://www.cricketvalley.com/news/cricket-valley-energy-center-and-ge-sign-agreement-to-help-reduce-carbon-emissions-in-new-york-with-green-hydrogen-fueled-power-plant/.
\74\ GE-powered gas-fired plant in Ohio now burning hydrogen
(power-eng.com).
\75\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units Docket ID No. EPA-HQ-OAR-2022-0289-0022.
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In both the IIJA and the IRA, Congress provided extensive support
for the development of hydrogen produced through low-GHG methods. This
support includes investment in infrastructure through the IIJA, and the
provision of tax credits in the IRA to incentivize the manufacture of
hydrogen through low GHG-emitting methods. These incentives are fueling
interest in co-firing hydrogen and creating expectations that the
availability of low-cost and low-GHG hydrogen will increase in the
coming years. These projections are based on a combination of economies
of scale as low-GHG production methods expand, the increasing
availability of low-cost electricity--largely powered by renewable
energy sources and potentially nuclear energy--and learning by doing as
more turbine projects are developed.
In developing these proposals, the EPA reviewed in detail the
current state of hydrogen co-firing technology and costs. This review
is reflected in the BSER discussions later in this preamble and is
further detailed in the accompanying RIA and technical support document
titled, Hydrogen in Combustion Turbine Electric Generating Units. Both
documents are included in the rulemaking docket.
F. Recent Changes in the Power Sector
1. Overview
The electric power sector is experiencing a prolonged period of
transition and structural change. Since the generation of electricity
from coal-fired power plants peaked nearly two decades ago, the power
sector has changed at a rapid pace. Today, natural gas-fired power
plants provide the largest share of net generation, coal-fired power
plants provide a significantly smaller share than in the recent past,
renewable energy provides a steadily increasing share, and as new
technologies enter the marketplace, power producers continue to replace
aging assets with more efficient and lower cost alternatives.
These developments have significant implications for the types of
controls that the EPA proposes to determine qualify as the BSER for
different types of fossil fuel-fired EGUs. For example, many utilities
and power plant operators have announced plans to voluntarily cease
operating coal-fired power plants in the near future, in some cases
after operating them at low levels for a several-year period. Industry
stakeholders have requested that the EPA structure this rule to avoid
imposing costly control obligations on coal-fired power plants that
have announced plans to voluntarily cease operations, and the EPA
proposes to accommodate those requests. In addition, the EPA recognizes
that utilities and power plant operators are building new natural gas-
fired combustion turbines with plans to operate them at varying levels
of utilization, in coordination with other existing and expected new
energy sources. These patterns of operation are important for the type
of controls that the EPA is proposing as the BSER for these turbines.
This section discusses the recent trends in the power sector. It
also includes a summary of the provisions and incentives included in
recent Federal legislation that will impact the power sector as well as
State actions and commitments by power producers to reduce GHG
emissions. The section
[[Page 33256]]
concludes with projections of future trends in power sector generation.
2. Broad Trends Within the Power Sector
For more than a decade, the power sector has experienced
substantial transition and structural change, both in terms of the mix
of generating capacity and in the share of electricity generation
supplied by different types of EGUs. These changes are the result of
multiple factors, including normal replacements of older EGUs; changes
in electricity demand across the broader economy; growth and regional
changes in the U.S. population; technological improvements in
electricity generation from both existing and new EGUs; changes in the
prices and availability of different fuels; State and Federal policy;
the preferences and purchasing behaviors of end-use electricity
consumers; and substantial growth in electricity generation from
renewable sources.
One of the most important developments of this transition has been
the evolving economics of the power sector. Specifically, the existing
fleet of coal-fired EGUs continues to age and become more costly to
maintain and operate. At the same time, the supply and availability of
natural gas has increased significantly, and its price has held
relatively low. For the first time, in April 2015, natural gas
surpassed coal in monthly net electricity generation and since that
time has maintained its position as the primary fossil fuel for base
load energy generation, for peaking applications, and for balancing
renewable generation.\76\ Additionally, there has been increased
generation from investments in zero- and low-GHG emission energy
technologies spurred by technological advancements, declining costs,
State and Federal policies, and most recently, the IIJA and the IRA.
For example, the IIJA provides investments and other policies to help
commercialize, demonstrate, and deploy technologies such as small
modular nuclear reactors, long-duration energy storage, regional clean
hydrogen hubs, carbon capture and storage and associated
infrastructure, advanced geothermal systems, and advanced distributed
energy resources (DER) as well as more traditional wind and solar
resources. The IRA provides numerous tax and other incentives to
directly spur deployment of clean energy technologies. Particularly
relevant to these proposals, the incentives in the IRA,\77\ which are
discussed in detail later in this section of the preamble, support the
expansion of technologies, such as CCS and hydrogen technologies, that
reduce GHG emissions from fossil-fired units.
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\76\ U.S. Energy Information Administration (EIA). Monthly
Energy Review and Short-Term Energy Outlook, March 2016. https://www.eia.gov/todayinenergy/detail.php?id=25392.
\77\ U.S. Department of Energy (DOE). August 2022. The Inflation
Reduction Act Drives Significant Emissions Reductions and Positions
America to Reach Our Climate Goals. https://www.energy.gov/sites/default/files/2022-08/8.18%20InflationReductionAct_Factsheet_Final.pdf.
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The ongoing transition of the power sector is illustrated by a
comparison of data between 2010 and 2021. In 2010, approximately 70
percent of the electricity provided to the U.S. grid was produced
through the combustion of fossil fuels, primarily coal and natural gas,
with coal accounting for the largest single share. By 2021, fossil fuel
net generation was approximately 60 percent, less than the share in
2010 despite electricity demand remaining relatively flat over this
same time period. Moreover, the share of fossil generation supplied by
coal-fired EGUs fell from 46 percent in 2010 to 23 percent in 2021
while the share supplied by natural gas-fired EGUs rose from 23 to 37
percent during the same period. In absolute terms, coal-fired
generation declined by 51 percent while natural gas-fired generation
increased by 64 percent. This reflects both the increase in natural gas
capacity as well as an increase in the utilization of new and existing
gas-fired EGUs. The combination of wind and solar generation also grew
from 2 percent of the electric power sector mix in 2010 to 12 percent
in 2021.\78\
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\78\ U.S. Energy Information Administration (EIA). Annual Energy
Review, table 8.2b Electricity net generation: electric power
sector. https://www.eia.gov/totalenergy/data/annual/.
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The broad trends throughout the power sector can also be seen in
the number of commitments and announced plans of many EGU owners and
operators across the industry to decarbonize--spanning all types of
companies in all locations. Moreover, State governments, which
traditionally regulate investment decisions regarding electricity
generation, have implemented their own policies to reduce GHG emissions
from power generation.
Additional analysis of the utility power sector, including
projections of future power sector behavior and the impacts of these
proposed rules, is discussed in more detail in section XV of this
preamble, in the accompanying RIA, and in the Power Sector Trends
technical support document (TSD). The latter two documents are
available in the rulemaking docket. Consistent with analyses done by
other energy modelers, the RIA and TSD demonstrate that the sector
trend of moving away from coal-fired generation is likely to continue
and that non-emitting technologies may eventually displace certain
natural gas-fired combustion turbines.
3. Trends in Coal-Fired Generation
Coal-fired steam generating units have historically been the
nation's foremost source of electricity, but coal-fired generation has
declined steadily since its peak approximately 20 years ago.\79\
Construction of new coal-fired steam generating units was at its
highest between 1967 and 1986, with approximately 188 GW (or 9.4 GW per
year) of capacity added to the grid during that 20-year period.\80\ The
peak annual capacity addition was 14 GW, which was added in 1980. These
coal-fired steam generating units operated as base load units for
decades. However, beginning in 2005, the U.S. power sector--and
especially the coal-fired fleet--began experiencing a period of
transition that continues today. Many of the older coal-fired steam
generating units built in the 1960s, 1970s, and 1980s have retired and/
or have experienced significant reductions in net generation due to
cost pressures and other factors. Some of these coal-fired steam
generating units repowered with combustion turbines and natural
gas.\81\ And with no new coal-fired steam generating units commencing
construction in more than a decade--and with the EPA unaware of any
plans by any companies to construct a new coal-fired EGU--much of the
fleet that remains is aging, expensive to operate and maintain, and
increasingly uncompetitive relative to other sources of generation in
many parts of the country.
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\79\ U.S. Energy Information Administration (EIA). Today in
Energy. Natural gas expected to surpass coal in mix of fuel used for
U.S. power generation in 2016. March 2016. https://www.eia.gov/todayinenergy/detail.php?id=25392.
\80\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, March 2022. https://www.eia.gov/electricity/data/eia860m/.
\81\ U.S. Energy Information Administration (EIA). Today in
Energy. More than 100 coal-fired plants have been replaced or
converted to natural gas since 2011. August 2020. https://www.eia.gov/todayinenergy/detail.php?id=44636.
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Since 2010, the power sector's total installed capacity \82\ has
increased by
[[Page 33257]]
144 GW (14 percent), while coal-fired steam generating unit capacity
has declined by 107 GW. This reduction in coal-fired steam generating
unit capacity was offset by an increase in total installed wind
capacity of 93 GW, natural gas capacity of 84 GW, and an increase in
utility-scale solar capacity of 60 GW during the same period.
Additionally, significant amounts of DER solar (33 GW) were also added.
Two-thirds or more of these changes were in the most recent 6 years of
this period. From 2015-2021, coal capacity was reduced by 70 GW and
this reduction in capacity was offset by a net increase of 60 GW of
wind capacity, 52 GW of natural gas capacity, and 47 GW of utility-
scale solar capacity. Additionally, 23 GW of DER solar were also added
from 2015 to 2021.
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\82\ This includes generating capacity at EGUs primarily
operated to supply electricity to the grid and combined heat and
power (CHP) facilities classified as Independent Power Producers and
excludes generating capacity at commercial and industrial facilities
that does not operate primarily as an EGU. Natural gas information
reflects data for all generating units using natural gas as the
primary fossil heat source unless otherwise stated. This includes
combined cycle, simple cycle, steam, and miscellaneous (<1 percent).
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At the end of 2021, there were more than 500 EGUs totaling 212 GW
of coal-fired capacity remaining in the U.S. Although much of the fleet
of coal-fired steam generating units has historically operated as base
load, there can be notable differences in design and operation across
various facilities. For example, coal-fired steam generating units
smaller than 100 MW comprise 18 percent of the total number of coal-
fired units, but only 2 percent of total coal-fired capacity.\83\
Moreover, average annual capacity factors for coal-fired steam
generating units have declined from 67 to 49 percent since 2010,\84\
indicating that a larger share of units are operating in non-base load
fashion.
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\83\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
\84\ U.S. Energy Information Administration (EIA). Electric
Power Annual 2021, table 1.2.
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Older power plants also tend to become uneconomic over time as they
become more costly to maintain and operate,\85\ especially when
competing for dispatch against newer and more efficient generating
technologies that have lower operating costs. The average coal-fired
power plant that retired between 2015 and 2021 was more than 50 years
old, and 65 percent of the remaining fleet of coal-fired steam
generating units will be 50 years old or more within a decade.\86\ To
further illustrate this trend, the existing coal-fired steam generating
units older than 40 years represent 71 percent (154 GW) \87\ of the
total remaining capacity. In fact, more than half (118 GW) of the coal-
fired steam generating units still operating have already announced
retirement dates prior to 2040.\88\ As discussed further in this
section, projections anticipate that this trend will continue.
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\85\ U.S. Energy Information Administration (EIA). U.S. coal
plant retirements linked to plants with higher operating costs.
December 2019. https://www.eia.gov/todayinenergy/detail.php?id=42155.
\86\ eGRID 2020 (January 2022 release from EPA eGRID website).
Represents data from generators that came online between 1950 and
2020 (inclusive); a 71-year period. Full eGRID data includes
generators that came online as far back as 1915.
\87\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. https://www.eia.gov/electricity/data/eia860m/.
\88\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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The reduction in coal-fired generation by electric utilities is
also evident in data for annual U.S. coal production, which reflects
reductions in international demand as well. In 2008, annual coal
production peaked at nearly 1,200 million short tons (MMst) followed by
sharp declines in 2015 and 2020.\89\ In 2015, less than 900 MMst were
produced, and in 2020, the total dropped to 535 MMst, the lowest output
since 1965.
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\89\ U.S. Energy Information Administration (EIA). Annual Coal
Report. Table ES-1. October 2022. https://eia.gov/coal/annual/pdf/tableES1.pdf.
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4. Trends in Natural Gas-Fired Generation
In the lower 48 states, most combustion turbine EGUs burn natural
gas, and some have the capability to fire distillate oil as backup for
periods when natural gas is not available, such as when residential
demand for natural gas is high during the winter. Areas of the country
without access to natural gas often use distillate oil or some other
locally available fuel. Combustion turbines have the capability to burn
either gaseous or liquid fossil fuels, including but not limited to
kerosene, naphtha, synthetic gas, biogases, liquified natural gas
(LNG), and hydrogen.
Natural gas consists primarily of methane, and after the raw gas is
extracted from the ground, it is processed to remove impurities and to
separate the methane from other gases and natural gas liquids to
produce pipeline quality gas.\90\ This gas is sent to intermediate
storage facilities prior to being piped through transmission feeder
lines to a distribution network on its path to storage facilities or
end users. During the past 20 years, advances in hydraulic fracturing
(i.e., fracking) and horizontal drilling techniques have opened new
regions of the U.S. to gas exploration.
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\90\ U.S. Energy Information Administration (EIA). Natural Gas
Explained. December 2022. https://www.eia.gov/energyexplained/natural-gas/.
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According to the U.S. Energy Information Administration (EIA),
annual natural gas marketed production in the U.S. remained consistent
at approximately 20 trillion cubic feet (Tcf) from the 1970s to the
early 2000s. However, since 2005, annual natural gas marketed
production has steadily increased and approached 35 Tcf in 2021, which
is an average of approximately 94.6 billion cubic feet per day.\91\
Thirty-four states produce natural gas with Texas (24.6 percent),
Pennsylvania (21.8 percent), Louisiana (9.9 percent), West Virginia
(7.4 percent), and Oklahoma (6.7 percent) accounting for approximately
70 percent of total production. Natural gas production exceeded
consumption in the U.S. for the first time in 2017.
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\91\ U.S. Energy Information Administration (EIA). Natural gas
explained. Where our natural gas comes from. https://www.eia.gov/energyexplained/natural-gas/where-our-natural-gas-comes-from.php.
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As the production of natural gas has increased, the annual average
price has declined during the same period.\92\ In 2008, U.S. natural
gas prices peaked at $13.39 per million British thermal units ($/MMBtu)
for residential customers. By 2020, the price was $10.45/MMBtu. The
decrease in average annual natural gas prices can also been seen in
city gate prices (i.e., a point or measuring station where natural gas
is transferred from long-distance pipelines to a local distribution
company), which peaked in 2008 at $8.85/MMBtu. By 2020, city gate
prices were $3.30/MMBtu. An equivalent $/MMBtu basis is a common way to
compare natural gas and coal fuel prices. For example, the price of
Henry Hub natural gas in July 2022 was $7.39/MMBtu while the spot price
of Central Appalachian coal was $7.25/MMBtu for the same month.
However, this method of fuel price comparison based on equivalent
energy content does not reflect differences in energy conversion
efficiency (i.e., heat rate) and other factors among different types of
generators. Because natural gas-fired combustion turbines are more
efficient than coal-fired steam units, any fuel cost comparison should
include an efficiency basis (dollar per megawatt-hour) to the
equivalent energy content. For illustrative purposes, an EIA comparison
based on this method showed that the Henry Hub natural gas
[[Page 33258]]
price in July 2022 was $59.18/MWh and the price for Central Appalachian
coal was $78.25/MWh for the same month.\93\
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\92\ U.S. Energy Information Administration (EIA). Natural Gas
Annual, September 2021. https://www.eia.gov/energyexplained/natural-gas/prices.php.
\93\ U.S. Energy Information Administration (EIA). Electric
Monthly Update. September 23. 2022. Report derived from Bloomberg
Energy. EIA notes that the competition between coal and natural gas
to produce electricity is complex, involving delivered prices and
emission costs, the terms of fuel supply contracts, and the workings
of fuel markets.
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There has been significant expansion of the natural gas-fired EGU
fleet since 2000, coinciding with efficiency improvements of combustion
turbine technologies, increased availability of natural gas, increased
demand for flexible generation to support the expanding capacity of
renewable energy resources, and declining costs for all three elements.
According to data from EIA, annual capacity additions for natural gas-
fired EGUs peaked between 2000 and 2006, with more than 212 GW added to
the grid during this period. Of this total, approximately 147 GW (70
percent) were combined cycle capacity and 65 GW were simple cycle
capacity.\94\ From 2007 to 2021, more than 125 GW of capacity were
constructed and approximately 78 percent of that total were combined
cycle EGUs. This figure represents an average of almost 4.2 GW of new
combustion turbine generation capacity per year. In 2021, the net
summer capacity of combustion turbine EGUs totaled 413 GW, with 281 GW
being combined cycle generation and 132 GW being simple cycle
generation.
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\94\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, July 2022. https://www.eia.gov/electricity/data/eia860m/.
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This trend away from coal to natural gas is also reflected in
comparisons of annual capacity factors, sizes, and ages of affected
EGUs. For example, the annual average capacity factors for natural gas-
fired units increased from 28 to 37 percent between 2010 and 2021. And
compared with the fleet of coal-fired steam generating units, the
natural gas fleet is generally smaller and newer. While 67 percent of
the coal-fired steam generating unit fleet capacity is over 500 MW per
unit, 75 percent of the gas fleet is between 50 and 500 MW per unit. In
terms of the age of the generating units, nearly 50 percent of the
natural gas capacity has been in service less than 15 years.\95\
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\95\ National Electric Energy Data System (NEEDS) v.6.
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As explained in greater detail later in this preamble and in the
accompanying RIA, future capacity projections for natural gas-fired
combustion turbines differ from those highlighted in recent historical
trends. The largest source of new generation is from renewable energy
and projections show that total natural gas-fired combined cycle
capacity is likely to decline after 2030 in response to increased
generation from renewables, energy storage, and other technologies, as
discussed in section IV.I. Approximately, 86 percent of capacity
additions in 2023 are expected to be from non-emitting generation
resources including solar, wind, nuclear, and energy storage.\96\ The
IRA is likely to accelerate this trend, which is also expected to
impact the operation of certain combustion turbines. For example, as
the electric output from additional non-emitting generating sources
fluctuates daily and seasonally, flexible low and intermediate load
combustion turbines will be needed to support these variable sources
and provide reliability to the grid. This requires the ability to start
and stop quickly and change load more frequently.
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\96\ U.S. Energy Information Administration (EIA). Today in
Energy. More than half of new U.S. electric-generating capacity in
2023 will be solar. February 2023. https://www.eia.gov/todayinenergy/detail.php?id=55419.
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5. Trends in Renewable Generation
Renewable sources of electric generation--especially solar and
wind--have expanded in the U.S. during the past decade. This growth has
coincided with a reduction in the costs of the technologies, supportive
State and Federal policies, and increased consumer demand for low-GHG
electricity. In 2021, renewable energy sources produced approximately
20 percent of the nation's net generation, led by wind (9.2 percent),
hydroelectric (6.3 percent), solar (2.8 percent), and other sources
such as geothermal and biomass (1.7 percent).\97\
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\97\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 7.2B Electricity Net Generation: Electric Power
Sector, May 2022. https://www.eia.gov/totalenergy/data/monthly/.
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The costs of renewable energy sources have fallen over time due to
technological advances, improvements in performance, and increased
demand for clean energy. For example, the unsubsidized average
levelized cost of wind energy from 1988 to 1999 was $106/MWh and has
since declined to $32/MWh in 2021.\98\ The average levelized cost of
energy for utility-scale solar photovoltaics has fallen from $227/MWh
in 2010 to $33/MWh in 2021.\99\ And the National Renewable Energy
Laboratory (NREL) has documented cost decreases of 64, 69, and 82
percent, respectively, for residential-, commercial-, and utility-scale
solar installations since 2010.\100\ Local, State, and Federal
incentives and tax credits have further reduced the cost of renewable
energy resources.
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\98\ U.S. Department of Energy (DOE), Land-Based Wind Market
Report: 2022 Edition, 2022. https://www.energy.gov/eere/wind/articles/land-based-wind-market-report-2022-edition.
\99\ Lawrence Berkeley National Laboratory (LBNL), Utility-Scale
Solar Technical Brief, 2022 Edition, September 2022. https://emp.lbl.gov/utility-scale-solar.
\100\ https://www.nrel.gov/news/program/2021/documenting-a-decade-of-cost-declines-for-pv-systems.html.
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During the past 15 years, more than 122 GW of wind (primarily
onshore) and 61 GW of solar capacity have been constructed, which
represent a tripling of wind capacity and a 20-fold increase in solar
capacity.\101\ Prior to 2007, no more than 2.6 GW of new wind capacity
was built in any year, and the wind capacity added from 2000 to 2006
averaged 1.2 GW per year. In 2007, the nation added 5.3 GW of total
wind capacity and the annual average was 7.2 GW through 2019. Wind
capacity additions peaked in the past 2 years at a total of nearly 29
GW. For solar, the pattern of expansion is similar. For example, from
2000 to 2006, a total of 11 MW of new solar capacity was constructed,
and from 2007 to 2011, total capacity additions increased to 1.2 GW.
However, from 2012 to 2019, more than 36 GW of solar capacity was built
(an average of 4.5 GW per year). And in 2020 and 2021, new solar
capacity totaled of 24 GW. In terms of the net operating share of
summer capacity in 2021, wind produced 46 percent of all renewable
energy while solar generated 21 percent. The remaining electricity
generated from renewables included 28 percent from hydroelectric and 5
percent from other sources that include geothermal systems, biogases/
biomethane from landfills, woody materials and other biomass, and
municipal solid waste.
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\101\ U.S. Energy Information Administration (EIA), Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators, July 2022. https://www.eia.gov/electricity/data/eia860m/.
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There are also emerging technologies such as battery storage that
have demonstrated the ability to further support the development and
integration of renewable energy to the grid by balancing variable
supply and demand resources. At the end of 2021, there were 331 large-
scale battery storage systems operating in the U.S. with a combined
capacity of 4.8 GW
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(10.7 GWh).\102\ In terms of small-scale battery storage, there were
781 MW of reported capacity in 2021, mostly in California.\103\ Energy
storage costs declined 72 percent between 2015 and 2019,\104\ and
declining costs have led to additional capacity being installed at each
facility, and this increases the duration of each system when operating
at maximum output. With 20.8 GW of grid storage already announced for
2023-2025, EIA expects that capacity will more than triple from 7.8 GW
in late 2022 to approximately 30 GW by the end of 2025.\105\
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\102\ U.S. Energy Information Administration (EIA). Annual
Electric Generator Report, 2021 Form EIA-860. https://www.eia.gov/electricity/data/eia860/.
\103\ U.S. Energy Information Administration (EIA). Annual
Electric Power Industry Report, 2021 Form EIA-861. https://www.eia.gov/electricity/data/eia861/.
\104\ U.S. Energy Information Administration (EIA). Annual
Electric Generator Report, 2019 Form EIA-860. https://www.eia.gov/analysis/studies/electricity/batterystorage/.
\105\ U.S. Energy Information Administration (EIA). Today in
Energy. U.S. battery storage capacity will increase significantly by
2025. December 2022. https://www.eia.gov/todayinenergy/detail.php?id=54939.
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6. Trends in Nuclear Generation
The U.S. power sector continues to rely on nuclear sources of
energy for a consistent portion of net generation. Since 1990, nuclear
energy has provided about 20 percent of the nation's electricity, and
92 reactors were operating at 54 nuclear power plants in 28 states in
2022.\106\
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\106\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form-860M, Inventory of Operating Generators
and Inventory of Retired Generators. August 2022. https://www.eia.gov/electricity/data/eia860m/.
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It should be noted that despite the consistent output from nuclear
power plants over time, the number of operating reactors has recently
declined. The average retirement age for a nuclear reactor is 44 years
and the average age of the remaining nuclear fleet is currently 42
years, although age is only one consideration for determining when a
nuclear plant may retire. For example, nuclear generating units at
Dominion Generation's Surry plant, Florida Power & Light's Turkey Point
plant, and Constellation Energy's Peach Bottom plant applied to the
Nuclear Regulatory Commission (NRC) for second 20-year license renewals
and subsequent renewed licenses were granted for six units, although
four of the six units have not had their license terms extended beyond
the periods of their first renewed licenses and are undergoing further
environmental review.\107\ Others who have applied to the NRC for a
second 20-year license renewal include Dominion for its North Anna
units 1 and 2; NextEra Energy for its Point Beach units 1 and 2; Duke
Energy Carolinas for its Oconee units 1, 2, and 3; Florida Power &
Light for its St. Lucie units 1 and 2; and Northern States Power
Company for its Monticello unit 1. If granted, these additional
licenses would also extend the lifespans of these units well past the
42-year average. Recent State and Federal policies, including the DOE's
$6 billion Civilian Nuclear Credit program enacted by the IIJA and the
45U tax credit (discussed below), are intended to support the continued
operation of existing nuclear power plants.
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\107\ U.S. Nuclear Regulatory Commission (NRC). Status of
Subsequent License Renewal Applications. April 2023. https://www.nrc.gov/reactors/operating/licensing/renewal/subsequent-license-renewal.html.
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There is also interest in the next generation of nuclear
technologies. Small modular nuclear reactors, which can provide both
firm dispatchable power and load-following capabilities to balance
greater volumes of variable renewable generation, could play a role in
future energy generation. The NRC has issued a final rule certifying
the first small modular reactor design.\108\ Expectations with respect
to output from advanced nuclear generation vary, from negligible on the
low end to as high as between 1,400 and 3,600 terawatt-hours per year
by 2050.\109\ According to one survey by the Nuclear Energy Institute,
utilities are currently considering building more than 90 GW of small
modular nuclear reactors by 2050.\110\
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\108\ 88 FR 3287 (January 19, 2023).
\109\ Stein, A., Messinger, J., Wang, S., Lloyd, J., McBride,
J., Franovich, R. (July 6, 2022). ``Advancing Nuclear Energy:
Evaluating Deployment, Investment, and Impact in America's Clean
Energy Future.'' Breakthrough Institute. https://thebreakthrough.imgix.net/Advancing-Nuclear-Energy_v3-compressed.pdf.
\110\ Derr, E. (July 29, 2022). Energy Studies and Models Show
Advanced Nuclear as the Backbone of Our Carbon-Free Future. Nuclear
Energy Institute (NEI). https://www.nei.org/news/2022/studies-and-models-show-demand-for-adv-nuclear.
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G. GHG Emissions From Fossil Fuel-Fired EGUs
The principal GHGs that accumulate in the Earth's atmosphere above
pre-industrial levels because of human activity are CO2,
CH4, N2O, HFCs, PFCs, and SF6. Of
these, CO2 is the most abundant, accounting for 80 percent
of all GHGs present in the atmosphere. This abundance of CO2
is largely due to the combustion of fossil fuels by the transportation,
electricity, and industrial sectors.\111\
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\111\ U.S. Environmental Protection Agency (EPA). Overview of
greenhouse gas emissions. July 2021. https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.
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The amount of CO2 emitted from fossil fuel-fired EGUs
depends on the carbon content of the fuel and the size and efficiency
of the EGU. Different fuels emit different amounts of CO2 in
relation to the energy they produce when combusted. The amount of
CO2 produced when a fuel is burned is a function of the
carbon content of the fuel. The heat content, or the amount of energy
produced when a fuel is burned, is mainly determined by the carbon and
hydrogen content of the fuel. For example, in terms of pounds of
CO2 emitted per million British thermal units of energy
produced, when combusted, natural gas is the lowest compared to other
fossil fuels at 117 lb CO2/MMBtu.112 113 The
average for coal is 216 lb CO2/MMBtu, but varies between 206
to 229 lb CO2/MMBtu by type (e.g., anthracite, lignite,
subbituminous, and bituminous).\114\ The value for petroleum products
such as diesel fuel and heating oil is 161 lb CO2/MMBtu.
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\112\ Natural gas is primarily CH4, which has a
higher hydrogen to carbon atomic ratio, relative to other fuels, and
thus, produces the least CO2 per unit of heat released.
In addition to a lower CO2 emission rate on a lb/MMBtu
basis, natural gas is generally converted to electricity more
efficiently than coal. According to EIA, the 2020 emissions rate for
coal and natural gas were 2.23 lb CO2/kWh and 0.91 lb
CO2/kWh, respectively. www.eia.gov/tools/faqs/faq.php?id=74&t=11.
\113\ Values reflect the carbon content on a per unit of energy
produced on a higher heating value (HHV) combustion basis and are
not reflective of recovered useful energy from any particular
technology.
\114\ Energy Information Administration (EIA). Carbon Dioxide
Emissions Coefficients. https://www.eia.gov/environment/emissions/co2_vol_mass.php.
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The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions and Sinks \115\ (the U.S. GHG Inventory) to comply with
commitments under the United Nations Framework Convention on Climate
Change (UNFCCC). This inventory, which includes recent trends, is
organized by industrial sectors. It presents total U.S. anthropogenic
emissions and sinks \116\ of GHGs, including CO2 emissions,
for the years 1990-2020.
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\115\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. https://cfpub.epa.gov/ghgdata.
\116\ Sinks are a physical unit or process that stores GHGs,
such as forests or underground or deep-sea reservoirs of carbon
dioxide.
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According to the latest inventory, in 2021, total U.S. GHG
emissions were 6,340 million metric tons of carbon dioxide equivalent
(MMT CO2e). The transportation sector (28.5 percent) was the
largest contributor to total U.S. GHG emissions, followed by the power
sector (25.0 percent) and industrial sources
[[Page 33260]]
(23.5 percent). In terms of annual CO2 emissions, the power
sector was responsible for 30.6 percent (1,541 MMT CO2e) of
the nation's 2021 total.
CO2 emissions from the power sector have declined by 36
percent since 2005 (when the power sector reached annual emissions of
2,400 MMT CO2, its historical peak to date).\117\ The
reduction in CO2 emissions can be attributed to the power
sector's ongoing trends away from carbon-intensive coal-fired
generation and toward more natural gas-fired and renewable sources. In
2005, CO2 emissions from coal-fired EGUs alone measured
1,983 MMT.\118\ This total dropped to 1,351 MMT in 2015 and reached 974
MMT in 2019, the first time since 1978 that coal-fired CO2
emissions were below 1,000 MMT. In 2020, emissions of CO2
from coal-fired EGUs measured 788 MMT before rebounding in 2021 to 909
MMT due to increased demand. By contrast, CO2 emissions from
natural gas-fired generation have almost doubled since 2005, increasing
from 319 MMT to 613 MMT in 2021, and CO2 emissions from
petroleum products (i.e., distillate fuel oil, petroleum coke, and
residual fuel oil) declined from 98 MMT in 2005 to 18 MMT in 2021.
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\117\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2020. https://cfpub.epa.gov/ghgdata/inventoryexplorer/#electricitygeneration/entiresector/allgas/category/all.
\118\ U.S. Energy Information Administration (EIA). Monthly
Energy Review, table 11.6. September 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/sec11.pdf.
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When the EPA finalized the Clean Power Plan (CPP) in October 2015,
the Agency projected that, as a result of the CPP, the power sector
would reduce its annual CO2 emissions to 1,632 MMT by 2030,
or 32 percent below 2005 levels (2,400 MMT).\119\ Instead, even in the
absence of Federal regulations for existing EGUs, annual CO2
emissions from sources covered by the CPP had fallen to 1,540 MMT by
the end of 2021, a nearly 36 percent reduction below 2005 levels. The
power sector achieved a deeper level of reductions than forecast under
the CPP and approximately a decade ahead of time. By the end of 2015,
several months after the CPP was finalized, those sources already had
achieved CO2 emission levels of 1,900 MMT, or approximately
21 percent below 2005 levels. However, progress in emission reductions
is not uniform across all states and so Federal policies play an
essential role. As discussed earlier in this section, the power sector
remains a leading emitter of CO2 in the U.S., and, despite
the emission reductions since 2005, current CO2 levels
continue to endanger human health and welfare. Further, as sources in
other sectors of the economy turn to electrification to decarbonize,
future CO2 reductions from fossil fuel-fired EGUs have the
potential to take on added significance and increased benefits.
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\119\ 80 FR 63662 (October 23, 2015).
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The Legislative, Market, and State Law Context
Recent Legislation Impacting the Power Sector
On November 15, 2021, President Biden signed the IIJA \120\ (also
known as the Bipartisan Infrastructure Law), which allocated more than
$65 billion in funding via grant programs, contracts, cooperative
agreements, credit allocations, and other mechanisms to develop and
upgrade infrastructure and expand access to clean energy technologies.
Specific objectives of the legislation are to improve the nation's
electricity transmission capacity, pipeline infrastructure, and
increase the availability of low-GHG fuels. Some of the IIJA programs
\121\ that will impact the utility power sector include: $16.5 billion
to build and upgrade the nation's electric grid; $6 billion in
financial support for existing nuclear reactors that are at risk of
closing and being replaced by high-emitting resources; and more than
$700 million for upgrades to the existing hydroelectric fleet. The IIJA
established the Carbon Dioxide Transportation Infrastructure Finance
and Innovation Program to provide flexible Federal loans and grants for
building CO2 pipelines designed with excess capacity,
enabling integrated carbon capture and geologic storage. The IIJA also
allocated $21.5 billion to fund new programs to support the
development, demonstration, and deployment of clean energy
technologies, such as $8 billion for the development of regional clean
hydrogen hubs. Other clean energy technologies with IIJA funding
include carbon capture, geologic sequestration, direct air capture,
grid-scale energy storage, and advanced nuclear reactors. States,
Tribes, local communities, utilities, and others are eligible to
receive funding.
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\120\ https://www.congress.gov/bill/117th-congress/house-bill/3684/text.
\121\ https://gfoaorg.cdn.prismic.io/gfoaorg/0727aa5a-308f-4ef0-addf-140fd43acfb5_BUILDING-A-BETTER-AMERICA-V2.pdf.
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The IRA, which President Biden signed on August 16, 2022,\122\ has
the potential for even greater impacts on the electric power sector.
With an estimated $369 billion in Energy Security and Climate Change
programs over the next 10 years, covering grant funding and tax
incentives, the IRA provides significant investments in non GHG-
emitting generation. For example, one of the conditions set by Congress
for the expiration of the Clean Electricity Production Tax Credits of
the IRA, found in section 13701, is a 75 percent reduction in GHG
emissions from the power sector below 2022 levels. The IRA also
contains the Low Emission Electricity Program (LEEP) with funding
provided to the EPA with the objective to reduce GHG emissions from
domestic electricity generation and use through promotion of
incentives, tools to facilitate action, and use of CAA regulatory
authority. In particular, CAA section 135, added by IRA section 60107,
requires the EPA to conduct an assessment of the GHG emission
reductions expected to occur from changes in domestic electricity
generation and use through fiscal year 2031 and, further, provides the
EPA $18 million ``to ensure that reductions in [GHG] emissions are
achieved through use of the existing authorities of [the Clean Air
Act], incorporating the assessment. . ..'' CAA section 135(a)(6).
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\122\ https://www.congress.gov/bill/117th-congress/house-bill/5376/text..
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The IRA's provisions also demonstrate an intent to support
development and deployment of low-GHG emitting technologies in the
power sector through a broad array of additional tax credits, loan
guarantees, and public investment programs. These provisions are aimed
at reducing emissions of GHGs from new and existing generating assets,
with tax credits for carbon capture, utilization, and storage (CCUS)
and clean hydrogen production providing a pathway for the use of coal
and natural gas as part of a low-GHG electricity grid. Finally, with
provisions such as the Methane Emissions Reduction Program, Congress
demonstrated a focus on the importance of actions to address methane
emissions from petroleum and natural gas systems.
To assist states and utilities in their decarbonizing efforts, and
most germane to these proposed rulemakings, the IRA increased the tax
credit incentives for capturing and storing CO2, including
from industrial sources, coal-fired steam generating units, and natural
gas-fired stationary combustion turbines. The increase in credit
values, found in section 13104 (which revises IRC section 45Q), is 70
percent, equaling $85/metric ton for CO2 captured and
securely stored in geologic formations and $60/metric ton for
CO2 captured and utilized or securely stored incidentally in
conjunction with
[[Page 33261]]
enhanced oil recovery (EOR).\123\ The CCUS incentives include 12 years
of credits that can be claimed at the higher credit value beginning in
2023 for qualifying projects. These incentives will significantly cut
costs and are expected to accelerate the adoption of CCS in the utility
power and other industrial sectors. Specifically for the power sector,
the IRA requires that a qualifying carbon capture facility have a
CO2 capture design capacity of not less than 75 percent of
the baseline CO2 production of the unit and that
construction must begin before January 1, 2033. Tax credits under 45Q
can be combined with other tax credits, in some circumstances, and with
State-level incentives, including California's low carbon fuel standard
which is a market-based program with fuel-specific carbon intensity
benchmarks.\124\ The magnitude of this incentive is driving investment
and announcements, evidenced by the increased number of permit
applications for geologic sequestration.
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\123\ 26 U.S.C. 45Q.
\124\ Global CCS Institute. (2019). The LCFS and CCS Protocol:
An Overview for Policymakers and Project Developers. Policy report.
https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf.
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The new provisions in section 13204 (IRC section 45V) codify
production tax credits for `clean hydrogen' as defined in the
provision. The value of the credits earned by a project is tiered (four
different tiers) and depends on the estimated GHG emissions of the
hydrogen production process from well-to-gate. The credits range from
$3/kg H2 for 0.0 to 0.45 kilograms of CO2-
equivalent emitted per kilogram of low-GHG hydrogen produced (kg
CO2e/kg H2) down to $0.6/kg H2 for 2.5
to 4.0 kg CO2e/kg H2 (assuming wage and
apprenticeship requirements are met). Projects with GHG emissions
greater than 4.0 kg CO2e/kg H2 are not eligible.
According to the DOE, current costs for hydrogen produced from
renewable energy are approximately $5/kg H2.\125\ These
production costs could decline by 2025 to between $2.5 and $2.7/kg
H2 (not including the production tax credits).\126\
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\125\ U.S. Department of Energy (DOE). Hydrogen and Fuel Cell
Technologies Office. Hydrogen Shot. https://www.energy.gov/eere/fuelcells/hydrogen-shot.
\126\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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The clean hydrogen production tax credit is expected to incentivize
the production of low-GHG hydrogen and ultimately exert downward
pressure on costs.\127\ Low-cost and widely available low-GHG hydrogen
has the potential to become a material decarbonization lever in the
power sector as the use of low-GHG hydrogen in stationary combustion
turbines reduces direct GHG emissions as hydrogen releases no
CO2 when combusted. The tiered eligibility requirements for
the clean hydrogen production tax credit also incentivize the lowest-
GHG emissions production processes.
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\127\ Larsen, J., King, B., Kolus, H., Dasari, N., Hiltbrand,
G., Herndon, W. (August 12, 2022). A Turning Point for US Climate
Progress: Assessing the Climate and Clean Energy Provisions in the
Inflation Reduction Act. Rhodium Group. https://rhg.com/research/climate-clean-energy-inflation-reduction-act/.
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Both IRC 45Q and 45V are eligible for additional provisions that
increase the value and usability of the credits. Certain tax-exempt
entities, such as electric co-ops, may use direct pay for the full 12-
or 10-year lifetime of the credits to monetize the credits directly as
cash refunds rather than through tax equity transactions. Tax-paying
entities may elect to have direct payment of 45Q or 45V credits for
five consecutive years. Tax-paying entities may also elect to transfer
credits to unrelated taxpayers, enabling direct monetization of the
credits again without relying on tax equity transactions.
The production tax credit is not the only provision in the IRA
designed to incentivize low-GHG hydrogen. Projects may also access an
investment tax credit (ITC) under IRC section 48. For example,
manufacturers of clean hydrogen production equipment, like
electrolyzers, may apply under IRC section 48C (the Advanced
Manufacturing Tax Credit). And the manufacturing facility for
electrolyzers could receive credits under section 48C while the
resulting hydrogen production facility could then earn credits under
section 45V (this form of stacking is allowed by statute). However, the
same project may not claim ITC credits under section 48C while claiming
PTC credits under section 45V. Projects may not generally combine
credits from IRC section 45V with credits in IRC section 45Q. Hydrogen
production tax credits became available in January 2023 for eligible
new projects. Entities that commence construction between 2023 and 2032
can claim credits for the first 10 years of production.
The magnitude of this incentive--combined with those in the IIJA
such as the $8 billion for regional hydrogen hubs and $1.5 billion for
electrolyzer advancement--should accelerate the production of low-GHG
hydrogen for use in a broad range of applications across many sectors,
including the utility power sector.\128\
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\128\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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Many of the IRA tax credit incentives are directed toward low- and
zero-emission electric generation. They are designed to lower costs and
market barriers to bring new zero-emitting generation and energy
storage capacity online, to retain existing zero-emitting generators,
and the energy efficiency tax credits are designed to reduce
electricity demand. These financial tools have been used historically
and shown to be a principal policy driver, buttressed by State
renewable and clean energy standards, for incentivizing deployment of
low- and zero-emitting generation.129 130
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\129\ Impacts of Federal Tax Credit Extensions on Renewable
Deployment and Power Sector Emissions, National Renewable Energy
Laboratory (NREL), February 2016.
\130\ A Retrospective Assessment of Clean Energy Investments in
the Recovery Act, February 2016, U.S. Executive Office of the
President, Memorandum.
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For example, the IRA expanded and extended the existing section
13101 (IRC section 45) production tax credits for new solar, wind,
geothermal, and other eligible zero- or low-GHG emissions energy
sources. The production tax credit (PTC) provides credits in a 10-year
stream for each MWh of clean energy produced. The IRA indexed the PTC
on inflation, increasing the credit amount to $27.50/MWh for facilities
meeting certain wage and apprenticeship requirements. For context, the
energy price in the nation's largest wholesale energy market, PJM,\131\
is typically between $20/MWh and $90/MWh depending on timing, load, and
transmission congestion.
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\131\ PJM Interconnection LLC (PJM) is a regional transmission
organization (RTO) serving all or parts of Delaware, Illinois,
Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina,
Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the
District of Columbia.
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In parallel, the existing investment tax credits in section 13101
(IRC section 48) were also expanded and extended in the IRA. Taxpayers
must elect between the ITC and the PTC for each applicable project. The
ITC enables taxpayers to recoup up to 30 percent of project costs for
technologies such as solar, geothermal, fiberoptic solar, fuel cells,
microturbines, small wind, offshore wind, combined heat and power
(CHP), and waste energy recovery for investments meeting certain wage
and apprenticeship requirements. There are also a range of bonus
credits available
[[Page 33262]]
if certain criteria are met, for example for meeting domestic content
and energy communities' requirements with each earning an additional 10
percent credit. The IRA expanded eligibility to include storage
technologies as well as some non-storage technologies.
The IRA also tied the availability of tax credits explicitly to
reductions of GHG emissions from the power sector. Sections 13701 and
13702 enacted technology-neutral production and investment tax credits
for projects placed in service after 2025 that have GHG emissions rates
of zero or less. These credits are available until the phaseout is
triggered when the power sector's GHG emissions fall below 25 percent
of 2022 levels.
Following State practices, Congress also included a zero-emission
nuclear power production credit in the IRA to ensure existing in-
service nuclear generators are retained for their contribution to base
load zero-carbon emitting electricity. When labor and apprenticeship
requirements are met, the credit price is $15/MWh. The credit amount
declines when gross receipts of services provided with electricity rise
above a specified level. The program begins in 2024 with credit streams
available for nine years. This PTC is complementary to the $6 billion
for nuclear advancements the IIJA authorized and appropriated to the
DOE. New nuclear plants, including small modular reactors, would be
eligible for either the technology-neutral Clean Electricity Production
or Investment Credit (IRC section 45Y and 48E).
In the evaluation of these proposed actions, many of the
technologies that receive investment under recent Federal legislation
are not directly considered, as the EPA has not evaluated the new
generation technologies that entities could employ as alternatives to
fossil fuel-fired EGUs in its assessment of the BSER. As the discussion
of that assessment will make clear later in this preamble, the EPA's
inquiry has focused on ``measures that improve the pollution
performance of individual sources.'' \132\ However, these overarching
incentives and policies are important context for this rulemaking.
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\132\ West Virginia v. EPA, 142 S. Ct. 2587, 2615 (2022).
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The following section (section IV.E.2) includes a review of
integrated resource plans (IRPs) filed by public utilities that
prioritize GHG reductions. IRPs demonstrate how utilities plan to meet
future forecasted energy demand while ensuring reliable and cost-
effective service. These IRPs demonstrate that most power companies
intend to meet their GHG reduction targets by retiring aging coal-fired
steam generating EGUs and replacing them with a combination of
renewable resources, energy storage, other non-emitting technologies,
and natural gas-fired combustion turbines. Many IRPs further
demonstrate the realization of power companies that to meet their GHG
reduction targets, their natural gas-fired assets will need to occupy a
much smaller GHG footprint through a combination of hydrogen, CCS, and
reduced utilization. The IRA is designed to encourage this trend. For
example, in addition to the provisions outlined above, including the 10
percent bonus value applied in `energy communities' that include
fossil-related properties, the IRA created grant and loan funding
sources for hard-to-abate energy assets. Section 22004 of the IRA
authorizes $9.7 billion in financing for rural electric co-operatives
and providers to invest in cleaner technologies to achieve GHG
reductions across rural electric systems while buttressing resilience
and reliability. Additionally, section 50144 of the IRA, known as the
Energy Infrastructure Reinvestment Financing provision, provides $5
billion for backing $250 billion in low-cost loans for utilities to
repower, repurpose, or replace existing infrastructure that has ceased
operations, or to enable operating energy infrastructure to reduce air
pollution or GHG emissions. The financing in this provision enables a
utility to repurpose an existing fossil site, such as a retired coal-
fired power plant, or add CCS, renewable generation, or hydrogen
capability to an operating coal- or natural gas-fired power plant and
retain community jobs while reducing GHG emissions.
2. Commitments by Utilities To Reduce GHG Emissions
The broad trends away from coal-fired generation and toward lower-
emitting generation are reflected in the recent actions and announced
plans of many utilities across the industry. As highlighted later in
this section, through planning documents, IRPs, filings with State and
local public utility commissions, and news releases, many utilities
have made public commitments to voluntarily cease operating coal-fired
generation and move toward zero- and low-GHG energy generation. Many
utilities and other power generators have announced plans to increase
their renewable energy holdings and continue reducing GHG emissions,
regardless of any potential Federal regulatory requirements. For
example, 50 power producers that are members of the Edison Electric
Institute have announced CO2 reduction goals, two-thirds of
which include net-zero carbon emissions by 2050.\133\ This trend is not
unique to the largest owner-operators of coal-fired EGUs; smaller
utilities, public power cooperatives, and municipal entities are also
contributing to these changes.
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\133\ See Comments of Edison Electric Institute to EPA's Pre-
Proposal Docket on Greenhouse Gas Regulations for Fossil Fuel-fired
Power Plants, Docket ID No. EPA-HQ-OAR-2022-0723, November 18, 2022
(``Fifty EEI members have announced forward-looking carbon reduction
goals, two-third of which include a net-zero by 2050 or earlier
equivalent goal, and members are routinely increasing the ambition
or speed of their goals or altogether transforming them into net-
zero goals.'').
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Some of the largest electric utilities that have publicly announced
near- and long-term GHG reduction commitments, many with emission
reduction targets of at least 80 percent (relative to 2005 levels
unless otherwise noted), include:
Xcel Energy: 80 percent reduction in CO2
emissions by 2030 and 100 percent carbon-free by 2050. This includes a
commitment to close or repower all remaining coal-fired EGUs by
2030.\134\
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\134\ Xcel Energy is based in Minnesota with operations in
Colorado, Michigan, New Mexico, North Dakota, South Dakota, Texas,
and Wisconsin. 2018 Integrated Resource Plan at https://www.xcelenergy.com/staticfiles/xe-responsive/Company/Rates%20&%20Regulations/Resource%20Plans/2018-SPS-NM-Integrated-Resource-Plan.pdf.
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DTE Energy: 65 percent reduction in CO2
emissions by 2028, 90 percent reduction by 2040, and net-zero carbon
emissions by 2050.\135\
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\135\ DTE Energy is based in Michigan. Our Bold Goal for
Michigan's Clean Energy Future at https://dtecleanenergy.com/.
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Ameren Energy: 60 percent reduction in CO2 by
2030, 85 percent reduction by 2040, and net-zero carbon emissions by
2045.\136\
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\136\ Ameren is based in Illinois and Missouri. 2022 Integrated
Resource Plan at https://www.ameren.com/missouri/company/environment-and-sustainability/integrated-resource-plan.
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Consumers Energy: 60 percent reduction in CO2
by 2025 and net-zero carbon emissions by 2040. This includes the
retirement of all coal-fired units by 2025.\137\
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\137\ Consumers Energy is based in Michigan. Integrated Resource
Plan at https://s26.q4cdn.com/888045447/files/doc_presentations/2021/06/2021-Integrated-Resource-Plan.pdf.
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Southern Company: 50 percent reduction in CO2
by 2030 (relative to 2007 levels) and net-zero carbon emissions by
2050.\138\
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\138\ Southern Company is based in Georgia with operations in
Alabama and Mississippi. https://www.southerncompany.com/sustainability/net-zero-and-environmental-priorities/net-zero-transition.html.
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Duke Energy: 70 percent reduction in CO2 by
2030 and net-zero carbon
[[Page 33263]]
emissions by 2050. All coal-fired units will retire by 2035.\139\
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\139\ Duke Energy is based in North Carolina with operations in
South Carolina, Florida, Indiana, Ohio, and Kentucky. NC IRP Fact
Sheet at https://p-scapi.duke-energy.com/-/media/pdfs/our-company/202296-nc-irp-fact-sheet.pdf.
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Minnesota Power (Allete Inc.): 70 percent renewable energy
by 2030, 80 percent reduction in CO2 and coal-free by 2035,
and 100 percent carbon-free by 2050.\140\
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\140\ Allete Energy is based in Minnesota with operations in
Wisconsin and North Dakota. Integrated Resource Plan at: https://www.edockets.state.mn.us/EFiling/edockets/searchDocuments.do?method=showPoup&documentId=%7b70795F77-0000-C41E-A71C-FD089119967C%7d&documentTitle=20212-170583-01.
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First Energy: 30 percent reduction in CO2 by
2030 (relative to 2019 levels) and net-zero carbon emissions by
2050.\141\
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\141\ First Energy is based in Ohio with operations in
Pennsylvania, West Virginia, and New Jersey. https://www.firstenergycorp.com/content/dam/environmental/files/climate-strategy.pdf.
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American Electric Power: 80 percent reduction in
CO2 by 2030 and net-zero carbon emissions by 2045.\142\
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\142\ American Electric Power (AEP) is based in Ohio with
operations in Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Oklahoma, Tennessee, Texas, Virginia, and West Virginia. Clean
Energy Future at https://www.aep.com/about/ourstory/cleanenergy.
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Alliant Energy: 50 percent reduction in CO2 by
2030 and net-zero carbon emissions by 2050; will retire final coal-
fired EGU by 2040.\143\
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\143\ Alliant Energy has operations in Iowa and Wisconsin. See
Our Sustainable Energy Plan at https://www.alliantenergy.com/cleanenergy/ourenergyvision/poweringwhatsnext/sustainableenergyplan.
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Tennessee Valley Authority: 70 percent reduction in
CO2 by 2030, 80 percent reduction by 2035, and net-zero
carbon emissions by 2050.\144\
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\144\ Tennessee Valley Authority (TVA) is based in Tennessee
with operations in Alabama, Georgia, Kentucky, Mississippi, North
Carolina, and Virginia. See https://www.tva.com/newsroom/press-releases/tva-charts-path-to-clean-energy-future.
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NextEra Energy: 70 percent reduction in CO2 by
2025, 82 percent reduction by 2030, 87 percent reduction by 2035, 94
percent reduction by 2040, and carbon-free by 2045.\145\
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\145\ NextEra Energy. See https://newsroom.nexteraenergy.com/2022-06-14-NextEra-Energy-sets-industry-leading-Real-Zero-TM-goal-to-eliminate-carbon-emissions-from-its-operations,-leverage-low-cost-renewables-to-drive-energy-affordability-for-customers.
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The geographic footprint of zero or net-zero carbon commitments
made by utilities, their parent companies, or in response to a State
clean energy requirement, covers portions of 47 states and includes 75
percent of U.S. customer accounts.\146\ These statements are often made
as part of long-term planning processes with considerable stakeholder
involvement, including regulators.
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\146\ Smart Electric Power Alliance Utility Carbon Tracker. See
https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/. Accessed January 12, 2023.
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3. State Actions To Reduce Power Sector GHG Emissions
States across the country have taken the lead in efforts to reduce
GHG emissions from the power sector. These actions include commitments
that require utilities to expand renewable and clean energy production
through the adoption of renewable portfolio standards (RPS) and clean
energy standards (CES), as well as other measures tailored to
decarbonize State power systems enacted in specific legislation.
Twenty-nine states and the District of Columbia have enforceable
RPS.\147\ RPS require a percentage of electricity that utilities sell
to come from eligible renewable sources like wind and solar rather than
from fossil fuel-based sources like coal and natural gas. Fifteen
states have RPS targets that are at or well above 50 percent. Eight of
these states--California, Illinois, Massachusetts, Maryland, Minnesota,
New Jersey, Nevada, and Oregon--have targets ranging from 50 percent to
just below 70 percent. Four states--Maine, New Mexico, New York, and
Vermont--have RPS targets greater than or equal to 70 percent but below
100 percent, and three states--Hawaii, Rhode Island, and Virginia plus
the District of Columbia--have 100 percent RPS requirements. Most of
these ambitious targets fall during the next decade. Ten states and the
District of Columbia have final targets that mature between 2025 and
2033, while the remaining five states impose peak requirements between
2040 and 2050. Resources that are eligible under an RPS vary by State
and are determined by the State's existing energy production and
possibility for renewable energy development. For example, Colorado's
RPS includes a range of resources such as solar, wind, emissions-
neutral coal mine methane and other sources as qualifying renewable
energy sources. Hawaii's includes, but is not limited to, solar, wind,
and energy produced from falling water, ocean water, waves, and water
currents. RPS in some other states include landfill gas, animal wastes,
CHP, and energy efficiency.\148\
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\147\ DSIRE, Renewable Portfolio Standards and Clean Energy
Standards (2022). https://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2022/11/RPS-CES-Nov2022.pdf.
\148\ NCSL (2021). State Renewable Portfolio Standards and
Goals. https://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.
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States are also shifting their generating fleets away from fossil
fuel generating resources through the adoption of CES. A CES requires a
percentage of retail electricity to come from sources that are defined
as clean. Unlike an RPS, which defines eligible generation in terms of
the renewable attributes of its energy source, CES eligibility is based
on the GHG emission attributes of the generation itself, typically with
a zero or net-zero carbon emissions requirement. Twenty-one states have
adopted some form of clean energy requirement or goal with 17 of those
states setting 100 percent targets. In nearly all cases, the CES
applies in addition to the State's other RPS requirements. Seven
states, including California, Colorado, Minnesota, New York,
Washington, Oregon, and Arizona, have a zero or net-zero carbon
emissions requirement with most target dates falling in 2040, 2045, or
2050. Two states--New Mexico and Massachusetts--have 80 percent clean
energy requirements that must be met in 2045 and 2050, respectively.
Ten additional states, including Connecticut, New Jersey, Nevada,
Wisconsin, Illinois, Maine, North Carolina, Nebraska, Louisiana, and
Michigan, have 100 percent clean energy goals with target dates falling
in either 2040 or 2050. Like an RPS, CES resource eligibility can vary
from State to State. One key difference between an RPS and a CES is the
extent to which a CES can allow for resources like nuclear and CCS-
enabled coal and natural gas, which are not renewable but have low or
zero direct GHG emission attributes that make them CES eligible.
In addition, states across the U.S. have announced specific
legislation aimed at reducing GHG emissions. In California, Senate Bill
32, passed in 2016, was a landmark legislation that requires California
to reduce its economy-wide GHG emissions to 1990 levels by 2020, 40
percent below 1990 levels by 2030, and 80 percent below 1990 levels by
2050. Senate Bill 100, passed in 2018, requires California to procure
60 percent of all electricity from renewable sources by 2030 and plan
for 100 percent from carbon-free sources by 2045. Senate Bills 605 and
1383, passed in 2016, require a reduction in emissions of short-lived
climate pollutants like methane by 40 to 50 percent below 2013 levels
by 2030.\149\ Achieving California's established goal
[[Page 33264]]
of carbon-free electricity by 2045 requires emissions to be balanced by
carbon sequestration, capture, or other technologies. Senate Bill 905,
passed in 2022, requires the California Air Resources Board to
establish programs for permitting CCS projects.\150\ Senate Bill 905,
also passed in 2022, prevents the use of captured CO2 for
enhanced oil recovery within California.
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\149\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
\150\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
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In New York, The Climate Leadership and Community Protection Act,
passed in 2019, sets several climate targets. The most important goals
include an 85 percent reduction in GHG emissions by 2050, 100 percent
zero-emission electricity by 2040, and 70 percent renewable energy by
2030. Other targets include 9,000 MW of offshore wind by 2035, 3,000 MW
of energy storage by 2030, and 6,000 MW of solar by 2025.\151\
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\151\ New York State. Our Progress. https://climate.ny.gov/Our-Progress.
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Washington State's Climate Commitment Act sets a target of reducing
GHG emissions by 95 percent by 2050. The State is required to reduce
emissions to 1990 levels by 2020, 45 percent below 1990 levels by 2030,
70 percent below 1990 levels by 2040, and 95 percent below 1990 levels
by 2050. This also includes achieving net-zero emissions by 2050.\152\
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\152\ Department of Ecology Washington State. Greenhouse Gases.
https://ecology.wa.gov/Air-Climate/Climate-change/Tracking-greenhouse-gases.
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In addition to the prevalence of State RPS and CES programs
outlined above, several states developed regulatory programs to retain
nuclear power plants to preserve the significant amount of zero-
emission output the plants provide, especially as many nuclear plants
face downward economic pressures resulting from ultra-low natural gas
spot prices combined with increasing NGCC capacity. Between 2016 and
2021, New York, New Jersey, Connecticut, and Illinois took action to
retain their nuclear power stations by providing State-level financial
incentives. Retention of nuclear power plants is another strategy that
some states have used to ensure an increasing market share for zero-
emission electricity generation. As discussed earlier, the IRA included
a zero-emission nuclear power production credit in section 13105, also
referred to as IRC section 45U.\153\
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\153\ https://uscode.house.gov/view.xhtml?req=(title:26%20section:45U%20edition:prelim).
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In the past two years, State actions have generally increased their
decarbonization ambitions. For example, legislation in Illinois and
North Carolina requires a transition away from GHG-emitting generation.
Illinois' Climate and Equitable Jobs Act, which became law on September
25, 2021, requires all private coal-fired or oil-fired power plants to
reach zero carbon emissions by 2030, municipal coal-fired plants to
reach zero carbon emissions by 2045, and natural gas-fired plants to
reach zero carbon emissions by 2045.\154\ On October 13, 2021, North
Carolina passed House Bill 951 that required the North Carolina
Utilities Commission to ``take all reasonable steps to achieve a
seventy percent (70%) reduction in emissions of carbon dioxide
(CO2) emitted in the State from electric generating
facilities owned or operated by electric public utilities from 2005
levels by the year 2030 and carbon neutrality by the year 2050.'' \155\
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\154\ State of Illinois General Assembly. Public Act 102-0662:
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
\155\ General Assembly of North Carolina, House Bill 951 (2021).
https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf.
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1. Projections of Power Sector Trends
Projections for the U.S. power sector--based on the landscape of
market forces in addition to the known actions of Congress, utilities,
and states--have indicated that the ongoing transition will continue
for specific fuel types and EGUs. The EPA's Power Sector Modeling
Platform v6 Using the Integrated Planning Model post-IRA 2022 reference
case (i.e., the EPA's projections of the power sector, which includes
representation of the IRA absent further regulation), provides
projections out to 2050 on future outcomes of the electric power
sector. For more information on the details of this modeling, see the
model documentation.\156\
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\156\ U.S. Environmental Protection Agency. Post-IRA 2022
Reference Case EPA's Power Sector Modeling Platform v6 Using IPM.
April 2023. https://www.epa.gov/power-sector-modeling/post-ira-2022-reference-case.
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Since the passage of the IRA in August 2022, the EPA has engaged
with many external partners, including other governmental entities,
academia, non-governmental organizations (NGOs), and industry, to
understand the impacts that the IRA will have on power sector GHG
emissions. In addition to engaging in several workgroups, the EPA has
contributed to two separate journal articles that include multi-model
comparisons of IRA impacts across several state-of-the-art models of
the U.S. energy system and electricity sector 157 158 and
participated in public events exploring modeling assumptions for the
IRA.\159\ The EPA plans to continue collaborating with stakeholders,
conducting external engagements, and using information gathered to
refine modeling of the IRA. As such, the EPA is soliciting comment on
power sector modeling of the IRA, including the assumptions and
potential impacts, including assumptions about growth in electric
demand, rates at which renewable generation can be built, and cost and
performance assumptions about all relevant technologies, including
carbon capture, renewables, energy storage and other generation
technologies.
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\157\ Bistline, et al. (2023). ``Emissions and Energy System
Impacts of the Inflation Reduction Act of 2022,'' Under Review.
\158\ Bistline, et al. (2023). ``Power Sector Impacts of the
Inflation Reduction Act of 2022,'' In Preparation.
\159\ Resource for the Future (2023). ``Future Generation:
Exploring the New Baseline for Electricity in the Presence of the
Inflation Reduction Act.'' https://www.rff.org/events/rff-live/future-generation-exploring-the-new-baseline-for-electricity-in-the-presence-of-the-inflation-reduction-act/.
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While much of the discussion below focuses on the EPA's post-IRA
2022 reference case, many other analyses show similar trends,\160\ and
these trends are consistent with utility IRPs and public GHG reduction
commitments, as well as State actions, both of which were described in
the previous sections.
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\160\ A wide variety of modeling teams have assessed baselines
with IRA. The baseline estimated here is generally in line with
these other estimates. Bistline, et al. (2023). ``Power Sector
Impacts of the Inflation Reduction Act of 2022,'' In Preparation.
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1. Projections for Coal-Fired Generation
In the post-IRA 2022 reference case, coal-fired steam EGU capacity
is projected to fall from 210 GW in 2021 \161\ to 44 GW in 2035, of
which 11 GW includes retrofit CCS. Generation from coal-fired steam
generating units is projected to also fall from 898 thousand GWh in
2021 \162\ to 120 thousand GWh by 2035. This change in generation
reflects the anticipated continued decline in projected coal-fired
steam generating unit capacity as well as a steady decline in annual
operation of those EGUs that remain online, with capacity factors
falling from approximately 41 percent in 2021 to 15 percent in 2035. By
2050, coal-fired steam generating unit capacity is projected to
diminish further, with only 10 GW, or less than 5 percent of 2021
[[Page 33265]]
capacity (and approximately 3 percent of the 2010 capacity), still in
operation across the continental U.S. These projections are driven by
the eroding economic opportunities for coal-fired steam generating
units to operate, the continued aging of the fleet of coal-fired steam
generating units, and the continued availability and expansion of low-
cost alternatives, like natural gas, renewable technologies, and energy
storage.
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\161\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 4.3. November 2022. https://www.eia.gov/electricity/annual/.
\162\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
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In 2020, there was a total of 1,439 million metric tons of
CO2 from the power sector with coal-fired sources
contributing to over half of those emissions. In the post-IRA 2022
reference case, power sector related CO2 emission are
projected to fall to 608 million metric tons by 2035, of which 8
percent is projected to come from coal-fired sources in 2035.
2. Projections for Natural Gas-Fired Generation
As described in the post-IRA 2022 reference case, natural gas-fired
capacity is expected to continue to buildout during the next decade
with 61 GW of new capacity projected to come online by 2035 and 309 GW
of new capacity by 2050. By 2035, the new natural gas capacity is
comprised of 24 GW of simple cycle combustion turbines and 37 GW of
combined cycle combustion turbines. By 2050, most of the incremental
new capacity is projected to come just from simple cycle combustion
turbines. This also represents a higher rate of new simple cycle
combustion turbine builds compared to the reference periods (i.e.,
2000-2006 and 2007-2021) discussed previously in this section.
It should be noted that despite this increase in capacity, both
overall generation and emissions from the natural gas-fired capacity
are projected to decline. Generation from natural gas units is
projected to fall from 1,579 thousand GWh in 2021 \163\ to 1,402
thousand GWh by 2035. Power sector related CO2 emissions
from natural gas-fired EGUs were 615 million metric tons in 2021.\164\
By 2035, emission levels are projected to reach 527 million metric
tons, 93 percent of which comes from NGCC sources.
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\163\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
\164\ U.S. Environmental Protection Agency, Inventory of U.S.
Greenhouse Gas Emission Sources and Sinks. February 2023. https://www.epa.gov/system/files/documents/2023-02/US-GHG-Inventory-2023-Main-Text.pdf.
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The decline in generation and emissions is driven by a projected
decline in NGCC capacity factors. In model projections, NGCC units have
a capacity factor early in the projection period of 64 percent, but by
2035, capacity factor projections fall to 50 percent as many of these
units switch from base load operation to more intermediate load
operation to support the integration of variable renewable energy
resources. Natural gas simple cycle combustion turbine capacity factors
also fall, although since they are used primarily as a peaking resource
and their capacity factors are already below 10 percent annually, their
impact on generation and emissions changes are less notable.
Some of the reasons for this continued growth in natural gas-fired
capacity include anticipated sustained lower fuel costs and the greater
efficiency and flexibility offered by combustion turbines. Simple cycle
combustion turbines operate at lower efficiencies but offer fast
startup times to meet peaking load demands. In addition, combustion
turbines, along with energy storage technologies, support the expansion
of renewable electricity by meeting demand during peak periods and
providing flexibility around the variability of renewable generation
and electricity demand. In the longer term, as renewables and battery
storage grow, they are anticipated to outcompete the need for natural
gas-fired generation and the overall utilization of natural gas-fired
capacity is expected to decline.
3. Projections for Renewable Generation
The EIA's Short-Term Energy Outlook (STEO) suggests that the U.S.
will continue its expansion of wind and solar renewable capacity with
most of the growth in electricity capacity additions in the next 2
years to come from renewable energy sources.\165\ The EIA projects
utility-scale solar capacity to grow by approximately 29 GW in 2023 and
by 35 GW in 2024 wind generating capacity to grow by 7 GW in 2023 and
by 7.5 GW in 2024. These increases in new renewable capacity will
continue to reduce the demand for fossil fuel-fired generation.
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\165\ U.S. Energy Information Administration (EIA). Short-Term
Energy Outlook, March 2023. https://www.eia.gov/outlooks/steo/.
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In the post-IRA 2022 reference case projections, shows that this
short-term trend in renewable capacity is expected to continue. Non-
hydroelectric utility-scale renewable capacity is projected to increase
from 209 GW in 2021 to 668 GW by 2035 and then to 1,293 GW by 2050.
This capacity growth is comprised mostly of wind and solar. The post-
IRA 2022 reference case shows projections of 399 GW of wind capacity by
2035 and 748 GW by 2050. Utility-scale solar capacity has a similar
trajectory with 263 GW by 2035 and 539 GW by 2050 and small-scale or
distributed solar capacity (e.g., rooftop solar) similarly increases
from 33 GW in 2021 to 198 GW in 2050.\166\ In total, non-hydroelectric
utility-scale renewable generation is projected to produce 45 percent
of electricity generation by 2035 in the post-IRA 2022 reference case.
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\166\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 4.3. November 2022. https://www.eia.gov/electricity/annual/.
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4. Projections for Energy Storage
According to EIA, the capacity of battery energy storage is
expected to increase by 10 times between 2019 and 2023, of which 6 GW
of battery storage capacity is planned to be co-located with solar
generation.\167\ The benefit of paring energy storage systems with
solar capacity deployment is that the batteries can recharge throughout
the middle of the day when surplus energy is available. Then this
stored energy can be discharged during peak hours, supporting grid
reliability and potentially displacing higher emitting generation. This
also reduces curtailment of renewable energy when generation exceeds
demand.
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\167\ U.S. Energy Information Administration (EIA). Preliminary
Monthly Electric Generator Inventory, December 2020 Form EIA-860M.
https://www.eia.gov/analysis/studies/electricity/batterstorage/.
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The build out of energy storage is projected to continue in the
long-term, enabling the integration of renewable technologies with
lower emission consequences. The post-IRA 2022 reference case shows
projections of 97 GW of energy storage to be available on the grid by
2035 and 152 GW by 2050.
5. Projections for Nuclear Energy
The post-IRA 2022 reference case shows a steady decline in nuclear
generating capacity, dropping from 96 GW in 2021 to 84 GW or by 12
percent by 2035. In the short-term, capacity reductions are expected to
be delayed in part due to programs passed as part of the IIJA and IRA.
These acts, along with several State programs, support the continued
use of existing nuclear facilities by providing payments that
[[Page 33266]]
will likely keep reactors in affected regions profitable for the next
5-10 years.168 169 After 2035, the EPA projects nuclear
capacity retirements to occur as EGUs begin to age out of operation,
and by 2050, the nuclear fleet is projected to reduce by more than
half, to 45 GW. However, breakthrough technologies like small modular
reactors, if successful, could result in higher levels of nuclear
capacity than discussed here. For example, output from advanced nuclear
generation could range from negligible to as high as 3,600 terawatt-
hours per year by 2050.\170\
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\168\ ``Constellation Making Major Investments in Two Illinois
Nuclear Plants to Increase Clean Energy Output.'' Constellation
Energy Corporation. February 21, 2023. https://www.constellationenergy.com/newsroom/2023/Constellation-Making-Major-Investment-in-Two-Illinois-Nuclear-Plants-to-Increase-Clean-Energy-Output.html.
\169\ Singer, S. (February 22, 2023). PSEG to consider nuclear
plant investments, capitalizing on the IRA's production tax credits,
CEO says. Utility Dive. https://www.utilitydive.com/news/pseg-ira-nuclear-production-tax-credits/643221/.
\170\ ``Advancing Nuclear Energy Evaluating Deployment,
Investment, and Impact in America's Clean Energy Future''
Breakthrough Institute, July 6, 2022.
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V. Statutory Background and Regulatory History for CAA Section 111
A. Statutory Authority To Regulate GHGs From EGUs Under CAA Section 111
The EPA's authority for and obligation to issue these proposed
rules is CAA section 111, which establishes mechanisms for controlling
emissions of air pollutants from new and existing stationary sources.
CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a
list of categories of stationary sources that the Administrator, in his
or her judgment, finds ``causes, or contributes significantly to, air
pollution which may reasonably be anticipated to endanger public health
or welfare.'' The EPA has the authority to define the scope of the
source categories, determine the pollutants for which standards should
be developed, and distinguish among classes, types, and sizes within
categories in establishing the standards.
1. Regulation of Emissions From New Sources
Once the EPA lists a source category, the EPA must, under CAA
section 111(b)(1)(B), establish ``standards of performance'' for
emissions of air pollutants from new sources (including modified and
reconstructed sources) in the source category. Under CAA section
111(a)(2), a ``new source'' is defined as ``any stationary source, the
construction or modification of which is commenced after the
publication of regulations (or, if earlier, proposed regulations)
prescribing a standard of performance under this section, which will be
applicable to such source.'' Under CAA section 111(a)(3), a
``stationary source'' is defined as ``any building, structure,
facility, or installation which emits or may emit any air pollutant.''
Under CAA section 111(a)(4), ``modification'' means any physical change
in, or change in the method of operation of, a stationary source which
increases the amount of any air pollutant emitted by such source or
which results in the emission of any air pollutant not previously
emitted. While this provision treats modified sources as new sources,
EPA regulations also treat a source that undergoes ``reconstruction''
as a new source. Under the provisions in 40 CFR 60.15,
``reconstruction'' means the replacement of components of an existing
facility such that: (1) The fixed capital cost of the new components
exceeds 50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility; and (2) it is
technologically and economically feasible to meet the applicable
standards. Pursuant to CAA section 111(b)(1)(B), the standards of
performance or revisions thereof shall become effective upon
promulgation.
The standards of performance for new sources are referred to as new
source performance standards, or NSPS. The NSPS are national
requirements that apply directly to the sources subject to them.
In setting or revising a performance standard, CAA section
111(a)(1) provides that performance standards are to reflect ``the
degree of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the cost
of achieving such reduction and any nonair quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' The term ``standard of
performance'' in CAA 111(a)(1) makes clear that the EPA is to determine
both the ``best system of emission reduction . . . adequately
demonstrated'' (BSER) for the regulated sources in the source category
and the ``degree of emission limitation achievable through the
application of the [BSER].'' West Virginia v. EPA, 142 S. Ct. 2587,
2601 (2022). To determine the BSER, the EPA first identifies the
``system[s] of emission reduction'' that are ``adequately
demonstrated,'' and then determines the ``best'' of those systems,
``taking into account'' factors including ``cost,'' ``nonair quality
health and environmental impact,'' and ``energy requirements.'' The EPA
then derives from that system an ``achievable'' ``degree of emission
limitation.'' The EPA must then, under CAA section 111(b)(1)(B),
promulgate ``standard[s] for emissions''--the NSPS--that reflect that
level of stringency.
2. Regulation of Emissions From Existing Sources
When the EPA establishes a standard for emissions of an air
pollutant from new sources within a category, it must also, under CAA
section 111(d), regulate emissions of that pollutant from existing
sources within the same category, unless the pollutant is regulated
under the National Ambient Air Quality Standards (NAAQS) program, under
CAA sections 108-110, or the National Emission Standards for Hazardous
Air Pollutants (NESHAP) program, under CAA section 112. See CAA section
111(d)(1)(A)(i) and (ii); West Virginia, 142 S. Ct. at 2601.
CAA section 111(d) establishes a framework of ``cooperative
federalism for the regulation of existing sources.'' American Lung
Ass'n, 985 F.3d at 931. CAA sections 111(d)(1)(A)-(B) require ``[t]he
Administrator . . . to prescribe regulations'' that require ``[e]ach
state . . . to submit to [EPA] a plan . . . which establishes standards
of performance for any existing stationary source for'' the air
pollutant at issue, and which ``provides for the implementation and
enforcement of such standards of performance.'' CAA section 111(a)(6)
defines an ``existing source'' as ``any stationary source other than a
new source.''
To meet these requirements, the EPA promulgates ``emission
guidelines'' that identify the BSER and the degree of emission
limitation achievable through the application of the BSER. Each State
must then establish standards of performance for its sources that
reflect that level of stringency. However, the states need not compel
regulated sources to adopt the particular components of the BSER
itself. The EPA's emission guidelines must also permit a State, ``in
applying a standard of performance to any particular source,'' to
``take into consideration, among other factors, the remaining useful
life of the existing source to which such standard applies.'' 42 U.S.C.
7411(d)(1). Once a State receives the EPA's approval of its plan, the
provisions in the plan become federally enforceable against the source,
in the same manner as the provisions of an approved State
Implementation Plan (SIP) under the Act. If a State elects not to
submit a plan or submits a plan that
[[Page 33267]]
the EPA does not find ``satisfactory,'' the EPA must promulgate a plan
that establishes Federal standards of performance for the State's
existing sources. CAA section 111(d)(2)(A).
3. EPA Review of Requirements
CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years, review and, if appropriate, revise'' new source performance
standards. However, the Administrator need not review any such standard
if the ``Administrator determines that such review is not appropriate
in light of readily available information on the efficacy'' of the
standard. Id. When conducting a review of an NSPS, the EPA has the
discretion and authority to add emission limits for pollutants or
emission sources not currently regulated for that source category. CAA
section 111 does not by its terms require the EPA to review emission
guidelines for existing sources, but the EPA retains the authority to
do so. See 81 FR 59276, 59277 (August 29, 2016) (explaining legal
authority to review emission guidelines for municipal solid waste
landfills).
B. History of EPA Regulation of Greenhouse Gases From Electricity
Generating Units Under CAA Section 111 and Caselaw
The EPA has listed more than 60 stationary source categories under
CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb-OOOO. In
1971, the EPA listed fossil fuel-fired EGUs (which includes natural
gas, petroleum, and coal) that use steam-generating boilers in a
category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31,
1971) (listing ``fossil fuel-fired steam generators of more than 250
million Btu per hour heat input''). In 1977, the EPA listed fossil
fuel-fired combustion turbines, which can be used in EGUs, in a
category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3,
1977) (listing ``stationary gas turbines'').
In 2015, the EPA promulgated two rules that addressed
CO2 emissions from fossil fuel-fired EGUs. The first
promulgated standards of performance for new fossil fuel-fired EGUs.
``Standards of Performance for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units; Final Rule,'' (80 FR 64510; October 23, 2015) (2015
NSPS). The second promulgated emission guidelines for existing sources.
``Carbon Pollution Emission Guidelines for Existing Stationary Sources:
Electric Utility Generating Units; Final Rule,'' (80 FR 64662; October
23, 2015) (Clean Power Plan, or CPP).
1. 2015 NSPS
In 2015, the EPA promulgated an NSPS to limit emissions of GHGs,
manifested as CO2, from newly constructed, modified, and
reconstructed fossil fuel-fired electric utility steam generating
units, i.e., utility boilers and IGCC EGUs, and newly constructed and
reconstructed stationary combustion turbine EGUs. These final standards
are codified in 40 CFR part 60, subpart TTTT.
In promulgating the NSPS for newly constructed fossil fuel-fired
steam generating units, the EPA determined the BSER to be a new, highly
efficient, supercritical pulverized coal (SCPC) EGU that implements
post-combustion partial CCS technology. The EPA concluded that CCS was
adequately demonstrated (including being technically feasible) and
widely available and could be implemented at reasonable cost. The EPA
identified natural gas co-firing and IGCC technology (either with
natural gas co-firing or implementing partial CCS) as alternative
methods of compliance.
The 2015 NSPS included standards of performance for steam
generating units that undergo a ``reconstruction'' as well as units
that implement ``large modifications,'' (i.e., modifications resulting
in an increase in hourly CO2 emissions of more than 10
percent). The 2015 NSPS did not establish standards of performance for
steam generating units that undertake ``small modifications'' (i.e.,
modifications resulting in an increase in hourly CO2
emissions of less than or equal to 10 percent), due to the limited
information available to inform the analysis of a BSER and
corresponding standard of performance.
The 2015 NSPS also finalized standards of performance for newly
constructed and reconstructed stationary combustion turbine EGUs. For
newly constructed and reconstructed base load natural gas-fired
stationary combustion turbines, the EPA finalized a standard based on
efficient NGCC technology as the BSER. For newly constructed and
reconstructed non-base load natural gas-fired stationary combustion
turbines and for both base load and non-base load multi-fuel-fired
stationary combustion turbines, the EPA finalized a heat input-based
standard based on the use of lower emitting fuels (referred to as clean
fuels in the 2015 NSPS). The EPA did not promulgate final standards of
performance for modified stationary combustion turbines due to lack of
information. These standards remain in effect today.
The EPA received six petitions for reconsideration of the 2015
NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the
petitions on the basis they did not satisfy the statutory conditions
for reconsideration under CAA section 307(d)(7)(B), and deferred action
on one petition that raised the issue of the treatment of biomass.
Multiple parties also filed petitions for judicial review of the
2015 NSPS in the D.C. Circuit. These cases have been briefed and, on
the EPA's motion, are being held in abeyance while the Agency reviews
the rule and considers whether to propose revisions to it.
In the 2015 NSPS, the EPA noted that it was authorized to regulate
GHGs from the fossil fuel-fired EGU source categories because it had
listed those source categories under CAA section 111(b)(1)(A). The EPA
added that CAA section 111 did not require it to make a determination
that GHGs from EGUs contribute significantly to dangerous air pollution
(a pollutant-specific significant contribution finding), but in the
alternative, the EPA did make that finding. It explained that
``[greenhouse gas] air pollution may reasonably be anticipated to
endanger public health or welfare,'' 80 FR 64530 (October 23, 2015) and
emphasized that power plants are ``by far the largest emitters'' of
greenhouse gases among stationary sources in the U.S. Id. at 64522. In
American Lung Ass'n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court
held that even if the EPA were required to determine that
CO2 from fossil fuel-fired EGUs contributes significantly to
dangerous air pollution--and the court emphasized that it was not
deciding that the EPA was required to make such a pollutant-specific
determination--the determination in the alternative that the EPA made
in the 2015 NSPS was not arbitrary and capricious and, accordingly, the
EPA had a sufficient basis to regulate greenhouse gases from EGUs under
CAA section 111(d) in the ACE Rule. The EPA is not reopening or
soliciting comment on any of those determinations in the 2015 NSPS
concerning its rational basis to regulate GHG emissions from EGUs or
its alternative finding that GHG emissions from EGUs contribute
significantly to dangerous air pollution.
2. 2018 Proposal To Revise the 2015 NSPS
In 2018, the EPA proposed to revise the NSPS for new, modified, and
reconstructed fossil fuel-fired steam generating units and IGCC units.
``Review of Standards of Performance
[[Page 33268]]
for Greenhouse Gas Emissions From New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units; Proposed Rule,''
(83 FR 65424; December 20, 2018) (2018 NSPS Proposal). The EPA proposed
to revise the NSPS for newly constructed units, based on a revised BSER
of a highly efficient SCPC, without partial CCS. The EPA also proposed
to revise the NSPS for modified and reconstructed units. The EPA has
not taken further action on this proposed rule.\171\
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\171\ In the 2018 NSPS Proposal, the EPA solicited comment on
whether it is required to make a determination that GHGs from a
source category contribute significantly to dangerous air pollution
as a predicate to promulgating a NSPS for GHG emissions from that
source category for the first time. 83 FR 65432 (December 20, 2018).
The EPA subsequently issued a final rule that provided that it would
not regulate GHGs under CAA section 111 from a source category
unless the GHGs from the category exceed 3 percent of total U.S. GHG
emissions, on grounds that GHGs emitted in a lesser amount do not
contribute significantly to dangerous air pollution. 86 FR 2652
(January, 13 2021). Shortly afterwards, the D.C. Circuit granted an
unopposed motion by the EPA for voluntary vacatur and remand of the
final rule. California v. EPA, No. 21-1035, doc. 1893155 (D.C. Cir.
April 5, 2021).
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3. Clean Power Plan
With the promulgation of the 2015 NSPS, the EPA also incurred a
statutory obligation under CAA section 111(d) to issue emission
guidelines for GHG emissions from existing fossil fuel-fired steam
generating EGUs and stationary combustion turbine EGUs, which the EPA
initially fulfilled with the promulgation of the CPP. See 80 FR 64662
(October 23, 2015). The EPA first determined that the BSER included
three types of measures: (1) Improving heat rate (i.e., the amount of
fuel that must be burned to generate a unit of electricity) at coal-
fired steam plants; (2) substituting increased generation from lower-
emitting NGCC plants for generation from higher-emitting steam plants
(which are primarily coal-fired); and (3) substituting increased
generation from new renewable energy sources for generation from fossil
fuel-fired steam plants and combustion turbines. See 80 FR 64667
(October 23, 2015). The latter two measures are known as ``generation
shifting'' because they involve shifting electricity generation from
higher-emitting sources to lower-emitting ones. See 80 FR 64728-29
(October 23, 2015).
The EPA based this BSER determination on a technical record that
evaluated generation-shifting, including its cost-effectiveness,
against the relevant statutory criteria for BSER and on a legal
interpretation that the term ``system'' in CAA section 111(a)(1) is
sufficiently broad to encompass shifting of generation from higher-
emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015).
The EPA then determined the ``degree of emission limitation achievable
through the application of the [BSER],'' CAA section 111(a)(1),
expressed as emission performance rates. See 80 FR 64667 (October 23,
2015). The EPA explained that a State would ``have to ensure, through
its plan, that the emission standards it establishes for its sources
individually, in the aggregate, or in combination with other measures
undertaken by the [S]tate, represent the equivalent of'' those
performance rates (80 FR 64667; October 23, 2015). Neither states nor
sources were required to apply the specific measures identified in the
BSER (80 FR 64667; October 23, 2015), and states could include trading
or averaging programs in their State plans for compliance. See 80 FR
64840 (October 23, 2015).
Numerous states and private parties petitioned for review of the
CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme
Court stayed the rule pending review, West Virginia v. EPA, 577 U.S.
1126 (2016), and the D.C. Circuit held the litigation in abeyance, and
ultimately dismissed it, as the EPA reassessed its position. American
Lung Ass'n, 985 F.3d at 937.
4. The CPP Repeal and ACE Rule
In 2019, the EPA repealed the CPP and replaced it with the ACE
Rule. In contrast to its interpretation of CAA section 111 in the CPP,
in the ACE Rule the EPA determined that the statutory ``text and
reasonable inferences from it'' make ``clear'' that a ``system'' of
emission reduction under CAA section 111(a)(1) ``is limited to measures
that can be applied to and at the level of the individual source,'' (84
FR 32529; July 8, 2019); that is, the system must be limited to control
measures that could be applied at and to each source to reduce
emissions at each source. See 84 FR 32523-24 (July 8, 2019).
Specifically, the ACE Rule argued that the requirements in CAA sections
111(d)(1), (a)(3), and (a)(6), that each State establish a standard of
performance ``for'' ``any existing source,'' defined, in general, as
any ``building . . . [or] facility,'' and the requirement in CAA
section 111(a)(1) that the degree of emission limitation must be
``achievable'' through the ``application'' of the BSER, by their terms,
impose this limitation. The EPA concluded that generation shifting is
not such a control measure. See 84 FR 32546 (July 8, 2019). Based on
its view that the CPP was a ``major rule,'' the EPA further determined
that, absent ``a clear statement from Congress,'' the term ```system of
emission reduction''' should not be read to encompass ``generation-
shifting measures.'' See 84 FR 32529 (July 8, 2019). The EPA
acknowledged, however, that ``[m]arket-based forces ha[d] already led
to significant generation shifting in the power sector,'' (84 FR 32532;
July 8, 2019), and that there was ``likely to be no difference between
a world where the CPP is implemented and one where it is not.'' See 84
FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal
of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units, 2-1 to 2-
5.\172\
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\172\ https://www.epa.gov/sites/default/files/2019-06/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf.
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In addition, the EPA promulgated in the ACE Rule a new set of
emission guidelines for existing coal-fired steam-generating EGUs. See
84 FR 32532 (July 8, 2019). In light of ``the legal interpretation
adopted in the repeal of the CPP,'' (84 FR 32532; July 8, 2019)--which
``limit[ed] `standards of performance' to systems that can be applied
at and to a stationary source,'' (84 FR 32534; July 8, 2019)--the EPA
found the BSER to be heat rate improvements alone. See 84 FR 32535
(July 8, 2019). The EPA listed various technologies that could improve
heat rate (84 FR 32536; July 8, 2019), and identified the ``degree of
emission limitation achievable'' by ``providing ranges of expected
[emission] reductions associated with each of the technologies.'' See
84 FR 32537-38 (July 8, 2019).
The EPA also stated that, under the ACE Rule, compliance measures
that the State plans could authorize the sources to implement ``should
correspond with the approach used to set the standard in the first
place,'' (84 FR 32556; July 8, 2019), and therefore must ``apply at and
to an individual source and reduce emissions from that source.'' See 84
FR 32555-56 (July 8, 2019). The EPA concluded that various measures
besides generation shifting--including averaging (i.e., allowing
multiple sources to average their emissions to meet an emission-
reduction goal), and trading (i.e., allowing sources to exchange
emission credits or allowances)--did not meet that requirement. The EPA
therefore barred states from using such measures in their plans. See 84
FR 32556 (July 8, 2019).
[[Page 33269]]
5. D.C. Circuit Decision in American Lung Association v. EPA Concerning
the CPP Repeal and ACE Rule
Numerous states and private parties petitioned for review of the
CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE
Rule, including the CPP Repeal. American Lung Ass'n v. EPA, 985 F.3d
914 (D.C. Cir. 2021). The court held, among other things, that CAA
section 111(d) does not limit the EPA, in determining the BSER, to
measures applied at and to an individual source. The court noted that
``the sole ground on which the EPA defends its abandonment of the [CPP]
in favor of the ACE Rule is that the text of [CAA section 111] is clear
and unambiguous in constraining the EPA to use only improvements at and
to existing sources in its [BSER].'' 985 F.3d at 944. The court found
``nothing in the text, structure, history, or purpose of [CAA section
111] that compels the reading the EPA adopted.'' 985 F.3d at 957. The
court explained that contrary to the ACE Rule, the above-noted
requirements in CAA section 111 that each State must establish a
standard of performance ``for'' any existing ``building . . . [or]
facility,'' mean that the State must establish standards applicable to
each regulated stationary source; and the requirements that the degree
of emission limitation must be achievable through the ``application''
of the BSER could be read to mean that the sources must be able to
apply the system to reduce emissions across the source category. None
of these requirements, the court further explained, can be read to
mandate that the BSER is limited to some measure that each source can
apply to its own facility to reduce its own emissions in a specified
amount. 985 F.3d at 944-51. The court likewise rejected the view that
the CPP's use of generation-shifting implicated a ``major question''
requiring unambiguous authorization by Congress. 985 F.3d at 958-68.
Having rejected the CPP Repeal Rule's view, also reflected in the
ACE Rule, that CAA section 111 unambiguously requires that the BSER be
``one that can be applied to and at the individual source,'' the court
also ``reject[ed] the ACE Rule's exclusion from [CAA section 111(d)] of
compliance measures'' that do not meet that requirement. 985 F.3d at
957. Thus, the court held that CAA section 111 does not preclude states
from allowing trading or averaging. The court explained that the ACE
Rule's premise for its view that compliance measures are limited to
measures applied at and to an individual source is that BSER measures
are so limited, but the court further stated that this premise was
invalid. The court added that in any event, CAA section 111(d) says
nothing about the type of compliance measures states may adopt,
regardless of what the EPA identifies as the BSER. Id. at 957-58.
The D.C. Circuit concluded that, because the EPA had relied on an
``erroneous legal premise,'' both the CPP Repeal Rule and the ACE Rule
should be vacated. 985 F.3d at 995. The court did not decide, however,
``whether the approach of the ACE Rule is a permissible reading of the
statute as a matter of agency discretion,'' 985 F.3d at 944, and
instead ``remanded to the EPA so that the Agency may `consider the
question afresh,' '' 985 F.3d at 995 (citations omitted). The court
also rejected the arguments that the EPA cannot regulate CO2
emissions from coal-fired power plants under CAA section 111(d) at all
because it had already regulated mercury emissions from coal-fired
power plants under CAA section 112. 985 F.3d at 988. In addition, the
court held that that the 2015 NSPS included a valid determination that
greenhouse gases from the EGU source category contributed significantly
to dangerous air pollution, which provided a sufficient basis for a CAA
section 111(d) rule regulating greenhouse gases from existing fossil
fuel-fired EGUs. Id. at 977.
Because the D.C. Circuit vacated the ACE Rule on the grounds noted
above, it did not address the numerous other challenges to the ACE
Rule, including the arguments by Petitioners that the heat rate
improvement BSER was inadequate because of the limited amount of
reductions it achieved and because the ACE Rule failed to include an
appropriately specific degree of emission limitation.
Upon a motion from the EPA, the D.C. Circuit agreed to stay its
mandate with respect to vacatur of the CPP Repeal, American Lung Assn
v. EPA, No. 19-1140, Order (February 22, 2021), so that the CPP
remained repealed. In its motion, the EPA explained that the CPP should
remain repealed because the deadline for states to submit their plans
under the CPP had long since passed. In addition, and most importantly,
because of ongoing changes in electricity generation--in particular,
retirements of coal-fired electricity generation--the emissions
reductions that the CPP was projected to achieve had already been
achieved by 2021. American Lung Assn v. EPA, No. 19-1140, Respondents'
Motion for a Partial Stay of Issuance of the Mandate (February 12,
2021). Therefore, following the D.C. Circuit's decision, no EPA rule
under CAA section 111 to reduce GHGs from existing fossil fuel-fired
EGUs remained in place.
6. U.S. Supreme Court Decision in West Virginia v. EPA Concerning the
CPP
In 2022, the U.S. Supreme Court reversed the D.C. Circuit's vacatur
of the ACE Rule's embedded repeal of the CPP. West Virginia v. EPA, 142
S. Ct. 2587 (2022). The Supreme Court made clear that CAA section 111
authorizes the EPA to determine the BSER and the degree of emission
limitation that State plans must achieve. Id. at 2601-02. However, the
Supreme Court invalidated the CPP's generation-shifting BSER under the
major questions doctrine. The Court characterized the generation-
shifting BSER as ``restructuring the Nation's overall mix of
electricity generation,'' and stated that the EPA's claim that CAA
section 111 authorized it to promulgate generation shifting as the BSER
was ``not only unprecedented; it also effected a fundamental revision
of the statute, changing it from one sort of scheme of regulation into
an entirely different kind.'' Id. at 2612 (internal quotation marks,
brackets, and citation omitted). The Court explained that the EPA, in
prior rules under CAA section 111, had set emissions limits based on
``measures that would reduce pollution by causing the regulated source
to operate more cleanly.'' Id. at 2610. The Court noted with approval
those ``more traditional air pollution control measures,'' and gave as
examples ``fuel-switching'' and ``add-on controls,'' which, the Court
observed, the EPA had considered in the CPP. Id. at 2611 (internal
quotations marks and citation omitted). In contrast, the Court
continued, generation-shifting was ``unprecedented'' because ``[r]ather
than focus on improving the performance of individual sources, it would
improve the overall power system by lowering the carbon intensity of
power generation. And it would do that by forcing a shift throughout
the power grid from one type of energy source to another.'' Id. at
2611-12 (internal quotation marks, emphasis, and citation omitted). The
Court also emphasized that the adoption of generation shifting was
based on a ``very different kind of policy judgment [than prior CAA
section 111 rules]: that it would be `best' if coal made up a much
smaller share of national electricity generation.'' Id. at 2612. The
Court recognized that a rule based on traditional measures ``may end up
causing an incidental loss of coal's market share,'' but emphasized
that the
[[Page 33270]]
CPP was ``obvious[ly] differen[t]'' because, with its generation-
shifting BSER, it ``simply announc[ed] what the market share of coal,
natural gas, wind, and solar must be, and then require[ed] plants to
reduce operations or subsidize their competitors to get there.'' Id. at
2613 n. 4. Beyond highlighting the novelty of generation shifting, the
Court also emphasized ``the magnitude and consequence'' of the CPP. Id.
at 2616. It noted ``the magnitude of this unprecedented power over
American industry,'' id. at 2612 (internal quotation marks and citation
omitted), and added that the EPA's adoption of generation shifting
``represent[ed] a transformative expansion in its regulatory
authority.'' Id. at 2610 (internal quotation marks and citation
omitted). The Court also viewed the CPP as promulgating ``a program
that . . . Congress had considered and rejected multiple times.'' Id.
at 2614 (internal quotation marks and citation omitted). The Court
explained that ``[a]t bottom, the [CPP] essentially adopted a cap-and-
trade scheme, or set of state cap-and-trade schemes, for carbon,'' and
that Congress ``has consistently rejected proposals to amend the Clean
Air Act to create such a program.'' Id.
For these and related reasons, the Court viewed the CPP as raising
a major question, and therefore, under the major questions doctrine,
required ``clear congressional authorization'' as a basis. Id.
(internal quotation marks and citation omitted). The EPA had defended
generation shifting as qualifying as a ``system of emission reduction''
under CAA section 111(a)(1), but the Court found that the term
``system'' is ``a vague statutory grant [that] is not close to the sort
of clear authorization required'' under the doctrine, id., and, on that
basis, invalidated the CPP.
The Court declined to address the D.C. Circuit's conclusion that
the text of CAA section 111 did not limit the type of ``system'' the
EPA could consider as the BSER to measures applied at and to an
individual source. See id. at 2615 (``We have no occasion to decide
whether the statutory phrase `system of emission reduction' refers
exclusively to measures that improve the pollution performance of
individual sources, such that all other actions are ineligible to
qualify as the BSER.'' (emphasis in original)). Nor did the Court
address the scope of the States' compliance flexibilities.
C. Detailed Discussion of CAA Section 111 Requirements
This section discusses in more detail the key requirements of CAA
section 111 for both new and existing sources that are relevant for
these rulemakings.
Approach to the Source Category and Subcategorizing
CAA section 111 requires the EPA first to list stationary source
categories that cause or contribute to air pollution which may
reasonably be anticipated to endanger public health or welfare and then
to regulate new sources within each such source category. CAA section
111(b)(2) grants the EPA discretion whether to ``distinguish among
classes, types, and sizes within categories of new sources for the
purpose of establishing [new source] standards,'' which we refer to as
``subcategorizing.'' The D.C. Circuit has stated that whether and how
to subcategorize is a decision for which the EPA is entitled to a
``high degree of deference'' because it entails ``scientific
judgement.'' Lignite Energy Council v. EPA, 198 F3d 930, 933 (D.C. Cir.
1999); see Sierra Cub, v. Costle, 657 F.2d 298, 318-19 (D.C. Cir.
1981).
Although CAA section 111(d)(1) does not by its terms address
subcategorization, the EPA interprets it to authorize the Agency to
exercise discretion as to whether and, if so, how to subcategorize, for
the following reasons. CAA section 111(d)(1) provides a broad grant of
authority to the EPA, directing it to ``prescribe regulations which
shall establish a procedure . . . under which each State shall submit
to the Administrator a plan [with standards of performance for existing
sources.]'' The EPA promulgates emission guidelines under this
provision directing the States to regulate existing sources. The
Supreme Court has recognized the breadth of authority that CAA section
111(d) grants the EPA:
Although the States set the actual rules governing existing
power plants, EPA itself still retains the primary regulatory role
in Section 111(d). The Agency, not the States, decides the amount of
pollution reduction that must ultimately be achieved. It does so by
again determining, as when setting the new source rules, ``the best
system of emission reduction . . . that has been adequately
demonstrated for [existing covered] facilities.''
West Virginia, 142 S. Ct. at 2601-02 (citations omitted). That this
broad authority under CAA section 111(d) includes subcategorization
follows from the fact that these provisions authorize the EPA to
determine the BSER. Subcategorizing is a mechanism for determining
different controls to be the BSER for different sets of sources. This
is clear from CAA section 111(b)(2) itself, which authorizes the EPA to
subcategorize new sources ``for the purpose of establishing . . .
standards.'' In addition, the EPA's implementing regulations under CAA
section 111(d), promulgated in 1975, 40 FR 53340 (November 17, 1975),
provide that the Administrator will specify different emission
guidelines or compliance times or both ``for different sizes, types,
and classes of designated facilities when costs of control, physical
limitations, geographical location, or [based on] similar factors.''
\173\ In promulgating this provision, the EPA made clear the purpose of
subcategorization is to tailor the BSER for different sets of sources:
---------------------------------------------------------------------------
\173\ 40 CFR 60.22(b)(5), 60.22a(b)(5). Because the definition
of subcategories depends on characteristics relevant to the BSER,
and because those characteristics can differ as between new and
existing sources, the EPA may establish different subcategories as
between new and existing sources.
EPA's emission guidelines will reflect subcategorization within
source categories where appropriate, taking into account differences
in sizes and types of facilities and similar considerations,
including differences in control costs that may be involved for
sources located in different parts of the country. Thus, EPA's
emission guidelines will in effect be tailored to what is reasonably
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achievable by particular classes of existing sources. . . .
Id. at 53343.
The EPA's authority to ``distinguish among classes, types, and
sizes within categories,'' as provided under CAA section 111(b)(2),
generally allows the Agency to place types of sources into
subcategories when they have characteristics that are relevant to the
controls they can apply to reduce their emissions. This is consistent
with the commonly understood meaning of the term ``type'' in CAA
section 111(b)(2): ``a particular kind, class, or group,'' or
``qualities common to a number of individuals that distinguish them as
an identifiable class.'' See https://www.merriam-webster.com/dictionary/type. That is, subcategorization is appropriate for a set of
sources that have qualities in common that are relevant for determining
what controls are appropriate for those sources. And where the
qualities in common are not relevant for determining what controls are
appropriate, subcategorization is not appropriate. This view is
consistent with the D.C. Circuit's interpretation of CAA section
112(d)(1), which is a subcategorization provision that is substantially
similar to CAA section 111(b)(2). In NRDC v. EPA, 489 F.3d 1364, 1375-
76 (D.C. Cir. 2007), the court upheld the EPA's decision under CAA
section 112(d)(1) not to subcategorize sources subject to control
requirements under CAA section 112(d)(3), known as the maximum
achievable control technology (MACT) floor, on the basis of
[[Page 33271]]
costs. That was because the EPA is not authorized to consider costs in
setting the MACT floor.\174\
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\174\ See Chem. Mfrs. Ass'n v. NRDC, 470 U.S. 116, 131 (1985)
(Court interprets similar subcategorization provision under the
Clean Water Act to grant the EPA broad discretion).
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The EPA has developed subcategories in numerous rulemakings under
CAA section 111 since it began promulgating them in the 1970s. These
rulemakings have included subcategories on the basis of the size of the
sources, see 40 CFR 60.40b(b)(1)-(2) (subcategorizing certain coal-
fired steam generating units on the basis of heat input capacity); the
types of fuel combusted, see Sierra Cub, v. EPA, 657 F.2d 298, 318-19
(D.C. Cir. 1981) (upholding a rulemaking that established different
NSPS ``for utility plants that burn coal of varying sulfur content''),
2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015)
(subdividing new combustion turbines on the basis of type of fuel
combusted); the types of equipment used to produce products, see 81 FR
35824 (June 3, 2016) (promulgating separate NSPS for many types of oil
and gas sources, such as centrifugal compressors, pneumatic
controllers, and well sites); types of manufacturing processes used to
produce product, see 42 FR 12022 (March 1, 1977) (announcing
availability of final guideline document for control of atmospheric
fluoride emissions from existing phosphate fertilizer plants) and
``Final Guideline Document: Control of Fluoride Emissions From Existing
Phosphate Fertilizer Plants, EPA-450/2-77-005 1-7 to 1-9, including
table 1-2 (applying different control requirements for different
manufacturing operations for phosphate fertilizer); levels of
utilization of the sources, see 2015 NSPS, 80 FR 64510, 64602 (table
15) (October 23, 2015) (dividing new natural gas-fired combustion
turbines into the subcategories of base load and non-base load); the
activity level of the sources, see 81 FR 59276, 59278-79 (August 29,
2016) (dividing municipal solid waste landfills into the subcategories
of active and closed landfills); and geographic location of the
sources, see 71 FR 38482 (July 6, 2006) (SO2 NSPS for
stationary combustion turbines subcategories turbines on the basis of
whether they are located in, for example, a continental area, a
noncontinental area, the part of Alaska north of the Arctic Circle, and
the rest of Alaska), see also Sierra Club v. Costle, 657 F.2d 298, 330
(D.C. Cir. 1981) (stating that the EPA could create different
subcategories for new sources in the Eastern and Western U.S. for
requirements that depend on water-intensive controls). As these
references indicate, the EPA has subcategorized many times in
rulemaking under CAA sections 111(b) and 111(d) and based on a wide
variety of physical, locational, and operational characteristics. It
should also be noted that in some instances, the EPA has declined to
subcategorize. Lignite Energy Council, 198 F.3d at 933 (upholding EPA
decision not to subcategorize utility boilers for purposes of
NOX NSPS on grounds that the decision was not arbitrary and
capricious).
Regardless of whether the EPA subcategorizes within a source
category for purposes of determining the BSER and the emission
performance level for the emission guideline, a State retains certain
flexibility in assigning standards of performance to its affected EGUs.
The statutory framework for CAA section 111(d) emission guidelines, and
the flexibilities available to States within that framework, are
discussed below.
D.C. Circuit Order To Reinstate the ACE Rule
On October 27, 2022, the D.C. Circuit responded to the U.S. Supreme
Court's reversal by recalling its mandate for the vacatur of the ACE
Rule. American Lung Ass'n v. EPA, No. 19-1140, Order (October 27,
2022). Accordingly, at that time, the ACE Rule came back into effect.
The court also revised its judgment to deny petitions for review
challenging the CPP Repeal Rule, consistent with the West Virginia
decision, so that the CPP remains repealed. The court took further
action denying several of the petitions for review unaffected by the
Supreme Court's decision in West Virginia, which means that certain
parts of its 2021 decision in American Lung Ass'n remain valid. These
parts include the holding that the EPA's prior regulation of mercury
emissions from coal-fired electric power plants under CAA section 112
does not preclude the Agency from regulating CO2 from coal-
fired electric power plants under CAA section 111, and the holding,
discussed above, that the 2015 NSPS included a valid significant
contribution determination and therefore provided a sufficient basis
for a CAA section 111(d) rule regulating greenhouse gases from existing
fossil fuel-fired EGUs. The court's holding to invalidate amendments to
the implementing regulations applicable to emission guidelines under
CAA section 111(d) that extended the preexisting schedules for State
and Federal actions and sources' compliance, also remains valid. Based
on the EPA's stated intention to replace the ACE Rule, the court stayed
further proceedings with respect to the ACE Rule, including the various
challenges that its BSER was flawed because it did not achieve
sufficient emission reductions and failed to specify an appropriately
specific degree of emission limitation.
3. Key Elements of Determining a Standard of Performance
Congress first included the definition of ``standard of
performance'' when enacting CAA section 111 in the 1970 Clean Air Act
Amendments (CAAA), amended it in the 1977 CAAA, and then amended it
again in the 1990 CAAA to largely restore the definition as it read in
the 1970 CAAA. The current text of CAA section 111(a)(1) reads: ``The
term `standard of performance' means a standard for emission of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' The
D.C. Circuit has reviewed CAA section 111 rulemakings on numerous
occasions since 1973,\175\ and has developed a body of caselaw that
interprets the term ``standard of performance,'' as discussed
throughout this preamble.
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\175\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981);
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999);
Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011);
American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021), rev'd in
part, West Virginia v. EPA, 142 S. Ct. 2587 (2022). See also
Delaware v. EPA, No. 13-1093 (D.C. Cir. May 1, 2015).
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The basis for standards of performance, whether promulgated by the
EPA under CAA section 111(b) or established by the States under CAA
section 111(d), is that the EPA determines the ``degree of emission
limitation'' that is ``achievable'' by the sources by application of a
``system of emission reduction'' that the EPA determines is
``adequately demonstrated,'' ``taking into account'' the factors of
``cost . . . nonair quality health and environmental impact and energy
requirements,'' and that the EPA determines to be the ``best.'' The
D.C. Circuit has stated that in determining the ``best'' system, the
EPA must also take into account ``the amount of air
[[Page 33272]]
pollution'' \176\ reduced and the role of ``technological innovation.''
\177\ The determination of the ``best'' system entails weighing the
various factors against each other, and the D.C. Circuit has emphasized
that the EPA has discretion in weighing the factors.178 179
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\176\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981).
\177\ See Sierra Club v. Costle, 657 F.2d at 347.
\178\ See Lignite Energy Council, 198 F.3d at 933.
\179\ Although CAA section 111(a)(1) may be read to state that
the factors enumerated in the parenthetical are part of the
``adequately demonstrated'' determination, the D.C. Circuit's case
law may be read to treat them as part of the ``best'' determination.
See Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA
section 111 gives the EPA authority ``when determining the best
technological system to weigh cost, energy, and environmental
impacts''). Nevertheless, it does not appear that those two
approaches would lead to different outcomes. See, e.g., Lignite
Energy Council, 198 F.3d at 933 (rejecting challenge to the EPA's
cost assessment of the ``best demonstrated system''). Regardless of
whether the factors are part of the ``adequately demonstrated''
determination or the ``best'' determination, our analysis and
outcome would be the same.
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The EPA's overall approach to determining the BSER and degree of
emission limitation achievable, which incorporates the various
elements, is as follows: The EPA identifies ``system[s] of emission
reduction'' that have been ``adequately demonstrated'' for a particular
source category and determines the ``best'' of these systems after
evaluating the amount of reductions, costs, any nonair health and
environmental impacts, and energy requirements. As discussed below, for
each of numerous subcategories, the EPA followed this approach to
propose the BSER on the basis that the identified costs are reasonable
and that the proposed BSER is rational in light of the statutory
factors and other impacts, including the amount of emission reductions,
that the EPA examined in its BSER analysis, consistent with governing
precedent.
After determining the BSER, the EPA determines an achievable
emission limit based on application of the BSER.\180\ For a CAA section
111(b) rule, we determine the standard of performance that reflects the
achievable emission limit. For a CAA section 111(d) rule, the States
have the obligation of establishing standards of performance for the
affected sources that reflect the degree of emission limitation that
the EPA has determined. As discussed below, the EPA proposed these
determinations in association with each of the proposed BSER
determinations.
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\180\ See, e.g., Oil and Natural Gas Sector: New Source
Performance Standards and National Emission Standards for Hazardous
Air pollutants Reviews (77 FR 49490, 49494; August 16, 2012)
(describing the three-step analysis in setting a standard of
performance).
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The remainder of this subsection discusses each element in our
general analytical approach.
a. System of Emission Reduction
The CAA does not define the phrase ``system of emission
reduction.'' In West Virginia v. EPA, the Supreme Court recognized that
historically, the EPA had looked to ``measures that improve the
pollution performance of individual sources and followed a
``technology-based approach'' in identifying systems of emission
reduction. In particular, the Court identified ``the sort of `systems
of emission reduction' [the EPA] had always before selected,'' which
included `` `efficiency improvements, fuel-switching,' and `add-on
controls'.'' 142 S. Ct. at 2611 (quoting the Clean Power Plan).\181\
Section 111 itself recognizes that such systems may include off-site
activities that may reduce a source's pollution contribution,
identifying ``precombustion cleaning or treatment of fuels'' as a
``system'' of ``emission reduction.'' 42 U.S.C. 7411(a)(7)(B). A
``system of emission reduction'' thus, at a minimum, includes measures
that an individual source applies that improve the emissions
performance of that source. Measures are fairly characterized as
improving the pollution performance of a source where they reduce the
individual source's overall contribution to pollution.
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\181\ As noted in section V.B.4 of this preamble, the ACE Rule
adopted the interpretation that CAA section 111(a)(1), by its plain
language, limits ``system of emission reduction'' to those control
measures that could be applied at and to each source to reduce
emissions at each source. 84 FR 32523-24 (July 8, 2019). The EPA has
proposed to reject that interpretation as too narrow. See
``Implementing Regulations under 40 CFR part 60 Subpart Ba Adoption
and Submittal of State Plans for Designated Facilities: Proposed
Rule,'' 87 FR 79176, 79208 (December 23, 2022).
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In West Virginia, the Supreme Court did not define the term
``system of emissions reduction,'' and so did not rule on whether
``system of emission reduction'' is limited to those measures that the
EPA has historically relied upon. It did go on to apply the major
questions doctrine to hold that the term ``system'' does not provide
the requisite clear authorization to support the Clean Power Plan's
BSER, which the Court described as ``carbon emissions caps based on a
generation shifting approach.'' Id. at 2614. While the Court did not
define the outer bounds of the meaning of ``system,'' systems of
emissions reduction like fuel switching, add-on controls, and
efficiency improvements fall comfortably within the scope of prior
practice as recognized by the Supreme Court.
b. ``Adequately Demonstrated''
Under CAA section 111(a)(1), an essential, although not sufficient,
condition for a ``system of emission reduction'' to serve as the basis
for an ``achievable'' emission limitation, is that the Administrator
must determine that the system is ``adequately demonstrated.'' This
means, according to the D.C. Circuit, that the system is ``one which
has been shown to be reasonably reliable, reasonably efficient, and
which can reasonably be expected to serve the interests of pollution
control without becoming exorbitantly costly in an economic or
environmental way.'' \182\ It does not mean that the system ``must be
in actual routine use somewhere.'' \183\ Rather, the court has said,
``[t]he Administrator may make a projection based on existing
technology, though that projection is subject to the restraints of
reasonableness and cannot be based on `crystal ball' inquiry.'' \184\
Similarly, the EPA may ``hold the industry to a standard of improved
design and operational advances, so long as there is substantial
evidence that such improvements are feasible.'' \185\ Ultimately, the
analysis ``is partially dependent on `lead time,' '' that is, ``the
time in which the technology will have to be available.'' \186\ The
caselaw is clear that the EPA may treat a set of control measures as
``adequately demonstrated'' regardless of whether the measures are in
widespread commercial use. For example, the D.C. Circuit upheld the
EPA's determination that selective catalytic reduction (SCR) was
adequately demonstrated to reduce NOX emissions from coal-
fired industrial boilers, even though it was a ``new technology.'' The
court explained that ``section 111 `looks toward what may fairly be
projected for the regulated future, rather than the state of the art at
present.' '' Lignite Energy Council, 198 F.3d at 934 (citing Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)). The
Court added that the EPA may determine that control measures are
``adequately demonstrated'' through a ``reasonable
[[Page 33273]]
extrapolation of [the control measures'] performance in other
industries.'' Id.
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\182\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C.
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\183\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted) (discussing the Senate and
House bills and reports from which the language in CAA section 111
grew).
\184\ Ibid.
\185\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
\186\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted).
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The D.C. Circuit's view that the EPA may determine a ``system of
emission reduction'' to be ``adequately demonstrated'' if the EPA
reasonably projects that it will be available by a future date certain,
is well-grounded in the purposes of CAA section 111 to reduce dangerous
air pollutants. This view recognizes that pollution control systems may
be complex and may require a predictable amount of time for sources
across the source category to be able to design, acquire, install, and
begin to operate them. In some instances, the control technology may be
available, but the installation may be a multi-year process. For
example, an existing coal-fired steam generating unit may require
several years to plan, design, and install a Flue Gas Desulfurization
(FGD) wet scrubber for the control of sulfur dioxide (SO2)
emissions. Under these circumstances, common sense dictates that the
EPA may promulgate a rulemaking that imposes a standard on the sources,
but establishes the date for compliance as a date-certain in the
future, consistent with the period of time the source needs to install
and start operating the control equipment. In other circumstances, a
system of emission reduction may be well-recognized as effective in
controlling pollutants emitted by a large source category, but
manufacturers may require a predictable amount of time to manufacture
enough control equipment to cover the source category. In still other
circumstances, the infrastructure needed to support the system so that
it will cover sources across the category--whether physical
infrastructure such as pipelines or human infrastructure such as
skilled labor to install the equipment--may require a predictable
amount of time to build out or develop in sufficient quantity to
achieve such coverage. In all of these circumstances, adopting
requirements under CAA section 111 at the time that the EPA is able to
reasonably project the future deployment of the system of emission
reduction, and establishing the date of compliance as a date-certain in
the future, serves the statutory purposes of protecting against
dangerous air pollution by ensuring that sources take action to control
their emissions as soon as practicable. It should also be noted that
because pollution control invariably entails additional cost, in some
cases, the EPA's promulgation of regulatory requirements may be an
essential trigger for the sometimes lengthy process of implementing
pollution controls. In these cases, delaying the promulgation of the
regulatory requirements until the pollution controls can be immediately
deployed would be futile.
c. Costs
Under CAA section 111(a)(1), in determining whether a particular
emission control is the ``best system of emission reduction . . .
adequately demonstrated,'' the EPA is required to take into account
``the cost of achieving [the emission] reduction.'' By its terms, this
provision makes clear that the cost that the EPA must take into account
is the cost to the affected source of the system of emission reduction.
Although the Clean Air Act does not describe how the EPA is to account
for costs, the D.C. Circuit has formulated the cost standard in various
ways.\187\ It has stated that the EPA may not adopt a standard the cost
of which would be ``exorbitant,'' \188\ ``greater than the industry
could bear and survive,'' \189\ ``excessive,'' \190\ or
``unreasonable.'' \191\ These formulations appear to be synonymous, and
for convenience, in these rulemakings, we are treating them as
synonymous with reasonableness as well, so that a control technology
may be considered the ``best system of emission reduction . . .
adequately demonstrated'' if its costs are reasonable, but cannot be
considered the best system if its costs are unreasonable.\192\
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\187\ 79 FR 1430, 1464 (January 8, 2014).
\188\ Lignite Energy Council, 198 F.3d at 933.
\189\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
\190\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\191\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\192\ These cost formulations are consistent with the
legislative history of CAA section 111. The 1977 House Committee
Report noted:
In the [1970] Congress [sic: Congress's] view, it was only right
that the costs of applying best practicable control technology be
considered by the owner of a large new source of pollution as a
normal and proper expense of doing business.
1977 House Committee Report at 184. Similarly, the 1970 Senate
Committee Report stated:
The implicit consideration of economic factors in determining
whether technology is ``available'' should not affect the usefulness
of this section. The overriding purpose of this section would be to
prevent new air pollution problems, and toward that end, maximum
feasible control of new sources at the time of their construction is
seen by the committee as the most effective and, in the long run,
the least expensive approach.
S. Comm. Rep. No. 91-1196 at 16.
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The D.C. Circuit has repeatedly upheld the EPA's consideration of
cost in reviewing standards of performance. In several cases, the court
upheld standards that entailed significant costs, consistent with
Congress's view that ``the costs of applying best practicable control
technology be considered by the owner of a large new source of
pollution as a normal and proper expense of doing business.'' \193\ See
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir.
1973); \194\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 387-88
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir.
1981) (upholding NSPS imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . . .
is substantial. EPA estimates that utilities will have to spend tens of
billions of dollars by 1995 on pollution control under the new
NSPS.'').
---------------------------------------------------------------------------
\193\ 1977 House Committee Report at 184.
\194\ The costs for these standards were described in the
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769
(March 21, 1972).
---------------------------------------------------------------------------
In its CAA section 111 rulemakings, the EPA has frequently used a
cost-effectiveness metric, which determines the cost in dollars for
each ton or other quantity of the regulated air pollutant removed
through the system of emission reduction. See, e.g., 81 FR 35824 (June
3, 2016) (NSPS for GHG and VOC emissions for the oil and natural gas
source category); 71 FR 9866, 9870 (February 27, 2006) (NSPS for
NOX, SO2, and PM emissions from fossil fuel-fired
electric utility steam generating units); 61 FR 9905, 9910 (March 12,
1996) (NSPS and emissions guidelines for nonmethane organic compounds
and landfill gas from new and existing municipal solid waste
landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO2
emissions from sweetening and sulfur recovery units in natural gas
processing plants). This metric allows the EPA to compare the amount a
regulation would require sources to pay to reduce a particular
pollutant across regulations and industries. In rules for the electric
power sector, a metric that determines the dollar increase in the cost
of a megawatt hour of electricity generated by the affected sources due
to the emission controls, shows the cost of controls relative to the
output of electricity. See section VII.F.3.b.iii(B)(5) of this
preamble, which discusses $/MWh costs of the March 15, 2023 Good
Neighbor Plan for the 2015 Ozone NAAQS and the Cross-State Air
Pollution Rule (CSAPR) 76 FR 48208 (August 8, 2011). This metric
facilitates comparing costs across regulations and pollutants. In this
proposal, as explained herein, the EPA looks at both of these metrics
to assess the cost reasonableness of the proposed requirements.
[[Page 33274]]
d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Under CAA section 111(a)(1), the EPA is required to take into
account ``any nonair quality health and environmental impact and energy
requirements'' in determining the BSER. Non-air quality health and
environmental impacts may include the impacts of the disposal of
byproducts of the air pollution controls, or requirements of the air
pollution control equipment for water. Portland Cement Ass'n v.
Ruckelshaus, 465 F.2d 375, 387-88 (D.C. Cir. 1973), cert. denied, 417
U.S. 921 (1974). Energy requirements may include the impact, if any, of
the air pollution controls on the source's own energy needs.
e. Sector or Nationwide Component of Factors in Determining the BSER
Another component of the D.C. Circuit's interpretations of CAA
section 111 is that the EPA may consider the various factors it is
required to consider on a national or regional level and over time, and
not only on a plant-specific level at the time of the rulemaking.\195\
The D.C. Circuit based this interpretation--which it made in the 1981
Sierra Club v. Costle case regarding the NSPS for new power plants--on
a review of the legislative history, stating,
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\195\ See 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club
v. Costle, 657 F.2d at 351).
[T]he Reports from both Houses on the Senate and House bills
illustrate very clearly that Congress itself was using a long-term
lens with a broad focus on future costs, environmental and energy
effects of different technological systems when it discussed section
111.\196\
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\196\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted)
(citing legislative history).
The court has upheld EPA rules that the EPA ``justified . . . in
terms of the policies of the Act,'' including balancing long-term
national and regional impacts. For example, the court upheld a standard
of performance for SO2 emissions from new coal-fired power
---------------------------------------------------------------------------
plants on grounds that it--
reflects a balance in environmental, economic, and energy
consideration by being sufficiently stringent to bring about
substantial reductions in SO2 emissions (3 million tons
in 1995) yet does so at reasonable costs without significant energy
penalties. . . .\197\
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\197\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR
33583-33584; June 11, 1979).
The EPA interprets this caselaw to authorize it to assess the
impacts of the controls it is considering as the BSER, including their
costs and implications for the energy system, on a sector-wide,
regional, or national basis, as appropriate. For example, the EPA may
assess whether controls it is considering would create risks to the
reliability of the electricity system in a particular area or
nationwide and, if they would, to reject those controls as the BSER.
f. ``Best''
In determining which adequately demonstrated system of emission
reduction is the ``best,'' the D.C. Circuit has made clear that the EPA
has broad discretion. Specifically, in Sierra Club v. Costle, 657 F.2d
298 (D.C. Cir. 1981), the court explained that ``section 111(a)
explicitly instructs the EPA to balance multiple concerns when
promulgating a NSPS,'' \198\ and emphasized that ``[t]he text gives the
EPA broad discretion to weigh different factors in setting the
standard,'' including the amount of emission reductions, the cost of
the controls, and the non-air quality environmental impacts and energy
requirements.\199\ In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C.
Cir. 1999), the court reiterated:
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\198\ Sierra Club v. Costle, 657 F.2d at 319.
\199\ Sierra Club v. Costle, 657 F.2d at 321; see also New York
v. Reilly, 969 F.2d at 1150 (because Congress did not assign the
specific weight the Administrator should assign to the statutory
elements, ``the Administrator is free to exercise [her] discretion''
in promulgating an NSPS).
Because section 111 does not set forth the weight that should be
assigned to each of these factors, we have granted the agency a
great degree of discretion in balancing them. . .-. EPA's choice [of
the `best system'] will be sustained unless the environmental or
economic costs of using the technology are exorbitant. . . . EPA
[has] considerable discretion under section 111.\200\
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\200\ Lignite Energy Council, 198 F.3d at 933 (paragraphing
revised for convenience). See New York v. Reilly, 969 F.2d 1147,
1150 (D.C. Cir. 1992) (``Because Congress did not assign the
specific weight the Administrator should accord each of these
factors, the Administrator is free to exercise his discretion in
this area.''); see also NRDC v. EPA, 25 F.3d 1063, 1071 (D.C. Cir.
1994) (The EPA did not err in its final balancing because ``neither
RCRA nor EPA's regulations purports to assign any particular weight
to the factors listed in subsection (a)(3). That being the case, the
Administrator was free to emphasize or deemphasize particular
factors, constrained only by the requirements of reasoned agency
decisionmaking.'').
See AEP v. Connecticut, 564 U.S. 410, 427 (2011) (under CAA section
111, ``The appropriate amount of regulation in any particular
greenhouse gas-producing sector cannot be prescribed in a vacuum: . . .
informed assessment of competing interests is required. Along with the
environmental benefit potentially achievable, our Nation's energy needs
and the possibility of economic disruption must weigh in the balance.
The Clean Air Act entrusts such complex balancing to the EPA in the
first instance, in combination with State regulators. Each ``standard
of performance'' the EPA sets must ``tak[e] into account the cost of
achieving [emissions] reduction and any nonair quality health and
environmental impact and energy requirements.'' (paragraphing revised;
citations omitted)).
Moreover, the D.C. Circuit has also read ``best'' to authorize the
EPA to consider factors in addition to the ones enumerated in CAA
section 111(a)(1), that further the purpose of the statute. In Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the D.C.
Circuit held that under CAA section 111(a)(1) as it read prior to the
enactment of the 1977 CAA Amendments that added a requirement that the
EPA take account of non-air quality environmental impacts, the EPA must
consider ``counter-productive environmental effects'' in determining
the BSER. Id. at 385. The court elaborated: ``The standard of the `best
system' is comprehensive, and we cannot imagine that Congress intended
that `best' could apply to a system which did more damage to water than
it prevented to air.'' Id., n.42. In Sierra Club v. Costle, 657 F.2d
298, 326, 346-47 (D.C. Cir. 1981), the court added that the EPA must
consider the amount of emission reductions and technology advancement
in determining BSER.
The court's view that ``best'' includes additional factors that
further the purpose of CAA section 111 is a reasonable interpretation
of that term in its statutory context. The purpose of CAA section 111
is to reduce emissions of air pollutants that endanger public health or
welfare. CAA section 111(b)(1)(A). The court reasonably surmised that
the EPA's determination of whether a system of emission reduction that
reduced certain air pollutants is ``best'' should be informed by
impacts that the system may have on other pollutants that affect public
or welfare. Portland Cement Ass'n, 486 F.2d at 385. The Supreme Court
confirmed the D.C. Circuit's approach in Michigan v. EPA 576 U.S. 743
(2015), explaining that administrative agencies must engage in
``reasoned decisionmaking'' that, in the case of pollution control,
cannot be based on technologies that ``do even more damage to human
health'' than the emissions they eliminate. Id. at 751-52. After
Portland Cement Ass'n, Congress revised CAA section 111(a)(1) to make
explicit that in determining whether a system of emission reduction is
the ``best,'' the EPA should account for non-air quality health and
environmental impacts. By the same token, the EPA
[[Page 33275]]
takes the position that in determining whether a system of emission
reduction is the ``best,'' the EPA may account for the impacts of the
system on air pollutants other than the ones that are the subject of
the CAA section 111 regulation.\201\ We discuss immediately below other
factors that the D.C. Circuit has held the EPA should account for in
determining what system is the ``best.''
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\201\ See generally ``Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Notice of Proposed Rulemaking,'' 87 FR 74702, 74765
(December 6, 2022) (proposing the BSER for reducing methane and VOC
emissions from natural gas-driven controllers in the oil and natural
gas sector on the basis of, among other things, impacts on emissions
of criteria pollutants). In this preamble, for convenience, the EPA
generally discusses the effects of controls on non-GHG air
pollutants along with the effects of controls on non-air quality
health and environmental impacts.
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g. Amount of Emissions Reductions
Consideration of the amount of emissions from the category of
sources or the amount of emission reductions achieved as factors the
EPA must consider in determining the ``best system of emission
reduction'' is implicit in the plain language of CAA section
111(a)(1)--the EPA must choose the best system of emission reduction.
Indeed, consistent with this plain language and the purpose of CAA
section 111, the D.C. Circuit has stated that the EPA must consider the
quantity of emissions at issue. See Sierra Club v. Costle, 657 F.2d
298, 326 (D.C. Cir. 1981) (``we can think of no sensible interpretation
of the statutory words ``best . . . system'' which would not
incorporate the amount of air pollution as a relevant factor to be
weighed when determining the optimal standard for controlling . . .
emissions'').\202\ The fact that the purpose of a ``system of emission
reduction'' is to reduce emissions, and that the term itself explicitly
incorporates the concept of reducing emissions, supports the court's
view that in determining whether a ``system of emission reduction'' is
the ``best,'' the EPA must consider the amount of emission reductions
that the system would yield. Even if the EPA were not required to
consider the amount of emission reductions, the EPA has the discretion
to do so, on grounds that either the term ``system of emission
reduction'' or the term ``best'' may reasonably be read to allow that
discretion.
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\202\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was
governed by the 1977 CAAA version of the definition of ``standard of
performance,'' which revised the phrase ``best system of emission
reduction'' to read, ``best technological system of continuous
emission reduction.'' As noted above, the 1990 CAAA deleted
``technological'' and ``continuous'' and thereby returned the phrase
to how it read under the 1970 CAAA. The court's interpretation of
the 1977 CAAA phrase in Sierra Club v. Costle to require
consideration of the amount of air emissions focused on the term
``best'', and the terms ``technological'' and ``continuous'' were
irrelevant to its analysis. It thus remains valid for the 1990 CAAA
phrase ``best system of emission reduction.''
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h. Expanded Use and Development of Technology
The D.C. Circuit has long held that Congress intended for CAA
section 111 to create incentives for new technology and therefore that
the EPA is required to consider technological innovation as one of the
factors in determining the ``best system of emission reduction.'' See
Sierra Club v. Costle, 657 F.2d at 346-47. The court has grounded its
reading in the statutory text of CAA 111(a)(1), defining the term
``standard of performance''.\203\ In addition, the court's
interpretation finds support in the legislative history.\204\ The
legislative history identifies three different ways that Congress
designed CAA section 111 to authorize standards of performance that
promote technological improvement: (1) The development of technology
that may be treated as the ``best system of emission reduction . . .
adequately demonstrated;'' under CAA section 111(a)(1); \205\ (2) the
expanded use of the best demonstrated technology; \206\ and (3) the
development of emerging technology.\207\ Even if the EPA were not
required to consider technological innovation as part of its
determination of the BSER, it would be reasonable for the EPA to
consider it because technological innovation may be considered an
element of the term ``best,'' particularly in light of Congress's
emphasis on technological innovation.
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\203\ Sierra Club v. Costle, 657 F.2d at 346 (``Our
interpretation of section 111(a) is that the mandated balancing of
cost, energy, and nonair quality health and environmental factors
embraces consideration of technological innovation as part of that
balance. The statutory factors which EPA must weigh are broadly
defined and include within their ambit subfactors such as
technological innovation.'').
\204\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of
performance should provide an incentive for industries to work
toward constant improvement in techniques for preventing and
controlling emissions from stationary sources''); S. Rep. No. 95-127
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n.
174) (``The section 111 Standards of Performance . . . sought to
assure the use of available technology and to stimulate the
development of new technology'').
\205\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (the best system of emission reduction must ``look[
] toward what may fairly be projected for the regulated future,
rather than the state of the art at present'').
\206\ 1970 Senate Committee Report No. 91-1196 at 15 (``The
maximum use of available means of preventing and controlling air
pollution is essential to the elimination of new pollution
problems'').
\207\ Sierra Club v. Costle, 657 F.2d at 351 (upholding a
standard of performance designed to promote the use of an emerging
technology).
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i. Achievability of the Degree of Emission Limitation
For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that
the EPA must establish ``standards of performance,'' which are
standards for emissions that reflect the degree of emission limitation
that is ``achievable'' through the application of the BSER. According
to the D.C. Circuit, a standard of performance is ``achievable'' if a
technology can reasonably be projected to be available to an individual
source at the time it is constructed that will allow it to meet the
standard.\208\ Moreover, according to the court, ``[a]n achievable
standard is one which is within the realm of the adequately
demonstrated system's efficiency and which, while not at a level that
is purely theoretical or experimental, need not necessarily be
routinely achieved within the industry prior to its adoption.'' \209\
To be achievable, a standard ``must be capable of being met under most
adverse conditions which can reasonably be expected to recur and which
are not or cannot be taken into account in determining the `costs' of
compliance.'' \210\ To show a standard is achievable, the EPA must
``(1) identify variable conditions that might contribute to the amount
of expected emissions, and (2) establish that the test data relied on
by the agency are representative of potential industry-wide
performance, given the range of variables that affect the achievability
of the standard.'' \211\
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\208\ Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C.
Cir. 1981).
\209\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\210\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C.
Cir. 1980).
\211\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981)
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In
considering the representativeness of the source tested, the EPA may
consider such variables as the `` `feedstock, operation, size and
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize
from a sample of one when one is the only available sample, or when
that one is shown to be representative of the regulated industry
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416,
434, n.52 (D.C. Cir. 1980).
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Although the D.C. Circuit established these standards for
achievability in cases concerning CAA section 111(b) new source
standards of performance, generally comparable standards for
achievability should apply under CAA section 111(d), although the BSER
may differ as between new and existing sources due to, for example,
higher costs
[[Page 33276]]
of retrofit. 40 FR 53340 (November 17, 1975). For existing sources, CAA
section 111(d)(1) requires the EPA to establish requirements for State
plans that, in turn, must include ``standards of performance.'' As the
Supreme Court has recognized, this provision requires the EPA to
promulgate emission guidelines that determine the BSER for a source
category and then identify the degree of emission limitation achievable
by application of the BSER. See West Virginia v. EPA, 142 S. Ct. 2587,
2601-02 (2022).\212\
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\212\ 40 CFR 60.21(e), 60.21a(e).
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The EPA has promulgated emission guidelines on the basis that the
existing sources can achieve the degree of emission limitation
described therein, even though under the RULOF provision of CAA section
111(d)(1), the State retains discretion to apply standards of
performance to individual sources that are more or less stringent,
which indicates that Congress recognized that the EPA may promulgate
emission guidelines that are consistent with CAA section 111(d) even
though certain individual sources may not be able to achieve the degree
of emission limitation identified therein by applying the controls that
the EPA determined to be the BSER. Note further that this requirement
that the emission limitation be ``achievable'' based on the ``best
system of emission reduction . . . adequately demonstrated'' indicates
that the technology or other measures that the EPA identifies as the
BSER must be technically feasible.
4. EPA Promulgation of Emission Guidelines for States To Establish
Standards of Performance
CAA section 111(d)(1) directs the EPA to promulgate regulations
establishing a CAA section 110-like procedure under which States submit
State plans that establish ``standards of performance'' for emissions
of certain air pollutants from sources which, if they were new sources,
would be regulated under CAA section 111(b), and that implement and
enforce those standards of performance. The term ``standard of
performance'' is defined under CAA section 111(a)(1), quoted above.
Thus, CAA sections 111(a)(1) and (d)(1) collectively require the EPA to
determine the BSER for the existing sources and, based on the BSER, to
establish emission guidelines that identify the minimum amount of
emission limitation that a State, in its State plan, must impose on its
existing sources through standards of performance. Consistent with
these CAA requirements, the EPA's regulations require that the EPA's
guidelines reflect--
the degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into account
the cost of such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator has
determined has been adequately demonstrated from designated
facilities.\213\
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\213\ 40 CFR 60.21a(e).
Following the EPA's promulgation of emission guidelines, each State
must determine the standards of performance for its existing sources,
which the EPA's regulations call ``designated facilities.'' \214\ While
the EPA specifies in emission guidelines the degree of emission
limitation achievable through application of the best system of
emission reduction, which it may express as a presumptive standard of
performance, a State retains discretion in applying such a presumptive
standard of performance to any particular designated facility. CAA
section 111(d)(1) requires the EPA's regulations to ``permit the State
in applying a standard of performance to any particular source . . . to
take into consideration, among other factors, the remaining useful life
the . . . source . . . .'' Consistent with this statutory direction,
the EPA's regulations provide requirements for States that wish to
apply standards of performance that deviate from an emission guideline.
In December 2022, the EPA proposed to clarify these requirements,
including the three circumstances under which States can invoke a
particular source's remaining useful life and other factors (RULOF), to
apply a less stringent standard of performance. These proposed
clarifications provided:
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\214\ 40 CFR 60.21a(b), 60.24a(b).
The State may apply a standard of performance to a particular
source that is less stringent than otherwise required by an
applicable emission guideline, taking into consideration remaining
useful life and other factors, provided that the State demonstrates
with respect to each such facility (or class of such facilities)
that it cannot reasonably apply the best system of emission
reduction to achieve the degree of emission limitation determined by
the EPA, based on:
(1) Unreasonable cost of control resulting from plant age,
location, or basic process design;
(2) Physical impossibility or technical infeasibility of
installing necessary control equipment; or
(3) Other circumstances specific to the facilities (or class of
facilities) that are fundamentally different from the information
considered in the determination of the best system of emission
reduction in the emission guidelines.
87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.24a(e)).\215\ In addition, under CAA sections
111(d) and 116, the State is authorized to establish a standard of
performance for any particular source that is more stringent than the
presumptive standards contained in the EPA's emission guidelines.\216\
Thus, for any particular source, a State may apply a standard of
performance that is either more stringent or less stringent than the
presumptive standards of performance in the emission guidelines. The
State must include the standards of performance in their State plans
and submit the plans to the EPA for review.\217\ Under CAA section
111(d)(2)(A), the EPA approves State plans that are determined to be
``satisfactory.''
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\215\ The EPA intends to finalize the December 2022 proposed
revisions to the CAA section 111 implementation regulations in 40
CFR part 60, subpart Ba, including any changes made in response to
public comments, prior to promulgating these emission guidelines.
Thus, 40 CFR part 60, subpart Ba, as revised, would apply to these
emission guidelines.
\216\ 40 CFR 60.24a(f). The EPA's December 2022 proposed
revisions to 40 CFR part 60, subpart Ba reflect its current
interpretation that the EPA has the authority to review and approve
plans that include standards of performance that are more stringent
than the presumptive standards in the EPA's emission guidelines,
thus making those more stringent requirements federally enforceable.
87 FR 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.24a(m), (n)). In addition, CAA section 116
authorizes the state to set standards of performance for all of its
sources that, together, are more stringent than the EPA's emission
guidelines.
\217\ 40 CFR 60.23a. In January 2021, the D.C. Circuit Court of
Appeals vacated the three-year deadline for state plan submissions
of a final emission guideline in 40 CFR 60.23a(a)(1). The EPA's
December 2022 proposed revisions to subpart Ba would revise 60.23a
to, inter alia, provide for a fifteen-month submission deadline. 87
FR 79182 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.23a(a)).
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IV. Stakeholder Engagement
Prior to proposing these actions, the EPA conducted outreach to a
broad range of stakeholders. The EPA also opened a non-regulatory pre-
proposal docket to solicit public input on the Agency's efforts to
reduce GHG emissions from new and existing EGUs.\218\ For additional
details on stakeholder engagement, see the memorandum in the docket
titled Stakeholder Outreach.
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\218\ Docket ID No. EPA-HQ-OAR-2022-0723.
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The EPA conducted two rounds of outreach to gather input for these
proposals. In the first round of outreach, in early 2022, the EPA
sought input in a variety of formats and settings from States, Tribal
nations, and a broad range
[[Page 33277]]
of stakeholders on the state of the power sector and how the Agency's
regulatory actions affect those trends. This outreach included State
energy and environmental regulators; Tribal air regulators; power
companies and trade associations representing investor-owned utilities,
rural electric cooperatives, and municipal power agencies;
environmental justice and community organizations; and labor,
environmental, and public health organizations. A second round of
outreach took place in August and September 2022, and focused on
seeking input specific to this rulemaking. The EPA asked to hear
perspectives, priorities, and feedback around five guiding questions,
and encouraged public input to the nonregulatory docket (Docket ID No.
EPA-HQ-OAR-2022-0723) on these questions as well.
The EPA also regularly interacts with other Federal agencies and
departments whose activities intersect with the power sector, and in
the course of developing these proposed rules the Agency conducted
multiple discussions with these agencies to benefit from their
expertise and to explore the potential interaction of these proposed
rules with their independent missions and initiatives. Among other
things, these discussions focused on the impacts of proposed
investments in energy technology by the Department of Energy and
Department of Treasury on the technical and economic analyses
underlying this proposal. In addition, the EPA evaluated structures in
these proposals to address reliability considerations with the
Department of Energy.
VII. Proposed Requirements for New and Reconstructed Stationary
Combustion Turbine EGUs and Rationale for Proposed Requirements
A. Overview
This section discusses and proposes requirements for stationary
combustion turbine EGUs that commence construction or reconstruction
after the date of publication of this proposed action. The EPA is
proposing that those requirements will be codified in 40 CFR part 60,
subpart TTTTa. The EPA explains in section VII.B the two basic turbine
technologies in use in the power sector and covered by 40 CFR part 60,
subpart TTTT, simple cycle turbines and combined cycle turbines. It
further explains how these technologies are used in the three
subcategories of low load turbines, intermediate load turbines, and
base load turbines. Section VII.C provides an overview of how
stationary combustion turbines have been previously regulated and how
the EPA recently took comment on a proposed white paper on GHG
mitigation options for stationary combustion turbines. Section VII.D
discusses the EPA's decision to revisit the standards for turbines as
part of the statutorily required 8-year review. Section VII.E discusses
changes that the EPA is proposing in both applicability and
subcategories in the new proposed 40 CFR part 60, subpart TTTTa as
compared to those codified in 40 CFR part 60, subpart TTTT. Most
notably, for natural gas-fired combustion turbines, the EPA is
proposing three subcategories, a low load subcategory, an intermediate
load subcategory, and a base load subcategory.
Section VII.F discusses the EPA's determination of the BSER for
each of the subcategories of turbines. For low load combustion
turbines, the EPA continues to believe that use of lower emitting fuels
is the appropriate BSER. For intermediate load turbines, the EPA
believes that both highly efficient generation and co-firing low-GHG
hydrogen are appropriate components of the BSER, and that there will be
enough low-GHG hydrogen at a reasonable price to supply the combustion
turbines that would need to use it in 2032. For this reason, the EPA is
proposing a two-component BSER for intermediate load combustion
turbines, and a two-phase standard of performance. The first component
of the BSER would be highly efficient generation (based on the
performance of a highly efficient simple cycle turbine), with a
corresponding first-phase standard of performance. The second component
of the BSER is co-firing 30 percent (by volume) low-GHG hydrogen, along
with continued use of highly efficient generation, with a corresponding
second-phase standard of performance. The EPA is also soliciting
comment on whether intermediate load combustion turbines should be
subject to a more stringent third-phase standard based on higher levels
of low-GHG hydrogen co-firing by 2038. Additionally, the EPA is
soliciting comment on whether the electric sales threshold used to
define intermediate and base load units should be reduced further.
For base load turbines, the EPA likewise believes that the BSER
includes multiple components that correspond to a multi-phase standard
of performance. This is appropriate based on consideration of the
manufacturing and installation capabilities within the larger EGU
category and other industries, and considerations of projected
operation of combustion turbines in the future. For base load turbines,
the EPA is proposing two BSER pathways with corresponding standards of
performance that new and reconstructed stationary combustion turbines
may take--one BSER pathway is based on the use of 90 percent CCS and a
separate BSER pathway is based on co-firing low-GHG hydrogen. The EPA
proposes that the first component of the BSER for both pathways is
highly efficient generation (based on the performance of a highly
efficient combined cycle unit) and the second component of the BSER is
based on the use of either 90 percent CCS in 2035 or co-firing 30
percent (by volume) low-GHG hydrogen in 2032, along with continued use
of highly efficient generation for both pathways. For base load
turbines that are subject to a second phase standard of performance
based on a highly efficient combined cycle unit co-firing 30 percent
(by volume) low-GHG hydrogen, the EPA proposes that those units also
meet a third phase component of the BSER based on the co-firing of 96
percent (by volume) low-GHG hydrogen by 2038. These two BSER pathways
both offer significant opportunities to reduce GHG emissions even
though they may be available on slightly different timescales. The EPA
seeks comment specifically on the percentages of hydrogen co-firing and
CO2 capture, the dates that meet the statutory BSER criteria
for each pathway, whether the Agency should finalize both pathways as
separate subcategories with separate standards of performance, or
whether it should finalize one pathway with the option of meeting the
standard of performance using either system of emission reduction--
e.g., a single standard of 90 lb CO2/MWh-gross based on the
application of CCS with 90 percent capture, which could also be met by
co-firing 96 percent low-GHG hydrogen.
For both intermediate load and base load turbines, the standards of
performance corresponding to both components of the BSER would apply to
all new and reconstructed sources that commence construction or
reconstruction after the publication date of this proposal. The EPA
occasionally refers to these standards of performance as the phase-1,
phase-2, or phase-3 standards.
B. Combustion Turbine Technology
For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary
combustion turbines include both simple cycle and combined cycle EGUs.
Simple cycle turbines operate in the Brayton thermodynamic cycle and
include three primary components: a
[[Page 33278]]
multistage compressor, a combustion chamber (i.e., combustor), and a
turbine. The compressor is used to supply large volumes of high-
pressure air to the combustion chamber. The combustion chamber converts
fuel to heat and expands the now heated, compressed air to create shaft
work. The shaft work drives an electric generator to produce
electricity. Combustion turbines that recover their high-temperature
exhaust--instead of venting it directly to the atmosphere--are combined
cycle EGUs and can obtain additional useful electric output. A combined
cycle EGU includes a heat recovery steam generator (HRSG) operating in
the Rankine thermodynamic cycle. The HRSG receives the high-temperature
exhaust and converts the heat to mechanical energy by producing steam
that is then fed into a steam turbine that, in turn, drives a second
electric generator. As the thermal efficiency of a stationary
combustion turbine EGU is increased, less fuel is burned to produce the
same amount of electricity, with a corresponding decrease in fuel costs
and lower emissions of CO2 and, generally, of other air
pollutants. The greater the output of electric energy for a given
amount of fuel energy input, the higher the efficiency of the electric
generation process.
Combustion turbines serve various roles in the power sector. Some
combustion turbines operate at low annual capacity factors and are
available to provide temporary power during periods of high load
demand. These turbines are often referred to as ``peaking units.'' Some
combustion turbines operate at intermediate annual capacity factors and
are often referred to as cycling or load-following units. Other
combustion turbines operate at high annual capacity factors to serve
base load demand and are often referred to as base load units. In this
proposal, the EPA refers to these types of combustion turbines as low
load, intermediate load, and base load, respectively.
Low load combustion turbines provide reserve capacity, support grid
reliability, and generally provide power during periods of peak
electric demand. As such, the units may operate at or near their full
capacity, but only for short periods, as needed. Because these units
only operate occasionally, capital expenses are a major factor in the
overall cost of electricity, and often, the lowest capital cost (and
generally less efficient) simple cycle EGUs are intended for use only
during periods of peak electric demand. Due to their low efficiency,
these units require more fuel per MWh of electricity produced and their
operating costs tend to be higher. Because of the higher operating
costs, they are generally some of the last units in the dispatch order.
Important characteristics for low load combustion turbines include
their low capital costs, their ability to start and quickly ramp to
full load, and their ability to operate at partial loads while
maintaining acceptable emission rates and efficiencies. The ability to
start and quickly attain full load is important to maximize revenue
during periods of peak electric prices and to meet sudden shifts in
demand. In contrast, under steady-state conditions, more efficient
combined cycle EGUs are dispatched ahead of low load turbines and often
operate at higher capacity factors.
Highly efficient simple cycle turbines and fast-start combined
cycle turbines both offer different advantages and disadvantages when
operating at intermediate loads. One of the roles of these intermediate
or load-following EGUs is to provide dispatchable backup power to
support variable renewable generating sources. A developer's decision
of whether to build a simple cycle combustion turbine or a combined
cycle combustion turbine to serve intermediate load demand would be
based on several factors related to the intended operation of the unit.
These factors include how frequently the unit is expected to cycle
between starts and stops, the predominant load level at which the unit
is expected to operate, and whether this level of operation is expected
to remain consistent or is expected to vary over the lifetime of the
unit. While the owner/operator of an individual combustion turbine
controls whether and how that unit will operate over time, they do not
necessarily control the precise timing of dispatch for the unit in any
given day or hour. Such short-term dispatch decisions are often made by
regional grid operators that determine, on a moment-to-moment basis,
which available individual units should operate to balance supply and
demand and other requirements in an optimal manner, based on operating
costs, price bids, and/or operational characteristics. However,
operating permits for simple cycle turbines often contain restrictions
on the annual hours of operation that owners/operators incorporate into
longer term operating plans and short-term dispatch decisions.
Intermediate load combustion turbines vary their generation,
especially during transition periods between low and high electric
demand. Both high-efficiency simple cycle combustion turbines and fast-
start combined cycle combustion turbines can fill this cycling role.
While the ability to start and quickly ramp is important, efficiency is
also an important characteristic. These combustion turbines generally
have higher capital costs than low load combustion turbines but are
generally less expensive to operate.
Base load combustion turbines are designed to operate for extended
periods at high loads with infrequent starts and stops. Quick start
capability and low capital costs are less important than low operating
costs. High-efficiency combined cycle combustion turbines typically
fill the role of base load combustion turbines.
The increase in generation from variable renewable energy sources
during the past decade has impacted the way in which firm dispatchable
generating resources operate.\219\ For example, the electric output
from wind and solar generating sources fluctuates daily and seasonally
due to increases and decreases in the wind speed or solar intensity.
Due to this variable nature of wind and solar, firm dispatchable
electric generating units are used to ensure the reliability of the
electric grid. This requires technologies such as dispatchable power
plants to start and stop and change load more frequently than was
previously needed. Important characteristics of combustion turbines
that provide firm backup capacity are the ability to start and stop
quickly and the ability to quickly change loads. Natural gas-fired
combustion turbines are much more flexible than coal-fired utility
boilers in this regard and have played an important role in ensuring
electric supply and demand are in balance during the past decade.
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\219\ Dispatchable EGUs can be turned on and off and adjust the
amount of power supplied to the electric grid based on the demand
for electricity. Variable (sometimes referred to as intermittent)
EGUs supply electricity based on external factors that are not
controlled by the owner/operator of the EGU.
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As discussed in section IV.F.2 of this preamble and in the
accompanying RIA, the post-IRA 2022 reference case projects that
natural gas-fired combustion turbines will continue to play an
important role in meeting electricity demand. However, that role is
projected to evolve as additional renewable and non-renewable low-GHG
generation and energy storage technologies are added to the grid.
Energy storage technologies can store energy during periods when
generation from renewable resources is high relative to demand and
provide electricity to the grid during other periods. This could reduce
the need for fossil fuel-fired firm dispatchable power plants to start
and stop as frequently. Consequently, in the future, natural gas-
[[Page 33279]]
fired stationary combustion turbine EGUs may run at more stable
operation and, thus, more efficiently (i.e., at higher duty cycles and
for longer periods of operation per start). The EPA is soliciting
comment on whether this a likely scenario.
C. Overview of Regulation of Stationary Combustion Turbines for GHGs
As explained earlier in this preamble, the EPA originally regulated
stationary combustion turbine EGUs for emissions of GHGs in 2015 under
40 CFR part 60, subpart TTTT. In 40 CFR part 60, subpart TTTT, the EPA
created three subcategories, two for natural gas-fired combustion
turbines and one for multi-fuel-fired combustion turbines. For natural
gas-fired turbines, the EPA created a subcategory for base load
turbines and a separate subcategory for non-base load turbines. Base
load turbines were defined as combustion turbines with electric sales
greater than a site-specific electric sales threshold that is based on
the design efficiency of the combustion turbine. Non-base load turbines
were defined as combustion turbines with a capacity factor less than or
equal to the site-specific electric sales threshold. For base load
turbines, the EPA set a standard of 1,000 lb CO2/MWh-gross
based on efficient combined cycle turbine technology and for non-base
load and multi-fuel-fired turbines, the EPA set a standard based on the
use of lower emitting fuels that varied from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu depending upon whether the turbine
burned primarily natural gas or other lower emitting fuels.
On April 21, 2022, the EPA issued an informational draft white
paper, titled Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units.\220\ The draft document included discussion of the basic types
of available stationary combustion turbines as well as factors that
influence GHG emission rates from these sources. The technology
discussion in the draft white paper included information on an array of
new and existing control technologies and potential reduction measures
for GHG emissions. These reduction measures included: the GHG reduction
potential of various efficiency improvements; technologies capable of
firing or co-firing alternative fuels such as hydrogen; the ongoing
advancement of CCS projects with NGCC units; and the co-location of
technologies that do not emit onsite GHG emissions with EGUs, such as
onsite renewables or short-duration energy storage.
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\220\ https://www.epa.gov/stationary-sources-air-pollution/white-paper-available-and-emerging-technologies-reducing.
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The EPA provided an opportunity for the public to comment on this
white paper to inform its approach to this proposed rulemaking. More
than 30 groups or individuals provided public comments on the topics
and technologies discussed in the draft white paper. Commenters
included representatives from utilities, technology providers, trade
associations, States, regulatory agencies, NGOs, and public health
advocates. The information provided in the public comments was
beneficial in enabling the EPA to review the current NSPS for new
stationary combustion turbines and to develop the proposed revisions
described in this preamble.
D. Eight-Year Review of NSPS
CAA section 111(b)(1)(B) requires the Administrator to ``at least
every 8 years, review and, if appropriate, revise [the NSPS] . . .''
The provision further provides that ``the Administrator need not review
any such standard if the Administrator determines that such review is
not appropriate in light of readily available information on the
efficacy of such [NSPS].''
The EPA promulgated the NSPS for GHG emissions for stationary
combustion turbines in 2015. Announcements and modeling projections
show companies are building new fossil fuel-fired combustion turbines
and plan to continue building additional capacity. Because the
emissions from this capacity have the potential to be large and these
units are likely to have long lives (25 years or more), the EPA
believes it is important to consider options to reduce emissions from
these new units. In addition, the EPA is aware of developments
concerning the types of control measures that may be available to
reduce GHG emissions from new stationary combustion turbines.
Accordingly, the EPA is proceeding to review and is proposing updated
NSPS for newly constructed and reconstructed fossil fuel-fired
stationary combustion turbines.
E. Applicability Requirements and Subcategorization
This section describes the proposed amendments to the specific
applicability criteria for non-fossil fuel-fired EGUs, industrial EGUs,
CHP EGUs, and combustion turbines EGUs not connected to a natural gas
pipeline. The EPA is also proposing certain changes to the
applicability requirements for stationary combustion turbines affected
by this proposal as compared to those for sources affected by the 2015
NSPS. The proposed changes are described below and include the
elimination of the multi-fuel-fired subcategory, further binning non-
base load combustion turbines into low and intermediate load
subcategories, and lowering the electric sales threshold for base load
combustion turbines.
1. Applicability Requirements
In general, the EPA refers to fossil fuel-fired EGUs that would be
subject to a CAA section 111 NSPS as ``affected'' EGUs or units. An EGU
is any fossil fuel-fired electric utility steam generating unit (i.e.,
a utility boiler or IGCC unit) or stationary combustion turbine (in
either simple cycle or combined cycle configuration). To be considered
an affected EGU under the current NSPS at 40 CFR part 60, subpart TTTT,
the unit must meet the following applicability criteria: The unit must:
(1) Be capable of combusting more than 250 million British thermal
units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of heat input
of fossil fuel (either alone or in combination with any other fuel);
and (2) serve a generator capable of supplying more than 25 MW net to a
utility distribution system (i.e., for sale to the grid).\221\ However,
40 CFR part 60, subpart TTTT includes applicability exemptions for
certain EGUs, including: (1) Non-fossil fuel-fired units subject to a
federally enforceable permit that limits the use of fossil fuels to 10
percent or less of their heat input capacity on an annual basis; (2)
CHP units that are subject to a federally enforceable permit limiting
annual net electric sales to no more than either the unit's design
efficiency multiplied by its potential electric output, or 219,000
megawatt-hours (MWh), whichever is greater; (3) stationary combustion
turbines that are not physically capable of combusting natural gas
(e.g., those that are not connected to a natural gas pipeline); (4)
utility boilers and IGCC units that have always been subject to a
federally enforceable permit limiting annual net electric sales to one-
third or less of their potential electric output (e.g., limiting hours
of operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less; (5) municipal waste combustors
that are subject to 40 CFR part 60, subpart Eb; (6) commercial or
industrial solid waste incineration units subject to 40 CFR part 60,
subpart CCCC; and (7)
[[Page 33280]]
certain projects under development, as discussed below.
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\221\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------
a. Revisions to 40 CFR Part 60, Subpart TTTT
The EPA is proposing to amend 40 CFR 60.5508 and 60.5509 to reflect
that 40 CFR part 60, subpart TTTT will remain applicable to steam
generating EGUs and IGCC units constructed after January 8, 2014 or
reconstructed after June 18, 2014. The EPA is also proposing that
stationary combustion turbines that commenced construction after
January 8, 2014 or reconstruction after June 18, 2014 and before May
23, 2023 that meet the relevant applicability criteria would be subject
to 40 CFR part 60, subpart TTTT. Upon promulgation of 40 CFR part 60,
subpart TTTTa, stationary combustion turbines that commence
construction or reconstruction after May 23, 2023 and meet the relevant
applicability criteria will be subject to 40 CFR part 60, subpart
TTTTa.
b. Revisions to 40 CFR Part 60, Subpart TTTT That Would Also Be
Included in 40 CFR Part 60, Subpart TTTTa
The EPA is proposing that 40 CFR part 60, subpart TTTT and 40 CFR
part 60, subpart TTTTa use similar regulatory text except where
specifically stated. This section describes proposed amendments that
would be included in both subparts.
i. Applicability to Non-Fossil Fuel-Fired EGUs
The current non-fossil applicability exemption in 40 CFR part 60,
subpart TTTT is based strictly on the combustion of non-fossil fuels
(e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU
must both (1) Be capable of combusting more than 50 percent non-fossil
fuel and (2) be subject to a federally enforceable permit condition
limiting the annual capacity factor for all fossil fuels combined of 10
percent (0.10) or less. The current language does not take heat input
from non-combustion sources (e.g., solar thermal) into account. Certain
solar thermal installations have natural gas backup burners larger than
250 MMBtu/h. As currently written, these solar thermal installations
would not be eligible to be considered non-fossil units because they
are not capable of deriving more than 50 percent of their heat input
from the combustion of non-fossil fuels. Therefore, solar thermal
installations that include backup burners could meet the applicability
criteria of 40 CFR part 60, subpart TTTT even if the burners are
limited to an annual capacity factor of 10 percent or less. These EGUs
would readily comply with the standard of performance, but the
reporting and recordkeeping would increase costs for these EGUs.
The EPA is proposing several amendments to align the applicability
criteria with the original intent to cover only fossil fuel-fired EGUs.
This would ensure that solar thermal EGUs with natural gas backup
burners, like other types of non-fossil fuel-fired units in which most
of their energy is derived from non-fossil fuel sources, are not
subject to the requirements of 40 CFR part 60, subparts TTTT or TTTTa.
Amending the applicability language to include heat input derived from
non-combustion sources would allow these facilities to avoid the
requirements of 40 CFR part 60, subparts TTTT or TTTTa by limiting the
use of the natural gas burners to less than 10 percent of the capacity
factor of the backup burners. Specifically, the EPA is proposing to
amend the definition of non-fossil fuel-fired EGUs from EGUs capable of
``combusting 50 percent or more non-fossil fuel'' to EGUs capable of
``deriving 50 percent or more of the heat input from non-fossil fuel at
the base load rating.'' (emphasis added). The definition of base load
rating would also be amended to include the heat input from non-
combustion sources (e.g., solar thermal).
The proposed amended non-fossil fuel applicability language
changing ``combusting'' to ``deriving'' will ensure that 40 CFR part
60, subparts TTTT and TTTTa cover the fossil fuel-fired EGUs, properly
understood, that the original rule was intended to cover, while
minimizing unnecessary costs to EGUs fueled primarily by steam
generated without combustion (e.g., through the use of solar thermal).
The corresponding change in the base load rating to include the heat
input from non-combustion sources is necessary to determine the
relative heat input from fossil fuel and non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
In simple terms, the current applicability provisions in 40 CFR
part 60, subpart TTTT require that an EGU be capable of combusting more
than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to a
utility distribution system to be subject to 40 CFR part 60, subpart
TTTT. These applicability provisions exclude industrial EGUs. However,
the definition of an EGU also includes ``integrated equipment that
provides electricity or useful thermal output.'' This language
facilitates the integration of non-emitting generation and avoids
energy inputs from non-affected facilities being used in the emission
calculation without also considering the emissions of those facilities
(e.g., an auxiliary boiler providing steam to a primary boiler). This
language could result in certain large processes being included as part
of the EGU and meeting the applicability criteria. For example, the
high-temperature exhaust from an industrial process (e.g., calcining
kilns, dryer, metals processing, or carbon black production facilities)
that consumes fossil fuel could be sent to a HRSG to produce
electricity. If the industrial process is more than 250 MMBtu/h heat
input and the electric sales exceed the applicability criteria, then
the unit could be subject to 40 CFR part 60, subparts TTTT or TTTTa.
This is potentially problematic for multiple reasons. First, it is
difficult to determine the useful output of the EGU (i.e., HRSG) since
part of the useful output is included in the industrial process. In
addition, the fossil fuel that is combusted might have a relatively
high CO2 emissions rate on a lb/MMBtu basis, making it
potentially problematic to meet the standard of performance using
efficient generation. This could result in the owner/operator reducing
the electric output of the industrial facility to avoid the
applicability criteria. Finally, the compliance costs associated with
40 CFR part 60, subparts TTTT or TTTTa could discourage the development
of environmentally beneficial projects.
To avoid these outcomes, the EPA is proposing to amend the
applicability provision that exempts EGUs where greater than 50 percent
of the heat input is derived from an industrial process that does not
produce any electrical or mechanical output or useful thermal output
that is used outside the affected EGU.\222\ Reducing the output or not
developing industrial electric generating projects where the majority
of the heat input is derived from the industrial process itself would
not necessarily result in reductions in GHG emissions from the
industrial facility. However, the electricity that would have been
produced from the industrial project could still be needed. Therefore,
projects of this type provide significant environmental benefit with
little if any additional emissions. Including these types of projects
would result in regulatory burden without any
[[Page 33281]]
associated environmental benefit and could discourage project
development, leading to potential overall increases in GHG emissions.
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\222\ Auxiliary equipment such as boilers or combustion turbines
that provide heat or electricity to the primary EGU (including to
any control equipment) would still be considered integrated
equipment and included as part of the affected facility.
---------------------------------------------------------------------------
(B) Industrial EGUs Electric Sales Threshold Permit Requirement
The current electric sales applicability exemption in 40 CFR part
60, subpart TTTT for non-CHP steam generating units includes the
provision that EGUs have ``always been subject to a federally
enforceable permit limiting annual net electric sales to one-third or
less of their potential electric output (e.g., limiting hours of
operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less'' (emphasis added). The
justification for this restriction includes that the 40 CFR part 60,
subpart Da applicability language includes ``constructed for the
purpose of . . .'' and the Agency concluded that the intent was defined
by permit conditions (80 FR 64544; October 23, 2015). This
applicability criterion is important for determining applicability with
both the new source CAA section 111(b) requirements and if existing
steam generating units are subject to the existing source CAA section
111(d) requirements. For steam generating units that commenced
construction after September 18, 1978, the applicability of 40 CFR part
60, subpart Da, would be relatively clear by what criteria pollutant
NSPS is applicable to the facility. However, for steam generating units
that commenced construction prior to September 18, 1978, or where the
owner/operator determined that criteria pollutant NSPS applicability
was not critical to the project (e.g., emission controls were
sufficient to comply with either the EGU or industrial boiler criteria
pollutant NSPS), owners/operators might not have requested an electric
sales permit restriction be included in the operating permit. Under the
current applicability language, some onsite EGUs could be covered by
the existing source CAA section 111(d) requirements even if they have
never sold electricity to the grid. To avoid covering these industrial
EGUs, the EPA is proposing to amend the electric sales exemption in 40
CFR part 60, subparts TTTT and TTTTa to read, ``annual net-electric
sales have never exceeded one-third of its potential electric output or
219,000 MWh, whichever is greater, and is'' (the ``always been'' would
be deleted) subject to a federally enforceable permit limiting annual
net electric sales to one-third or less of their potential electric
output (e.g., limiting hours of operation to less than 2,920 hours
annually) or limiting annual electric sales to 219,000 MWh or less''
(emphasis added). EGUs that reduce current generation would continue to
be covered as long as they sold more than one-third of their potential
electric output at some time in the past. The proposed revisions would
simply make it possible for an owner/operator of an existing industrial
EGU to provide evidence to the Administrator that the facility has
never sold electricity in excess of the electricity sales threshold and
to modify their permit to limit sales in the future. Without the
amendment, owners/operators of any non-CHP industrial EGU capable of
selling 25 MW would be subject to the existing source CAA section
111(d) requirements even if they have never sold any electricity.
Therefore, the EPA is proposing the exemption to eliminate the
requirement that existing industrial EGUs must have always been subject
to a permit restriction limiting net electric sales.
iii. Determination of the Design Efficiency
The design efficiency (i.e., the efficiency of converting thermal
energy to useful energy output) of a combustion turbine is used to
determine the electric sales applicability threshold and is relevant to
both new and existing EGUs.\223\ The sales criteria are based in part
on the individual EGU design efficiency. Three methods for determining
the design efficiency are currently provided in 40 CFR part 60, subpart
TTTT.\224\ Since the 2015 NSPS was finalized, the EPA has become aware
that owners/operators of certain existing EGUs do not have records of
the original design efficiency. These units are not able to readily
determine whether they meet the applicability criteria and are
therefore subject to the CAA section 111(d) requirements for existing
sources in the same way that 111(b) sources would be able to determine
if the facility meets the applicability criteria. Many of these EGUs
are CHP units and it is likely they do not meet the applicability
criteria. However, the language in the 2015 NSPS would require them to
conduct additional testing to demonstrate this. The requirement would
result in burden to the regulated community without any environmental
benefit. The electricity generating market has changed, in some cases
dramatically, during the lifetime of existing EGUs, especially
concerning ownership. As a result of acquisitions and mergers, original
EGU design efficiency documentation as well as performance guarantee
results that affirmed the design efficiency, may no longer exist.
Moreover, such documentation and results may not be relevant for
current EGU efficiencies, as changes to original EGU configurations,
upon which the original design efficiencies were based, render those
original design efficiencies moot, meaning that there would be little
reason to maintain former design efficiency documentation since it
would not comport with the efficiency associated with current EGU
configurations. As the three specified methods would rely on
documentation from the original EGU configuration performance guarantee
testing, and results from that documentation may no longer exist or be
relevant, it is appropriate to allow other means to demonstrate EGU
design efficiency. To reduce compliance burden, the EPA is proposing in
40 CFR part 60, subparts TTTT and TTTTa to allow alternative methods as
approved by the Administrator on a case-by-case basis. Owners/operators
of EGUs would petition the Administrator in writing to use an alternate
method to determine the design efficiency. The Administrator's
discretion is intentionally left broad and could extend to other
American Society of Mechanical Engineers (ASME) or International
Organization for Standardization (ISO) methods as well as to operating
data to demonstrate the design efficiency of the EGU. The EPA is also
proposing to change the applicability of paragraph 60.8(b) in table 3
of 40 CFR part 60, subpart TTTT from ``no'' to ``yes'' and that the
applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60,
subpart TTTTa is ``yes.'' This would allow the Administrator to approve
alternatives to the test methods specified in 40 CFR part 60, subparts
TTTT and TTTTa.
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\223\ While the EPA could specifically allow different methods
to determine the design efficiency in the 111(d) existing source
emission guidelines, the Agency is proposing to align the criteria
for regulatory clarity.
\224\ 40 CFR part 60, subpart TTTT currently lists ASME PTC 22
Gas Turbines, ASME PTC 46 Overall Plant Performance, and ISO 2314
Gas turbines acceptance tests as approved methods to determine the
design efficiency.
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c. Applicability for 40 CFR Part 60, Subpart TTTTa
This section describes proposed amendments that would only be
incorporated into 40 CFR part 60, subpart TTTTa and would differ from
the requirements in 40 CFR part 60, subpart TTTT.
i. Proposed Applicability
Section 111 of the CAA defines a new or modified source for
purposes of a given NSPS as any stationary source
[[Page 33282]]
that commences construction or modification after the publication of
the proposed regulation. Thus, any standards of performance the Agency
finalizes as part of this rulemaking will apply to EGUs that commence
construction or reconstruction after the date of this proposal. EGUs
that commenced construction after the date of the proposal for the 2015
NSPS and by the date of this proposal will remain subject to the
standards of performance promulgated in the 2015 NSPS. A modification
is any physical change in, or change in the method of operation of, an
existing source that increases the amount of any air pollutant emitted
to which a standard applies.\225\ The NSPS General Provisions (40 CFR
part 60, subpart A) provide that an existing source is considered a new
source if it undertakes a reconstruction.\226\
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\225\ 40 CFR 60.2.
\226\ 40 CFR 60.15(a).
---------------------------------------------------------------------------
The EPA is proposing the same applicability requirements in 40 CFR
part 60, subpart TTTTa as the applicability requirements in 40 CFR part
60, subpart TTTT. The stationary combustion turbine must meet the
following applicability criteria: The stationary combustion turbine
must: (1) Be capable of combusting more than 250 million British
thermal units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of
heat input of fossil fuel (either alone or in combination with any
other fuel); and (2) serve a generator capable of supplying more than
25 MW net to a utility distribution system (i.e., for sale to the
grid).\227\ In addition, the EPA is proposing in 40 CFR part 60,
subpart TTTTa to include applicability exemptions for stationary
combustion turbines that are: (1) Capable of deriving 50 percent or
more of the heat input from non-fossil fuel at the base load rating and
subject to a federally enforceable permit condition limiting the annual
capacity factor for all fossil fuels combined of 10 percent (0.10) or
less; (2) combined heat and power units subject to a federally
enforceable permit condition limiting annual net-electric sales to no
more than 219,000 MWh or the product of the design efficiency and the
potential electric output, whichever is greater; (3) serving a
generator along with other steam generating unit(s), IGCC, or
stationary combustion turbine(s) where the effective generation
capacity is 25 MW or less; (4) municipal waste combustors that are
subject to 40 CFR part 60, subpart Eb; (5) commercial or industrial
solid waste incineration units subject to 40 CFR part 60, subpart CCCC;
and (6) deriving greater than 50 percent of heat input from an
industrial process that does not produce any electrical or mechanical
output that is used outside the affected stationary combustion turbine.
---------------------------------------------------------------------------
\227\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------
The EPA is proposing to apply the same requirements to combustion
turbines in non-continental areas (i.e., Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern
Mariana Islands) and non-contiguous areas (non-continental areas and
Alaska) as the EPA is proposing for comparable units in the contiguous
48 States. However, new units in non-continental and non-contiguous
areas may operate on small, isolated electric grids, may operate
differently from units in the contiguous 48 States, and may have
limited access to certain components of the proposed BSER due to their
uniquely isolated geography or infrastructure. Therefore, the EPA is
soliciting comment on whether combustion turbines in non-continental
and non-contiguous areas should be subject to different requirements.
ii. Applicability to CHP Units
For 40 CFR part 60, subpart TTTT, owner/operators of CHP units
calculate net electric sales and net energy output using an approach
that includes ``at least 20.0 percent of the total gross or net energy
output consists of electric or direct mechanical output.'' It is
unlikely that a CHP unit with a relatively low electric output (i.e.,
less than 20.0 percent) would meet the applicability criteria. However,
if a CHP unit with less than 20.0 percent of the total output
consisting of electricity were to meet the applicability criteria, the
net electric sales and net energy output would be calculated the same
as for a traditional non-CHP EGU. Even so, it is not clear that these
CHP units would have less environmental benefit per unit of electricity
produced than more traditional CHP units. For 40 CFR part 60, subpart
TTTTa, the EPA is proposing to eliminate the restriction that CHP units
produce at least 20.0 percent electrical or mechanical output to
qualify for the CHP-specific method for calculating net electric sales
and net energy output.
In the 2015 NSPS, the EPA did not issue standards of performance
for certain types of sources--including industrial CHP units and CHPs
that are subject to a federally enforceable permit limiting annual net
electric sales to no more than the unit's design efficiency multiplied
by its potential electric output, or 219,000 MWh or less, whichever is
greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT
for determining net electric sales for applicability purposes allows
the owner/operator to subtract the purchased power of the thermal host
facility. The intent of the approach is to determine applicability
similarly for third-party developers and CHP units owned by the thermal
host facility.\228\ However, as written in 40 CFR part 60, subpart
TTTT, each third-party CHP unit would subtract the entire electricity
use of the thermal host facility when determining its net electric
sales. It is clearly not the intent of the provision to allow multiple
third-party developers that serve the same thermal host to all subtract
the purchased power of the thermal host facility when determining net
electric sales. This would result in counting the purchased power
multiple times. In addition, it is not the intent of the provision to
allow a CHP developer to provide a trivial amount of useful thermal
output to multiple thermal hosts and then subtract all the thermal
hosts' purchased power when determining net electric sales for
applicability purposes. The proposed approach in 40 CFR part 60,
subpart TTTTa would set a limit to the amount of thermal host purchased
power that a third-party CHP developer can subtract for electric sales
when determining net electric sales equivalent to the percentage of
useful thermal output provided to the host facility by the specific CHP
unit. This approach would eliminate both circumvention of the intended
applicability by sales of trivial amounts of useful thermal output and
double counting of thermal host-purchased power.
---------------------------------------------------------------------------
\228\ For contractual reasons, many developers of CHP units sell
all the generated electricity to the electricity distribution grid
even though in actuality a significant portion of the generated
electricity is used onsite. Owners/operators of both the CHP unit
and thermal host can subtract the site purchased power when
determining net electric sales. Third party developers that do not
own the thermal host can also subtract the purchased power of the
thermal host when determining net electric sales for applicability
purposes.
---------------------------------------------------------------------------
Finally, to avoid potential double counting of electric sales, the
EPA is proposing that for CHP units determining net electric sales,
purchased power of the host facility would be determined based on the
percentage of thermal power provided to the host facility by the
specific CHP facility.
iii. Non-Natural Gas Stationary Combustion Turbines
There is currently an exemption in 40 CFR part 60, subpart TTTT for
[[Page 33283]]
stationary combustion turbines that are not physically capable of
combusting natural gas (e.g., those that are not connected to a natural
gas pipeline). While combustion turbines not connected to a natural gas
pipeline meet the general applicability of 40 CFR part 60, subpart
TTTT, these units are not subject to any of the requirements. The EPA
is proposing requirements for new and reconstructed combustion turbines
that are not capable of combusting natural gas. As described in the
standards of performance section, the Agency is proposing that owners/
operators of combustion turbines burning fuels with a higher heat input
emission rate than natural gas would adjust the natural gas-fired
emissions rate by the ratio of the heat input-based emission rates. The
overall result is that new stationary combustion turbines combusting
fuels with higher GHG emissions rates than natural gas on a lb
CO2/MMBtu basis would have to maintain the same efficiency
compared to a natural gas-fired combustion turbine and comply with a
standard of performance based on the identified BSER. Therefore, the
EPA is not including in 40 CFR part 60, subpart TTTTa, the exemption
for stationary combustion turbines that are not physically capable of
combusting natural gas.
F. Determination of the Best System of Emission Reduction (BSER) for
New and Reconstructed Stationary Combustion Turbines
In this section, the EPA describes the technologies it is proposing
to determine are the BSER for each of the subcategories of new and
reconstructed combustion turbines that commence construction after the
date of this proposal, and explains its basis for proposing those
controls, and not others, as the BSER. The controls that the EPA is
evaluating include combusting non-hydrogen lower emitting fuels (e.g.,
natural gas and distillate oil), using highly efficient generation,
using CCS, and co-firing with low-GHG hydrogen.
For the low-load subcategory, the EPA is proposing the use of lower
emitting fuels as the BSER. For the intermediate load subcategory, the
EPA is proposing an approach under which the BSER is made up of two
components that each represent a different set of controls, and that
form the basis of standards of performance that apply in multiple
phases. That is, affected facilities--which are facilities that
commence construction or reconstruction after the date of this proposed
rulemaking--must meet the first phase of the standard of performance,
which is based on the application of the first component of the BSER,
highly efficient generation, by the date the rule is finalized; and
then meet the second and more stringent phase of the standard of
performance, which is based on co-firing 30 percent (by volume) low-GHG
hydrogen by 2032. The EPA is also soliciting comment on whether the
intermediate load subcategory should apply a third component of BSER,
which is co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In
addition, the EPA is also soliciting comment on whether the low load
subcategory should apply the second component of BSER, which is co-
firing 30 percent (by volume) low-GHG hydrogen by 2032. These latter
components of BSER would also include the continued application of
highly efficient generation.
For the base load subcategory, the EPA is also proposing a multi-
component BSER and an associated multi-phase standard of performance.
The first component of the BSER, as with intermediate load combustion
turbines, is highly efficient generation. New base load combustion
turbines would be required to meet a phase one standard of performance
based on the application of the first component of the BSER upon
initial startup of the source. Subsequently, EPA is proposing two
technology pathways as potential BSER for base load combustion
turbines, with corresponding standards of performance. The first
technology pathway is based on 90 percent CCS, which base load
combustion turbines may install and begin to operate to meet the
standard of performance by 2035. The second technology pathway is based
on co-firing low-GHG hydrogen, which EPA proposes base load combustion
turbines may undertake in two steps--by co-firing 30 percent (by
volume) low-GHG hydrogen to meet the second phase of the standard of
performance by 2032 and, then by co-firing 96 percent (by volume) low-
GHG hydrogen to meet the third phase of the standard of performance by
2038. Throughout, base load turbines, like intermediate load turbines,
would remain subject to the BSER of highly efficient generation.
This approach reflects the EPA's view that the BSER for the
intermediate load and base load subcategories should reflect the deeper
reductions in GHG emissions that can be achieved by implementing CCS
and co-firing low-GHG hydrogen but recognizes that building the
infrastructure required to support widespread use of CCS and low-GHG
hydrogen in the power sector will take place on a multi-year time
scale. Accordingly, newly constructed or reconstructed facilities must
be aware of their need to ramp toward more stringent phases of the
standards, which reflect application of the more stringent controls in
the BSER, either through use of co-firing a lower level of low-GHG
hydrogen by 2032 and a higher level of low-GHG hydrogen by 2038 or
through use of CCS by 2035. The EPA is also soliciting comment on the
potential for an earlier compliance date for the second phase, for
instance, 2030 for units co-firing 30 percent hydrogen by volume and
2032 for units installing CCS.
For the base load subcategory, the EPA is proposing both potential
BSER pathways because it believes there may be more than one viable
BSER pathway for base load combustion turbines to significantly reduce
their CO2 emissions and believes there is value in receiving
comment on, and potentially finalizing, both BSER pathways to enable
project developers to elect how they will reduce their CO2
emissions on timeframes that make sense for each BSER pathway. The EPA
recognizes that standards of performance are technology neutral and
that if the EPA finalizes a standard based on application of CCS, units
could meet that standard using co-firing of low-GHG hydrogen. The EPA
solicits comment on whether co-firing of low-GHG hydrogen should be
considered a compliance pathway for sources to meet a single standard
of performance based on application of CCS rather than a separate BSER
pathway. The EPA believes that there will be earlier opportunities for
units to begin co-firing lower amounts of low-GHG hydrogen than to
install and begin operating 90 percent CCS systems. However, it will
likely take a longer timeframe for those units to then ramp up to co-
firing significant quantities of low-GHG hydrogen. Therefore, in this
proposal, the EPA presents these pathways as separate subcategories,
while soliciting comment on the option of finalizing a single standard
of performance based on application of CCS.
Specifically, with respect to the first phase of the standards of
performance, for both the intermediate load and base load
subcategories, the EPA is proposing that the BSER is highly efficient
generating technology--combined cycle technology for the base load
subcategories and simple cycle technology for the intermediate load
subcategory--as well as operating and maintaining it efficiently. The
EPA sometimes refers to highly efficient generating technology in
combination with the best operating and
[[Page 33284]]
maintenance practices as highly efficient generation.
The affected sources must meet standards based on this efficient
generating technology upon the effective date of the final rule. With
respect to the second phase of the standards of performance, for base
load combustion turbines adopting the CCS pathway, the BSER includes
the use of 90 percent CCS. These sources would be required to meet
standards of performance by 2035 that reflect application of both
components of the BSER--highly efficient generation and CCS--and thus
are more stringent. For base load combustion turbines adopting the low-
GHG hydrogen co-firing pathway and for intermediate load combustion
turbines, the BSER includes co-firing 30 percent by volume (12 percent
by heat input) low-GHG hydrogen. These sources would be required to
meet second phase standards of performance by 2032 that reflect the
application of both components of the BSER--in this case, highly
efficient generation and co-firing 30 percent (by volume) low-GHG
hydrogen--and that are, again, more stringent. Finally, for base load
combustion turbines adopting the low-GHG hydrogen co-firing pathway,
the BSER also includes a third component--co-firing 96 percent (by
volume) low-GHG hydrogen. These sources would be required to meet a
third phase standard of performance equivalent to that for the affected
sources applying CCS as a second component of the BSER. These sources
would be required to meet that equivalent standard of performance
reflecting the application of highly efficient generation and co-firing
high levels of low-GHG hydrogen. Table 1 summarizes the proposed BSER
for combustion turbine EGUs that commence construction or
reconstruction after publication of this proposal. The EPA is also
proposing standards of performance based on those BSER for each
subcategory, as discussed in section VII.G.
Table 1--Proposed BSER for Combustion Turbine EGUs
----------------------------------------------------------------------------------------------------------------
1st Component 2nd Component 3rd Component
Subcategory Fuel BSER BSER BSER
----------------------------------------------------------------------------------------------------------------
Low Load *...................... All Fuels......... Lower emitting N/A............... N/A
fuels.
Intermediate Load............... All Fuels......... Highly Efficient 30 percent (by N/A
Generation. volume) Low-GHG
Hydrogen Co-
firing by 2032.
Base Load....................... Sources adopting Highly Efficient 90 percent CCS by N/A
the CCS pathway. Generation. 2035.
Sources adopting .................. 30 percent (by 96 percent (by
the low-GHG volume) Low-GHG volume) Low-GHG
hydrogen co- Hydrogen Co- Hydrogen Co-
firing pathway. firing by 2032. firing by 2038
----------------------------------------------------------------------------------------------------------------
* The low load subcategory has a single-component BSER consisting of fuels that emit lower GHG emissions.
1. BSER for Low Load Subcategory
This section describes the proposed BSER for the low load (i.e.,
peaking) subcategory, which is the use of lower emitting fuels. For
this proposed rule, the Agency proposes to determine that the use of
lower emitting fuels, which the EPA determined to be the BSER for the
non-base load subcategory in the 2015 NSPS, is the BSER for this low
load subcategory in the standards of performance proposed in this
action. As explained above, the EPA is proposing to narrow the
definition of the low load subcategory by lowering the electric sales
threshold (as compared to the electric sales threshold for non-base
load combustion turbines in the 2015 NSPS), so that turbines with
higher electric sales would be placed in the proposed intermediate load
subcategory and therefore be subject to a more stringent standards
based on the more stringent component of the BSER. Unlike the proposals
for intermediate and base load combustion turbines, the proposed low
load subcategory includes only a single-phase BSER component.
a. Background: The Non-Base Load Subcategory in the 2015 NSPS
The 2015 NSPS defined non-base load natural gas-fired EGUs as
stationary combustion turbines that (1) Burn more than 90 percent
natural gas and (2) have net electric sales equal to or less than their
design efficiency (not to exceed 50 percent) multiplied by their
potential electric output (80 FR 64601; October 23, 2015). These are
calculated on 12-operating-month and 3-year rolling average bases. The
EPA also determined in the 2015 NSPS that the BSER for newly
constructed and reconstructed non-base load natural gas-fired
stationary combustion turbines is the use of lower emitting fuels. Id.
at 64515. These lower emitting fuels are primarily natural gas with a
small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils),
which have been widely used in stationary combustion turbine EGUs for
decades.
The EPA also determined in the 2015 NSPS that the standard of
performance for sources in this subcategory is a heat input-based
standard of 120 lb CO2/MMBtu. The EPA established this
clean-fuels BSER for this subcategory because of the variability in the
operation in non-base load combustion turbines and the challenges
involved in determining a uniform output-based standard that all new
and reconstructed non-base load units could achieve.
Specifically, in the 2015 NSPS, the EPA recognized that a BSER for
the non-base load subcategory based on the use of lower emitting fuels
results in limited GHG reductions, but further recognized that an
output-based standard of performance could not reasonably be applied to
the subcategory. The EPA explained that a combustion turbine operating
at a low capacity factor could operate with multiple starts and stops,
and that its emission rate would be highly dependent on how it was
operated and not its design efficiency. Moreover, combustion turbines
with low annual capacity factors typically operated differently from
each other, and therefore had different emission rates. The EPA
recognized that, as a result, it would not be possible to determine a
standard of performance that could reasonably apply to all combustion
turbines in the subcategory. For that reason, the EPA further
recognized, efficient design \229\ and operation would not qualify as
the BSER; rather, the BSER should be lower
[[Page 33285]]
emitting fuels and the associated standard of performance should be
based on heat input. Since the 2015 NSPS, all newly constructed simple
cycle turbines have been non-base load units and thus have become
subject to this standard of performance.
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\229\ Important characteristics for minimizing emissions from
low load combustion turbines include the ability to operate
efficiently while operating at part load conditions and the ability
to rapidly achieve maximum efficiency to minimize periods of
operation at lower efficiencies. These characteristics do not
necessarily always align with higher design efficiencies that are
determined under steady state full load conditions.
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b. Proposed BSER
Consistent with the rationale of the 2015 NSPS, the EPA proposes
that the use of fuels with an emissions rate of less than 160 lb
CO2/MMBtu (i.e., lower emitting fuels) meets the BSER
requirements for the low load subcategory. Use of these fuels is
technically feasible for combustion turbines. Natural gas comprises the
majority of the heat input for simple cycle turbines and is the lowest
cost fossil fuel. In the 2015 NSPS, the EPA determined that natural gas
comprised 96 percent of the heat input for simple cycle turbines. See
80 FR 64616 (October 23, 2015). Therefore, a BSER based on the use of
natural gas and/or distillate oil would have minimal, if any, costs to
regulated entities. The use of lower emitting fuels would not have any
significant adverse energy requirements or non-air quality or
environmental impacts, as the EPA determined in the 2015 NSPS. Id. at
64616. In addition, the use of fuels meeting this criterion would
result in some emission reductions by limiting the use of fuels with
higher carbon content, such as residual oil, as the EPA also explained
in the 2015 NSPS. Id. Although the use of fuels meeting this criterion
would not advance technology, in light of the other reasons described
here, the EPA proposes that the use of natural gas, Nos. 1 and 2 fuel
oils, and other fuels \230\ currently specified in 40 CFR part 60,
subpart TTTT, qualify as the BSER for new and reconstructed combustion
turbine EGUs in the low load subcategory. The EPA is also proposing to
add low-GHG hydrogen to the list of fuels meeting the uniform fuels
criteria in 40 CFR part 60, subpart TTTTa. The addition of low-GHG
hydrogen (and fuels derived from hydrogen) to 40 CFR part 60, subpart
TTTTa would simplify the recordkeeping and reporting requirements for
low load combustion turbines that elect to burn low-GHG hydrogen. As
described in section VII.F, a component of the BSER for certain
subcategories in subpart TTTTa is based on the use of low-GHG hydrogen.
An owner/operator of a subpart TTTTa affected combustion turbine that
combusts hydrogen for compliance purposes not meeting the definition of
low-GHG hydrogen would be in violation of the subpart TTTTa
requirements.
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\230\ The BSER for multi-fuel-fired combustion turbines subject
to 40 CFR part 60, subpart TTTT is also the use of fuels with an
emissions rate of 160 lb CO2/MMBtu or less. The use of
these fuels would demonstrate compliance with the low load
subcategory.
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For the reasons discussed in the 2015 NSPS and noted above, the EPA
is not proposing that efficient design and operation qualify as the
BSER for the low load subcategory. The EPA is not proposing high-
efficiency simple cycle or combined cycle turbine design and operation
as the BSER for the low load subcategory because they are not
necessarily cost reasonable and would not necessarily result in
emission reductions. High efficiency combustion turbines have higher
initial costs compared to lower efficiency combustion turbines. The
cost of combustion turbine engines is dependent upon many factors, but
the EPA estimates that the capital cost of a high-efficiency simple
cycle turbine is 5 percent more than that of a comparable lower
efficiency simple cycle turbine. Assuming all other costs are the same
and that the high-efficiency simple cycle turbine uses 6 percent less
fuel, it would not necessarily be cost reasonable to use a high-
efficiency simple cycle turbine until the combustion turbine is
operated at a 12-operating-month capacity factor of approximately 20
percent. At lower capacity factors, the CO2 abatement costs
on both a $/ton and $/MW basis increase rapidly.\231\ Further, the
emission rate of a low load combustion turbine is highly dependent upon
the way the combustion turbine is operated. If the combustion turbine
is frequently operated at part load conditions with frequent starts and
stops, a combustion turbine with a high design efficiency, which is
determined at full load steady state conditions, would not necessarily
emit at a lower GHG rate than a combustion turbine with a lower design
efficiency.
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\231\ The cost effectiveness calculation is highly dependent
upon assumptions concerning the increase in capital costs, the
decrease in heat rate, and the price of natural gas.
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The EPA solicits comment on whether, and the extent to which, high-
efficiency designs also operate more efficiently at part loads and can
start more quickly and reach the desired load more rapidly than
combustion turbines with less efficient design efficiencies. If high-
efficiency simple cycle turbines do operate at higher part-load
efficiencies and are able to reach the intended operating load more
quickly, the use of highly efficient simple cycle turbines for low load
applications would result in lower GHG reductions. In addition, the EPA
solicits comment on the cost premium of high-efficiency simple cycle
turbines. If the use of highly efficient simple cycle turbines results
in GHG reductions at reasonable cost, their use could qualify as the
BSER for low load combustion turbines. The EPA is soliciting comment on
whether the BSER for new low load combustion turbines should be the use
of high efficiency simple cycle technology. However, since the method
of operation has a substantial impact on the emissions rate, it may not
be feasible for to prescribe or enforce a single numerical standard of
performance for affected sources strictly based on design efficiency.
Accordingly, the EPA solicits comment on whether it would be
appropriate to promulgate such a requirement as a design standard
pursuant to CAA section 111(h). Pursuant to such a design standard,
compliance would be demonstrated (i) initially, through an emissions
test and (ii) subsequently, based on the use of lower emitting fuels.
The initial full load performance test for natural gas-fired low load
combustion turbines the EPA is considering is 1,150 lb CO2/
MWh-gross or 1,100 lb CO2/MWh-gross.\232\ Combustion turbine
manufacturers conduct testing on their products and the initial
performance test is equivalent to a design efficiency of approximately
35 and 36 percent, respectively. According to Gas Turbine World 2021,
approximately three-fourths of simple cycle combustion turbines have
design efficiencies of 35 percent or higher and half of simple cycle
combustion turbines have design efficiencies of 36 percent or higher.
The EPA is soliciting comment on if the initial performance test for
low load combustion turbines could be conducted by the manufacturer
certifying the design GHG emissions rate or if the owner or operator
should be required to conduct separate testing to verify the emissions
rate. The EPA notes that even if the Agency determines that a
manufacturer design efficiency-based emissions requirement is
appropriate for new low load combustion turbines, owners/operators
would also have the option to either comply with the intermediate load
standard of performance on a continuous basis or conduct an initial
performance test as an alternative to purchasing a combustion turbine
that
[[Page 33286]]
achieves the specified design efficiency. For example, owners/operators
could elect to cofire low-GHG hydrogen or install integrated renewable
generation as an alternative to purchasing a combustion turbine that
meets the specified design efficiency.
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\232\ The initial full load compliance test would be a 3-hour
performance test and the measured emissions rate would be corrected
to ISO conditions.
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The EPA expects that units in the low load subcategory will be
simple cycle turbines. The capital cost of a combined cycle EGU is
approximately 250 percent that of a comparable sized simple cycle EGU
and would not be recovered by reduced fuel costs if operated as low
load units. Furthermore, low load combustion turbines start and stop so
frequently that there might not be sufficient periods of continuous
operation for the HRSG to begin generating steam to operate the steam
turbine enough to significantly lower the emissions rate of the EGU.
The EPA is not proposing the use of CCS or hydrogen co-firing as
the BSER (or as a component of the BSER) for low load combustion
turbines.\233\ As described in the section discussing the second
component of BSER for the intermediate load subcategory, the EPA is not
proposing that CCS is the BSER for simple cycle combustion turbines
based on the Agency's assessment that CCS may not be cost-effective for
such combustion turbines when operated at intermediate load. This
rationale applies with even greater force for low load combustion
turbines. In addition, currently available post-combustion amine-based
carbon capture systems require that the exhaust from a combustion
turbine be cooled prior to entering the carbon capture equipment. The
most energy efficient way to do this is to use a HSRG, which is an
integral component of a combined cycle turbine system but is not
incorporated in a simple cycle unit. For these reasons, the Agency is
not proposing that CCS qualifies as the BSER for this subcategory of
sources.
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\233\ The EPA will not finalize the use of CCS or hydrogen co-
firing as the BSER (or as a component of the BSER) for low load
combustion turbines unless it first issues a subsequent notice of
proposed rulemaking further evaluating such measures for that
subcategory.
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The EPA is not proposing low-GHG hydrogen co-firing as the BSER for
low load combustion turbines because not all new combustion turbines
can necessarily co-fire higher percentages of hydrogen, there are
potential infrastructure issues specific to low load combustion
turbines, and at the relatively infrequent levels of utilization that
characterize the low load subcategory, a low-GHG hydrogen co-firing
BSER would not necessarily result in cost-effective GHG reductions for
all low load combustion turbines. As discussed later in this section,
the announced hydrogen co-firing combustion turbine projects appear to
be intermediate and base load combustion turbines. Manufacturers may
focus initial research and development for hydrogen co-firing on
combustion turbines that operate at higher capacity factors and that
can achieve higher levels of overall GHG reductions. The EPA is
soliciting comment on whether this development could limit the
availability of low load combustion turbines that are capable of
burning higher percentages of hydrogen. The EPA is also soliciting
comment on technologies to reduce potential costs and technical
challenges for the transport and storage of hydrogen for owners/
operators of low load combustion turbines. In particular, the EPA is
soliciting comment on approaches that could be used for owners/
operators of low load combustion turbines located in high demand
centers (e.g., dense urban areas). To the extent these factors are not
significant, the EPA is soliciting comment, with the intention of
determining whether it would be appropriate to consider such a
requirement in a future rulemaking, on whether the EPA should add a
second component of the BSER for low load combustion turbines, based on
hydrogen co-firing that would begin in 2032. The hydrogen co-firing
requirement would be a separate requirement in addition to the proposed
lower emitting fuels requirement. Based on simple cycle turbines that
recently commenced operation, the average 12-operating-month capacity
factor of low load combustion turbines would be less than 8 percent. If
hydrogen co-firing were to qualify as the BSER, based on historical
trends for construction of new simple cycle turbines and the operation
of those turbines in 2021, a BSER based on 30 percent low-GHG hydrogen
co-firing by volume for low load combustion turbines would result in
annual reductions of 49,000 tons of CO2.
2. BSER for Base Load and Intermediate Load Subcategories--First
Component
This section describes the first component of the EPA's proposed
BSER for newly constructed and reconstructed combustion turbines in the
base load and intermediate load subcategories. For combustion turbines
in the intermediate load subcategory, this first component of the BSER
is the use of high-efficiency simple cycle turbine technology in
combination with the best operating and maintenance practices. For
combustion turbines in the base load subcategory, the first component
of the BSER is the use of high-efficiency combined cycle technology in
combination with the best operating and maintenance practices.
a. Lower Emitting Fuels
The EPA is not proposing lower emitting fuels as the BSER for
intermediate load or base load EGUs because, as described earlier in
this section, it would achieve few GHG emission reductions compared to
highly efficient generation.
b. Highly Efficient Generation
The use of highly efficient generating technology in combination
with the best operating and maintenance practices has been demonstrated
by multiple facilities for decades. Notably, over time, as technologies
have improved, what is considered highly efficient has changed as well.
Highly efficient generating technology is available and offered by
multiple vendors for both simple cycle and combined cycle combustion
turbines. Both types of turbines can also employ best operating and
maintenance practices, which include routine operating and maintenance
practices that minimize fuel use.
For simple cycle combustion turbines, manufacturers continue to
improve the efficiency by increasing firing temperature, increasing
pressure ratios, using intercooling on the air compressor, and adopting
other measures. These improved designs allow for improved operating
efficiencies and reduced emission rates. Design efficiencies of simple
cycle combustion turbines range from 33 to 40 percent. Best operating
practices for simple cycle combustion turbines include proper
maintenance of the combustion turbine flow path components and the use
of inlet air cooling to reduce efficiency losses during periods of high
ambient temperatures.
For combined cycle turbines, high-efficiency technology uses a
highly efficient combustion turbine engine matched with a high-
efficiency HRSG. The most efficient combined cycle EGUs use HRSG with
three different steam pressures and incorporate a steam reheat cycle to
maximize the efficiency of the Rankine cycle. It is not necessarily
practical for owner/operators of combined cycle facilities using a
turbine engine with an exhaust temperature below 593 [deg]C or a steam
turbine engine smaller than 60 MW to incorporate a steam reheat cycle.
Smaller combustion turbine engines, less than those rated at
approximately 2,000 MMBtu/h, tend to have lower
[[Page 33287]]
exhaust temperatures and are paired with steam turbines of 60 MW or
less. These smaller combined cycle units are limited to using triple-
pressure steam without a reheat cycle. This reduces the overall
efficiency of the combined cycle unit by approximately 2 percent.
Therefore, the EPA is proposing less stringent standards of performance
for smaller combined cycle EGUs with base load ratings of less than
2,000 MMBtu/h relative to those for larger combined cycle combustion
turbine EGUs. High efficiency also includes, but is not limited to, the
use of the most efficient steam turbine and minimizing energy losses
using insulation and blowdown heat recovery. Best operating and
maintenance practices include, but are not limited to, minimizing steam
leaks, minimizing air infiltration, and cleaning and maintaining heat
transfer surfaces.
New technologies are available for new simple and combined cycle
EGUs that could reduce emissions beyond what is currently being
achieved by the best performing EGUs. For example, pressure gain
combustion in the turbine engine would increase the efficiency of both
simple and combined cycle EGUs. For combined cycle EGUs, the HRSG could
be designed to utilize supercritical steam conditions or to utilize
supercritical CO2 as the working fluid instead of water;
useful thermal output could be recovered from a compressor intercooler
and boiler blowdown; and fuel preheating could be implemented. For
additional information on these and other technologies that could
reduce the emissions rate of new combustion turbines, see the Efficient
Generation at Combustion Turbine Electric Generating Units TSD, which
is available in the rulemaking docket. The EPA is soliciting comment on
whether these technologies should be incorporated into a standard of
performance based on an efficient generation BSER. To the extent
commenters support the inclusion of emission reductions from the use of
these technologies, the EPA requests that cost information and
potential emission reductions be included.
i. Adequately Demonstrated
The EPA proposes that highly efficient simple cycle and combined
cycle designs are adequately demonstrated because highly efficient
simple cycle EGUs and highly efficient combined cycle EGUs have been
demonstrated by multiple facilities for decades, the efficiency
improvements of the most efficient designs are incremental in nature
and do not change in any significant way how the combustion turbine is
operated or maintained, and the levels of efficiency that the EPA is
proposing have been achieved by many recently constructed turbines.
Approximately 14 percent of simple cycle and combined cycle combustion
turbines that have commenced operation since 2015 have maintained
emission rates below the proposed standards, demonstrating that the
efficient generation technology described in this BSER is commercially
available and that the standards of performance the EPA is proposing
are achievable.
ii. Costs
In general, advanced generation technologies enhance operational
efficiency compared to lower efficiency designs. Such technologies
present little incremental capital cost compared to other types of
technologies that may be considered for new and reconstructed sources.
In addition, more efficient designs have lower fuel costs that offset
at least a portion of the increase in capital costs.
For the intermediate load subcategory, the EPA proposes that the
costs of high-efficiency simple cycle combustion turbines are
reasonable. As described in the subcategory section, the cost of
combustion turbine engines is dependent upon many factors, but the EPA
estimates that that the capital cost of a high-efficiency simple cycle
turbine is 5 percent more than a comparable lower efficiency simple
cycle turbine. Assuming all other costs are the same and that the high-
efficiency simple cycle turbine uses 6 percent less fuel, high-
efficiency simple cycle combustion turbines have a lower LCOE compared
to standard efficiency simple cycle combustion turbines at a 12-
operating-month capacity factor of approximately 20 percent. Therefore,
a BSER based on the use of high-efficiency simple cycle combustion
turbines for intermediate load combustion turbines would have minimal,
if any, overall compliance costs since the capital costs would be
recovered through reduced fuel costs. The EPA considered but is not
proposing combined cycle unit design for combustion turbines in the
intermediate subcategory because the capital cost of a combined cycle
EGU is approximately 250 percent that of a comparable-sized simple
cycle EGU and because the amount of GHG reductions that could be
achieved by operating combined cycle EGUs as intermediate load EGUs is
unclear. Furthermore, intermediate load combustion turbines start and
stop so frequently that there might not be sufficient periods of
continuous operation where the HRSG would have sufficient time to
generate steam to operate the steam turbine enough to significantly
lower the emissions rate of the EGU.
For the base load subcategory, the EPA proposes that the cost of
high-efficiency combined cycle EGUs is reasonable. While the capital
costs of a higher efficiency combined cycle EGUs are 1.9 percent higher
than standard efficiency combined cycle EGUs, fuel use is 2.6 percent
lower.\234\ The reduction in fuel costs fully offset the capital costs
at capacity factors of 40 percent or greater over the expected 30-year
life of the facility. Therefore, a BSER based on the use of high-
efficiency combined cycle combustion turbines for base load combustion
turbines would have minimal, if any, overall compliance costs since the
capital costs would be recovered through reduced fuel costs over the
expected 30-year life of the facility. For additional information on
costs, see the Efficient Generation at Combustion Turbine Electric
Generating Units TSD, which is available in the rulemaking docket.
---------------------------------------------------------------------------
\234\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A
(October 2022), https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Use of highly efficient simple cycle and combined cycle generation
reduces all non-air quality health and environmental impacts and energy
requirements as compared to use of less efficient generation. Even when
operating at the same input-based emissions rate, the more efficient a
unit is, the less fuel is required to produce the same level of output;
and, as a result, emissions are reduced for all pollutants. The use of
highly efficient simple cycle turbines, compared to the use of less
efficient simple cycle turbines, reduces all pollutants. Similarly, the
use of high-efficiency combined combustion turbines, compared to the
use of less efficient combine cycle turbines, reduces all pollutants.
By the same token, because improved efficiency allows for more
electricity generation from the same amount of fuel, it will not have
any adverse effects on energy requirements.
Designating highly efficient generation as part of the BSER for new
and reconstructed base load and intermediate load combustion turbines
will not have significant impacts on the
[[Page 33288]]
nationwide supply of electricity, electricity prices, or the structure
of the electric power sector. On a nationwide basis, the additional
costs of the use of highly efficient generation will be small because
the technology does not add significant costs and at least some of
those costs are offset by reduced fuel costs. In addition, at least
some of these new combustion turbines would be expected to incorporate
highly efficient generation technology in any event.
iv. Extent of Reductions in CO2 Emissions
The EPA estimated the potential emission reductions associated with
a standard that reflects the application of highly efficient generation
as BSER for the intermediate load and base load subcategories. As
discussed in section VII.G, the EPA determined that the standards of
performance reflecting this BSER are 1,150 lb CO2/MWh-gross
for intermediate load and 770 lb CO2/MWh-gross for large
base load combustion turbines.
Between 2015 and 2021, an average of 16 simple cycle turbines
commenced operation per year. Of these, the EPA estimates that an
average of six operated at greater than a 20 percent capacity factor on
a 12-operating-month basis and thus would be considered intermediate
load combustion turbines. For recent intermediate load simple cycle
turbines, the EPA determined that the weighted average maximum 12-
operating-month emissions rate \235\ is 1,250 lb CO2/MWh-
gross. This is 8.3 percent higher than the proposed intermediate load
standard of 1,150 lb CO2/MWh-gross. Therefore, the EPA
estimates that the proposed standard of performance based on the
application of the proposed BSER for intermediate load combustion
turbines would reduce the GHG emissions from those sources by 8.3
percent annually. Based on historical trends for construction of new
simple cycle turbines and the operation of those turbines in 2021, the
proposed standards for intermediate load combustion turbines would
result in annual reductions of 44,000 tons of CO2 as well as
13 tons of NOX. For the base load subcategory, the weighted
average maximum 12-operating-month emissions rate of large (base load
ratings of 2,000 MMBtu/h or more) NGCC combustion turbines that
commenced operation since 2015 has been 810 lb CO2/MWh-
gross. This is 5 percent higher than the proposed standard of 770 lb
CO2/MWh-gross for large base load combustion turbines. The
only small, combined cycle combustion turbine (base load rating of 593
MMBtu/h) reporting emissions that commenced operation since 2015 has
had a reported annual emissions rate of 870 lb CO2/MWh-
gross, which is slightly lower than the proposed standard of 875 lb
CO2/MWh-gross for a small base load combustion turbine with
a base load rating of 593 MMBtu/h. Therefore, the EPA estimates that
the proposed standards would require owners/operators to construct and
maintain highly efficient combined cycle combustion turbines that would
result in reductions in emissions of approximately 5 percent for new
large stationary combustion EGUs and maintaining best performing
emission rates for new small stationary combustion EGUs. Using
historical trends for new combined cycle turbines and the operation of
those combustion turbines in 2021, the proposed standards for base load
combustion turbines would result in annual reductions of 940,000 tons
of CO2 as well as 75 tons of NOX.
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\235\ The EPA is defining the achievable emissions rate as
either the maximum 12-operating-month or the 99th percent confidence
12-operating-month emissions rate. The weighted average maximum
emissions rate is the heat input weighted overall average of the
maximum emission rates.
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v. Promotion of the Development and Implementation of Technology
The EPA also considered the potential impact of selecting highly
efficient generation technology as the BSER in promoting the
development and implementation of improved control technology. This
technology is more efficient than the average new generation technology
and determining it to be a component of the BSER will advance its
penetration throughout the industry. Accordingly, consideration of this
factor supports the EPA's proposal to determine this technology to be
the first component of the BSER.
c. Low-GHG Hydrogen and CCS
For reasons discussed in sections VII.F.3.b.v (CCS) and
VII.F.3.c.vi (low-GHG hydrogen), the EPA is not proposing either CCS or
co-firing low-GHG hydrogen as the first component of the BSER for
intermediate load or base load EGUs.
d. Proposed BSER
The EPA proposes that highly efficient generating technology in
combination with the best operating and maintenance practices is the
first component BSER for base load and intermediate load combustion
turbines and the phase 1 standards of performance are based on the
application of that technology. Specifically, the use of highly
efficient simple cycle technology in combination with the best
operating and maintenance practices is the first component of the BSER
for intermediate load combustion turbines. The use of highly efficient
combined cycle technology in combination with best operating and
maintenance practices is the first component of the BSER for base load
combustion turbines.
Highly efficient generation qualifies as a component of the BSER
because it is adequately demonstrated, it can be implemented at
reasonable cost, it achieves emission reductions, and it does not have
significant adverse non-air quality health or environmental impacts or
significant adverse energy requirements. The fact that it promotes
greater use of advanced technology provides additional support;
however, the EPA would consider highly efficient generation to be a
component of the BSER for base load and intermediate load combustion
turbines even without taking this factor into account.
3. BSER for Base Load and Intermediate Load Subcategories--Second and
Third Components
This section describes the proposed second (and in some cases
third) component of the BSER for base load and intermediate load
combustion turbines, which would be reflected in the second phase (and
in some cases third phase) standards of performance. The proposed
second component of the BSER for base load combustion turbines that are
adopting the CCS pathway is the use of 90 percent CCS; and the
corresponding standard of performance would apply beginning in 2035.
The second component of the BSER for base load combustion turbines that
are adopting the low-GHG hydrogen co-firing pathway and for
intermediate load combustion turbines is co-firing 30 percent (by
volume) low-GHG hydrogen and the corresponding standard of performance
would apply beginning in 2032. The third component of the BSER would
apply only to base load combustion turbines that are subject to a
second phase standard that is based on co-firing 30 percent (by volume)
low-GHG hydrogen. For those sources, the third component of the BSER is
co-firing 96 percent (by volume) low-GHG hydrogen and the corresponding
standard of performance would apply beginning in 2038. The EPA is also
soliciting comment on whether intermediate load combustion turbines
should be subject to a more stringent third phase standard based on 96
percent low-GHG hydrogen co-firing by 2038. A BSER based on 96 percent
co-firing would result in a standard of
[[Page 33289]]
performance of 140 lb CO2/MWh-gross for a natural gas-fired
intermediate load combustion turbine.
a. Authority To Promulgate a Multi-Part BSER and Standard of
Performance
The EPA's proposed approach of promulgating standards of
performance that apply in multiple phases, based on determining the
BSER to be a set of controls with multiple components, is consistent
with CAA section 111(b). That provision authorizes the EPA to
promulgate ``standards of performance,'' CAA section 111(b)(1)(B),
defined, in the singular, as ``a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable
through the application of the [BSER].'' CAA section 111(a)(1). CAA
section 111(b)(1)(B) further provides, ``[s]tandards of performance . .
. shall become effective upon promulgation.'' In this rulemaking, the
EPA is proposing to determine that the BSER is a set of controls that,
depending on the subcategory, include either highly efficient
generation plus use of CCS or highly efficient generation plus co-
firing low-GHG hydrogen. The EPA is further proposing that affected
sources can apply the first component of the BSER--highly efficient
generation--by the effective date of the final rule and can apply both
the first and second components of the BSER--highly efficient
generation in combination with co-firing 30 percent (by volume) low-GHG
hydrogen and highly efficient generation in combination with 90 percent
CCS--in 2032 and 2035, respectively. The EPA is also proposing that
certain sources can apply the third component of the BSER--co-firing 96
percent (by volume) low-GHG hydrogen--by 2038.
Accordingly, the EPA is proposing standards of performance that
reflect the application of this multi-component BSER and that take the
form of standards of performance that affected sources must comply with
in either two or three phases. Affected sources must comply with the
first phase standards that are based on the application of the first
component of the BSER upon initial startup of the facility. The second
phase standards are based on the application of both the first and
second components of the BSER by 2032 (for those sources utilizing co-
firing low-GHG hydrogen) and by 2035 (for those sources utilizing CCS).
The third phase standards are only applicable to those sources that are
subject to a second phase standard of performance based on the highly
efficient generation in combination with co-firing 30 percent (by
volume) low-GHG hydrogen. The third phase standards for those sources
are based on the application of the first component of the BSER and on
the third component, which is co-firing 96 percent (by volume) low-GHG
hydrogen by 2038. In this manner, this multi-phase standard of
performance ``become[s] effective upon promulgation.'' CAA section
111(b)(1)(B). That is, upon promulgation, affected sources become
subject to a standard of performance that limits their emissions
immediately, which is the first phase of the standard of performance,
and they also become subject to more stringent standards beginning in
2032 or later, which are the second and in some cases third phase of
the standard of performance.
D.C. Circuit caselaw supports the proposition that CAA section 111
authorizes the EPA to determine that controls qualify as the BSER--
including meeting the ``adequately demonstrated'' criterion--even if
the controls require some amount of ``lead time,'' which the court has
defined as ``the time in which the technology will have to be
available.'' \236\ The caselaw's interpretation of ``adequately
demonstrated'' to accommodate lead time accords with common sense and
the practical experience of certain types of controls, discussed below.
Consistent with this caselaw, the phased implementation of the
standards of performance in this rule ensures that facilities have
sufficient lead time for planning and implementation of the use of CCS
or low GHG-hydrogen-based controls necessary to comply with the second
phase of the standards, and thereby ensures that the standards are
achievable. Indeed, interpreting CAA section 111 to preclude phased
implementation of standards of performance would be tantamount to
interpreting the provision to preclude standards based on lead time,
which would be contrary to the D.C. Circuit caselaw and common sense.
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\236\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted).
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The EPA has promulgated several prior rulemakings under CAA section
111(b) that have similarly provided the regulated sector with lead time
to accommodate the availability of technology, which also serve as
precedent for the two-phase implementation approach proposed in this
rule. See 81 FR 59332 (August 29, 2016) (establishing standards for
municipal solid waste landfills with 30-month compliance timeframe for
installation of control device, with interim milestones); 80 FR 13672,
13676 (March 16, 2015) (establishing stepped compliance approach to
wood heaters standards to permit manufacturers lead time to develop,
test, field evaluate and certify current technologies to meet Step 2
emission limits); 78 FR 58416, 58420 (September 23, 2013) (establishing
multi-phased compliance deadlines for revised storage vessel standards
to permit sufficient time for production of necessary supply of control
devices and for trained personnel to perform installation); 77 FR
56422, 56450 (September 12, 2012) (establishing standards for petroleum
refineries, with 3-year compliance timeframe for installation of
control devices); 71 FR 39154, 39158 (July 11, 2006) (establishing
standards for stationary compression ignition internal combustion
engines, with 2 to 3-year compliance timeframe and up to 6 years for
certain emergency fire pump engines); 70 FR 28606, 28617 (March 18,
2005) (establishing two-phase caps for mercury standards of performance
from new and existing coal-fired electric utility steam generating
units based on timeframe when additional control technologies were
projected to be adequately demonstrated).\237\ Cf. 80 FR 64662, 64743
(October 23, 2015) (establishing interim compliance period to phase in
final power sector GHG standards to allow time for planning and
investment necessary for implementation activities).\238\ In each
action, the standards and compliance timelines were effective upon the
final rule, with affected facilities required to comply consistent with
the phased compliance deadline specified in each action.
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\237\ Cf. New Jersey v. EPA, 517 F.3d 574, 583-584 (D.C. Cir.
2008) (vacating rule on other grounds).
\238\ Cf. West Virginia v. EPA, 142 S. Ct. 2587 (2022) (vacating
rule on other grounds).
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It should be noted that the multi-phased implementation of the
standards of performance that the EPA is proposing in this rule, like
the delayed or multi-phased standards in prior rules just described, is
distinct from the promulgation of revised standards of performance
under the 8-year review provision of CAA section 111(b)(1)(B). As
discussed in section VII.F, the EPA has determined that the proposed
BSER--highly efficient generation and use of CCS or highly efficient
generation and co-firing low-GHG hydrogen--meet all of the statutory
criteria and are adequately demonstrated for the compliance timeframes
being proposed. Thus, the second and third phases of the standard of
performance, if finalized, would apply to affected facilities that
commence construction after the date of
[[Page 33290]]
this proposal. In contrast, when the EPA later reviews and (if
appropriate) revises a standard of performance under the 8-year review
provision, then affected sources that commence construction after the
date of that proposal of the revised standard of performance would be
subject to that standard, but not sources that commenced construction
earlier.
Similarly, the multi-phased implementation of the standard of
performance that the EPA is proposing in this rule is also distinct
from the promulgation of emission guidelines for existing sources under
CAA section 111(d). Emission guidelines only apply to existing sources,
which are defined in CAA section 111(a)(6) as ``any stationary source
other than a new source.'' Because new sources are defined relative to
the proposal of standards pursuant to CAA section 111(b)(1)(B),
standards of performance adopted pursuant to emission guidelines will
only apply to sources constructed before the date of these proposed
standards of performance for new sources.
b. BSER for Base Load Subcategory of Combustion Turbines Adopting the
CCS Pathway--Second Component
This section describes the second component of the BSER for the
base load subcategory of combustion turbines that are adopting the CCS
pathway. This subcategory is expected to include highly efficient
combined cycle combustion turbines that primarily combust fossil fuels,
and therefore have higher levels of CO2 in the exhaust.
The EPA is proposing the use of CCS as the second component of the
BSER for these combustion turbines. A detailed discussion of CCS
follows. It should be noted that the EPA is also proposing use of CCS
as the BSER for existing long-term coal-fired steam generating units
(i.e., coal-fired utility boilers), as discussed in section X.D of this
preamble, as well as for large and frequently operated existing
stationary combustion turbines. Many aspects of CCS are common to new
combined cycle combustion turbines, existing long-term steam generating
units, and existing stationary combustion turbines, and the following
discussion details those common aspects and considerations.
i. Lower Emitting Fuels
The EPA is not proposing lower emitting fuels as the second
component of the BSER for base load combustion turbines because it
would achieve few emission reductions, compared to highly efficient
generation in combination with the use of CCS.
ii. Highly Efficient Generation
For the reasons described above, the EPA is proposing that highly
efficient generation technology in combination with best operating and
maintenance practices continues to be a component of the BSER that is
reflected in the second phase of the standards of performance for base
load combustion turbine EGUs that are adopting the CCS pathway. Highly
efficient generation reduces fuel use and the amount of CO2
that must be captured by a CCS system. Since less flue gas needs to be
treated, physically smaller carbon capture equipment may be used--
potentially reducing capital, fixed, and operating costs.
iii. CCS
In this section of the preamble, the EPA provides a description of
the components of CCS and evaluates it against the criteria to qualify
as the BSER. CCS has three major components: CO2 capture,
transportation, and sequestration/storage. Post-combustion capture
processes remove CO2 from the exhaust gas of a combustion
system, such as a combustion turbine or a utility boiler. This
technology is referred to as ``post-combustion capture'' because
CO2 is a product of the combustion of the primary fuel and
the capture takes place after the combustion of that fuel. The exhaust
gases from most combustion processes are at atmospheric pressure and
are moved through the flue gas duct system by fans. The concentration
of CO2 in most fossil fuel combustion flue gas streams is
somewhat dilute. Most post-combustion capture systems utilize liquid
solvents--most commonly amine-based solvents--that separate the
CO2 from the flue gas in CO2 scrubber systems
using chemical absorption (or chemisorption). In a chemisorption-based
separation process, the flue gas is processed through the
CO2 scrubber and the CO2 is absorbed by the
liquid solvent. The CO2-rich solvent is then regenerated by
heating the solvent to release the captured CO2.
Another technology, oxy-combustion, uses a purified oxygen stream
from an air separation unit (often diluted with recycled CO2
to control the flame temperature) to combust the fuel and produce a
higher concentration of CO2 in the flue gas, as opposed to
combustion with oxygen in air which contains 80 percent nitrogen. The
high purity CO2 is then compressed and transported,
generally through pipelines, to a site for geologic sequestration
(i.e., the long-term containment of CO2 in subsurface
geologic formations). These sequestration sites are widely available
across the nation, and the EPA has developed a comprehensive regulatory
structure to oversee geological sequestration projects and assure their
safety and effectiveness. See 80 FR 64549 (October 23, 2015).
(A) Adequately Demonstrated
For new base load combustion turbines, the EPA proposes that CCS
with a 90 percent capture rate, beginning in 2035, meets the BSER
criteria. This amount of CCS is feasible and has been adequately
demonstrated. The use of CCS at this level can be implemented at
reasonable cost because it allows affected sources to maximize the
benefits of the IRC section 45Q tax credit, and sources can maintain it
over time by capturing a higher percentage at certain times in order to
offset a lower capture rate at other times due to, for example, the
need to undertake maintenance or due to unplanned capture system
outages. Higher capture rates may be possible--the 2022 NETL Baseline
report evaluated capture rates at 90 and 95 percent with marginal
differences in cost. The Agency is soliciting comment on the range of
the capture rate of CO2 at the stack from 90 to 95 percent
or greater. The EPA also notes that the operating availability (the
fraction of time CCS equipment is operational relative to the operation
of the combustion turbine) may be less than 100 percent and is
therefore soliciting comment on a range in emission reduction from 75
to 90 percent, as further discussed in section VII.G.2 of this
preamble.
The EPA previously determined ``partial CCS'' to be a component of
the BSER (in combination with the use of a highly efficient
supercritical utility boiler) for new coal-fired steam generating units
as part of the 2015 NSPS (80 FR 64538; October 23, 2015).\239\ As
described in that action, reiterated in this section of the preamble,
and detailed further in accompanying TSDs available in the docket for
this rulemaking, numerous projects demonstrate the feasibility and
effectiveness of CCS technology.
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\239\ In the present action, the EPA is not re-opening any
aspect of the CCS determinations in the 2015 NSPS.
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In the 2015 NSPS, the EPA considered coal-fired industrial projects
that had installed at least some components of CCS technology. In doing
so, the EPA recognized that some of those projects had received
assistance in the form of grants, loan guarantees, and Federal tax
credits for investment in ``clean coal technology,'' under provisions
of the
[[Page 33291]]
Energy Policy Act of 2005 (``EPAct05''). See 80 FR 64541-42 (October
23, 2015). (The EPA refers to projects that received assistance under
that legislation as ``EPAct05-assisted projects.'') The EPA further
recognized that the EPAct05 included provisions that constrained how
the EPA could rely on EPAct05-assisted projects in determining whether
technology is adequately demonstrated for the purposes of CAA section
111.\240\ The EPA went on to provide a legal interpretation of those
constraints. Under that legal interpretation, ``these provisions [in
the EPAct05] . . . preclude the EPA from relying solely on the
experience of facilities that received [EPAct05] assistance, but [do]
not . . . preclude the EPA from relying on the experience of such
facilities in conjunction with other information.'' \241\ Id. at 64541-
42. In the present action, the EPA is applying the same legal
interpretation and is not reopening it for comment.
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\240\ The relevant EPAct05 provisions include the following:
Section 402(i) of the EPAct05, codified at 42 U.S.C. 15962(a),
provides as follows:
``No technology, or level of emission reduction, solely by
reason of the use of the technology, or the achievement of the
emission reduction, by 1 or more facilities receiving assistance
under this Act, shall be considered to be adequately demonstrated [
] for purposes of section 111 of the Clean Air Act . . . .''
IRC section 48A(g), as added by EPAct05 1307(b), provides as
follows:
``No use of technology (or level of emission reduction solely by
reason of the use of the technology), and no achievement of any
emission reduction by the demonstration of any technology or
performance level, by or at one or more facilities with respect to
which a credit is allowed under this section, shall be considered to
indicate that the technology or performance level is adequately
demonstrated [ ] for purposes of section 111 of the Clean Air Act .
. . .''
Section 421(a) states:
``No technology, or level of emission reduction, shall be
treated as adequately demonstrated for purpose [sic] of section 7411
of this title, . . . solely by reason of the use of such technology,
or the achievement of such emission reduction, by one or more
facilities receiving assistance under section 13572(a)(1) of this
title.''
\241\ In the 2015 NSPS, the EPA adopted several other legal
interpretations of these EPAct05 provisions as well, which it is not
reopening in this rule. See 80 FR 64541 (October 23, 2015).
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(1) CO2 Capture Technology
The EPA is proposing that the CO2 capture component of
CCS has been adequately demonstrated and is technically feasible based
on the demonstration of the technology at existing coal-fired steam
generating units and industrial sources in addition to combustion
turbines. While the EPA would propose that the CO2 capture
component of CCS is adequately demonstrated on those bases alone, this
determination is further corroborated by EPAct05-assisted projects.
Various technologies may be used to capture CO2, the
details of which are described in the GHG Mitigation Measures for Steam
Generating Units TSD, which is available in the rulemaking docket.\242\
For post-combustion capture, these technologies include solvent-based
methods (e.g., amines, chilled ammonia), solid sorbent-based methods,
membrane filtration, pressure-swing adsorption, and cryogenic
methods.\243\ Lastly, as noted above, oxy-combustion uses a purified
oxygen stream from an air separation unit (often diluted with recycled
CO2 to control the flame temperature) to combust the fuel
and produce a higher concentration of CO2 in the flue gas,
as opposed to combustion with oxygen in air which contains 80 percent
nitrogen. The CO2 can then be separated by the
aforementioned CO2 capture methods. Of the available capture
technologies, solvent-based processes have been the most widely
demonstrated at commercial scale for post-combustion capture and are
applicable to use with either combustion turbines or steam generating
units.
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\242\ Technologies to capture CO2 are also discussed
in the GHG Mitigation Measures--Carbon Capture and Storage for
Combustion Turbines TSD.
\243\ For pre-combustion capture (as is applicable to an IGCC
unit), syngas produced by gasification passes through a water-gas
shift catalyst to produce a gas stream with a higher concentration
of hydrogen and CO2. The higher CO2
concentration relative to conventional combustion flue gas reduces
the demands (power, heating, and cooling) of the subsequent
CO2 capture process (e.g., solid sorbent-based or
solvent-based capture), the treated hydrogen can then be combusted
in the unit.
---------------------------------------------------------------------------
Solvent-based capture processes usually use an amine (e.g.,
monoethanolamine, MEA). Carbon capture occurs by reactive absorption of
the CO2 from the flue gas into the amine solution in an
absorption column. The amine reacts with the CO2 but will
also react with potential contaminants in the flue gas, including
SO2. After absorption, the CO2-rich amine
solution passes to the solvent regeneration column, while the treated
gas passes through a water 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
CO2. The released CO2 is then compressed and
transported offsite, usually by pipeline. The amine solution from the
regenerating column is cooled and sent back to the absorption column,
and any spent solvent is replenished with new solvent.
(2) Capture Demonstrations at Coal-Fired Steam Generating Units and
Industrial Processes
The function, design, and operation of post-combustion
CO2 capture equipment is similar, although not identical,
for both steam generating units and combustion turbines. As a result,
application of CO2 capture at existing coal-fired steam
generating units helps demonstrate the adequacy of the CO2
capture component of CCS.
SaskPower's Boundary Dam Unit 3, a 110 MW lignite-fired unit in
Saskatchewan, Canada, has demonstrated CO2 capture rates of
90 percent using an amine-based post-combustion capture system
retrofitted to the existing steam generating unit. The capture plant,
which began operation in 2014, was the first full-scale CO2
capture system retrofit on an existing coal-fired power plant. It uses
the amine-based Shell CANSOLV process, with integrated heat and power
from the steam generating unit.\244\ While successfully demonstrating
the commercial-scale feasibility of 90 percent capture rates, the plant
has also provided valuable lessons learned for the next generation of
capture plants. A feasibility study for SaskPower's Shand Power Station
indicated achievable capture rates of 97 percent, even at lower
loads.\245\
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\244\ Giannaris, S., et al. Proceedings of the 15th
International Conference on Greenhouse Gas Control Technologies
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
\245\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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For all industrial processes, operational availability (the percent
of time a unit operates relative to its planned operation) is usually
less than 100 percent due to unplanned maintenance and other factors.
As a first-of-a-kind commercial-scale project, Boundary Dam Unit 3
experienced some additional challenges with availability during its
initial years of operation, due to the fouling of heat exchangers and
issues with its CO2 compressor.\246\ However, identifying
and correcting those problems has improved the operational availability
of the capture system. The facility has reported greater than 90
percent capture system
[[Page 33292]]
availability in the second and third quarters of 2022.\247\ Currently,
newly constructed and retrofit CO2 capture systems are
anticipated to have operational availability of around 90 percent, on
the same order of that is expected at coal-fired steam generating
units. The EPA is soliciting comment on information relevant to the
expected operational availability of new and retrofit CO2
capture systems.
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\246\ S&P Global Market Intelligence (January 6, 2022). Only
still-operating carbon capture project battled technical issues in
2021. https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/only-still-operating-carbon-capture-project-battled-technical-issues-in-2021-68302671.
\247\ SaskPower (October 18, 2022). BD3 Status Update: Q3 2022.
https://www.saskpower.com/about-us/our-company/blog/2022/bd3-status-update-q3-2022.
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Several other projects have successfully demonstrated the capture
component of CCS at electricity generating plants and other industrial
facilities, some of which were previously noted in the discussion in
the 2015 NSPS (80 FR 64548-54; October 23, 2015). Amine-based carbon
capture has been demonstrated at AES's Warrior Run (Cumberland,
Maryland) and Shady Point (Panama, Oklahoma) coal-fired power plants,
with the captured CO2 being sold for use in the food
processing industry.\248\ At the 180-MW Warrior Run plant,
approximately 10 percent of the plant's CO2 emissions (about
110,000 metric tons of CO2 per year) has been captured since
2000 and sold to the food and beverage industry. AES's 320-MW coal-
fired Shady Point plant captured CO2 from an approximate 5
percent slipstream (about 66,000 metric tons of CO2 per
year) from 2001 through around 2019.\249\ These facilities, which have
operated for multiple years, clearly show the technical feasibility of
post-combustion carbon capture.
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\248\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\249\ Shady Point Plant (River Valley) was sold to Oklahoma Gas
and Electric in 2019. https://www.oklahoman.com/story/business/columns/2019/05/23/oklahoma-gas-and-electric-acquires-aes-shady-point-after-federal-approval/60454346007/.
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The capture component of CCS has also been demonstrated at other
industrial processes. Since 1978, the Searles Valley Minerals soda ash
plant in Trona, California, has used an amine-based system to capture
approximately 270,000 metric tons of CO2 per year from the
flue gas of a coal-fired industrial power plant that generates steam
and power for onsite use. The captured CO2 is used for the
carbonation of brine in the process of producing soda ash.\250\
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\250\ IEA (2009), World Energy Outlook 2009, OECD/IEA, Paris.
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The Quest CO2 capture facility in Alberta, Canada, uses
amine-based CO2 capture retrofitted to three existing steam
methane reformers at the Scotford Upgrader facility (operated by Shell
Canada Energy) to capture and sequester approximately 80 percent of the
CO2 in the produced syngas.\251\ The Quest facility has been
operating since 2015 and captures approximately 1 million metric tons
of CO2 per year.
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\251\ Quest Carbon Capture and Storage Project Annual Summary
Report, Alberta Department of Energy: 2021. https://open.alberta.ca/publications/quest-carbon-capture-and-storage-project-annual-report-2021.
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(3) Capture Demonstrations at Combustion Turbines
While most demonstrations of CCS have been for applications other
than combustion turbines, CCS has been successfully applied to an
existing combined cycle EGU and several other projects are in
development, as discussed immediately below. Currently available post-
combustion amine-based carbon capture systems require that the flue gas
be cooled prior to entering the carbon capture equipment. This holds
true for the exhaust from a combustion turbine. The most energy
efficient way to do this is to use a HSRG--which, as explained above,
is an integral component of a combined cycle turbine system--to
generate additional useful output. Because simple cycle combustion
turbines do not incorporate a HRSG, the Agency is not considering the
use of CCS as a potential component of the BSER for them.
(a) CCS on Combined Cycle EGUs
Examples of the use of CCS on combined cycle EGUs include the
Bellingham Energy Center in south central Massachusetts and the
proposed Peterhead Power Station in Scotland. The Bellingham plant used
Fluor's Econamine FG Plus\SM\ capture system and demonstrated the
commercial viability of carbon capture on a combined cycle combustion
turbine EGU using first-generation technology. The 40-MW slipstream
capture facility operated from 1991 to 2005 and captured 85 to 95
percent of the CO2 in the slipstream for use in the food
industry.\252\ In Scotland, the proposed 900-MW Peterhead Power Station
combined cycle EGU with CCS is in the planning stages of development.
It is anticipated that the power plant will be operational by the end
of the 2020s and will have the potential to capture 90 percent of the
CO2 emitting from the combined cycle facility and sequester
up to 1.5 million metric tons of CO2 annually. A storage
site being developed 62 miles off the Scottish North Sea coast might
serve as a destination for the captured CO2.\253\ Moreover,
an 1,800-MW NGCC EGU that will be constructed in West Virginia and will
utilize CCS has been announced. The project is planned to begin
operation later this decade, and its feasibility was partially credited
to the expanded IRC section 45Q tax credit for sequestered
CO2 provided through the IRA.\254\
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\252\ U.S. Department of Energy (DOE). Carbon Capture
Opportunities for Natural Gas Fired Power Systems. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems.
\253\ Buli, N. (2021, May 10). SSE, Equinor plan new gas power
plant with carbon capture in Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/.
\254\ Competitive Power Ventures (2022). Multi-Billion Dollar
Combined Cycle Natural Gas Power Station with Carbon Capture
Announced in West Virginia. Press Release. September 16, 2022.
https://www.cpv.com/2022/09/16/multi-billion-dollar-combinedcycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/.
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(b) Net Power Cycle
In addition, there are several planned projects using the NET Power
Cycle.\255\ The NET Power Cycle is a proprietary process for producing
electricity that combusts a fuel with purified oxygen and uses
supercritical CO2 as the working fluid instead of water/
steam. This cycle is designed to achieve thermal efficiencies of up to
59 percent.\256\ Potential advantages of this cycle are that it emits
no NOX and produces a stream of high-purity CO2
\257\ that can be delivered by pipeline to a storage or sequestration
site without extensive processing. A 50-MW (thermal) test facility in
La Porte, Texas was completed in 2018 and was synchronized to the grid
in 2021. There are several announced commercial projects proposing to
use the NET Power Cycle. These include the 280-MW Broadwing Clean
Energy Complex in Illinois, and several international projects.
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\255\ https://netpower.com/technology/. The Net Power Cycle was
formerly referred to as the Allam-Fetvedt cycle.
\256\ Yellen, D. (2020, May 25). Allam Cycle carbon capture gas
plants: 11 percent more efficient, all CO2 captured.
Energy Post. https://energypost.eu/allam-cycle-carbon-capture-gas-plants-11-more-efficient-all-co2-captured/.
\257\ This allows for capture of over 97 percent of the
CO2 emissions. www.netpower.com.
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(4) EPAct05-Assisted CO2 Capture Projects
While the EPA is proposing that the capture component of CCS is
adequately demonstrated based solely on the other demonstrations of
CO2 capture discussed in this preamble, adequate
demonstration of CO2 capture technology is further
corroborated by
[[Page 33293]]
CO2 capture projects assisted by grants, loan guarantees,
and Federal tax credits for ``clean coal technology'' authorized by the
EPAct05. 80 FR 64541-42 (October 23, 2015).
(a) EPAct05-Assisted CO2 Capture Projects at Coal-Fired
Steam Generating Units
Petra Nova is a 240 MW-equivalent capture facility that is the
first at-scale application of carbon capture at a coal-fired power
plant in the U.S. The system is located at the W.A. Parish Generating
Station in Thompsons, Texas, and began operation in 2017, successfully
capturing and sequestering CO2 for several years. Although
the system was put into reserve shutdown (i.e., idled) in May 2020,
citing the poor economics of utilizing captured CO2 for
enhanced oil recovery (EOR) at that time, there are reports of plans to
restart the capture system.\258\ A final report from National Energy
Technology (NETL) details the success of the project and what was
learned from this first-of-a-kind demonstration at scale.\259\ The
project used Mitsubishi Heavy Industry's proprietary KM-CDR
Process[supreg], a process that is similar to an amine-based solvent
process but that uses a proprietary solvent and is optimized for
CO2 capture from a coal-fired generator's flue gas. During
its operation, the project successfully captured 92.4 percent of the
CO2 from the slip stream of flue gas processed with 99.08
percent of the captured CO2 sequestered by EOR. Plant Barry
in Mobile, Alabama, began using the KM-CDR Process[supreg] in 2011 for
a fully integrated 25-MW CCS project with a capture rate of 90
percent.\260\ The CCS project at Plant Barry captured approximately
165,000 tons of CO2 annually, which is then transported via
pipeline and sequestered underground in geologic formations. See 80 FR
64552 (October 23, 2015).
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\258\ ``The World's Largest Carbon Capture Plant Gets a Second
Chance in Texas'' Bloomberg News, February 8, 2023. https://www.bloomberg.com/news/articles/2023-02-08/the-world-s-largest-carbon-capture-plant-gets-a-second-chance-in-texas?leadSource=uverify%20wall.
\259\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
\260\ U.S. Department of Energy (DOE). National Energy
Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741.
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(b) EPAct05-Assisted CO2 Capture Projects at Stationary
Combustion Turbines
There are several EPAct05-assisted projects related to NGCC units
including: 261 262 263 264 265
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\261\ General Electric (GE) (2022). U.S. Department of Energy
Awards $5.7 Million for GE-Led Carbon Capture Technology Integration
Project Targeting to Achieve 95% Reduction of Carbon Emissions.
Press Release. February 15, 2022. https://www.ge.com/news/press-releases/us-department-of-energy-awards-57-million-for-ge-led-carbon-capture-technology.
\262\ Larson, A. (2022). GE-Led Carbon Capture Project at
Southern Company Site Gets DOE Funding. Power. https://www.powermag.com/ge-led-carbon-capture-project-at-southern-company-site-gets-doe-funding/.
\263\ U.S. Department of Energy (DOE) (2021). DOE Invests $45
Million to Decarbonize the Natural Gas Power and Industrial Sectors
Using Carbon Capture and Storage. October 6, 2021. https://www.energy.gov/articles/doe-invests-45-million-decarbonize-natural-gas-power-and-industrial-sectors-using-carbon.
\264\ DOE (2022). Additional Selections for Funding Opportunity
Announcement 2515. Office of Fossil Energy and Carbon Management.
https://www.energy.gov/fecm/additional-selections-funding-opportunity-announcement-2515.
\265\ DOE (2019). FOA 2058: Front-End Engineering Design (FEED)
Studies for Carbon Capture Systems on Coal and Natural Gas Power
Plants. Office of Fossil Energy and Carbon Management. https://www.energy.gov/fecm/foa-2058-front-end-engineering-design-feed-studies-carbon-capture-systems-coal-and-natural-gas.
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General Electric (GE) (Bucks, Alabama) was awarded
$5,771,670 to retrofit an NGCC facility with CCS technology to capture
95 percent of CO2 and is targeting commercial deployment by
2030.
Wood Environmental & Infrastructure Solutions (Blue Bell,
Pennsylvania) was awarded $4,000,000 to complete an engineering design
study for CO2 capture at the Shell Chemicals Complex. The
aim is to reduce CO2 emissions by 95 percent using post-
combustion technology to capture CO2 from several plants,
including an onsite natural gas CHP plant.
General Electric Company, GE Research (Niskayuna, New
York) was awarded $1,499,992 to develop a design to capture 95 percent
of CO2 from NGCC flue gas with the potential to reduce
electricity costs by at least 15 percent.
SRI International (Menlo Park, California) was awarded
$1,499,759 to design, build, and test a technology that can capture at
least 95 percent of CO2 while demonstrating a 20 percent
cost reduction compared to existing NGCC carbon capture.
CORMETECH, Inc. (Charlotte, North Carolina) was awarded
$2,500,000 to further develop, optimize, and test a new, lower cost
technology to capture CO2 from NGCC flue gas and improve
scalability to large NGCC plants.
TDA Research, Inc. (Wheat Ridge, Colorado) was awarded
$2,500,000 to build and test a post-combustion capture process to
improve the performance of NGCC flue gas CO2 capture.
GE Gas Power (Schenectady, New York) was awarded
$5,771,670 to perform an engineering design study to incorporate a 95
percent CO2 capture solution for an existing NGCC site while
providing lower costs and scalability to other sites.
Electric Power Research Institute (EPRI) (Palo Alto,
California) was awarded $5,842,517 to complete a study to retrofit a
700-Mwe NGCC with a carbon capture system to capture 95 percent of
CO2.
Gas Technology Institute (Des Plaines, Illinois) was
awarded $1,000,000 to develop membrane technology capable of capturing
more than 97 percent of NGCC CO2 flue gas and demonstrate
upwards of 40 percent reduction in costs.
RTI International (Research Triangle Park, North Carolina)
was awarded $1,000,000 to test a novel non-aqueous solvent technology
aimed at demonstrating 97 percent capture efficiency from simulated
NGCC flue gas.
Tampa Electric Company (Tampa, Florida) was awarded
$5,588,173 to conduct a study retrofitting Polk Power Station with
post-combustion CO2 capture technology aiming to achieve a
95 percent capture rate.
There are also several announced NET Power Cycle based
CO2 capture projects that are EPAct05-assisted. These
include the 280-MW Coyote Clean Power Project on the Southern Ute
Indian Reservation in Colorado and a 300-MW project located near
Occidental's Permian Basin operations close to Odessa, Texas.
Commercial operation of the facility near Odessa, Texas is expected in
2026.
(5) CO2 Transport
(a) Demonstration of CO2 Transport
The majority of CO2 transported in the U.S. is
transported through pipelines. Pipeline transport of CO2 has
been occurring for nearly 60 years, and over this time, the design,
construction, and operational requirements for CO2 pipelines
have been demonstrated.\266\ Moreover, the U.S. CO2 pipeline
network has steadily expanded, and appears primed to continue to do so.
The Pipeline and Hazardous Materials
[[Page 33294]]
Safety Administration (PHMSA) reported that 5,339 miles of
CO2 pipelines were in operation in 2021, a 13 percent
increase in CO2 pipeline miles since 2011.\267\ Moreover,
several major projects have recently been announced to expand the
CO2 pipeline network across the U.S. For example, the
Midwest Carbon Express has proposed to add more than 2,000 miles of
dedicated CO2 pipeline in Iowa, Nebraska, North Dakota,
South Dakota, and Minnesota. The Midwest Carbon Express is projected to
begin operations in 2024.\268\ Another example is the Heartland
Greenway project, which has proposed to add more than 1,300 miles of
dedicated CO2 pipeline in Iowa, Nebraska, South Dakota,
Minnesota, and Illinois. The Heartland Greenway project is projected to
start its initial system commissioning in the second quarter of
2025.\269\ The proximity to existing or planned CO2
pipelines and geologic sequestration sites can be a factor to consider
in the construction of stationary combustion turbines, and pipeline
expansion, when needed, has been proven to be
feasible.270 271 The IIJA also included substantial support
for CO2 transportation infrastructure.
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\266\ For additional information on CO2
transportation infrastructure project timelines, costs and other
details, please see the GHG Mitigation Measures for Steam Generating
Units TSD.
\267\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\268\ Beach, Jeff. ``World's Largest Carbon Capture Pipeline
Aims to Connect 31 Ethanol Plants, Cut across Upper Midwest.''
Agweek, December 6, 2021. https://www.agweek.com/business/worlds-largest-carbon-capture-pipeline-aims-to-connect-31-ethanol-plants-cut-across-upper-midwest.
\269\ Navigator CO2, ``NavCO2 Fact
Sheet.'' 2022. https://d3o151.p3cdn1.secureserver.net/wp-content/uploads/2022/08/HG-Fact-Sheet-vFINAL.pdf.
\270\ For additional information regarding planned or announced
pipelines please see section 4.6.1.2 of the GHG Mitigation Measures
for Steam Generating Units TSD.
\271\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
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(b) Security of CO2 Transport
The safety of existing and new CO2 pipelines that
transport CO2 in a supercritical state is exclusively
regulated by PHMSA. These regulations include standards related to
pipeline design, construction, and testing, operations and maintenance,
operator reporting requirements, operator qualifications, corrosion
control and pipeline integrity management, incident reporting and
response, and public awareness and communications. PHMSA has regulatory
authority to conduct inspections of supercritical CO2
pipeline operations and issue notices to operators in the event of
operator noncompliance with regulatory requirements.\272\ Furthermore,
PHMSA initiated a rulemaking in 2022 to develop and implement new
measures to strengthen its safety oversight of supercritical
CO2 pipelines following investigation into a CO2
pipeline failure in Satartia, Mississippi in 2020.\273\ Following that
incident, PHMSA also issued a Notice of Probable Violation, Proposed
Civil Penalty, and Proposed Compliance Order (Notice) to the operator
related to probable violations of Federal pipeline safety regulations.
The Notice was ultimately resolved through a Consent Agreement between
PHMSA and the operator that includes the assessment of civil penalties
and identifies actions for the operator to take to address the alleged
violations and risk conditions.\274\ PHMSA has further issued an
updated nationwide advisory bulletin to all pipeline operators, and
solicited research proposals to strengthen CO2 pipeline
safety.\275\ Additionally, certain States have authority delegated from
the U.S. Department of Transportation to conduct safety inspections and
enforce State and Federal pipeline safety regulations for intrastate
CO2 pipelines.276 277 These CO2
pipeline controls, in addition to the PHMSA standards, ensure that
captured CO2 will be securely conveyed to a sequestration
site.
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\272\ See generally 49 CFR 190-199.
\273\ PHMSA, ``PHMSA Announces New Safety Measures to Protect
Americans From Carbon Dioxide Pipeline Failures After Satartia, MS
Leak.'' 2022. https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
\274\ Consent Order, Denbury Gulf Coast Pipelines, LLC, CPF No.
4-2022-017-NOPV (U.S. Dep't of Transp. Mar. 24, 2023). https://primis.phmsa.dot.gov/comm/reports/enforce/CaseDetail_cpf_42022017NOPV.html?nocache=7208.
\275\ Ibid.
\276\ New Mexico Public Regulation Commission. 2023.
Transportation Pipeline Safety. New Mexico Public Regulation
Commission, Bureau of Pipeline Safety. https://www.nm-prc.org/transportation/pipeline-safety.
\277\ Texas Railroad Commission. 2023. Oversight & Safety
Division. Texas Railroad Commission. https://www.rrc.texas.gov/about-us/organization-and-activities/rrc-divisions/oversight-safety-division.
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States are also directly involved in siting proposed CO2
pipeline projects. CO2 pipeline siting authorities,
landowner rights, and eminent domain laws reside with the States and
vary from State to State. Pipeline developers may secure rights-of-way
for proposed projects through voluntary agreements with landowners;
pipeline developers may also secure rights-of-way through eminent
domain authority, which typically accompanies siting permits from State
utility regulators with jurisdiction over CO2 pipeline
siting.\278\
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\278\ Congressional Research Service. 2022. Carbon Dioxide
Pipelines: Safety Issues, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
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Transportation of CO2 via pipeline is the most viable
and cost-effective method at the scale needed for sequestration of
captured EGU CO2 emissions. However, CO2 can also
be liquified and transported via vessel (e.g., ship), highway (e.g.,
cargo tank, portable tank), ship, or rail (e.g., tank cars) when
pipelines are not available. Liquefied natural gas and liquefied
petroleum gases are already routinely transported via ship at a large
scale, and the properties of liquified CO2 are not
significantly different.\279\ In fact, the food and beverage as well as
specialty gas industries already have experience transporting
CO2 by rail.\280\ Highway road tankers and rail
transportation can provide for the transport of smaller quantities of
CO2 and can be used in tandem with other modes of
transportation to move CO2 captured from an EGU.\281\
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\279\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
\280\ EU CCUS Projects Network. (2019). Briefing on Carbon
Dioxide Specifications for Transport. https://www.ccusnetwork.eu/sites/default/files/TG3_Briefing-CO2-Specifications-for-Transport.pdf.
\281\ Ibid.
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(6) Geologic Sequestration of CO2
(a) Security of Sequestration
Geologic sequestration (or storage), which is the long-term
containment of a CO2 stream in subsurface geologic
formations, is well proven and broadly available in many locations
across the U.S. Independent analyses of the potential availability of
geologic sequestration capacity in the United States have been
conducted by DOE, and the U.S. Geological Survey (USGS) has also
undertaken a comprehensive assessment of geologic sequestration
resources in the U.S.282 283 Geologic sequestration is based
on a demonstrated understanding of the trapping processes that retain
CO2 in the subsurface; most importantly, geologic
sequestration occurs securely when the CO2 is trapped under
a low permeability
[[Page 33295]]
seal. There have been numerous efforts demonstrating successful
geologic sequestration projects in the U.S. and overseas, and the U.S.
has developed a detailed set of regulatory requirements to ensure the
security of sequestered CO2.
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\282\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
\283\ U.S. Geological Survey Geologic Carbon Dioxide Storage
Resources Assessment Team, 2013, National assessment of geologic
carbon dioxide storage resources--Summary: U.S. Geological Survey
Factsheet 2013-3020. https://pubs.usgs.gov/fs/2013/3020/.
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(i) Demonstration of Geologic Sequestration
Existing project and regulatory experience, along with other
information, indicate that geologic sequestration is a viable long-term
CO2 sequestration option. The effectiveness of long-term
trapping of CO2 has been demonstrated by natural analogues
in a range of geologic settings where CO2 has remained
trapped for millions of years.\284\ For example, CO2 has
been trapped for more than 65 million years in the Jackson Dome,
located near Jackson, Mississippi.\285\ Other examples of natural
CO2 sources include the Bravo Dome and the McElmo Dome in
New Mexico and Colorado, respectively.\286\ These naturally occurring
sequestration sites demonstrate the feasibility of containing the large
volumes of CO2 that may be captured from fossil fuel-fired
EGUs, as these sites have held volumes of CO2 that are much
larger than the volume of CO2 expected to be captured from a
fossil fuel-fired EGU over the course of its useful life. In 2010, the
DOE estimated CO2 reserves of 594 million metric tons at
Jackson Dome, 424 million metric tons at Bravo Dome, and 530 million
metric tons at McElmo Dome.\287\ Between 2000 and 2020, the Department
of Energy-sponsored research totaling $1 billion to prove carbon
storage technologies and enable large-scale deployment. Research
conducted through the Department of Energy's Regional Carbon
Sequestration Partnerships has demonstrated geologic sequestration
through a series of field research projects that increased in scale
over time, injecting more than 11 million tons of CO2 with
no indications of negative impacts to either human health or the
environment.\288\ Building on this experience, the Department of Energy
launched the Carbon Storage Assurance Facility Enterprise (CarbonSAFE)
Initiative in 2016 to demonstrate how knowledge from the Regional
Carbon Sequestration Partnerships can be applied to commercial-scale
safe storage. This initiative is furthering the development and
refinement of technologies and techniques critical to the
characterization of potential sequestration sites greater than 50
million tons.\289\
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\284\ Holloway, S., et al. Natural Emissions of CO2
from the Geosphere and their Bearing on the Geological Storage of
Carbon Dioxide. 2007. Energy 32: 1194-1201.
\285\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
\286\ See K.J. Sathaye, M.A. Hesse, M. Cassidy, D.F. Stockli,
``Constraints on the magnitude and rate of CO2
dissolution at Bravo Dome natural gas field.'' Proceedings of the
National Academy of Sciences 111, 15332-15337. 2014. and Kinder
Morgan. ``Carbon Dioxide (CO2) Operations; CO2
Supply.'' https://www.kindermorgan.com/Operations/CO2/Index.
\287\ DiPietro, P., et al. 2012. ``A Note on Sources of
CO2 Supply for Enhanced-Oil Recovery Operations.'' SPE
Economics & Management.
\288\ Safe Geologic Storage of Captured Carbon Dioxide--DOE's
Carbon Storage R&D Program: Two Decades in Review,'' National Energy
Technology Laboratory, Pittsburgh, April 13, 2020. https://www.netl.doe.gov/sites/default/files/Safe%20Geologic%20Storage%20of%20Captured%20Carbon%20Dioxide_April%2015%202020_FINAL.pdf.
\289\ https://netl.doe.gov/carbon-management/carbon-storage/carbonsafe.
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Numerous additional saline facilities are under development across
the United States. The Great Plains Synfuel Plant currently captures 2
million metric tons of CO2 per year, which is used for
enhanced oil recovery (EOR); a planned addition of saline sequestration
for this facility is expected to increase the amount captured and
sequestered (through both geologic sequestration and EOR) to 3.5
million metric tons of CO2 per year.\290\ The EPA is
currently reviewing Underground Injection Control (UIC) Class VI
geologic sequestration well permit applications for proposed
sequestration sites in at least seven States.291 292
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\290\ Basin Electric Power Cooperative. ``Great Plains Synfuels
Plant Potential to Be Largest Coal-Based Carbon Capture and Storage
Project to Use Geologic Storage,'' September 9, 2021. https://www.basinelectric.com/News-Center/news-releases/Great-Plains-Synfuels-Plant-potential-to-be-largest-coal-based-carbon-capture-and-storage-project-to-use-geologic-storage.
\291\ UIC regulations for Class VI wells facilitate the
injection of CO2 for geologic sequestration while
protecting human health and the environment by ensuring the
protection of underground sources of drinking water. The major
components to be included in UIC Class VI permits are detailed
further in section VII.F.3.b.iii.
\292\ U.S. EPA Class VI Underground Injection Control (UIC)
Class VI Wells Permitted by EPA as of January 12, 2023. https://www.epa.gov/uic/class-vi-wells-permitted-epa.
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Geologic sequestration has been proven to be successful and safe in
projects internationally. The oldest international facility has
geologically sequestered CO2 for over twenty years. In
Norway, facilities conduct offshore sequestration under the Norwegian
continental shelf.\293\ In addition, the Sleipner CO2
Storage facility in the North Sea, which began operations in 1996,
injects around 1 million metric tons of CO2 per year from
natural gas processing.\294\ The Snohvit CO2 Storage
facility in the Barents Sea, which began operations in 2008, injects
around 0.7 million metric tons of CO2 per year from natural
gas processing. The SaskPower carbon capture and storage facility at
Boundary Dam Power Station in Saskatchewan, Canada had, as of mid-2022,
captured 4.6 million tons of CO2 since it began operating in
2014.\295\ Other international sequestration facilities in operation
include Glacier Gas Plant MCCS (Canada),\296\ Quest (Canada), and Qatar
LNG CCS (Qatar).
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\293\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
\294\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com/2022-status-report/introduction/.
\295\ Boundary Dam Carbon Capture Project. https://www.saskpower.com/Our-Power-Future/Infrastructure-Projects/Carbon-Capture-and-Storage/Boundary-Dam-Carbon-Capture-Project.
\296\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com.
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(ii) EPAct05-Assisted Geologic Sequestration Projects
While the EPA is proposing that the sequestration component of CCS
is adequately demonstrated based solely on the other demonstrations of
geologic sequestration discussed in this preamble, adequate
demonstration of geologic sequestration is further corroborated by
geologic sequestration currently operational and planned projects
assisted by grants, loan guarantees, and Federal tax credits for
``clean coal technology'' authorized by the EPAct05. 80 FR 64541-42
(October 23, 2015).
Two saline sequestration facilities are currently in operation in
the U.S. and several are under development.\297\ The Illinois
Industrial Carbon Capture and Storage Project began injecting
CO2 from ethanol production into the Mount Simon Sandstone
in April 2017. The project has the potential to store up to 5.5 million
metric tons of CO2,\298\ and, according to the facility's
report to the EPA's GHGRP, as of 2021, 2.5 million metric tons of
CO2 had been injected
[[Page 33296]]
into the saline reservoir.\299\ The Red Trail Energy CCS facility in
North Dakota, which is the first saline sequestration facility in the
U.S. to operate under a State-led regulatory authority for carbon
storage, began injecting CO2 from ethanol production in
2022.\300\ This project is expected to inject a total of 3.7 million
tons of CO2 over its lifetime.\301\
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\297\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com/.
\298\ Archer Daniels Midland, Monitoring, Reporting, and
Verification Plan CCS#2, 2017. https://www.epa.gov/sites/default/files/2017-01/documents/adm_mrv_plan.pdf.
\299\ EPA Greenhouse Gas Reporting Program. Data reported as of
August 12, 2022.
\300\ Zapantis, Alex, Noora Al Amer, Ian Havercroft, Ruth Ivory-
Moore, Matt Steyn, Xiaoliang Yang, Ruth Gebremedhin, et al. ``Global
Status of CCS 2022.'' Global CCS Institute, 2022. https://status22.globalccsinstitute.com.
\301\ North Dakota Industrial Commission, NDIC Case No. 28848--
Draft Permit Fact Sheet and Storage Facility Permit Application.''
https://www.dmr.nd.gov/oilgas/GeoStorageofCO2.asp. This injection
well is permitted by North Dakota.
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There are additional planned geologic sequestration facilities
across the United States.\302\ Project Tundra, a saline sequestration
project planned at the lignite-fired Milton R. Young Station in North
Dakota is projected to capture 4 million metric tons of CO2
annually.\303\ Finally, in Wyoming, Class VI permit applications have
been filed for a proposed saline sequestration facility located in
Southwestern Wyoming. At full capacity, the facility will permanently
store up to 5 million metric tons of CO2 annually from
industrial facilities in the Nugget saline sandstone reservoir.\304\
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\302\ In addition, Denbury Resources injected CO2
into a depleted oil and gas reservoir at a rate greater than 1.2
million tons/year as part of a DOE Southeast Regional Carbon
Sequestration Partnership study. The Texas Bureau of Economic
Geology tested a wide range of surface and subsurface monitoring
tools and approaches to document sequestration efficiency and
sequestration permanence at the Cranfield oilfield in Mississippi.
Texas Bureau of Economic Geology, ``Cranfield Log.'' https://www.beg.utexas.edu/gccc/research/cranfield.
\303\ Project Tundra. ``Project Tundra.'' https://www.projecttundrand.com/.
\304\ Wyoming DEQ Class VI Permit Applications. https://deq.wyoming.gov/water-quality/groundwater/uic/class-vi/.
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(iii) Security of Geologic Sequestration
Regulatory oversight of geologic sequestration is built upon an
understanding of the proven mechanisms by which CO2 is
retained in geologic formations. These mechanisms include (1)
Structural and stratigraphic trapping (generally trapping below a low
permeability confining layer); (2) residual CO2 trapping
(retention as an immobile phase trapped in the pore spaces of the
geologic formation); (3) solubility trapping (dissolution in the in
situ formation fluids); (4) mineral trapping (reaction with the
minerals in the geologic formation and confining layer to produce
carbonate minerals); and (5) preferential adsorption trapping
(adsorption onto organic matter in coal and shale).
Based on the understanding developed from natural analogs and
existing projects, the security of sequestered CO2 is
expected to increase over time after injection ceases.\305\ This is due
to trapping mechanisms that reduce CO2 mobility over time,
e.g., physical CO2 trapping by a low-permeability geologic
seal or chemical trapping by conversion or adsorption.\306\ In
addition, site characterization, site operations, and monitoring
strategies as required through the Underground Injection Control (UIC)
Program and the GHGRP, discussed below, work in combination to ensure
security and transparency.
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\305\ ``Report of the Interagency Task Force on Carbon Capture
and Storage.'' 2010. https://www.osti.gov/servlets/purl/985209.
\306\ See, e.g., Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture and Storage.
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The UIC Program, the GHGRP and other regulatory requirements
comprise a detailed regulatory framework for facilitating geologic
sequestration in the U.S., according to a 2021 report from the Council
on Environmental Quality (CEQ). This framework is already in place and
capable of reviewing and permitting CCS activities.\307\
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\307\ CEQ. ``Council on Environmental Quality Report to Congress
on Carbon Capture, Utilization, and Sequestration.'' 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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This regulatory framework includes the UIC Class VI well
regulations, promulgated under the authority of the Safe Drinking Water
Act (SDWA); and the GHGRP, promulgated under the authority of the CAA.
The requirements of the UIC and GHGRP programs work together to ensure
that sequestered CO2 will remain securely stored
underground. The UIC regulations facilitate the injection of
CO2 for geologic sequestration while protecting human health
and the environment by ensuring the protection of underground sources
of drinking water (USDW). These regulations are built upon nearly a
half-century of Federal experience regulating underground injection
wells, and many additional years of State UIC program expertise. The
IIJA established a program to assist States and Tribal regulatory
authorities interested in Class VI primacy.\308\ As the EPA considers
Class VI primacy applications, it has indicated that it will require
approaches that balance the use of geologic sequestration with
mitigation of impacts on vulnerable communities. States and Tribes
applying for Class VI primacy are asked to support communities by
implementing an inclusive public participation process, considering
environmental justice impacts on communities, enforcing Class VI
regulatory protections and incorporating other mitigation
measures.\309\
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\308\ On April 27, 2023, the EPA Administrator signed a proposed
rule to approve the State of Louisiana's request to have primacy for
UIC Class VI wells within the state. Louisiana is the third state to
request primacy for UIC Class VI wells. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\309\ EPA. Letter from the EPA Administrator Michael S. Regan to
U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
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To complement the UIC regulations, the EPA included in the GHGRP
air-side monitoring and reporting requirements for CO2
capture, underground injection, and geologic sequestration. These
requirements are included in 40 CFR part 98, subpart RR, also referred
to as ``GHGRP subpart RR.''
The GHGRP subpart RR requirements provide the monitoring mechanisms
to identify, quantify, and address potential leakage. The EPA designed
them to complement and build on UIC monitoring and testing
requirements. Although the regulations for the UIC program are designed
to ensure protection of USDWs from endangerment, the practical effect
of these GHGRP subpart RR requirements is that they also prevent
releases of CO2 to the atmosphere.\310\
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\310\ In 2022, EPA proposed a new GHGRP subpart, ``Geologic
Sequestration of Carbon Dioxide with Enhanced Oil Recovery (EOR)
Using ISO 27916'' (or GHGRP subpart VV). For more information on
proposed GHGRP subpart VV, see section VII.K.2 of this preamble.
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Major components to be included in UIC Class VI permits are site
characterization, area of review,\311\ corrective action,\312\ well
construction and operation, testing and monitoring, financial
responsibility, post-injection site care, well plugging, emergency and
remedial response, and site closure. Reporting under GHGRP subpart RR
is required for, but not limited to, all facilities that have received
a UIC Class VI permit for injection of CO2.\313\ GHGRP
subpart RR requires facilities
[[Page 33297]]
meeting the source category definition (40 CFR 98.440) for any well or
group of wells to report basic information on the mass of
CO2 received for injection; develop and implement an EPA-
approved monitoring, reporting, and verification (MRV) plan; report the
mass of CO2 sequestered using a mass balance approach; and
report annual monitoring activities.314 315 316 317 Although
deep subsurface monitoring is required for UIC Class VI wells at 40 CFR
146.90 and is the primary means of determining if there are any leaks
to a USDW, and is generally effective in doing so, the surface air and
soil gas monitoring employed under a GHGRP subpart RR MRV Plan can be
utilized in addition to subsurface monitoring required under 40 CFR
146.90, if required by the UIC Program Director under 40 CFR 146.90(h),
to further ensure protection of USDWs.\318\ The MRV plan includes five
major components: a delineation of monitoring areas based on the
CO2 plume location; an identification and evaluation of the
potential surface leakage pathways and an assessment of the likelihood,
magnitude, and timing, of surface leakage of CO2 through
these pathways; a strategy for detecting and quantifying any surface
leakage of CO2 in the event leakage occurs; an approach for
establishing the expected baselines for monitoring CO2
surface leakage; and, a summary of considerations made to calculate
site-specific variables for the mass balance equation.\319\
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\311\ Per 40 CFR 146.84(a), the area of review is the region
surrounding the geologic sequestration project where USDWs may be
endangered by the injection activity. The area of review is
delineated using computational modeling that accounts for the
physical and chemical properties of all phases of the injected
carbon dioxide stream and is based on available site
characterization, monitoring, and operational data.
\312\ UIC permitting authorities may require corrective action
for existing wells within the area of review to ensure protection of
underground sources of drinking water.
\313\ 40 CFR 98.440.
\314\ 40 CFR 98.446.
\315\ 40 CFR 98.448.
\316\ 40 CFR 98.446(f)(9) and (10).
\317\ 40 CFR 98.446(f)(12).
\318\ See 75 FR 77263 (December 10, 2010).
\319\ 40 CFR 98.448(a).
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Geologic sequestration efforts on Federal lands as well as those
efforts that are directly supported with Federal funds may need to
comply with other regulations, depending on the nature of the
project.\320\
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\320\ CEQ. ``Council on Environmental Quality Report to Congress
on Carbon Capture, Utilization, and Sequestration.'' 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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(b) Broad Availability of Sequestration
Geologic sequestration potential for CO2 is widespread
and available throughout the U.S. Nearly every State in the U.S. has or
is in close proximity to formations with geologic sequestration
potential, including areas offshore. These areas include deep saline
formation, unmineable coal seams, and oil and gas reservoirs. Moreover,
the amount of storage capacity can readily accommodate the amount of
CO2 for which sequestration could be required under this
proposed rule.
The DOE and the United States Geological Survey (USGS) have
independently conducted preliminary analyses of the availability and
potential CO2 sequestration resources in the U.S. The DOE
estimates are compiled in the DOE's National Carbon Sequestration
Database and Geographic Information System (NATCARB) using volumetric
models and are published in its Carbon Utilization and Sequestration
Atlas (NETL Atlas).\321\ The DOE estimates that areas of the U.S. with
appropriate geology have a sequestration potential of at least 2,400
billion to over 21,000 billion metric tons of CO2 in deep
saline formations, unmineable coal seams, and oil and gas
reservoirs.\322\ The USGS assessment estimates a mean of 3,000 billion
metric tons of subsurface CO2 sequestration potential across
the U.S.\323\
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\321\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
\322\ Ibid.
\323\ U.S. Geological Survey Geologic Carbon Dioxide Storage
Resources Assessment Team, National assessment of geologic carbon
dioxide storage resources--Summary: U.S. Geological Survey Factsheet
2013-3020. 2013. https://pubs.usgs.gov/fs/2013/3020/.
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With respect to deep saline formations, the DOE estimates a
sequestration potential of at least 2,200 billion metric tons of
CO2 in these formations in the U.S. At least 37 States have
geologic characteristics that are amenable to deep saline
sequestration, and an additional 6 States are within 100 kilometers of
potentially amenable deep saline formations in either onshore or
offshore locations.324 325
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\324\ Alaska has deep saline formation storage capacity, geology
amenable to EOR operations, and potential geologic sequestration
capacity in unmineable coal seams.
\325\ The U.S. DOE NETL Carbon Storage Atlas, Fifth Edition did
not assess deep saline formation potential for Alaska, Connecticut,
Hawaii, Maine, Massachusetts, Nevada, New Hampshire, Rhode Island,
and Vermont. We are assuming for purposes of our analysis here that
they do not have storage potential in this type of formation.
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Unmineable coal seams offer another potential option for geologic
sequestration of CO2. Enhanced coalbed methane recovery is
the process of injecting and storing CO2 in unmineable coal
seams to enhance methane recovery. These operations take advantage of
the preferential chemical affinity of coal for CO2 relative
to the methane that is naturally found on the surfaces of coal. When
CO2 is injected, it is adsorbed to the coal surface and
releases methane that can then be captured and produced. This process
effectively ``locks'' the CO2 to the coal, where it remains
stored. States with the potential for sequestration in unmineable coal
seams include Iowa and Missouri, which have little to no saline
sequestration potential and have existing coal-fired EGUs. Unmineable
coal seams have a sequestration potential of at least 54 billion metric
tons of CO2, or 2 percent of total potential in the U.S.,
and are located in 22 States.\326\
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\326\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
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The potential for CO2 sequestration in unmineable coal
seams has been demonstrated in small-scale demonstration projects,
including the Allison Unit pilot project in New Mexico, which injected
a total of 270,000 tons of CO2 over a six-year period (1995-
2001). Further, DOE Regional Carbon Sequestration Partnership projects
have injected CO2 volumes in unmineable coal seams ranging
from 90 tons to 16,700 tons, and completed site characterization,
injection, and post-injection monitoring for sites.327 328
DOE has judged unmineable coal seams worthy of inclusion in the NETL
Atlas.\329\
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\327\ M. Godec et al., ``CO2-ECBM: A Review of its
Status and Global Potential,'' Energy Procedia 63: 5858-5869 (2014).
https://doi.org/10.1016/j.egypro.2014.11.619.
\328\ N. Ripepi et al., ``Central Appalachian Basin
Unconventional (Coal/Organic Shale) Reservoir Small Scale
CO2 Injection,'' US DOE/NETL Annual Carbon Storage and
Oil and Natural Gas Technologies Review Meeting (2017). https://www.netl.doe.gov/sites/default/files/event-proceedings/2017/carbon-storage-oil-and-natural-gas/thur/Nino-Ripepi-VirginiaTech.DOEMeeting.CoalShaleUpdate.8.3.2017.pdf.
\329\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
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Although the large-scale injection of CO2 in coal seams
can lead to swelling of coal, the literature also suggests that there
are available technologies and techniques to compensate for the
resulting reduction in injectivity.\330\ Further, the reduced
injectivity can be anticipated and accommodated in sizing and
characterizing prospective sequestration sites.
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\330\ Xiachun Li & Zhi-Ming Fang, ``Current Status and Technical
Challenges of CO2 Storage in Coal Seams and Enhanced
Coalbed Methane Recovery: An Overview,'' International Journal of
Coal Science & Technology, 93, 99 (2014) (suggesting existing
technologies that can be used to address injectivity reduction in
unmineable coal seams).
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There is sufficient technical basis and scientific evidence that
depleted oil and gas reservoirs represent another option for geologic
storage. The reservoir characteristics of older fields are well known
as a result of exploration and many years of hydrocarbon production
and, in many areas, infrastructure
[[Page 33298]]
already exists for CO2 transportation and storage.\331\
Other types of geologic formations such as organic rich shale and
basalt may also have the ability to store CO2, and DOE is
continuing to evaluate their potential sequestration capacity and
efficacy.\332\
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\331\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
\332\ Goodman, A., et al. ``Methodology for Assessing
CO2 Storage Potential of Organic-Rich Shale Formations.''
Energy Procedia, 12th International Conference on Greenhouse Gas
Control Technologies, GHGT-12, 63 (2014): 5178-84. https://doi.org/10.1016/j.egypro.2014.11.548. NETL DOE. ``Big Sky Carbon
Sequestration Partnership.'' https://netl.doe.gov/coal/carbon-storage/atlas/bscsp. Schaef, T., and McGrail, P. ``Sequestration of
CO2 in Basalt Formations.'' Pacific Northwest National
Laboratory, NETL, DOE, 2013. https://www.netl.doe.gov/sites/default/files/event-proceedings/2013/carbon%20storage/8-00-Schaef-58159-Task-1-082213.pdf.
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The EPA performed a geographic availability analysis in which the
Agency examined areas of the country with sequestration potential in
deep saline formations, unmineable coal seams, and oil and gas
reservoirs; information on existing and probable, planned or under
study CO2 pipelines; and areas within a 100-kilometer (km)
(62-mile) area of locations with sequestration potential. The distance
of 100 km is consistent with the assumptions underlying the NETL cost
estimates for transporting CO2 by pipeline.\333\ Overall,
the EPA found that there are 43 States containing areas within 100 km
from currently assessed onshore or offshore storage resources in deep
saline formations, unmineable coal seams, and depleted oil and gas
reservoirs. There are additional areas that have not yet been assessed
and may provide additional infrastructure capability.\334\
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\333\ Although a 100 km pipeline is used in this analysis, this
does not represent a technical limitation, but rather a
standardization used for NETL cost estimates. As noted in the GHG
Mitigation Measures for Steam Generating Units TSD, large pipelines
connect CO2 sources in south central Colorado, northeast
New Mexico, and Mississippi to Texas, Oklahoma, New Mexico, Utah,
and Louisiana. Additionally, as noted in section VII.F.3.b.iii.(5)
of this preamble, CO2 can by transported via other modes
such as ship, road tanker, or rail tank cars.
\334\ GHG Mitigation Measures for Steam Generating Units TSD,
chapter 4.6.2. As discussed in the TSD, geologic sequestration
potential has not yet been assessed for Connecticut, Hawaii, Nevada,
New Hampshire, Rhode Island, and Vermont, and may provide additional
infrastructure capability.
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As described in the 2015 NSPS, electricity demand in States that
may not have geologic sequestration sites may be served by new
generation, including new base load combustion turbines, built in
nearby areas with geologic sequestration, and this electricity can be
delivered through transmission lines.\335\ This approach has long been
used in the electricity sector because siting an EGU away from a load
center and transmitting the generation long distances to the load area
can be less expensive and easier to permit than siting the EGU near the
load area.
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\335\ This was described as ``coal-by-wire'' in the 2015 NSPS.
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In many of the areas without reasonable access to geologic
sequestration, utilities, electric cooperatives, and municipalities
have a history of joint ownership of electricity generation outside the
region or contracting with electricity generation in outside areas to
meet demand. Some of the areas are in Regional Transmission
Organizations (RTOs),\336\ which engage in planning as well as
balancing supply and demand in real time throughout the RTO's
territory. Accordingly, generating resources in one part of the RTO can
serve load in other parts of the RTO, as well as load outside of the
RTO. For example, the Prairie State Generating Plant, a 1,600-MW coal-
fired EGU in Illinois that is currently considering retrofitting with
CCS, serves load in eight different States from the Midwest to the mid-
Atlantic.\337\ The Intermountain Power Project, a coal-fired plant
located in Delta, Utah, that is converting to burn hydrogen and natural
gas, serves customers in both Utah and California.\338\
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\336\ In this discussion, the term RTO indicates both ISOs and
RTOs.
\337\ https://prairiestateenergycampus.com/about/ownership/.
\338\ https://www.ipautah.com/participants-services-area/.
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(B) Costs
The EPA has evaluated the costs of CCS for new combined cycle
units, including the cost of installing and operating CO2
capture equipment as well as the costs of transport and storage. The
EPA has also compared the costs of CCS for new combined cycle units to
other control costs, in part derived from other rulemakings that the
EPA has determined to be cost reasonable, and the costs are comparable.
Based on these analyses, the EPA is proposing that the costs of CCS for
new combined cycle units are reasonable. Certain elements of the
transport and storage costs are similar for new combustion turbines and
existing steam generating units. In this section, the EPA outlines
these costs and identifies the considerations specific to new
combustion turbines. These costs are significantly reduced by the IRC
section 45Q tax credit. For additional details on the EPA's CCS costing
analysis see the GHG Mitigation Measures for Steam Generating Units
TSD, which is available in the rulemaking docket.
(1) Capture Costs
According to the NETL Fossil Energy Baseline Report (October 2022
revision), before accounting for the IRC section 45Q tax credit for
sequestered CO2, using a 90 percent capture amine-based
post-combustion CO2 capture system increases the capital
costs of a new combined cycle EGU by 115 percent on a $/kW basis,
increases the heat rate by 13 percent, increases incremental operating
costs by 35 percent, and derates the unit (i.e., decreases the capacity
available to generate useful output) by 11 percent.\339\ For a base
load combustion turbine, carbon capture increases the LCOE by 61
percent (an increase of 27 $/MWh) and has an estimated cost of $81/ton
($89/metric ton) of onsite CO2 reduction.\340\ The NETL
costs are based on the use of a second generation amine-based capture
system without exhaust gas recirculation (EGR) and does not take into
account further cost reductions that can be expected to occur as post-
combustion capture systems are more widely deployed.
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\339\ CCS reduced the net output of the NETL F class combined
cycle EGU from 726 MW to 645 MW.
\340\ These calculations use a service life of 30 years, an
interest rate of 7.0 percent, a natural gas price of $3.69/MMBtu,
and a capacity factor of 65 percent. These costs do not include
CO2 transport, storage, or monitoring costs.
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The flue gas from NGCC EGUs differs from that of a coal-fired EGUs
in several ways that impact the cost of CO2 capture. These
include that the CO2 concentration is approximately one-
third, the volumetric flow rate on a per MW basis is larger, and the
oxygen concentration is approximately 3 times that of a coal-fired EGU.
The higher amount of excess oxygen has the potential to reduce the
efficiency of amine-based solvents that are susceptible to oxidation.
Other important factors include that the lower concentrations of
CO2 reduce the efficiency of the capture process and that
the larger volumetric flow rates require a larger CO2
absorber, which increases the capital cost of the capture process.
Exhaust gas recirculation (EGR), also referred to as flue gas
recirculation (FGR), is a process that addresses all of these issues.
EGR diverts some of the combustion turbine exhaust gas back into the
inlet stream for the combustion turbine. Doing so increases the
CO2 concentration and decreases the O2
concentration in the
[[Page 33299]]
exhaust stream and decreases the flow rate, producing more favorable
conditions for CCS. One study found that EGR can decrease the capital
costs of a combined cycle EGU with CCS by 6.4 percent, decrease the
heat rate by 2.5 percent, decrease the LCOE by 3.4 percent, and
decrease the overall CO2 capture costs by 11 percent
relative to a combined cycle EGU without EGR.\341\
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\341\ Energy Procedia. (2014). Impact of exhaust gas
recirculation on combustion turbines. Energy and economic analysis
of the CO2 capture from flue gas of combined cycle power
plants. https://www.sciencedirect.com/science/article/pii/S1876610214001234.
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Furthermore, the EPA expects that the costs of capture systems will
also decrease over the rest of this decade and continue to decrease
afterwards. As part of the plan to reduce the costs of CO2
capture, the DOE is funding multiple projects to advance CCS
technology.\342\ It should be noted that these projects are EPAct05-
assisted. The EPA proposes that the rest of the information it has is
sufficient to support a determination that the costs of capture systems
are reasonable, and that CCS is adequately demonstrated. These EPAct05-
assisted projects provide additional confirmation for this proposal
because they will contribute to improvements in the costs of CCS. These
include projects falling under carbon capture research and development,
engineering-scale testing of carbon capture technologies, and
engineering design studies for carbon capture systems. The projects
will aim to capture CO2 from various point sources,
including NGCC units, cement manufacturing plants, and iron and steel
plants. The general aim is to reach 95 percent or greater capture of
CO2, to lower the costs of the technologies, and to prove
feasible scalability at the industrial scale for these new
technologies. Some projects are designed solely to develop new carbon
capture technologies, while others are designed to apply existing
technologies at the industrial scale. For a list of notable projects,
see section VII.F.3.b.iii(A)(4)(b) of this preamble.
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\342\ The DOE has also previously funded FEED studies for NGCC
facilities. These include FEED studies at existing NGCC facilities
at Panda Energy Fund in Texas, Elk Hills Power Plant in Kern County,
California, Deer Park Energy Center in Texas, Delta Energy Center in
Pittsburg, California, and utilization of a Piperazine Advanced
Stripper (PZAS) process for CO2 capture conducted by The
University of Texas at Austin.
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Although current post-combustion CO2 capture projects
have primarily been based on amine capture systems, there are multiple
alternate capture technologies in development--many of which are funded
through industry research programs--that could have reductions in
capital, operating, and auxiliary power requirements and could reduce
the cost of capture significantly or improve performance. More
specifically, post combustion carbon capture systems generally fall
into one of several categories: solvents, sorbents, membranes,
cryogenic, and molten carbonate fuel cells \343\ systems. It is
expected that as CCS infrastructure increases, technologies from each
of these categories will become more economically competitive. For
example, advancements in solvents, that are potentially direct
substitutes for current amine-solvents, will reduce auxiliary energy
requirements and reduce both operating and capital costs, and thereby,
increasing the economic competitiveness of CCS.\344\ Planned large-
scale projects, pilot plants, and research initiatives will also
decrease the capital and operating costs of future CCS technologies.
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\343\ Molten carbonate fuel cells are configured for emissions
capture through a process where the flue gas from an EGU is routed
through the molten carbonate fuel cell that concentrates the
CO2 as a side reaction during the electric generation
process in the fuel cell. FuelCell Energy, Inc. (2018). SureSource
Capture. https://www.fuelcellenergy.com/recovery-2/suresource-capture/.
\344\ DOE. Carbon Capture, Transport, & Storage. Supply Chain
Deep Dive Assessment. February 24, 2022. https://www.energy.gov/sites/default/files/2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf.
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In general, CCS costs have been declining as carbon capture
technology advances.\345\ While the cost of capture has been largely
dependent on the concentration of CO2 in the gas stream,
advancements in varying individual CCS technologies tend to drive down
the cost of capture for other CCS technologies. The increase in CCS
investment is already driving down the costs of near-future CCS
technologies. The Global CCS Institute has tracked publicly available
information on previously studied, executed, and proposed
CO2 capture projects.\346\ The cost of CO2
capture from low-to-medium partial pressure sources such as coal-fired
power generation has been trending downward over the past decade, and
is projected to fall by 50 percent by 2025 compared to 2010. This is
driven by the familiar learning-processes that accompany the deployment
of any industrial technology. Studies of the cost of capture and
compression of CO2 from power stations completed ten years
ago averaged around $95/metric ton ($2020). Comparable studies
completed in 2018/2019 estimated capture and compression costs could
fall to approximately $50/metric ton CO2 by 2025. Current
target pricing for announced projects at coal-fired steam generating
units is approximately $40/metric ton on average, compared to Boundary
Dam whose actual costs were reported to be $105/metric ton, noting that
these estimates do not include the impact of the 45Q tax credit as
enhanced by the IRA. Additionally, IEA suggests this trend will
continue in the future as technology advancements ``spill over'' into
other projects to reduce costs.\347\ Policies in the IIJA and IRA are
further increasing investment in CCS technology that can accelerate the
pace of innovation and deployment.
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\345\ International Energy Agency (IEA) (2020). CCUS in Clean
Energy Transitions-A new era for CCUS. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus.
\346\ Technology Readiness and Costs of CCS (2021). Global CCS
Institute. https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.
\347\ International Energy Agency (IEA) (2020). CCUS in Clean
Energy Transitions-CCUS technology innovation. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus.
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(2) CO2 Transport and Sequestration Costs
NETL's ``Quality Guidelines for Energy System Studies; Carbon
Dioxide Transport and Sequestration Costs in NETL Studies'' provides an
estimation of transport costs based on the CO2 Transport
Cost Model.\348\ The CO2 Transport Cost Model estimates
costs for a single point-to-point pipeline. Estimated costs reflect
pipeline capital costs, related capital expenditures, and operations
and maintenance costs.
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\348\ Grant, T., et al. ``Quality Guidelines for Energy System
Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
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NETL's Quality Guidelines also provide an estimate of sequestration
costs. These costs reflect the cost of site screening and evaluation,
permitting and construction costs, the cost of injection wells, the
cost of injection equipment, operation and maintenance costs, pore
volume acquisition expense, and long-term liability protection.
Permitting and construction costs also reflect the regulatory
requirements of the UIC Class VI program and GHGRP subpart RR for
geologic sequestration of CO2 in deep saline formations.
NETL calculates these sequestration costs on the basis of generic plant
locations in the Midwest, Texas, North Dakota, and Montana, as
described in the NETL energy system studies that utilize the coal found
in Illinois, East Texas, Williston, and Powder River basins.\349\
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\349\ National Energy Technology Laboratory (NETL), ``FE/NETL
CO2 Saline Storage Cost Model (2017),'' U.S. Department of Energy,
DOE/NETL-2018-1871, 30 September 2017. https://netl.doe.gov/energy-analysis/details?id=2403.
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[[Page 33300]]
There are two primary cost drivers for a CO2
sequestration project: the rate of injection of the CO2 into
the reservoir and the areal extent of the CO2 plume in the
reservoir. The rate of injection depends, in part, on the thickness of
the reservoir and its permeability. Thick, permeable reservoirs provide
for better injection and fewer injection wells. The areal extent of the
CO2 plume depends on the sequestration capacity of the
reservoir. Thick, porous reservoirs with a good sequestration
coefficient will present a small areal extent for the CO2
plume and have lower testing and monitoring costs. NETL's Quality
Guidelines model costs for a given cumulative storage potential.\350\
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\350\ Details on CO2 transportation and sequestration
costs can be found in the GHG Mitigation Measures for Steam
Generating Units TSD.
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In addition, provisions in the IIJA and IRA are expected to
significantly increase the CO2 pipeline infrastructure and
development of sequestration sites, which, in turn, are expected to
result in further cost reductions for the application of CCS at a new
combined cycle EGUs. The IIJA establishes a new Carbon Dioxide
Transportation Infrastructure Finance and Innovation program to provide
direct loans, loan guarantees, and grants to CO2
infrastructure projects, such as pipelines, rail transport, ships and
barges.\351\ The IIJA also establishes a new Regional Direct Air
Capture Hubs program which includes funds to support four large-scale,
regional direct air capture hubs and more broadly support projects that
could be developed into a regional or inter-regional network to
facilitate sequestration or utilization.\352\ DOE is additionally
implementing IIJA section 40305 (Carbon Storage Validation and Testing)
through its CarbonSAFE initiative, which aims to further development of
geographically widespread, commercial-scale, safe storage.\353\ The IRA
increases and extends the IRC section 45Q tax credit, discussed next.
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\351\ Department of Energy. ``Biden-Harris Administration
Announces $2 Billion from Bipartisan Infrastructure Law to Finance
Carbon Dioxide Transportation Infrastructure.'' (2022). https://www.energy.gov/articles/biden-harris-administration-announces-2-billion-bipartisan-infrastructure-law-finance.
\352\ Department of Energy. ``Regional Direct Air Capture
Hubs.'' (2022). https://www.energy.gov/oced/regional-direct-air-capture-hubs.
\353\ For more information, see the NETL announcement. https://www.netl.doe.gov/node/12405.
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(3) IRC Section 45Q Tax Credit
In determining the cost of CCS, the EPA is taking into account the
tax credit provided under IRC section 45Q, as revised by the IRA. The
tax credit is available at $85/metric ton ($77/ton) and offsets a
significant portion of the capture, transport, and sequestration costs
noted above.
It is reasonable to take the tax credit into account because it
reduces the cost of the controls to the source, which has a significant
effect on the actual cost of installing and operating CCS. In addition,
all sources that install CCS to meet the requirements of these
proposals are eligible for the tax credit. The legislative history of
the IRA makes clear that Congress was well aware that the EPA may
promulgate rulemaking under CAA section 111 based on CCS and explicitly
stated that the EPA should consider the tax credit to reduce the costs
of CCUS (i.e., CCS). Rep. Frank Pallone, the chair of the House Energy
& Commerce Committee, included a statement in the Congressional Record
when the House adopted the IRA in which he explained: ``The tax credit[
] for CCUS . . . included in this Act may also figure into CAA Section
111 GHG regulations for new and existing industrial sources[.] . . .
Congress anticipates that EPA may consider CCUS . . . as [a] candidate[
] for BSER for electric generating plants . . . . Further, Congress
anticipates that EPA may consider the impact of the CCUS . . . tax
credit[ ] in lowering the costs of [that] measure[ ].'' 168 Cong. Rec.
E879 (August 26, 2022) (statement of Rep. Frank Pallone).
In the 2015 NSPS, in which the EPA determined partial CCS to be the
BSER for GHGs from new coal-fired steam generating EGUs, the EPA
recognized that the IRC section 45Q tax credit or other tax incentives
could factor into the cost of the controls to the sources.
Specifically, the EPA calculated the cost of partial CCS on the basis
of cost calculations from NETL, which included ``a range of assumptions
including the projected capital costs, the cost of financing the
project, the fixed and variable O&M costs, the projected fuel costs,
and incorporation of any incentives such as tax credits or favorable
financing that may be available to the project developer.'' 80 FR 64570
(October 23, 2015).\354\
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\354\ In fact, because of limits on the availability of the IRC
section 45Q tax credit at the time of the 2015 NSPS, the EPA did not
factor it into the cost calculation for partial CCS. 80 FR 64558-64
(October 23, 2015).
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Similarly, in the 2015 NSPS, the EPA also recognized that revenues
from utilizing captured CO2 for EOR would reduce the cost of
CCS to the sources, although the EPA did not account for potential EOR
revenues for purposes of determining the BSER. Id. at 64563-64. In
other rules, the EPA has considered revenues from sale of the by-
products of emission controls to affect the costs of the emission
controls. For example, in the 2016 Oil and Gas Methane Rule, the EPA
determined that certain control requirements would reduce natural gas
leaks and therefore result in the collection of recovered natural gas
that could be sold; and the EPA further determined that revenues from
the sale of the recovered natural gas reduces the cost of controls. See
81 FR 35824 (June 3, 2016). In a 2011 action concerning a regional haze
SIP, the EPA recognized that a NOX control would alter the
chemical composition of fly ash that the source had previously sold, so
that it could no longer be sold; and as a result, the EPA further
determined that the cost of the NOX control should include
the foregone revenues from the fly ash sales. 76 FR 58570, 58603
(September 21, 2011). In the 2016 emission guidelines for landfill gas
from municipal solid waste landfills, the EPA reduced the costs of
controls by accounting for revenue from the sale of electricity
produced from the landfill gas collected through the controls. 81 FR
59276, 19679 (August 29, 2016).
The amount of the IRC section 45Q tax credit that the EPA is taking
into account is $85/metric ton for CO2 that is captured and
geologically stored. This amount is available to the affected source as
long as it meets the prevailing wage and apprenticeship requirements of
IRC section 45Q(h)(3)-(4). The legislative history to the IRA
specifically stated that when the EPA considers CCS as the BSER for GHG
emissions from industrial sources in CAA section 111 rulemaking, the
EPA should determine the cost of CCS by assuming that the sources would
meet those prevailing wage and apprenticeship requirements. 168 Cong.
Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone). If
prevailing wage and apprenticeship requirements are not met, the value
of the IRC section 45Q tax credit falls to $17/metric ton. The
substantially higher credit available provides a considerable incentive
to meeting the prevailing wage and apprenticeship requirements.
Therefore, the EPA assumes that investors maximize the value of the IRC
section 45Q tax credit at $85/metric ton by meeting those requirements.
(4) Total Costs of CCS
In a typical NSPS analysis, the EPA amortizes costs over the
expected life of
[[Page 33301]]
the affected facility and assumes constant revenue and expenses over
that period of time. This analysis is different because the IRC section
45Q tax credits for the sequestration of CO2 are only
available for combustion turbines that commence construction by the end
of 2032 and are available for 12 years. The construction timeframe is
within the NSPS review cycle, and the EPA has determined that it is
appropriate to include the credits as part of the CCS costing analysis.
Since the duration of the tax credit is less than the expected life of
a new base load combustion turbine, the EPA conducted the costing
analysis assuming a 30-year useful life and a separate analysis
assuming the capital costs are amortized over a 12-year period. For the
30-year analysis, the EPA used a discount rate of 3.8 percent for the
45Q tax credits to get an effective 30-year value of $41/ton.
Even considering that the IRC section 45Q tax credits are currently
available for only 12 years and would, therefore, only offset costs for
a portion of a new NGCC turbine's expected operating life, the current
overall CO2 abatement costs of CCS of a 90 percent capture
amine-based post combustion capture system, accounting for the tax
credit, are $44/ton ($49/metric ton) and the increase in the LCOE is
$15/MWh.\355\ These costs assume a stable 30-year operating life,
transport, storage, and monitoring costs of $10/metric ton, and do not
include any revenues from sale of the CO2 following the 12-
year period when the IRC section 45Q tax credit is available. An
alternate costing approach is to assume all capital costs are amortized
during the 12-year period when tax credits are available. These tax
credits are a significant source of revenue and would lower the
incremental generating costs of the unit. Therefore, under the 12-year
costing approach the EPA increased the assumed annual capacity factor
from 65 to 75 percent. The 12-year CO2 abatement costs are
$19/ton ($21/metric ton) and the increase in the LCOE is $6/MWh. These
costs are for a combined cycle unit with a base load rating of 4,600
MMBtu/h with an output of approximately 700 MW.\356\ These costs could
be higher for small units and lower for larger units. For additional
details on the CCS costing analysis see the GHG Mitigation Measures--
Carbon Capture and Storage for Combustion Turbines TSD, which is
available in the rulemaking docket. The EPA is soliciting comment on
whether the CCS transport, storage, and monitoring costs are
appropriate for determining the BSER costs for combustion turbines.
---------------------------------------------------------------------------
\355\ The EPA used 3.76 percent discount factor to levelized the
45Q tax credits to an annual value of $45.4/metric ton. These
calculations use a service life of 30 years, an interest rate of 7.0
percent, a natural gas price of $3.69/MMBtu, a capacity factor of 65
percent, and a transport, storage, and monitoring cost of $10/metric
ton.
\356\ The output of the model combined cycle EGU without CCS is
726 MW. The auxiliary load of CCS reduces the net out to 645 MW.
---------------------------------------------------------------------------
(5) Comparison to Other Costs of Controls
In assessing cost reasonableness for the BSER determination for
this rule, the EPA compares the costs of GHG control measures to
control costs that the EPA has previously determined to be reasonable.
This includes comparison to the costs of controls at EGUs for other air
pollutants, such as SO2 and NOX, and costs of
controls for GHGs in other industries. The costs presented in this
section of the preamble are in 2019 dollars.\357\
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\357\ The EPA used the NETL Baseline Report costs directly for
the combustion turbine model plant BSER analysis. Even though these
costs are in 2018 dollars, the adjustment to 2019 dollars (1.018
using the U.S. GDP Implicit Price Deflator) is well within the
uncertainty range of the report and the minor adjustment would not
impact the EPA's BSER determination.
---------------------------------------------------------------------------
At different times, many coal-fired steam generating units have
been required to install and operate flue gas desulfurization (FGD)
equipment--that is, wet or dry scrubbers--to reduce their
SO2 emissions or SCR to reduce their NOX
emissions. The EPA compares these control costs across technologies--
steam generating units and combustion turbines--because these costs are
indicative of what is reasonable for the power sector in general. The
fact that EPA required these controls in prior rules, and that many
EGUs subsequently installed and operated these controls, provide
evidence that these costs are reasonable, and as a result, the cost of
these controls provides a benchmark to assess the reasonableness of the
costs of the controls in this preamble. In the 2011 Cross-State Air
Pollution Rule (CSAPR) (76 FR 48208; August 8, 2011), the EPA estimated
the annualized costs to install and operate wet FGD retrofits on
existing coal-fired steam generating units. Using those same cost
equations and assumptions (i.e., a 63 percent annual capacity factor--
the average value in 2011) for retrofitting wet FGD on a representative
700 to 300 MW coal-fired steam generating unit results in annualized
costs of $14.80 to $18.50/MWh of generation, respectively.\358\ In the
March 15, 2023 Good Neighbor Plan for the 2015 Ozone NAAQs (2023 GNP),
the EPA estimated the annualized costs to install and operate SCR
retrofits on existing coal-fired steam generating units. Using those
same cost equations and assumptions (including a 56 percent annual
capacity factor--a representative value in that rulemaking) to retrofit
SCR on a representative 700 to 300 MW coal-fired steam generating unit
results in annualized costs of $10.60 to $11.80/MWh of generation,
respectively.\359\ Finally, using current cost equations and
assumptions (including a 50 percent annual capacity factor, and
otherwise consistent with the 2023 GNP) for retrofitting wet FGD on a
representative 700 to 300 MW coal-fired steam generating unit results
in annualized costs of $23.20 to $29.00/MWh of generation,
respectively.\360\
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\358\ For additional details, see https://www.epa.gov/power-sector-modeling/documentation-integrated-planning-model-ipm-base-case-v410.
\359\ For additional details, see https://www.epa.gov/system/files/documents/2023-01/Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%20for%20the%202015%20Ozone%20NAAQS%20Actions_0.pdf.
\360\ Ibid.
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Finally, the EPA compares costs to the costs for GHG controls in
rulemakings for other industries. In the 2016 NSPS regulating GHGs for
the Crude Oil and Natural Gas source category, the EPA found the costs
of reducing methane emissions of $2,447/ton to be reasonable (80 FR
56627; September 18, 2015).\361\ Converted to a ton of CO2e
reduced basis, those costs are expressed as $98/ton of CO2e
reduced.\362\
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\361\ The EPA finalized the 2016 NSPS GHGs for the Crude Oil and
Natural Gas source category at 81 FR 35824 (June 3, 2016). The EPA
included cost information in the proposed rulemaking, at 80 FR 56627
(September 18, 2015).
\362\ Based on the 100-year global warming potential for methane
of 25 used in the GHGRP (40 CFR 98 Subpart A, Table A-1).
---------------------------------------------------------------------------
The costs for CCS applied to a representative new base load
stationary combustion turbine EGU are generally lower than the above-
described costs, which supports the EPA's view that the CCS costs are
reasonable. The CCS costs range from $6 to $15/MWh of generation or $19
to $44/ton of CO2 reduced (depending on the amortization
period).
(C) Non-Air Quality Health and Environmental Impact and Energy
Requirements
In this section of the preamble, the EPA explains that it does not
expect the use of CCS for new combined cycle combustion turbines to
have unreasonable adverse consequences related to non-air quality
health and environmental impact and energy requirements to combined
cycle combustion turbines. The EPA first discusses energy requirements,
and then considers non-GHG emissions impacts
[[Page 33302]]
and water use impacts, resulting from the capture, transport, and
sequestration of CO2.
With respect to energy requirements, including a 90 percent or
greater carbon capture system in the design of a new NGCC will increase
the parasitic/auxiliary energy demand and reduce its net power output.
A utility that wants to construct an NGCC unit to provide 500 MWe-net
of power could build a 500 MWe-net plant knowing that it will be de-
rated by 11 percent (to a 444 MWe-net plant) with the installation and
operation of CCS. In the alternative, the project developer could build
a larger 563 MWe-net NGCC plant knowing that, with the installation of
the carbon capture system, the unit will still be able to provide 500
MWe-net of power to the grid. Although the use of CCS imposes
additional energy demands on the affected units, those units are able
to accommodate those demands by scaling larger, as needed.
Regardless of whether a unit is scaled larger, the installation and
operation of CCS itself does not impact the unit's potential-to-emit
any of the criteria or hazardous air pollutants. In other words, a new
base load stationary combustion turbine EGU constructed using highly
efficient generation (the first component of the BSER) would not see an
increase in emissions of criteria or hazardous air pollutants as a
direct result of installing and using 90 percent or greater
CO2 capture CCS to meet the second phase standard of
performance.\363\
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\363\ While the absolute onsite mass emissions would not
increase from the second component of the BSER, the emissions rate
on a lb/MWh-net basis would increase by 13 percent.
---------------------------------------------------------------------------
Scaling a unit larger to provide heat and power to the
CO2 capture equipment would have the potential to increase
non-GHG air emissions. However, most of them would be mitigated or
adequately controlled by equipment needed to meet other CAA
requirements. In general, the emission rates and flue gas
concentrations of most non-GHG pollutants from the combustion of
natural gas in stationary combustion turbines are relatively low
compared to the combustion of oil or coal in boilers. As such, it is
not necessary to use an FGD to pretreat the flue gas prior to
CO2 removal in the CO2 scrubber column. The
sulfur content of natural gas is low relative to oil or coal and
resulting SO2 emissions are therefore also relatively low.
Similarly, PM emissions from combustion of natural gas in a combustion
turbine are relatively low. Furthermore, the high combustion efficiency
of combustion turbines results in relatively low organic-HAP emissions,
and there are likely few, if any, metallic-HAP emissions from
combustion of natural gas. Additionally, combustion turbines at major
sources of HAP are subject to the stationary combustion turbine NESHAP,
which includes limits for formaldehyde emissions for new sources that
may require installation of an oxidation catalyst (87 FR 13183; March
9, 2022). Regarding NOX emissions, in most cases, the
combustion turbines in new combined cycle units will be equipped with
low-NOX burners to control flame temperature and reduce
NOX formation. Additionally, new combined cycle units may be
subject to major NSR requirements for NOX emissions, which
may necessitate the installation of SCR to comply with a control
technology determination by the permitting authority. See section
XIII.A of this preamble for additional details regarding implications
for the NSR program. Although NOX concentrations may be
controlled by SCR, for some amine solvents NOX in the post-
combustion flue gas can react in the CO2 scrubber to form
nitrosamines. A conventional multistage water wash or acid wash and a
mist eliminator at the exit of the CO2 scrubber is effective
at removal of gaseous amine and amine degradation products (e.g.,
nitrosamine) emissions.364 365
---------------------------------------------------------------------------
\364\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
\365\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
---------------------------------------------------------------------------
Stakeholders have shared with the EPA concerns about the safety of
CCS projects and that historically disadvantaged and overburdened
communities may bear a disproportionate environmental burden associated
with CCS projects.\366\ For the reasons noted above, the EPA does not
expect CCS projects to result in uncontrolled or substantial increases
in emissions of non-GHG air pollutants from new combustion turbines.
The EPA is committed to working with its fellow agencies to foster
meaningful engagement with communities and protect communities from
pollution. This can be facilitated through the existing detailed
regulatory framework for CCS projects and further supported through
robust and meaningful public engagement early in the technological
deployment process. Furthermore, the EPA is soliciting comment on
additional ways that may be identified to responsibly advance the
deployment of CCS and ensure meaningful engagement with local
communities.
---------------------------------------------------------------------------
\366\ In outreach with potentially vulnerable communities,
residents have voiced two primary concerns. First, there is the
concern that their communities have experienced historically
disproportionate burdens from the environmental impacts of energy
production, and second, that as the sector evolves to use new
technologies such as CCS and hydrogen, they may continue to face
disproportionate burden. This is discussed further in section XIV.E
of this preamble.
---------------------------------------------------------------------------
The use of water for cooling presents an additional issue. Due to
their relatively high efficiency, combined cycle EGUs have relatively
small cooling requirements compared to other base load EGUs. According
to NETL, a combined cycle EGU without CCS requires 190 gallons of
cooling water per MWh of electricity. CCS increases the cooling water
requirements due both to the decreased efficiency and the cooling
requirements for the CCS process to 290 gallons per MWh, an increase of
about 50 percent. However, because NGCC units require limited amounts
of cooling water, the absolute amount of increase in cooling water
required due to use of CCS does not present unsurmountable concerns. In
addition, many combined cycle EGUs currently use dry cooling
technologies and the use of dry or hybrid cooling technologies for the
CO2 capture process would reduce the need for additional
cooling water. Therefore, the EPA is proposing that the additional
cooling water requirements from CCS are reasonable.
As noted in section VII.F.3 of this preamble, PHMSA oversight of
supercritical CO2 pipeline safety protects against
environmental release during transport and UIC Class VI regulations
under the SDWA in tandem with GHGRP requirements ensure the protection
of USDWs and the security of geologic sequestration.
(D) Impacts on the Energy Sector
The EPA does not believe that determining CCS to be BSER for base
load units will cause reliability concerns, for two independent
reasons. First, the EPA is proposing that the costs of CCS are
reasonable and comparable to other controls the electric power industry
has used without significant effects on reliability. Second, while CCS
is adequately demonstrated and cost reasonable, the current proposal
allows companies that want to build a base load combined cycle
combustion turbine a second pathway to meet its requirements: building
a unit that co-fires low-GHG hydrogen in the appropriate amount. In
fact, companies are pursing both of these options,
[[Page 33303]]
including units with CCS, in various stages of development. The EPA
also expects there to be considerable interest in building intermediate
load and peaker units to meet market demand for dispatchable
generation. Indeed, the portion of the combustion turbine fleet that is
operating at base load is declining as shown in the EPA's reference
case modeling (post-IRA 2022 reference case, see section IV.F of the
preamble). Finally, combined cycle units are only one of many options
that companies have to build new generation. For instance, in 2023,
combined cycle units are only expected to represent 14 percent of all
new generating capacity built in the US and only a portion of that is
natural gas combined cycle capacity.\367\ Finally, several companies
have recently announced plans to move away from new combined cycle
projects in favor of more non-base load combustion turbines,
renewables, and battery storage. For example, Xcel recently announced
plans to build new renewable power generation instead of the combined
cycle plant it had initially proposed to replace the retiring Sherco
coal-fired plant.\368\ For these reasons, determining CCS to be the
BSER for base load units will not cause reliability concerns.
---------------------------------------------------------------------------
\367\ https://www.eia.gov/todayinenergy/detail.php?id=55419.
\368\ https://cubminnesota.org/xcel-is-no-longer-pursuing-gas-power-plant-proposes-more-renewable-power/.
---------------------------------------------------------------------------
(E) Extent of Reductions in CO2 Emissions
Designating CCS as a component of the BSER for certain base load
combustion turbine EGUs prevents large amounts of CO2
emissions. For example, a new base load combined cycle EGU without CCS
could be expected to emit 45 million tons of CO2 over its
operating life. Use of CCS would avoid the release of nearly 41 million
tons of CO2 over the operating life of the combined cycle
EGU. However, due to the auxiliary/parasitic energy requirements of the
carbon capture system, capturing 90 percent of the CO2 does
not result in a corresponding 90 percent reduction in CO2
emissions. According to the NETL baseline report, adding a 90 percent
CO2 capture system increases the EGU's gross heat rate by 7
percent and the unit's net heat rate by 13 percent. Since more fuel
would be consumed in the CCS case, the gross and net emissions rates
are reduced by 89.3 percent and 88.7 percent respectively.
(F) Promotion of the Development and Implementation of Technology
The EPA also considered whether determining CCS to be a component
of the BSER for new base load combustion turbines will advance the
technological development of CCS and concluded that this factor
supports our BSER determination. A standard of performance based on
highly efficient generation in combination with the use of CCS--
combined with the availability of 45Q tax credits and investments in
supporting CCS infrastructure from the IIJA--should incentivize
additional use of CCS, which should incentivize cost reductions through
the development and use of better performing solvents or sorbents.
While solvent-based CO2 capture has been adequately
demonstrated at the commercial scale, a determination that a component
of the BSER for new base load stationary combustion turbine (and long
term coal-fired steam generating units) is the use of CCS will also
likely incentivize the deployment of alternative CO2 capture
techniques at scale. Moreover, as noted above, the cost of CCS has
fallen in recent years and is expected to continue to fall; and further
implementation of the technology can be expected to lead to additional
cost reductions, due to added experience and cost efficiencies through
scaling.
The experience gained by utilizing CCS with stationary combustion
turbine EGUs, with their lower CO2 flue gas concentration
relative to other industrial sources such as coal-fired EGUs, will
advance capture technology with other lower CO2
concentration sources. The EIA 2023 Annual Energy Outlook projects that
almost 862 billion kWh of electricity will be generated from natural
gas-fired sources in 2040.\369\ Much of that generation is projected to
come from existing combined cycle EGUs and further development of
carbon capture technologies could facilitate increased retrofitting of
those EGUs.
---------------------------------------------------------------------------
\369\ Does not include 114 billion kilowatt hours from natural
gas-fired CHP projected in AEO 2023.
---------------------------------------------------------------------------
(G) Proposed BSER
The Agency proposes that for new natural gas-fired base load
combustion turbines, an efficient stationary combined cycle combustion
turbine utilizing CCS at a capture rate of 90 percent, beginning in
2035, qualifies as the BSER because it is adequately demonstrated; it
entails reasonable costs taking account of the IRC section 45Q tax
credit, it achieves significant emission reductions, and it does not
have significant adverse non-air quality health or environmental
impacts or significant adverse energy requirements, including on a
nationwide basis. The fact that it promotes useful technology provides
additional, although not essential, support for this proposal.
iv. Low-GHG Hydrogen
As discussed, the EPA is proposing two BSER pathways that new
stationary combustion turbines may take--one that is based on the use
of 90 percent CCS and a separate BSER pathway based upon co-firing low-
GHG hydrogen. In this section, the EPA explains why it believes that
CCS could form the basis of the BSER. In section VII.F.3.c, we discuss
why we believe burning low-GHG hydrogen could also form the basis of
the BSER.
v. Basis for Proposal of a Second Component of BSER, Based on CCS, in
2035
When considering whether a technology should be BSER, the EPA must
consider both unit level and nationwide questions. At the unit level,
the EPA must ask whether the technology is proven, can be implemented
at reasonable cost, and achieves emission reductions without causing
other significant environmental or energy issues. With regard to CCS at
the unit level, the EPA believes there is ample evidence to conclude
that it is available and cost reasonable (with the 45Q tax credits)
today, and that a well-sited individual new unit could meet the
standard of performance based on the application of 90 percent CCS on
the startup date of the facility. However, when looking at the
technology from a nationwide basis, the EPA must take larger system-
wide impacts into consideration. For CCS, this includes questions about
the development and availability of infrastructure for transportation
and storage \370\ as well as considerations related to the lead time
needed to scale manufacturing and the installation of carbon capture
equipment to meet the amount of capacity potentially subject to this
proposed BSER (in addition to meeting IRA-driven demand for CCS in
other sectors).
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\370\ For further information on timing associated with
CO2 transport and storage design, engineering, and
construction, see GHG Mitigation Measures for Steam Generating Units
TSD, chapter 4.7.1.
---------------------------------------------------------------------------
The EPA considered establishing the start of phase 2 of the
standard of performance as early as 2030 on the assumption that
projects that commence construction in the period immediately following
this rulemaking will need at least that amount of time to implement the
BSER. However, the EPA is also
[[Page 33304]]
proposing to determine that the BSER for long-term coal-fired steam
generating units (those that will be in operation beyond 2040) is the
use of 90 percent capture CCS and that the associated standard of
performance for those units is effective beginning in 2030. The EPA is
also aware that a significant number of new base load combined cycle
stationary combustion turbines are projected to be constructed by 2030,
and that there are other, non-power sector industries that will also be
pursuing implementation of CCS in that timeframe. The EPA believes that
while CCS poses low supply chain risk due to the required
infrastructure relying on common and readily available raw materials
and CCS infrastructure can be supplied in large part by domestic
components,\371\ the deployment of CCS infrastructure, including the
demand for the manufacturing and installation of CCS equipment and
CO2 pipeline infrastructure, and the demand for conducting
sequestration site characterization and permitting, should be
prioritized for the higher GHG-emitting fleet of existing long-term
coal-fired steam generating units. The EPA also understands that many
utilities and power generating companies are trying to assess their
near-term and long-term base load generating needs and may have useful
information to provide to the record that would help to assess the
demand for CCS. Therefore, in consideration of these factors, the EPA
is proposing that phase 2 of the standard of performance begin in 2035
to ensure achievability of the standard. The EPA also recognizes that
commenters may have more information about implementing CCS on a
broader scale that would help to assess whether 2030 or 2035 (or
somewhere in between) would be an appropriate start date for phase 2 of
the standards of performance that are based, in part, on the use of
CCS. For this reason, the EPA solicits comment on whether the
compliance date for phase 2 of the standards of performance should
begin earlier than 2035, including as early as 2030.
---------------------------------------------------------------------------
\371\ U.S. Department of Energy, Achieving American Leadership
in the Carbon Capture, Transport, and Storage Supply Chain, March
23, 2022 (DOE/OP-0001-1). https://www.energy.gov/sites/default/files/2022-03/Carbon%20Capture%20factsheet.pdf.
---------------------------------------------------------------------------
c. BSER for Base Load Subcategory of Combustion Turbines Adopting the
Low-GHG Hydrogen Co-Firing Pathway and Intermediate Load Subcategory--
Second and Third Components
This section describes the second and third components of the EPA's
proposed BSER for the subcategory of base load combustion turbines that
are adopting the low-GHG hydrogen co-firing pathway and the second
component for combustion turbines in the intermediate load subcategory.
For both subcategories, the EPA is proposing that the second component
of the BSER is co-firing 30 percent (by volume) low-GHG hydrogen and
that sources meet a corresponding standard of performance beginning in
2032. For base load combustion turbines in this subcategory of sources
that adopt the low-GHG hydrogen co-firing pathway, the EPA is proposing
that the third component of the BSER is co-firing 96 percent (by
volume) low-GHG hydrogen and that sources meet a corresponding standard
of performance beginning in 2038. The EPA is also soliciting comment on
whether, in lieu of providing a subcategory for base load combustion
turbines that adopt the low-GHG hydrogen co-firing pathway, a single
BSER for base load combustion turbines should be selected based on
application of CCS with 90 percent capture--which could also be met by
co-firing 96 percent (by volume) low-GHG hydrogen. The first part of
this section is a background discussion concerning several key aspects
of the hydrogen industry as it is currently developing. At the outset,
the EPA summarizes the activities of some power producers and turbine
manufacturers to develop and demonstrate hydrogen co-firing as a viable
decarbonization technology for the power sector. The EPA then discusses
the GHG emissions performance of stationary combustion turbines when
hydrogen is used as a fuel. This discussion includes the different
methods of production and the associated GHG emissions for each. The
second part of this section describes the proposed second component of
the BSER, which is co-firing 30 percent (by volume) low-GHG hydrogen
and the third component of the BSER, which, for certain units, is co-
firing 96 percent (by volume) low-GHG hydrogen.
The EPA is also proposing a definition of low-GHG hydrogen. The EPA
is proposing that hydrogen qualifies as low-GHG hydrogen if it is
produced through a process that results in a GHG emission rate of less
than 0.45 kilograms of CO2 equivalent per kilogram of
hydrogen (kg CO2e/kg H2) on a well-to-gate basis
consistent with the system boundary established in IRC section 45V
(Credit for Production of Clean Hydrogen) of the IRA. Hydrogen produced
by electrolysis (splitting water into hydrogen and oxygen) using non-
emitting energy sources such as solar, wind, nuclear, and hydroelectric
power, can produce hydrogen with carbon intensities lower than 0.45 kg
CO2e/kg H2, which could qualify as low-GHG
hydrogen for the purposes of this proposed BSER.\372\ However, the EPA
is also soliciting comment on whether a specific definition of low-GHG
hydrogen should be included in the final rule. The third part of this
section explains why the EPA proposes that co-firing 30 percent (by
volume) low-GHG hydrogen qualifies as a component of the BSER. Co-
firing 30 percent (by volume) hydrogen is technically feasible and
well-demonstrated in new combustion turbines, it will be supported by
an adequate supply of hydrogen by 2032, it will be of reasonable cost,
it will ensure reductions of GHG emissions, and it will be consistent
with the other BSER factors. The EPA also includes in this section an
explanation of why the Agency thinks that highly efficient generating
technology combined with co-firing only low-GHG hydrogen is the
``best'' system of emission reduction, taking into account the
statutory considerations. This third part of this section also explains
why the EPA proposes that co-firing 96 percent (by volume) low-GHG
hydrogen qualifies as a third component of the BSER for base load
combustion turbines that are subject to a second phase standard of
performance based on co-firing 30 percent (by volume) low-GHG hydrogen.
The EPA proposes that co-firing 96 percent (by volume) low-GHG hydrogen
is technically feasible and well-demonstrated in new combustion
turbines, it will be supported by an adequate supply of low-GHG
hydrogen by 2038, it will be of reasonable cost, it will ensure
reductions of GHG emissions, and it will be consistent with the other
BSER factors.
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\372\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen, March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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i. Lower Emitting Fuels
The EPA is not proposing lower emitting fuels as the second
component of BSER for base load or intermediate load combustion
turbines because it would achieve few emission reductions compared to
co-firing low-GHG hydrogen.
ii. Highly Efficient Generation
For the reasons described above, the EPA is proposing that highly
efficient generation technology in combination with best operating and
maintenance practices continues to be a component of the BSER that is
reflected in the
[[Page 33305]]
second phase of the standards of performance for base load turbines
that are adopting the low-GHG hydrogen co-firing pathway and
intermediate load combustion turbines. Highly efficient generation
reduces fuel use as well as the absolute amount and cost of low-GHG
hydrogen that would be required to comply with the second phase
standards.
iii. CCS
The EPA is not proposing the use of CCS as a component of the BSER
for base load turbines combusting that are adopting low-GHG hydrogen
co-firing or intermediate load combustion turbines. As described
previously, simple cycle technology is the most common combustion
turbine technology applicable to the intermediate load subcategory and
the Agency is limiting consideration of CCS to base load combined cycle
EGUs. Intermediate load combustion turbines tend to start and stop
frequently and have relatively short periods of continuous operation.
CCS systems could have difficulty starting fast enough to get
significant levels of CO2 capture. The EPA solicits comment
on flexible CCS technologies that could be used by intermediate load
combustion turbines. In addition, the CCS equipment could essentially
remain idle for much of the time while these intermediate units are not
running. For these reasons, CCS would be less cost-effective for
intermediate load combustion turbine EGUs--particularly at much lower
capacity factors--as compared to base load combined cycle units that
are not on the pathway to combusting 96 percent (by volume) low-GHG
hydrogen.
With respect to base load combustion turbine EGUs, as explained
previously, the EPA is proposing two BSER pathways that new base load
stationary combustion turbines may take--one that is based on the use
of 90 percent CCS and a separate BSER pathway based upon co-firing low-
GHG. In this section, the EPA explains why it believes that co-firing
with low-GHG hydrogen could form the basis of the BSER. In section
VII.C.3.b.iii, we discuss why we believe CCS could also form the basis
of the BSER.
iv. Background Discussion of Hydrogen and the Electric Power Sector,
Hydrogen Co-Firing in Combustion Turbines, and Hydrogen Production
Processes
Hydrogen in the United States is primarily used for refining
petroleum and producing fertilizer, with smaller amounts also used in
sectors like metals treatment, processing foods, and production of
specialty chemicals.\373\ In recent years, applications of hydrogen
have expanded to include co-firing in combustion turbines used to
generate electricity. In fact, many models of existing combustion
turbines that are used for electricity generation have successfully
demonstrated the ability to co-fire blends of 5 to 10 percent hydrogen
by volume without modification to the combustion system. Furthermore,
combustion of hydrogen blends as high as 20 to 30 percent by volume are
being tested and demonstrated; and new turbine designs that can
accommodate co-firing much greater percentages of hydrogen are being
developed.
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\373\ U.S. Department of Energy (DOE). National Clean Hydrogen
Strategy and Roadmap. September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
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Several power producers made financial investments and began work
on hydrogen co-firing projects prior to passage of the IRA in August
2022. For example, in early 2021, the Intermountain Power Agency (IPA)
project in Utah began the transition away from operating an 1,800-MW
coal-fired steam generating unit to an 840-MW combined cycle combustion
turbine that will integrate 30 percent by volume hydrogen co-firing at
startup in 2025.\374\ IPA and its partners have announced plans to
produce low-GHG hydrogen via solar-powered electrolysis with storage in
underground geologic formations en route to combusting 100 percent low-
GHG hydrogen in the combined cycle unit by 2045. IPA also has
agreements to sell its electricity to the Los Angeles Department of
Water and Power.
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\374\ Intermountain Power Agency (2022). https://www.ipautah.com/ipp-renewed/.
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Another example is the Long Ridge Energy Generation Project in
Ohio.\375\ The 485-MW combined cycle combustion turbine became
operational in 2021 and is designed to transition to 100 percent
hydrogen in the future.\376\ The unit successfully co-fired 5 percent
by volume hydrogen in March 2022.377 378 The planned next
step for Long Ridge is to co-fire 20 percent by volume hydrogen with
the existing turbine design, which has been commercially available
since 2017 and can co-fire 15 to 20 percent by volume hydrogen without
modification.\379\ Furthermore, in June 2022, Southern Company
successfully demonstrated the co-firing of a 20 percent by volume
hydrogen blend at Georgia Power's Plant McDonough-Atkinson. The co-
firing demonstration was performed on a combustion turbine at partial
and full loads and produced a 7 percent reduction in CO2
emissions.\380\ In September 2022, the New York Power Authority (NYPA)
successfully co-fired a 44 percent by volume blend of hydrogen in a
retrofitted combustion turbine. According to the Electric Power
Research Institute (EPRI), the project demonstrated a 14 percent
reduction in CO2 at a 35 percent by volume hydrogen blend.
The unit's existing SCR controlled NOX emissions within
permit limits.381 382 383 We note other projects to develop
combustion turbines that co-fire hydrogen in section IV.E of this
preamble.
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\375\ Hering, G. (2021). First major US hydrogen-burning power
plant nears completion in Ohio. S&P Global Market Intelligence.
https://www.spglobal.com/platts/en/market-insights/latest-news/electric-power/081221-first-major-us-hydrogen-burning-power-plant-nears-completion-in-ohio.
\376\ McGraw, D. (2021). World science community watching as
natural gas-hydrogen power plant comes to Hannibal, Ohio. Ohio
Capital Journal. https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gas-hydrogen-power-plant-comes-to-hannibal-ohio/.
\377\ McGraw, D. (2021). World science community watching as
natural gas-hydrogen power plant comes to Hannibal, Ohio. Ohio
Capital Journal. https://ohiocapitaljournal.com/2021/08/27/world-science-community-watching-as-natural-gas-hydrogen-power-plant-comes-to-hannibal-ohio/.
\378\ Defrank, Robert (2022). Cleaner Future in Sight: Long
Ridge Energy Terminal in Monroe County Begins Blending Hydrogen.
https://www.theintelligencer.net/news/community/2022/04/cleaner-future-in-sight-long-ridge-energy-terminal-in-monroe-county-begins-blending-hydrogen.
\379\ Patel, S. (April 22, 2022). First Hydrogen Burn at Long
Ridge HA-Class Gas Turbine Marks Triumph for GE. Power. https://www.powermag.com/nypa-ge-successfully-pilot-hydrogen-retrofit-at-aeroderivative-gas-turbine/.
\380\ Patel, S. (2022). Southern Co. Gas-Fired Demonstration
Validates 20% Hydrogen Fuel Blend. https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/.
\381\ Palmer, W., & Nelson, B. (2021). An H2 Future: GE and New
York power authority advancing green hydrogen initiative. https://www.ge.com/news/reports/an-h2-future-ge-and-new-york-power-authority-advancing-green-hydrogen-initiative.
\382\ Van Voorhis, S. (2021). New York to test green hydrogen at
Long Island power plant. Utility Dive. https://www.utilitydive.com/news/new-york-to-test-green-hydrogen-at-long-island-power-plant/603130/.
\383\ Electric Power Research Institute (EPRI). (2022, September
15). Hydrogen Co-Firing Demonstration at New York Power Authority's
Brentwood Site: GE LM6000 Gas Turbine. Low Carbon Resources
Initiative. https://www.epri.com/research/products/000000003002025166.
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Other power producers have implemented large low-GHG hydrogen plans
that integrate multiple elements of their generating assets. In
Florida, NextEra announced in June 2022 a comprehensive carbon
emissions reduction plan that will eventually convert 16 GW of natural
gas-fired generation to operate on low-GHG hydrogen as part of the
utility's 2045
[[Page 33306]]
GHG reduction goal.\384\ Also, NextEra's Cavendish NextGen Hydrogen Hub
will produce hydrogen with a 25-MW electrolyzer system powered by solar
energy and the hydrogen will then be co-fired by combustion turbines at
Florida Power and Light's 1.75-GW Okeechobee power plant.\385\
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\384\ NextEra Energy (2022). Zero Carbon Blueprint. https://www.nexteraenergy.com/content/dam/nee/us/en/pdf/NextEraEnergyZeroCarbonBlueprint.pdf.
\385\ Clean Energy Group. Hydrogen Projects in the U.S. https://www.cleanegroup.org/ceg-projects/hydrogen/projects-in-the-us/.
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One of the first power producers to invest in hydrogen as a fuel
for combustion turbines was Entergy, which reached an agreement with
turbine manufacturer Mitsubishi Power in 2020 to develop hydrogen-
capable combined cycle facilities that include low-GHG hydrogen
production, storage, and transportation components.\386\ In October
2022, Entergy and New Fortress Energy announced plans to collaborate on
a renewable energy and 120-MW hydrogen production plant in southeast
Texas.\387\ The partnership includes electricity transmission
infrastructure as well as the development of renewable energy resources
and the offtake of low-GHG hydrogen. A feature of the agreement is the
potential to supply hydrogen to Entergy's Orange County Advanced Power
Station, which received approval from the Public Utility Commission of
Texas in November 2022.\388\ The 1,115-MW power plant will replace end-
of-life gas generation with new combined cycle combustion turbines that
are ready to co-fire hydrogen with the ability to move to 100 percent
hydrogen in the future. Construction will begin in 2023 and the project
will be completed in 2026.
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\386\ Mitsubishi Power Americas. (September 23, 2020).
Mitsubishi Power and Entergy to Collaborate and Help Decarbonize
Utilities in Four States. https://power.mhi.com/regions/amer/news/20200923.html.
\387\ Entergy. (October 19, 2022). Entergy Texas and New
Fortress Energy partner to advance hydrogen economy in Southeast
Texas. https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/
.
\388\ Entergy. (November 28, 2022). Entergy Texas receives
approval to build a cleaner, more reliable power station in
Southeast Texas. https://www.entergynewsroom.com/news/entergy-texas-receives-approval-build-cleaner-more-reliable-power-station-in-southeast-texas/.
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Hydrogen offers unique solutions for decarbonization because of its
potential to provide dispatchable, clean energy with long-term storage
and seasonal capabilities. For example, hydrogen is an energy carrier
that can provide long-term storage of low-GHG energy that can be co-
fired in combustion turbines and used to balance load with the
increasing volumes of variable generation.\389\ These services can
enhance the reliability of the power system while facilitating the
integration of variable renewable energy resources and supporting
decarbonization of the electric grid. Hydrogen has the potential to
mitigate curtailment, which is the deliberate reduction of electric
output below what could have been produced. Curtailment often occurs
when RTOs need to balance the grid's energy supply to meet demand. For
example, in 2020, the California Independent System Operator (CAISO)
curtailed an estimated 1.5 million MWh of solar generation.\390\
Curtailment will likely increase as the capacity of variable generation
continues to expand. One technology with the potential to reduce
curtailment is energy storage, and some power producers envision a role
for hydrogen to supplement natural gas as a fuel to support the
balancing and reliability of an increasingly decarbonized electric
grid.
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\389\ For example, when the sun is not shining and/or the wind
is not blowing.
\390\ Walton, R. (August 25, 2021). CAISO forced to curtail 15%
of California utility-scale solar in March, 5% last year. Power
Engineering. https://www.power-eng.com/solar/caiso-forced-to-curtail-15-of-california-utility-scale-solar-in-march-5-last-year/#gref.
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Rapid progress is being made, and, due to the demonstrated ability
of new and existing combustion turbines to co-fire hydrogen, other
utility owners/operators have publicly made long-term commitments to
hydrogen co-firing and have identified the technology as a key
component of their future operations and GHG reduction strategies. As
highlighted by the earlier examples, the outlook expressed by multiple
power producers and developers includes a future generation asset mix
that retains combustion turbines fired exclusively with hydrogen.
Utilities in vertically integrated States and merchant generators in
wholesale markets rely on combustion turbines to provide reliable,
dispatchable power.
Hydrogen gas released into the atmosphere will also have climate
and air quality effects through atmospheric chemical reactions. In
particular, hydrogen is known to react with the hydroxyl radical,
reducing concentrations of the hydroxyl radical in the atmosphere.
Because the hydroxyl radical is important for the destruction of many
other gases, a reduction in hydroxyl radical concentrations will lead
to increased lifetimes of many other gases--including methane and
tropospheric ozone. This means that hydrogen gas emissions can also
indirectly contribute to warming through increasing concentrations of
methane and ozone. Hydrogen is not a greenhouse gas as defined by the
Framework Convention on Climate Change under the IPCC, and its
secondary impacts on warming should mitigate over time as methane
emissions are controlled. Even as hydrogen scales and much larger
volumes are consumed, with the attendant potential for emissions of
hydrogen to oxidize in the atmosphere, we expect the benefits of low-
GHG hydrogen as part of a BSER pathway to outweigh any such effects in
the future.
v. Hydrogen Production Processes and Associated Levels of GHG Emissions
Hydrogen is used in industrial processes, and as discussed
previously, in recent years, applications of hydrogen co-firing have
expanded to include stationary combustion turbines used to generate
electricity. However, at present, nearly all industrial hydrogen is
produced via methods that are GHG-intensive. To fully evaluate the
potential GHG emission reductions from co-firing low-GHG hydrogen in a
combustion turbine EGU, it is important to consider the different
processes of producing the hydrogen and the GHG emissions associated
with each process. The following discussion highlights the primary
methods of hydrogen production as well as the sources of energy used
during production and the level of GHG emissions that result from each
production method. The varying levels of CO2 emissions
associated with hydrogen production are well-recognized, and
stakeholders routinely refer to hydrogen on the basis of the different
production processes and their different GHG intensities.\391\
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\391\ Some organizations have developed a convention for
labeling each hydrogen production method, based on the GHG emissions
associated with each method, according to a color scheme. The color
labels are insufficiently specific for the purposes of this proposed
rule, so the EPA generally does not refer to hydrogen using this
color convention.
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More than 95 percent of the dedicated hydrogen currently produced
in the U.S. originates from natural gas using steam methane reforming
(SMR). This method produces hydrogen by adding steam and heat to
natural gas in the presence of a catalyst. Methane reacts with the
steam to produce hydrogen, carbon monoxide (CO), and trace amounts of
CO2. Further, the CO byproduct is routed to a second
process, known as a water-gas shift reaction, to react with more steam
to create additional hydrogen and CO2. After these
processes, the CO2 is removed from the gas stream, leaving
[[Page 33307]]
almost pure hydrogen.\392\ CO2 emissions are generated from
the conversion process itself and from the creation of the thermal
energy and steam (assuming the boilers are fueled by natural gas) or
external energy sources powering the production process. Because the
thermal efficiency of SMR of natural gas is generally 80 percent or
less,\393\ less overall energy is in the produced hydrogen than in the
natural gas required to produce the hydrogen. Therefore, the use of
hydrogen produced through SMR in a combustion turbine would consume
more natural gas than would have been consumed if the combustion
turbine had burned the natural gas directly. Therefore, co-firing
hydrogen derived from SMR based on fossil fuels without CCS results in
higher overall CO2 emissions than using the natural gas
directly in the EGU.
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\392\ U.S. Department of Energy (DOE) (n.d.). Hydrogen
Production: Natural Gas Reforming. https://www.energy.gov/eere/fuelells/hydrogen-production-natural-gas-reforming. For each kg of
hydrogen produced through SMR, 4.5 kg of water is consumed.
\393\ Thermal efficiency is the amount of energy in the
production (e.g., hydrogen) compared to the energy input to the
process (e.g., natural gas). At an efficiency of 80 percent, the
product contains 80 percent of the energy input and 20 percent is
lost.
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The GHG emissions from hydrogen production via SMR can be
controlled with CCS technology at different points in the production
process. There are varying levels of CO2 capture for
different techniques, but typically a range of 65 to 90 percent is
viable.\394\ The autothermal reforming (ATR) of methane is a similar
technology to SMR, but ATR utilizes natural gas in the process itself
without an external heat source.\395\ CCS can also be applied to ATR.
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\394\ Powell, D. (2020). Focus on Blue Hydrogen. Gaffney Cline.
https://www.gaffneycline.com/sites/g/files/cozyhq681/files/2021-08/Focus_on_Blue_Hydrogen_Aug2020.pdf.
\395\ ``Comparative assessment of blue hydrogen from steam
methane reforming, autothermal reforming, and natural gas
decomposition technologies for natural gas production regions,''
Energy Conversion and Management, February 15, 2022.
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Another process to produce hydrogen is methane pyrolysis. Methane
pyrolysis is the thermal decomposition of methane in the absence (or
near absence) of oxygen, which produces hydrogen and solid carbon
(i.e., carbon black) as the only byproducts. Pyrolysis uses energy to
power its hydrogen production process, and therefore the level of its
overall GHG emissions depends on the carbon intensity of its energy
inputs. For SMR, ATR, and pyrolysis technologies, emissions from
methane extraction, production, and transportation are also significant
aspects of their GHG emissions footprints.\396\
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\396\ In addition, methane extraction operations are known to
contribute to air toxics including benzene, ethylbenzene, and n-
hexane. https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/basic-information-oil-and-natural-gas.
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In contrast to the three methods discussed above, electrolysis does
not use methane as a feedstock. In electrolysis, hydrogen is produced
by splitting water into its components, hydrogen and oxygen
(O2), via electricity. During electrolysis, a negatively
charged cathode and positively charged anode are submerged in water and
an electric current is passed through the water. The result is hydrogen
molecules appearing at the negative cathodes and O2
appearing at the positive anodes. Electrolysis does not emit GHG
emissions at the hydrogen production site; the overall GHG emissions
associated with electrolysis are instead dependent upon the source of
the energy used to decompose the water.\397\ According to the DOE,
electrolysis powered by fossil fuel energy supplied by the electric
grid, based on a national average, would generate overall GHG emissions
double those of hydrogen produced via SMR without
CCS.398 399 However, electrolysis powered by wind, solar,
hydroelectric, or nuclear energy is generally considered to lower
overall GHG emissions.400 401 402 It should be noted that
electrolytic systems utilizing even a small portion of grid-based
electricity may not have lower overall GHG emissions and carbon
intensities than SMR without CCS.\403\ This concern is likely to be
mitigated over time as the carbon intensity of the grid declines, given
the influx of new renewable generation--the EPA's post-IRA 2022
reference case projects a lower carbon intensity of the grid---coupled
with expected retirements of higher-emitting sources. Naturally
occurring hydrogen stored in subsurface geologic formations is also
gaining attention as a potential low-GHG source of hydrogen.
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\397\ Similarly, the overall GHG emissions associated with
methane pyrolysis are dependent upon the source of the energy used
to decompose the methane and is a key factor to whether it qualifies
as low-GHG hydrogen.
\398\ DOE (2022). DOE National Clean Hydrogen Strategy and
Roadmap. Draft--September 2022. https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-strategy-roadmap.pdf.
\399\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023: https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. From the Liftoff
report, ``Carbon intensities are based on data from the Carnegie
Mellon Power Sector Carbon Index as well as national averages in
grid mix carbon intensity--in some states, grid carbon intensity can
be as high as 40 kg CO2e/kg H2.''
\400\ U.S. Department of Energy (DOE) (n.d.). Hydrogen
Production: Electrolysis. https://www.energy.gov/eere/fuelcells/hydrogen-production-electrolysis.
\401\ For each kg of hydrogen produced through electrolysis, 9
kg of byproduct oxygen are also produced and 9 kg of purified water
are consumed. To reduce the cost of hydrogen production, this
byproduct oxygen could be captured and sold. For each gallon of
water consumed, 0.057 MMBtu of hydrogen is produced. According to
the water use requirements for combined cycle EGUs with cooling
towers, if this hydrogen is later used to produce electricity in a
combined cycle EGU, overall water requirements would be greater than
a combined cycle EGU with CCUS.
\402\ Electrolysis and other technologies that break apart water
to form hydrogen and oxygen consume more water than SMR without CCS.
Resource Assessment for Hydrogen Production. National Renewable
Energy Laboratory (NREL/TP-5400-77198, July 2020). https://www.nrel.gov/docs/fy20osti/77198.pdf. Aside from methane pyrolysis
and byproduct hydrogen, other hydrogen production methods consume
water during the production process and indirectly due to
electricity generation upstream. The moisture present in coal and
biomass could be recovered and used in the water gas shift reaction
to reduce (or eliminate) water requirements.
\403\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen. March 2023. https://www.energy.gov/articles/doe-releases-new-reports-pathways-commercial-liftoff-accelerate-clean-energy-technologies.
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vi. The EPA's Proposed BSER and Definition of Low-GHG Hydrogen
The EPA is proposing that the second component of the BSER for new
combustion turbines in the relevant subcategories is co-firing 30
percent (by volume) low-GHG hydrogen and that sources meet a
corresponding standard of performance by 2032. The EPA is also
proposing that new base load combustion turbines that are subject to a
standard of performance based on co-firing 30 percent (by volume) low-
GHG hydrogen in 2032 must also meet a more stringent standard of
performance based on a BSER of co-firing 96 percent (by volume) low-GHG
hydrogen by 2038. This section describes the factors the EPA considered
in determining what level of co-firing qualifies as a component of the
BSER for affected sources and the timing for when that level of co-
firing could be technically feasible and of reasonable cost. Key
factors informing this determination include the magnitude of
CO2 emission reductions at the combustion turbines, the
availability of combustion turbines capable of co-firing hydrogen,
potential infrastructure limitations, and access to low-GHG hydrogen.
The relationship between the volume of hydrogen fired and the
reduction in CO2 stack emissions is exponential. At low
levels of co-firing there are modest emission reduction benefits, but
these reduction benefits amplify as the volume of hydrogen increases
due to the lower energy density of hydrogen
[[Page 33308]]
compared to natural gas. For example, co-firing 10 percent hydrogen by
volume yields approximately a 3 percent CO2 reduction at the
stack, co-firing 30 percent hydrogen yields a 12 percent CO2
reduction, co-firing 75 percent hydrogen yields a 49 percent
CO2 reduction, and at 100 percent hydrogen co-firing there
are zero CO2 emissions at the stack.
Importantly, co-firing 30 percent hydrogen by volume is consistent
with existing technologies across multiple combustion turbine designs
and should be considered a minimal level for evaluation as a system of
emission reduction. While all major manufacturers are developing
combustion turbines that can co-fire higher volumes of hydrogen, some
combustion turbine models are already able to co-fire relatively high
percentages.\404\ Several currently available new combustion turbine
models can burn up to 75 percent hydrogen by volume.\405\ Combustion
turbine designs capable of co-firing 30 percent hydrogen by volume are
available from multiple manufacturers at multiple sizes. As such, a
BSER that included co-firing 30 percent hydrogen by volume would not
pose challenges for near-term implementation for the EPA's proposed
second phase standards beginning in 2032. The EPA is soliciting comment
on whether the new and reconstructed combustion turbines will have
available combustion turbine designs that would allow higher levels of
hydrogen co-firing, such as 50 percent or more by volume by 2030 or
2032. If such combustion turbines are sufficiently available, this
would support moving forward the starting compliance date of the second
phase of the standards of performance and/or increasing the percent of
hydrogen co-firing assumed in establishing the standards.
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\404\ Mitsubishi Power Americas. https://power.mhi.com/special/hydrogen/article_1.
\405\ Overcoming technical challenges of hydrogen power plants
for the energy transition. https://www.nsenergybusiness.com.
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Because the cost of natural gas is lower than the cost of hydrogen,
most new combustion turbines are not, at the present time, designed to
burn 100 percent hydrogen when they are placed into service. However,
some turbines are available now that can combust 100 percent hydrogen
in the future and there is significant evidence that such turbines will
be more widely available by the 2030s.\406\ Multiple vendors have
indicated that they intend to have turbines available that fire 100
percent hydrogen in that timeframe.407 408 409 For example,
as noted in section IV.E of this preamble, the LADWP Scattergood
Modernization project includes plans to have a hydrogen-ready
combustion turbine in place when the 346-MW combined cycle plant
(potential for up to 830 MW) begins initial operations in 2029. LADWP
foresees the plant running on 100 percent electrolytic hydrogen by
2035.\410\ The Intermountain Power Project, also noted in section IV.E
of this preamble, commenced construction in 2022 on an 840-MW M501 JAC
Mitsubishi Hitachi Power Systems combustion turbine designed to operate
using 30 percent (by volume) hydrogen upon startup. The plant is
projected to be operational by July 2025 and to transition to 100
percent hydrogen by 2045.\411\ Several existing gas turbine
technologies are capable of operating with 100 percent hydrogen,
including Siemens Energy's SGT-A35 and General Electric's B, E, and F
class gas turbines.\412\ Comments submitted to the EPA's non-regulatory
docket confirm that at the present time, existing units can be
retrofitted to operate using 100 percent hydrogen. DOE's National
Energy Technology Lab states: Based on data from a literature survey
and input from manufacturers, NETL has found that today's modern gas
turbines can reliably combust 30-60 percent hydrogen fuels with similar
NOX emissions as compared to their pure natural gas
counterparts. Public and private research is underway to produce a 100
percent hydrogen-fueled turbine. NETL anticipates that industry will
achieve this technology by around 2030 based on current research
progress and publicly announced forecasts.'' \413\ Turbine projects
that have recently been built and that are currently under construction
(such as the Longview turbine and the Intermountain Power Project
discussed elsewhere in this preamble) are being developed with the
understanding that these technology advances will be retrofittable to
these types of turbines. It is worth noting that in many cases,
existing turbines are able to co-fire large amounts of hydrogen without
significant re-engineering. This is because their burners are developed
relatively simply and are able to combust large amounts of hydrogen. In
retrospect almost all new turbines are designed with more sophisticated
burners that closely control the mixture of air and fuel to maximize
efficiency while limiting nitrogen oxide generation. Because hydrogen
has very different characteristics than natural gas such as higher
flame temperature, these burners need to be re-engineered to
accommodate large amounts of hydrogen 414 415 For more
information about the status of combustion turbines with respect to
combusting hydrogen see the TSD, ``Hydrogen in Combustion Turbine
EGUs,'' in the docket for this rulemaking.
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\406\ https://www.dieselgasturbine.com/news/siemens-energy-explores-gas-turbines-future-in-net-zero-energy-mix/8024799.article.
\407\ Mitsubishi highlights four hydrogen projects at CERAWeek.
https://www.power-eng.com/hydrogen/mitsubishi-power-highlights-four-hydrogen-projects/#gref.
\408\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units Docket ID No. EPA-HQ-OAR-2022-0289. Docket comments noted,
``Retrofits using existing technology are available to achieve 50-
100% hydrogen combustion by volume at some generators.''
\409\ Siemens Energy to provide hydrogen-capable turbines to
back up utility-scale solar installation in Nebraska. https://press.siemens-energy.com/global/en/pressrelease/siemens-energy-provide-hydrogen-capable-turbines-back-utility-scale-solar-installation.
\410\ https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
\411\ IPP Renewed--Intermountain Power Agency.ipautah.com.
\412\ ICF. Retrofitting Gas Turbine Facilities for Hydrogen
Blending.
\413\ National Energy Technology Laboratory, A Literature Review
of Hydrogen and Natural GAS Turbines: Current State of the Art With
Regard to Performance and NOX Control (DOE/NETL-2022/
3812), August 12, 2022. https://netl.doe.gov/sites/default/files/publication/A-Literature-Review-of-Hydrogen-and-Natural-Gas-Turbines-081222.pdf; Department of Energy, National Energy
Technology Laboratory, ``Experts Discuss Use of Hydrogen-Fueled
Turbines to Drive Clean Energy'' September 15, 2022. https://netl.doe.gov/node/12058.
\414\ Siemens Energy, ``Ten Fundamentals to Hydrogen Readiness''
September 2022. https://www.siemens-energy.com/global/en/news/magazine/2022/hydrogen-ready.html.
\415\ General Electric, ``Hydrogen-Fueled Gas Turbines'' https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
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Access to low-GHG hydrogen, however, is also an important component
of the BSER analysis. Midstream infrastructure limitations and the
adequacy and availability of hydrogen storage facilities currently
present obstacles and increase prices for delivered low-GHG hydrogen.
This is part of the rationale for why the EPA is not proposing hydrogen
co-firing as part of the first component of the BSER. Moving gas via
pipeline tends to be the least expensive transport and today there are
1,600 miles of dedicated hydrogen pipeline infrastructure.\416\ As
noted later in a section of this preamble, based on industry
announcements, many electrolytic hydrogen production projects will be
sited near existing
[[Page 33309]]
infrastructure and, in certain cases, will provide combustion turbines
access to supply and delivery solutions. Hydrogen blending into
existing natural gas pipelines presents another mode of transport and
distribution that is actively in use in Hawaii and under exploration in
other areas of the country.\417\ On-road distribution methods include
gas-phase trucking and liquid hydrogen trucking, the latter requiring
cooling and compression prior to transport. Different regional
distribution solutions may emerge initially in response to localized
hydrogen demand.
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\416\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
\417\ https://www.hawaiigas.com/clean-energy/decarbonization.
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Gaseous and liquified hydrogen storage technologies are developing,
along with lined hard rock storage and limited but promising geologic
salt cavern storage. Increased storage capacity and market demand for
low-GHG hydrogen is anticipated in response to Federal H2Hub
investments as low-GHG hydrogen develops from a localized fuel into a
national commodity.
Given the growth in the hydrogen sector and Federal funding for the
H2Hubs, which will explicitly explore and incentivize hydrogen
distribution, the EPA therefore believes hydrogen distribution and
storage infrastructure will not present a barrier to access for new
combustion turbines opting to co-fire 30 percent low-GHG hydrogen by
volume in 2032 and to co-fire 96 percent low-GHG hydrogen by volume in
2038. The EPA is soliciting comment on the expected low-GHG hydrogen
availability by those dates. The EPA is also soliciting comment on
whether hydrogen infrastructure is likely to be sufficiently developed
by 2030 to provide access to low-GHG hydrogen for new and reconstructed
combustion turbines. If so, this would support moving forward the
compliance date of the second phase of the standards of performance
and/or increase the percent of hydrogen co-firing assumed in
establishing the standards.
Whether there will be sufficient volumes of low-GHG hydrogen for
new sources to co-fire 30 percent by volume between 2030 and 2032 and
then for some base load sources to co-fire 96 percent by 2038 will
depend on the deployment of additional low-GHG electric generation
sources, the growth of electrolyzer capacity, and market demand. Along
with the power sector, the industrial and transportation sectors are
also advancing hydrogen-ready technologies. Industries and policymakers
in those sectors are actively planning to use hydrogen to drive
decarbonization. For the industrial sector where hydrogen is a chemical
input to the process or a replacement for liquid fuels, multiple
projection pathways are being considered as approaches to lower the GHG
intensity of these sectors. The production pathways for the industrial
sector include, but are not limited to, fossil-derived hydrogen in
combination with CCS. However, due to thermodynamic inefficiencies in
using hydrogen to produce electricity, it is likely that only a
specific type of low-GHG hydrogen will be used in the power sector.
Announcements of co-firing applications support this assertion, and as
discussed in another section of this preamble, the power sector is
already focused on utilizing low-GHG hydrogen, electricity generators
are likely to have ample access to low-GHG hydrogen and in sufficient
quantities to support 30 percent co-firing by 2032 and 96 percent by
2038. The DOE's estimates of clean hydrogen production volumes of 10
MMT by 2030 and 20 MMT by 2040, referenced throughout this rulemaking,
do not apportion which type of hydrogen is likely to be produced, just
that it is `clean.' \418\ The available credits for the lowest GHG
hydrogen production tier under IRC section 45V tax subsidies going into
effect in 2023, as outlined in another section of this preamble, are
three times higher than the credit values allotted for other hydrogen
production tiers in IRC section 45V. This incentive can be combined
with additional monetization access through direct pay and
transferability, and therefore has the potential to drive significant
volumes of electrolytic hydrogen, which is likely to be considered as
low-GHG hydrogen in this proposal.\419\ The EPA's hydrogen co-firing
BSER proposal, if finalized, would create a significant additional
demand driver for electrolytic hydrogen not considered in the DOE's
hydrogen production goals of 10 MMT by 2030 and 20 MMT by 2040. Indeed,
high volumes of electrolytic hydrogen were central to pathways enabling
the power sector to achieve net-zero emissions by 2035 according to
analysis by the National Renewable Energy Laboratory (NREL).\420\ These
incentives will be multiplied by investments through the DOE's H2Hub
program. Electrolytic production costs, inclusive of the 45V PTC, are
estimated to fall to less than $0.40/kg by 2030; this could translate
to delivered cost of hydrogen for combustion turbines in 2030 between
$0.70/kg and $1.15/kg depending on storage and distribution costs.\421\
The EPA is soliciting comment on whether sufficient quantities of low-
GHG hydrogen are likely to be available at reasonable costs by 2030. If
so, this would support moving forward the compliance date of the second
component of the BSER and/or increase the percent of hydrogen co-firing
assumed in establishing the standard of performance.
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\418\ DOE, as required by the IIJA, proposed a Clean Hydrogen
Production Standard (CHPS) of having an overall emissions rate of 4
kg CO2e/kg H2. CHPS is not an actual standard,
rather a non-binding tool for DOE's internal use with selecting
projects under the H2Hubs program. DOE's proposed CHPS can be found
at https://www.hydrogen.energy.gov/pdfs/clean-hydrogen-production-standard.pdf.
\419\ ``The Hydrogen Credit Catalyst: How US Treasury guidance
on a new tax credit could shape the clean hydrogen economy, the
future of American industry, and orient the power sector for full
decarbonization,'' Rocky Mountain Institute, February 27, 2023.
\420\ Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022.
Examining Supply-Side Options to Achieve 100% Clean Electricity by
2035. Golden, CO: National Renewable Energy Laboratory. NREL/
TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
\421\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Clean Hydrogen. March 2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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As discussed earlier, an important feature of hydrogen as a
potential fuel for combustion turbines is the level of GHG emissions
generated during the production process, with different processes
resulting in different levels of GHG emissions. The EPA proposes to
conclude that co-firing with low-GHG hydrogen (but not other forms of
hydrogen) appropriately considers the statutory factors and constitutes
the ``best'' system of emission reduction. Here, the EPA discusses the
proposed definition of low-GHG hydrogen. In the IIJA and IRA, Congress
established programs to support the development of low-GHG hydrogen,
including section 40314 of the IIJA which established a $8 billion
Clean Hydrogen Hubs H2Hubs program, the $500 million Clean Hydrogen
Manufacturing and Recycling Program, and a $1 billion Clean Hydrogen
Electrolysis Program to further electrolysis development. Section 40315
of the IIJA required DOE to establish a non-regulatory Clean Hydrogen
Production Standard (CHPS). Most recently, in the IRA, section 13204,
Congress authorized the clean hydrogen production tax credit (45V).
Several Federal agencies, including the EPA, are implementing those
programs. DOE consulted the EPA while developing its proposed CHPS,
which included examining various hydrogen production processes and the
spectrum of resulting overall carbon intensities.
[[Page 33310]]
That collaborative process provided useful points of reference for the
EPA to use in proposing a definition in this rulemaking.
In enacting the IRA, Congress recognized that different methods of
hydrogen production generate different amounts of GHG emissions and
sought to encourage lower-emitting production methods through the
multi-tier hydrogen production tax credit (IRC section 45V). The IRC
section 45V tax credits provide four tiers of tax credits, and thus
award the highest amount of tax credits to the hydrogen production
processes with the lowest estimated GHG emissions. The highest tier of
the credits is $3/kg H2 for 0.0 to 0.45 kg CO2e/
kg H2 produced, and the lowest is $0.6/kg H2 for
2.5 to 4.0 kg CO2e/kg H2.\422\ Congress also
provided a definition of ``clean hydrogen'' in section 822 of the IIJA.
This provision sets out a non-binding goal intended for use in
development of the DOE's Clean Hydrogen Production Standard (CHPS) and
DOE's funding programs to promote promising new hydrogen technologies.
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\422\ These amounts assume that wage and apprenticeship
requirements are met.
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Several Federal agencies are engaging in low-GHG hydrogen-related
efforts, some of which implement the IRA and IIJA provisions. As
discussed earlier in this section, the DOE is working on a Clean
Hydrogen Production Standard,\423\ an $8 billion Clean Hydrogen Hub
solicitation,\424\ and several hydrogen-related research and
development grant programs.\425\ The Department of the Treasury is
taking public comment on examining appropriate parameters for
evaluating overall emissions associated with hydrogen production
pathways as it prepares to implement IRC section 45V.\426\ Within the
EPA, there are rulemaking efforts that could impact low-GHG hydrogen
production pathways, namely the proposed and supplemental oil and gas
emission guidelines to reduce methane emissions.
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\423\ U.S. Department of Energy (DOE). (September 22, 2022).
Clean Hydrogen Production Standard. Hydrogen and Fuel Cell
Technologies Office. https://www.energy.gov/eere/fuelcells/articles/clean-hydrogen-production-standard.
\424\ https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
\425\ https://www.hydrogen.energy.gov/funding_opportunities.html.
\426\ https://home.treasury.gov/news/press-releases/jy0993.
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The IIJA includes both a textual definition of ``clean hydrogen''
and requires the DOE to develop a Clean Hydrogen Production Standard:
these two references are related but distinct. Upon review of the
reference points that these legislative provisions and Agency programs
provide, it is apparent that the clean hydrogen definition in section
822 of the IIJA is not appropriate for the purposes of this rule. As
noted, this provision sets a non-binding goal for use in the
development of the DOE's Clean Hydrogen Production Standard (CHPS) and
the DOE's funding programs to promote promising new hydrogen
technologies. The definition of clean hydrogen in the IIJA is limited
to GHGs emitted at the hydrogen production site and is therefore not
intended to consider overall GHG emissions associated with that
production method. According to the IIJA, clean hydrogen as defined as
part of the CHPS is ``. . . hydrogen produced with a carbon intensity
equal to or less than 2 kilograms of carbon dioxide-equivalent produced
at the site of production per kilogram of hydrogen produced'' (emphasis
added). A significant portion of the GHG emissions associated with
hydrogen derived from natural gas originates from upstream methane
emissions, which are not accounted for in the CHPS definition.\427\
That definition was taken into consideration, along with multiple other
data points, for development of the CHPS. In CHPS draft guidance, a
target of 4 kg CO2e/kg H2 on a well-to-gate
basis, which aligns with full range of the IRC section 45V definition
in the IRA.\428\
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\427\ Infrastructure Investment and Jobs Act of 20211Law
PUBL058.PS (https://www.congress.gov).
\428\ U.S. Department of Energy Clean Hydrogen Production
Standard (CHPS) Draft Guidance
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In contrast, the EPA believes that the highest tier of the IRC
section 45V(b)(2) production tax credit is salient for purposes of the
present rule. That provision provides the highest available amount of
production tax credit for hydrogen produced through a process that has
a GHG emissions rate of 0.45 kg CO2e/kg H2 or
less, from well-to-gate. As explained further below, the EPA proposes
that co-firing hydrogen that meets this criterion qualifies as a
component of the ``best'' system of emission reduction, taking into
account the statutory considerations. Thus, consistent with the tiered
approach and system boundaries in the IRA definition of clean hydrogen,
the EPA is proposing that low-GHG hydrogen is hydrogen that is produced
through a process that has a GHG emissions rate of 0.45 kg
CO2e/kg H2 or less, from well-to-gate. Each of
the subsequent hydrogen production categories outlined in 45V(b)(2)
convey increasingly higher amounts of GHG emissions (from a well-to-
gate analysis), making them less suitable to be a component of the
BSER.
Electrolyzers with various low-GHG energy inputs, like solar, wind,
hydroelectric, and nuclear, appear most likely to produce hydrogen that
would meet the 0.45 kg CO2e/kg H2 or less, from
well-to-gate criteria.\429\ Hydrogen production pathways using methane
as a feedstock induce upstream methane emissions associated with
extraction, production, and transport of the methane. SMR and ATR also
release heating and process-related CO2 emissions that are
difficult to capture at high rates economically. High contributions to
overall GHG emission rates may disqualify certain hydrogen production
pathways from producing low-GHG hydrogen. The EPA recognizes that the
pace and scale of government programs and private research suggest that
we will gain significant experience and knowledge on this topic during
the timeframe of this proposed rulemaking. Accordingly, the EPA is
soliciting comment broadly on its proposed definition for low-GHG
hydrogen, and on alternative approaches, to ensure that co-firing low-
GHG hydrogen minimizes GHG emissions, and that combustion turbines
subject to this standard utilize only low-GHG hydrogen.
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\429\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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The EPA is also taking comment on whether it is necessary to
provide a definition of low-GHG hydrogen in this rule. Given the
incentives provided in both the IRA and IIJA for low-GHG hydrogen
production and the current trajectory of hydrogen use in the power
sector, by 2032, the start date for compliance with the proposed second
phase of the standards for this rule, low-GHG hydrogen may be the most
common source of hydrogen available for electricity production. For the
most part, companies that have announced that they are exploring the
use of hydrogen co-firing have stated that they intend to use low-GHG
hydrogen. These power suppliers include NextEra, Los Angeles Department
of Power and Water, and New York Power Authority, as discussed earlier
in this section. Many utilities and merchant generators own nuclear,
wind, solar, and hydroelectric generating sources as well as combustion
turbines. The EPA has identified an emerging trend in which energy
companies with this broad collection of generation assets are planning
to produce low-GHG hydrogen for sale and to use a portion of it to fuel
their stationary combustion turbines. This emerging trend lends support
to the view that the power sector is likely
[[Page 33311]]
to have access to and will choose to utilize low-GHG hydrogen for its
co-firing applications. Some NGOs have expressed concern that existing
non-emitting assets will channel electricity from the grid toward
electrolyzers, potentially increasing marginal electricity generation
from assets with higher carbon intensities. The EPA agrees these are
important issues that should be considered as levels of excess zero
carbon-emitting generation vary diurnally and by region. The EPA notes
that these concerns should mitigate over time as the carbon intensity
of the grid is projected to decline.
Moreover, by the next decade, costs for low-GHG hydrogen are
expected to be competitive with higher-GHG forms of hydrogen given
declines due to learning and the IRC section 45V subsidies. Given the
tax credits in IRC section 45V(b)(2)(D) of $3/kg H2 for
hydrogen with GHG emissions of less than 0.45 kg CO2e/kg
H2, and substantial DOE grant programs to drive down costs
of clean hydrogen, some entities project the delivered costs of
electrolytic low-GHG hydrogen to range from $1/kg H2 to $0/
kg H2 or less.430 431 432 These projections are
more optimistic than, but still comparable to, DOE projections of 2030
for delivered costs of electrolytic low-GHG hydrogen in the range of
$0.70/kg to $1.15/kg for power sector applications, given R&D
advancements and economies of scale.\433\ A growing number of studies
are demonstrating more efficient and less expensive techniques to
produce low-GHG electrolytic hydrogen; and, tax credits and market
forces are expected to accelerate innovation and drive down costs even
further over the next decade.434 435 436 The combination of
competitive pricing and widespread net-zero commitments throughout the
utility and merchant electricity generation market has the potential to
drive future hydrogen co-firing applications to be low-GHG
hydrogen.\437\ The EPA is therefore soliciting comment on whether low-
GHG hydrogen needs to be defined as part of the BSER in this proposed
rulemaking.
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\430\ ``US green hydrogen costs to reach sub-zero under IRA:
longer-term price impacts remain uncertain,'' S&P Global Commodity
Insights, September 29, 2022.
\431\ ``DOE Funding Opportunity Targets Clean Hydrogen
Technologies'' American Public Power, January 31, 2023.
\432\ With the 45V PTC, delivered costs of hydrogen are
projected to fall in the range of $0.70/kg to $1.15/kg for power
sector applications.
\433\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
\434\ ``Sound waves boost green hydrogen production,'' Power
Engineering, January 4, 2023.
\435\ ``Direct seawater electrolysis by adjusting the local
reaction environment of a catalyst,'' Nature Energy, January 30,
2023.
\436\ https://h2new.energy.gov/.
\437\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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vii. Justification for Proposing 30 Percent Co-Firing Low-GHG Hydrogen
and 96 Percent Co-Firing Low-GHG Hydrogen as Components of the BSER
The EPA is proposing that co-firing 30 percent low-GHG hydrogen, as
proposed to be defined above, by new combustion turbines in the
relevant subcategories, by 2032, meets the requirements under CAA
section 111(a)(1) to qualify as a component of the BSER. Similarly, the
EPA is proposing that co-firing 96 percent low-GHG hydrogen by new base
load combustion turbines in the relevant subcategory, by 2038, also
meets the requirements under CAA section 111(a)(1) to qualify as a
component of the BSER. As discussed below, co-firing 30 percent low-GHG
hydrogen is adequately demonstrated because it is feasible and well-
demonstrated for new combustion turbines to co-fire that percentage of
hydrogen and multiple combustion turbine vendors have targets to have
100 percent hydrogen-capable combustion turbines available by around
2030 and are selling combustion turbines today with the intention of
those combustion turbines being retrofittable to 100 percent hydrogen
firing.438 439 Several project developers have announced
plans to transition from lower levels of co-firing up to firing with
100 percent hydrogen.
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\438\ https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-marks-triumph-for-ge/.
\439\ https://www.doosan.com/en/media-center/press-release_view?id=20172449.
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The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032
and 96 percent by 2038 qualify as a BSER pathway for new baseload
combustion turbines. For the reasons discussed next, the EPA proposes
that co-firing low-GHG hydrogen on that pathway is adequately
demonstrated in light of the capability of combustion turbines to co-
fire hydrogen and the EPA's reasonable expectation that adequate
quantities of low-GHG hydrogen will be available by 2032 and 2038 and
at reasonable cost. Moreover, combusting hydrogen will achieve
reductions because it does not produce GHG emissions and will not have
adverse non-air quality health or environmental impacts or energy
requirements, including on the nationwide energy sector. Because the
production of low-GHG hydrogen generates the fewest GHG emissions, the
EPA proposes that co-firing low-GHG hydrogen, and not other types of
hydrogen, qualifies as the ``best'' system of emission reduction. The
fact that co-firing low GHG hydrogen creates market demand for, and
advances the development of, low-GHG hydrogen, a fuel that is useful
for reducing emissions in the power sector and other industries,
provides further support for this proposal.
(A) Adequately Demonstrated
As part of the present rulemaking, the EPA evaluated the ability of
new combustion turbines to operate with certain percentages (by volume)
of hydrogen blended into their fuel systems. This evaluation included
an analysis of the technical challenges of co-firing hydrogen in a
combustion turbine EGU to generate electricity. The EPA also evaluated
available information to determine if adequate quantities of low-GHG
hydrogen can be reasonably expected to be available for combustion
turbine EGUs by 2032.
Although industrial combustion turbines have been burning byproduct
fuels containing large percentages of hydrogen for decades, utility
combustion turbines have only recently begun to co-fire smaller amounts
of hydrogen as a fuel to generate electricity. The primary technical
challenges of hydrogen co-firing are related to certain physical
characteristics of the gas. When hydrogen fuel is combusted, it
produces a higher flame speed than the flame speed produced with the
combustion of natural gas; and hydrogen typically combusts at a faster
rate than natural gas. When the combustion speed is faster than the
flow rate of the fuel, a phenomenon known as ``flashback'' can occur,
which can lead to upstream complications.\440\ Hydrogen also has a
higher flame temperature and a wider flammability range compared to
natural gas.\441\
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\440\ Inoue, K., Miyamoto, K., Domen, S., Tamura, I., Kawakami,
T., & Tanimura, S. (2018). Development of Hydrogen and Natural Gas
Co-firing Gas Turbine. Mitsubishi Heavy Industries Technical Review.
Volume 55, No. 2. June 2018.https://power.mhi.com/randd/technical-review/pdf/index_66e.pdf.
\441\ Andersson, M., Larfeldt, J., Larsson, A. (2013). Co-firing
with hydrogen in industrial gas turbines. https://sgc.camero.se/ckfinder/userfiles/files/SGC256(1).pdf.
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The industrial combustion turbines currently burning hydrogen are
smaller than the larger utility combustion turbines and use diffusion
flame combustion, often in combination with water injection, for
NOX control. While
[[Page 33312]]
water injection requires demineralized water and is generally only a
NOX control option for simple cycle turbines, existing
simple cycle combustion turbines have successfully demonstrated that
relatively high levels of hydrogen can be co-fired in combustion
turbines using diffusion flame and supports the EPA's proposal to
determine that co-firing 30 percent hydrogen is technically feasible
for new base load and intermediate load stationary combustion turbine
EGUs by 2032 and that co-firing higher levels--up to 96 percent by
volume--is feasible by 2038. The EPA solicits comment on these proposed
findings.
The more commonly used NOX combustion control for base
load combined cycle turbines is dry low NOX (DLN)
combustion. Even though the ability to co-fire hydrogen in combustion
turbines that are using DLN combustors to reduce emissions of
NOX is currently more limited, all major combustion turbine
manufacturers have developed DLN combustors for utility EGUs that can
co-fire hydrogen.\442\ Moreover, the major combustion turbine
manufacturers are designing combustion turbines that will be capable of
combusting 100 percent hydrogen by 2030, with DLN designs that assure
acceptable levels of NOX emissions.443 444
Several developers have announced installations with plans to initially
co-fire lower percentages of low-GHG hydrogen by volume before
gradually increasing their co-firing percentages--to as high as 100
percent in some cases--depending on the pace of the anticipated
expansion of low-GHG hydrogen production processes and associated
infrastructure. The goals of equipment manufacturers and the fact that
existing combined cycle combustion turbines have successfully
demonstrated the ability to co-fire various percentages of hydrogen
supports the EPA's proposal to determine that co-firing 30 percent
hydrogen is technically feasible for new base load stationary
combustion turbine EGUs by 2032 and that co-firing 96 percent hydrogen
is technically feasible for new base load stationary combustion turbine
EGUs by 2038.
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\442\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
\443\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power
plants by 2030. https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
\444\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas
Turbines. https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
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The combustion characteristics of hydrogen can lead to localized
higher temperatures during the combustion process. These ``hotspots''
can increase emissions of the criteria pollutant NOX.\445\
NOX emissions resulting from the combustion of high
percentage by volume blends of hydrogen are also of concern in many
regions of the country. For turbines using diffusion flame combustion,
water or steam injection is used to control emissions of
NOX. The level of water injection can be varied for
different levels of NOX control and adjustments can be made
to address any potential increases in NOX that would occur
from co-firing hydrogen in combustion turbines using diffusion flame
combustion. As stated previously, all major combustion turbine
manufacturers have developed DLN combustors for utility EGUs that can
co-fire hydrogen and are designing combustion turbines that will be
capable of combusting 100 percent hydrogen by 2030, with DLN designs
that assure acceptable levels of NOX emissions. In addition,
EGR in diffusion flame combustion turbines reduces the oxygen
concentration in the combustor and limits combustion temperatures and
NOX formation. Furthermore, while combustion controls can
achieve low levels of NOX, many new intermediate load and
base load combustion turbines using DLN combustion also use selective
catalytic reduction (SCR) to reduce NOX emissions even
further. The design level of control from SCR can be tied to the
exhaust gas concentration. At higher levels of incoming NOX,
either the reagent injection rate can be increased and/or the size of
the catalyst bed can be increased.\446\ The EPA has concluded that any
potential increases in NOX emissions do not change the
Agency's view that on balance, co-firing low-GHG hydrogen qualifies as
a component of the BSER.
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\445\ Guarco, J., Langstine, B., Turner, M. (2018). Practical
Consideration for Firing Hydrogen Versus Natural Gas. Combustion
Engineering Association. https://cea.org.uk/practical-considerations-for-firing-hydrogen-versus-natural-gas/.
\446\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
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As noted above, at present, most of the hydrogen produced in the
U.S. is produced for the industrial sector through SMR, which is a high
GHG-emitting process. Limited quantities of hydrogen are currently
being produced via SMR with CCS, which reduces some, but not all, of
the associated GHG-emitting processes. Only small-scale facilities are
currently producing hydrogen through electrolysis with renewable or
nuclear energy, and as described below, much larger facilities are
under development.
However, as also noted above, incentives in recent Federal
legislation are anticipated to significantly increase the availability
of low-GHG hydrogen by 2032, including for the utility power sector.
The IIJA, enacted in 2021, allocated more than $9 billion to the DOE
for research, development, and demonstration of low-GHG hydrogen
technologies and the creation of at least four regional low-GHG
hydrogen hubs. The DOE has indicated its intention to fund between six
and 10 hubs.\447\ In addition, the IRA provided significant incentives
to invest in low-GHG hydrogen production (For additional discussion of
the IIJA and/or IRA, see section IV.E of this preamble.)
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\447\ IIJA authorized a total of $9.5B for hydrogen related
programs ($8 billion for Clean Hydrogen Hubs H2Hubs, $1B for
electrolyzer research and development and $500 million for hydrogen-
related manufacturing incentives). See also: U.S. Dept. of Energy,
Regional Clean Hydrogen Hubs. https://www.energy.gov/oced/regional-clean-hydrogen-hubs.
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Programs from the IIJA and IRA have been successful in prompting
the development of new low-GHG hydrogen projects and infrastructure. As
of August 2022, 374 new projects had been announced that would produce
2.2 megatons (Mt) of low-GHG hydrogen annually, which represents a 21
percent increase over current output.\448\ Examples include:
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\448\ Energy Futures Initiative (February 2023). U.S. Hydrogen
Demand Action Plan. https://energyfuturesinitiative.org/reports/.
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In June 2022, the DOE issued a $504.4 million loan
guarantee to finance Advanced Clean Energy Storage (ACES), a low-GHG
hydrogen production and long-term storage facility in Delta, Utah.\449\
The facility will use 220 MW of electrolyzers powered by renewable
energy to produce low-GHG hydrogen. The hydrogen will be stored in salt
caverns and serve as a long-term fuel supply for the combustion turbine
at the Intermountain Power Agency (IPA) project, which is described
earlier in this section.
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\449\ U.S. Department of Energy (DOE). (2022). Loan Office
Programs. Advanced Clean Energy Storage. https://www.energy.gov/lpo/advanced-clean-energy-storage.
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In January 2023, NextEra announced an 800-MW solar project
in the central U.S. to support the development of low-GHG hydrogen as
well as plans to produce its own low-
[[Page 33313]]
GHG hydrogen at a facility in Arizona.\450\
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\450\ Penrod, Emma. (January 30, 2023). NextEra charts path for
renewables expansion, but campaign finance allegations loom in the
background. Utility Dive. https://www.utilitydive.com/news/nextera-renewables-expansion-green-hydrogen-solar-alleged-campaign-finance-violation/641475/.
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In New York, Constellation (formerly Exelon Generation) is
exploring the potential benefits of integrating onsite low-GHG hydrogen
production, storage, and usage at its Nine Mile Point nuclear station.
The project is funded by a DOE grant and includes partners such as Nel
Hydrogen, Argonne National Laboratory, Idaho National Laboratory, and
the National Renewable Energy Laboratory. The project is expected to
generate an economical supply of low-GHG hydrogen that will be safely
captured, stored, and potentially taken to market as a source of power
for other purposes, including industrial applications such as
transportation.\451\
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\451\ https://www.exeloncorp.com/newsroom/Pages/DOE-Grant-to-Support-Hydrogen-Production-Project-at-Nine-Mile-Point.aspx.
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Bloom Energy began installation of a 240-kW electrolyzer
at Xcel Energy's Prairie Island nuclear plant in Minnesota in September
2022 to produce low-GHG hydrogen. The demonstration project, designed
to create ``immediate and scalable pathways'' for producing cost-
effective hydrogen, is expected to be operational in 2024 and is also
funded with a DOE grant.\452\
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\452\ https://www.utilitydive.com/news/bloom-energy-hydrogen-xcel-nuclear-prairie-island/632148/.
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In California, Sempra subsidiary SoCalGas has announced
plans to develop the nation's largest hydrogen infrastructure system
called ``Angeles Link.'' When operational, the project will provide
enough hydrogen to convert up to four natural gas-fired power plants.
Developers predict the increased access to hydrogen will also displace
3 million gallons of diesel fuel from heavy-duty
trucks.453 454
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\453\ https://www.socalgas.com/sustainability/hydrogen/angeles-link.
\454\ Penrod, Emma. (February 18, 2022). SoCalGas begins
developing 100% clean hydrogen pipeline system. Utility Dive.
https://www.utilitydive.com/news/socalgas-begins-developing-100-clean-hydrogen-pipeline-system/619170/.
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In December 2022, Air Products and AES announced plans to
build a $4-billion low-GHG hydrogen production facility at the site of
a former coal-fired power plant in Texas.455 456 The plant
is expected to be completed in 2027, and once operational, will produce
approximately 200 metric tons of low-GHG hydrogen per day from
electrolyzers powered by 1.4 GW of wind and solar energy, as noted
earlier. This follows an announcement by Air Products in October 2022
to invest $500 million in a low-GHG hydrogen production facility in New
York. This 35 metric-ton-per-day project is also expected to be
operational by 2027, and in July 2022, received approval from the New
York Power Authority for 94 MW of hydroelectric power.\457\
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\455\ McCoy, Michael. (December 8, 2022). Air Products plans big
green hydrogen plant in U.S. Chemical and Engineering News. https://cen.acs.org/energy/hydrogen-power/Air-Products-plans-big-green/100/web/2022/12.
\456\ Air Products (December 8, 2022). Air Products and AES
Announce Plans to Invest Approximately $4 Billion to Build First
Mega-scale Green Hydrogen Production Facility in Texas. https://www.airproducts.com/news-center/2022/12/1208-air-products-and-aes-to-invest-to-build-first-mega-scale-green-hydrogen-facility-in-texas/.
\457\ Air Products (October 6, 2022). Air Products to Invest
About $500 Million to Build Green Hydrogen Production Facility in
New York. https://www.airproducts.com/news-center/2022/10/1006-air-products-to-build-green-hydrogen-production-facility-in-new-york.
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The DOE National Clean Hydrogen Strategy and Roadmap
identified a plausible path forward for the production of 10 MMT of
low-GHG hydrogen annually by 2030, 20 MMT annually by 2040, and 50 MMT
annually by 2050.
The NREL Clean Grid 2035 analysis examined several
pathways for the power sector to reach net-zero emissions by 2035: each
of those pathways included at least 10 MMT of electrolytic hydrogen by
2035, demonstrating how electrolytic hydrogen technologies support
rapid grid decarbonization.\458\
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\458\ Denholm, Paul, Patrick Brown, Wesley Cole, et al. 2022.
Examining Supply-Side Options to Achieve 100% Clean Electricity by
2035. Golden, CO: National Renewable Energy Laboratory NREL/
TP[1]6A40-81644. https://www.nrel.gov/docs/fy22osti/81644.pdf.
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The [email protected] is a DOE initiative that brings together
stakeholders to advance affordable hydrogen production, transport,
storage, and utilization to enable decarbonization and revenue
opportunities across multiple sectors.
These legislative actions, utility initiatives, and industrial
sector production and infrastructure projects indicate that sufficient
low-GHG hydrogen and sufficient distribution infrastructure can
reasonably be expected to be available by 2032, when offtake scales
after 2030,\459\ so that, at a minimum, the majority of new combustion
turbines could co-fire low-GHG hydrogen. The EPA specifically solicits
comment on whether rural areas and small utility distribution systems
(serving 50,000 customers or less) can expect to have access to low-GHG
hydrogen. To the extent low-GHG hydrogen might be less available in
rural areas compared to areas with higher population densities, the EPA
solicits comment if sufficient electric transmission capacity is
available, or could be constructed, such that electricity generated
from low-GHG hydrogen could be transmitted to these rural areas.
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\459\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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By 2035, substantial additional amounts of renewable energy are
expected to be available, which can support the production of low-GHG
hydrogen through electrolysis.
(B) Costs
There are three sets of potential costs associated with co-firing
hydrogen in combustion turbines: (1) The capital costs of combustion
turbines that have the capability of co-firing hydrogen; (2) pipeline
infrastructure to deliver hydrogen; and (3) the fuel costs related to
production of low-GHG hydrogen.
As stated previously, manufacturers are already developing
combustion turbines that can co-fire up to 100 percent hydrogen.
Accordingly, this limits the amount of additional costs needed to allow
combustion turbines to co-fire 30 percent (by volume) hydrogen and,
later, 96 percent (by volume). According to data from EPRI's US-REGEN
model, the heat rate of a hydrogen-fired combustion turbine model plant
is 5 percent higher and the capital, fixed, and non-fuel variable costs
are 10 percent higher than a natural gas-fired combustion turbine.\460\
However, the EPA is soliciting comment on what additional costs would
be required to ensure that combustion turbines are able to co-fire
between 30 to 96 percent (by volume) hydrogen and if there are
efficiency impacts from co-firing hydrogen.
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\460\ https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#new-generation-capacity.
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With respect to pipeline infrastructure, there are approximately
1,600 miles of dedicated hydrogen pipelines currently operating in the
U.S. Existing natural gas infrastructure may be capable of accepting
blends of hydrogen with modest investments, but the actual limits will
vary depending on pipeline materials, age, and operating conditions.
Due to the lower energy density of hydrogen relative to natural gas,
the piping required to deliver pure hydrogen would have to be larger,
and the material used to construct the piping could need to be
specifically designed
[[Page 33314]]
to be able to handle higher concentrations of hydrogen that would
prevent embrittlement and leaks. These risks can be mitigated through
deployment of new pipeline infrastructure designed for compatibility
with hydrogen in support of a new combustion turbine installation. The
majority of announced combustion turbine EGU projects proposing to co-
fire hydrogen are located close to the source of hydrogen. Therefore,
the fuel delivery systems (i.e., pipes) for new combustion turbines can
be designed to transport hydrogen without additional costs. Therefore,
the EPA proposes that co-firing rates of 30 percent and up to 100
percent by volume would have limited, if any, additional capital costs
for new combustion turbine EGU projects. The EPA is soliciting comment
on if additional infrastructure costs, such as bulk hydrogen storage in
salt caverns, should be accounted for when determining the costs of
hydrogen co-firing.
The primary cost for co-firing hydrogen is the cost of hydrogen
relative to natural gas. The cost of delivered hydrogen depends on the
technology used to produce the hydrogen and the cost to transport the
hydrogen to the end user. For context, the DOE National Clean Hydrogen
Strategy and Roadmap cites the current cost of low-GHG electrolytic
hydrogen production at approximately $5/kg. The DOE has established a
goal of reducing the cost of low-GHG hydrogen production to $1/kg
(equivalent to $7.4/MMBtu) by 2030, which is approximately the same as
the current production costs of hydrogen from SMR. Using $1/kg
(equivalent to $7.4/MMBtu) as the delivered cost of low-GHG hydrogen,
co-firing 30 percent (by volume) hydrogen in a combined cycle EGU
operating at a capacity factor of 65 percent would increase both the
levelized cost of electricity (LCOE) by $2.9/MWh.\461\ This is a 6
percent increase from the baseline LCOE. A 96 percent (by volume) co-
firing rate increases the LCOE by $21/MWh, a 47 percent increase in the
baseline LCOE. Regardless of the level of hydrogen co-firing, the
CO2 abatement cost is $64/ton ($70/metric ton) at the
affected facility.\462\ For an aeroderivative simple cycle combustion
turbine operating at a capacity factor of 40 percent, co-firing 30
percent hydrogen increases the LCOE by $4.1/MWh, representing a 5
percent increase from the baseline LCOE. A 96 percent (by volume) co-
firing rate increases the LCOE by $30/MWh, a 31 percent increase in the
baseline LCOE.
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\461\ The EIA long-term natural gas price for utilities is
$3.69/MMBtu.
\462\ The abatement cost of co-firing low-GHG hydrogen is
determined by the relative delivered cost of the low-GHG hydrogen
and natural gas.
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However, DOE's projected goal of $1/kg production costs (equivalent
to $7.4/MMBtu) for low-GHG hydrogen was established prior to the IIJA
incentives and IRA tax subsidies for low-GHG hydrogen production, CCS,
and generation from renewable sources. These subsidies could be
equivalent to, or even exceed, the production costs of low-GHG
hydrogen. Even when the cost to transport the hydrogen from the
production facility to the end user is accounted for, the cost of low-
GHG hydrogen to the end user could be less than $1/kg. Assuming a
delivered price of $0.75/kg ($5.6/MMBtu), the CO2 abatement
costs for co-firing hydrogen would be $32/ton ($35/metric ton). For a
combined cycle EGU, the LCOE increase would be $1.4/MWh and $11/MWh for
the 30 percent and 96 percent (by volume) cases, respectively. For a
simple cycle EGU, the LCOE would be $2.1/MWh and $15/MWh for the 30
percent and 96 percent (by volume) cases, respectively. If the
delivered cost of low-GHG hydrogen is $0.50/kg ($3.7/MMBtu), this would
represent cost parity with natural gas and abatement costs would be
zero.
The EPA is proposing to determine that the increase in operating
costs from a BSER based on low-GHG hydrogen is reasonable.
(C) Non-Air Quality Health and Environmental Impact and Energy
Requirements
The co-firing of hydrogen in combustion turbines in the amounts
that the EPA proposes as the BSER would not have adverse non-air
quality health and environmental impacts. It would result in
NOX emissions, but those emissions can be controlled, as
described in section VII.F.3.c.vii.(A) of this preamble.
In addition, co-firing hydrogen in the amounts proposed would not
have adverse impacts on energy requirements, including either the
requirements of the combustion turbines to obtain fuel or on the energy
sector more broadly, particularly with respect to reliability. As
discussed in sections VII.F.3.c.vii.(A)-(B), combustion turbines can be
constructed to co-fire high volumes of hydrogen in lieu of natural gas,
and the EPA expects that low-GHG hydrogen will be available in
sufficient quantities and at reasonable cost. Any impact on the energy
sector would be further mitigated by the large amounts of existing
generation that would not be subject to requirements in this rule and
the projected new capacity in the base case modeling.
(D) Extent of Reductions in CO2 Emissions
The site-specific reduction in CO2 emissions achieved by
a combustion turbine co-firing hydrogen is dependent on the volume of
hydrogen blended into the fuel system. Due to the lower energy density
by volume of hydrogen compared to natural gas, an affected source that
combusts 30 percent by volume hydrogen with natural gas would achieve
approximately a 12 percent reduction in CO2 emissions versus
firing 100 percent natural gas.\463\ A source combusting 100 percent
hydrogen would have zero CO2 stack emissions because
hydrogen contains no carbon, as previously discussed. A source co-
firing 96 percent by volume hydrogen (approximately 89 percent by heat
input) would achieve an approximate 90 percent CO2 emission
reduction, which is roughly equivalent to the emission reduction
achieved by sources utilizing 90 percent CCS.
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\463\ The energy density by volume of hydrogen is lower than
natural gas.
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(E) Promotion of the Development and Implementation of Technology
Determining co-firing 30 percent (by volume) low-GHG hydrogen by
2032 and co-firing 96 percent (by volume) to be components of the BSER
would generally advance technology development in both the production
of low-GHG hydrogen and the use of hydrogen in combustion turbines.
This would facilitate co-firing larger amounts of low-GHG hydrogen and
facilitate co-firing low-GHG hydrogen in existing combustion turbines.
Developing new configurations for flame dimensions and turbine
modifications to adjust for the characteristics unique to hydrogen
combustion are technology forcing advancements that industry appears to
be already leaning into based on the project announcements. Thus, co-
firing low-GHG hydrogen fulfills the requirements of BSER to generally
advance technology development. In addition, co-firing 30 percent (by
volume) low-GHG hydrogen by 2032 would promote additional technology
development and infrastructure to facilitate co-firing at higher
amounts of low-GHG hydrogen in 2038. As discussed in the preceding
section, there are multiple combustion turbine projects planned by
industry to co-fire hydrogen initially and progress to firing with 100
percent hydrogen. Fueling combustion turbines with 100 percent hydrogen
would eliminate all carbon
[[Page 33315]]
dioxide stack emissions. It would also promote reliability because it
would provide grid operators with asset options, in addition to battery
and energy storage, capable of voltage support and frequency
regulation. These are asset characteristics that will be required in
increasing capacities as more variable generation is deployed.
(F) Basis for Proposing Co-Firing Low-GHG Hydrogen, Not Other Types of
Hydrogen, as the ``Best'' System of Emissions Reduction
In this section, the EPA explains further why the type of hydrogen
co-fired as a component of the BSER must be limited to low-GHG
hydrogen, and not include other types of hydrogen. The EPA explains
further the proposed definition of low-GHG hydrogen as 0.45 kg
CO2e/kg H2 or less from the production of
hydrogen, from well-to-gate. Finally, the Agency summarizes the
reasons, described above, for the proposal that co-firing 30 percent
low-GHG hydrogen meets the criteria under CAA section 111 as the BSER.
(1) Limitation of Co-Firing to Low-GHG Hydrogen
Hydrogen is a zero-GHG emitting fuel when combusted, so that co-
firing it in a combustion turbine in place of natural gas reduces GHG
emissions at the stack. Co-firing low-emitting fuels--sometimes
referred to as clean fuels--is a traditional type of emissions control,
and recognized as a system of emission reduction under CAA section 111.
In West Virginia v. EPA, the Supreme Court noted that in the EPA's
prior CAA section 111 actions, the Agency has treated ``measures that
improve the pollution performance of individual sources'' as
``system[s] of emission reduction,'' 142 S. Ct. at 2615,\464\ and
further noted with approval a statement the EPA made in the Clean Power
Plan that ``fuel-switching'' was one of the ``more traditional air
pollution control measures.'' 142 S. Ct. at 2611 (quoting 80 FR 64784;
October 23, 2015). The EPA has relied on lower-emitting fuels as the
BSER in several CAA section 111 rules. See 44 FR 33580, 33593 (June 11,
1979) (coal that undergoes washing prior to its combustion to remove
sulfur, so that its combustion emits fewer SO2 emissions);
72 FR 32742 (June 13, 2007) (same); 80 FR 64510 (October 23, 2015)
(natural gas and clean fuel oil). Co-firing hydrogen in a combustion
turbine in place of natural gas reduces GHG emissions at the source and
therefore plainly qualifies as a ``system of emission reduction.'' This
is true even if that phrase is narrowly defined to be limited to
controls measures that can be applied at and to the source and that
reduce emissions from the source, as the ACE Rule provided, or if it is
defined more broadly.\465\
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\464\ As discussed in section V.B.4 of this preamble, the ACE
Rule took the position that under CAA section 111(a)(1), a ``system
of emission reduction'' must be limited to measures that apply at or
to the source. 84 FR 32524 (July 8, 2019).
\465\ Co-firing hydrogen in place of fossil fuel (generally,
natural gas in a combustion turbine) may be contrasted with co-
firing biomass in place of fossil fuel (generally, coal in a steam
generating unit). The ACE Rule rejected co-firing biomass as a
potential BSER for existing coal-fired steam generating units. The
rule explained that co-firing biomass does not meet the definition
of a ``system of emission reduction,'' under the ACE Rule's
interpretation of that term, because co-firing biomass in place of
coal at a steam generating unit does not reduce emissions emitted
from that source; rather, any emission reductions rely on accounting
for activities that occur upstream. 84 FR 32546 (July 8, 2019). In
contrast, as discussed in the accompanying text, co-firing hydrogen
in place of natural gas at a combustion turbine achieves emission
reductions at the source. For that reason, co-firing hydrogen
qualifies as a ``system of emission reduction,'' even as the ACE
Rule defined the term. As noted in section V.C.3.a of this preamble,
the EPA has proposed to reject that definition as too narrow.
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In the present proposal, the EPA recognizes that even though the
combustion of hydrogen is zero-GHG emitting, its production entails a
range of GHG emissions, from low to high, depending on the method. As
noted in VII.F.3.c.v of this preamble, these differences in GHG
emissions from the different methods of hydrogen production are well-
recognized in the energy sector, and, in fact, hydrogen is generally
characterized by its production method and the attendant level of GHG
emissions.
Accordingly, the EPA is proposing to require that to qualify as the
``best'' system of emission reduction, the hydrogen that is co-fired
must be low-GHG hydrogen, as defined above. This is because the purpose
of CAA section 111 is to reduce pollution that endangers human health
and welfare to the extent achievable, CAA section 111(b), through
promulgation of standards of performance that reflect the ``best''
system of emission reduction that, taking into account certain factors,
is adequately demonstrated. CAA section 111(a)(1). Co-firing hydrogen
at combustion turbines when that hydrogen is produced with large
amounts of GHG emissions would ultimately result in increasing overall
GHG emissions, compared to combusting solely natural gas at the
combustion turbine. To avoid this anomalous outcome, in evaluating a
``system of emission reduction'' of co-firing hydrogen, the GHG
emissions from producing the hydrogen should be recognized to determine
whether co-firing that hydrogen is the ``best'' system of emission
reduction, within the meaning of CAA section 111(a)(1). The EPA
recognizes that the production of low-GHG hydrogen also results in
fewer emissions of other air pollutants, although it also requires the
use of more water, compared to other methods of producing hydrogen, in
particular, ones involving methane, as discussed in section VII.F.3.c.v
of this preamble. All these factors, considered together, point towards
co-firing low-GHG hydrogen, and not other types of hydrogen, as the
``best'' system of emission reduction.
D.C. Circuit caselaw supports applying the term ``best'' in this
manner. In several cases decided under CAA section 111(a)(1) as enacted
by the 1970 CAA Amendments, which did not provide that the EPA must
consider non-air quality health and environmental impacts in
determining the BSER,\466\ the court stated that the EPA must consider
whether byproducts of pollution control equipment could cause
environmental damage in determining whether the pollution control
equipment qualified as the best system of emission reduction. See
Portland Cement Ass'n v. Ruckelshaus, 465 F.2d 375, 385 n.42 (D.C. Cir.
1973), cert. denied, 417 U.S. 921 (1974) (stating that ``[t]he standard
of the `best system' is comprehensive, and we cannot imagine that
Congress intended that `best' could apply to a system which did more
damage to water than it prevented to air''); Essex Chemical Corp. v.
Ruckelshaus, 486 F.2d 427, 439 (D.C. Cir. 1973) (remanding because the
EPA failed to consider ``the significant land or water pollution
potential'' from byproducts of air pollution control equipment). The
situation here is analogous because a standard that allowed for co-
firing with other hydrogen would create more damage (in the form of GHG
emissions) than it prevented, the precise problem CAA section 111 is
intended to address. Considering the overall emissions impact of the
production of fuel used by the affected facility to lower its
[[Page 33316]]
emissions--here, hydrogen--is consistent with considering the
environmental impacts of the byproducts of pollution control technology
used by the affected facility to lower its emissions.
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\466\ As enacted under the 1970 CAA Amendments, CAA section
111(a)(1) read as follows:
The term ``standard of performance'' means a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the best system of
emission reduction which (taking into account the cost of achieving
such reduction) the Administrator determines has been adequately
demonstrated.
In the 1977 CAA Amendments, Congress revised section 111(a)(1)
to incorporate a reference to ``non-air quality health and
environmental impacts,'' and Congress retained that phrase in the
1990 CAA Amendments when it revised CAA section 111(a)(1) to read as
it currently does.
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In addition, the EPA's proposed determination that co-firing low-
GHG hydrogen qualifies as the BSER is supported by the IRA and its
legislative history. In the IRA, Congress enacted or expanded tax
credits to encourage the production and use of low-GHG hydrogen.\467\
In addition, as discussed in section IV.E.1 of this preamble, IRA
section 60107 added new CAA section 135, LEEP. This provision provides
$1 million for the EPA to assess the GHG emissions reductions from
changes in domestic electricity generation and use anticipated to occur
annually through fiscal year 2031; and further provides $18 million for
the EPA to promulgate additional CAA rules to ensure GHG emissions
reductions that go beyond the reductions expected in that assessment.
CAA section 135(a)(5)-(6). The legislative history of this provision
makes clear that Congress anticipated that the EPA could promulgate
rules under CAA section 111(b) to ensure GHG emissions reductions from
fossil fuel-fired electricity generation. 168 Cong. Rec. E879 (August
26, 2022) (statement of Rep. Frank Pallone, Jr.). The legislative
history goes on to state that ``Congress anticipates that EPA may
consider . . . clean hydrogen as [a] candidate[ ] for BSER for electric
generating plants. . . .'' Id.
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\467\ These tax credits include IRC section 45V (tax credit for
production of hydrogen through low- or zero-emitting processes), IRC
section 48 (tax credit for investment in energy storage property,
including hydrogen production), IRC section 45Q (tax credit for
CO2 sequestration from industrial processes, including
hydrogen production); and the use of hydrogen in transportation
applications, IRC section 45Z (clean fuel production tax credit),
IRC section 40B (sustainable aviation fuel credit).
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Most broadly, proposing that only low-GHG hydrogen qualifies as
part of the co-firing BSER is required by the ``reasoned
decisionmaking'' that the Supreme Court has long held, including
recently in Michigan v. EPA, 576 U.S. 743 (2015), that ``[f]ederal
administrative agencies are required to engage in.'' Id. at 751
(internal quotation marks omitted and citation omitted). In Michigan,
the Court held that CAA section 112(n)(1)(A), which directs the EPA to
regulate hazardous air pollutants from coal-fired power plants if the
EPA ``finds such regulation is appropriate and necessary,'' must be
interpreted to require the EPA to consider the costs of the regulation.
The Court explained that if the EPA failed to consider cost, it could
promulgate a regulation to eliminate power plant emissions harmful to
human health but do so through the use of technologies that ``do even
more damage to human health'' than the emissions they eliminate. Id. at
752. The Court emphasized, ``No regulation is `appropriate' if it does
significantly more harm than good.'' Id. Here, as explained above,
permitting EGUs to burn high-GHG hydrogen would ``do even more damage
to human health'' than the emissions eliminated and therefore could not
be considered ``reasoned decisionmaking.'' Id. at 751. Likewise, the
Supreme Court has long said that an agency engaged in reasoned
decisionmaking may not ignore ``an important aspect of the problem.''
Motor Vehicles Mfrs. Ass'n v. State Farm Auto Ins. Co., 463 U.S. 29, 43
(1983). Permitting EGUs to burn high-GHG hydrogen to meet the standard
of performance here would ignore an important aspect of the problem
being addressed, contrary to reasoned decisionmaking.
The proposed standard of performance that is founded upon a BSER of
burning hydrogen and the requirement that owners and operators seeking
to burn hydrogen use low-GHG hydrogen are distinct requirements that
could function independently. It may not be necessary to require that
only low-GHG hydrogen be used to comply for owners and operators
choosing this pathway included in the BSER in order to be confident
that low-GHG hydrogen will be used to meet the standard. Incentives in
the IRA may render production of low-GHG hydrogen less costly than
higher-GHG hydrogen at some point, thus pushing the hydrogen market
toward low-GHG hydrogen. In addition, the EPA may also initiate a
rulemaking to regulate GHG emissions from hydrogen production under
section 111 of the CAA. The EPA solicits comment on whether it is
necessary to define and require low-GHG in this rulemaking. Similarly,
the EPA also solicits comment as to whether the low-GHG hydrogen
requirement could be treated as severable from the remainder of the
standard such that the standard could function without this
requirement.
(2) Definition of Low-GHG Hydrogen
As noted in section VII.F.3.c.vi of this preamble, the EPA proposes
a definition for low-GHG hydrogen that aligns with the highest of the
four tiers of tax credit available for hydrogen production, IRC section
45V(b)(2)(D). Under this provision, taxpayers are eligible for a tax
credit of $3 per kilogram of hydrogen that is produced with a GHG
emissions rate of 0.45 kg CO2e/kg H2 or less,
from well-to-gate. This amount is three times higher than the amount
for the next tier of credit, which is for hydrogen produced with a GHG
emissions rate between 1.5 and 0.45 kg CO2e/kg
H2, from well-to-gate, IRC section 45V(b)(2)(C); and four
and five times higher than the amount for the next two tiers of credit,
respectively. IRC section 45V(b)(2)(B), (A). With these provisions,
Congress indicated its judgement as to what constitutes the lowest-GHG
hydrogen production, and its intention to incentivize production of
that type of hydrogen. Congress's views inform the EPA's proposal to
define low-GHG hydrogen for purposes the BSER for this CAA section 111
rulemaking consistent with IRC section 45V(b)(2)(D).
It should be noted that the EPA is not proposing that the ``clean
hydrogen'' definition in section 822 of the IIJA is appropriate for the
EPA's regulatory purposes. This definition is designed for a non-
regulatory purpose. It sets out a non-binding goal, not a standard or a
regulatory definition, intended for use in development of the DOE's
CHPS and funding programs to promote promising new hydrogen
technologies.
For the reasons discussed above, co-firing low-GHG hydrogen
qualifies as the BSER because it is adequately demonstrated, is of
reasonable cost, does not have adverse non-air quality health or
environmental impacts or energy requirements--in fact, it offers
potential benefits to the energy sector--and reduces GHG emissions. The
fact that this control promotes the advancement of hydrogen co-firing
in combustion turbines provides additional support for proposing it as
part of the BSER. Finally, Congress's direction to choose the ``best''
system of emissions reduction and principles of reasoned decision-
making dictate that the standard should be based on burning low-GHG
hydrogen, and not using other forms of hydrogen.
4. Other Options for BSER
The EPA considered several other systems of emission reduction as
candidates for the BSER for combustion turbines, but is not proposing
them as the BSER. They include CHP and the hybrid power plant, as
discussed below.
a. Combined Heat and Power (CHP)
CHP, also known as cogeneration, is the simultaneous production of
electricity and/or mechanical energy and useful thermal output from a
single fuel. CHP requires less fuel to produce a given energy output,
and because less fuel is burned to produce each unit of energy output,
CHP has lower emission rates and can be more economic than
[[Page 33317]]
separate electric and thermal generation. However, a critical
requirement for a CHP facility is that it primarily generates thermal
output and generates electricity as a byproduct and must therefore be
physically close to a thermal host that can consistently accept the
useful thermal output. It can be particularly difficult to locate a
thermal host with sufficiently large thermal demands such that the
useful thermal output would impact the emissions rate. The refining,
chemical manufacturing, pulp and paper, food processing, and district
energy systems tend to have large thermal demands. However, the thermal
demand at these facilities is generally only sufficient to support a
smaller EGU, approximately a maximum of several hundred MW. This would
limit the geographically available locations where new generation could
be constructed in addition to limiting its size. Furthermore, even if a
sufficiently large thermal host were in close proximity, the owner/
operator of the EGU would be required to rely on the continued
operation of the thermal host for the life of the EGU. If the thermal
host were to shut down, the EGU could be unable to comply with the
standard of performance. This reality would likely result in difficulty
in securing funding for the construction of the EGU and could also lead
the thermal host to demand discount pricing for the delivered useful
thermal output. For these reasons, the EPA is not proposing CHP as the
BSER.
b. Hybrid Power Plant
Hybrid power plants combine two or more forms of energy input into
a single facility with an integrated mix of complementary generation
methods. While there are multiple types of hybrid power plants, the
most relevant type for this proposal is the integration of solar energy
(e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both
coal-fired and NGCC EGUs have operated using the integration of
concentrating solar thermal energy for use in boiler feed water
heating, preheating makeup water, and/or producing steam for use in the
steam turbine or to power the boiler feed pumps.
One of the benefits of integrating solar thermal with a fossil
fuel-fired EGU is the lower capital and operation and maintenance (O&M)
costs of the solar thermal technology. This is due to the ability to
use equipment (e.g., HRSG, steam turbine, condenser, etc.) already
included at the fossil fuel-fired EGU. Another advantage is the
improved electrical generation efficiency of the non-emitting
generation. For example, solar thermal often produces steam at
relatively low temperatures and pressures, and the conversion of the
thermal energy in the steam to electricity is relatively low. In a
hybrid power plant, the lower quality steam is heated to higher
temperatures and pressures in the boiler (or HSRG) prior to expansion
in the steam turbine, where it produces electricity. Upgrading the
relatively low-grade steam produced by the solar thermal facility in
the boiler improves the relative conversion efficiencies of the solar
thermal to electricity process. The primary incremental costs of the
non-emitting generation in a hybrid power plant are the costs of the
mirrors, additional piping, and a steam turbine that is 10 to 20
percent larger than that in a comparable fossil-only EGU to accommodate
the additional steam load during sunny hours. A drawback of integrating
solar thermal is that the larger steam turbine will operate at part
loads and reduced efficiency when no steam is provided from the solar
thermal panels (i.e., the night and cloudy weather). This limits the
amount of solar thermal that can be integrated into the steam cycle at
a fossil fuel-fired EGU.
In the 2018 Annual Energy Outlook,\468\ the levelized cost of
concentrated solar power (CSP) without transmission costs or tax
credits is $161/MWh. Integrating solar thermal into a fossil fuel-fired
EGU reduces the capital cost and O&M expenses of the CSP portion by 25
and 67 percent compared to a stand-alone CSP EGU respectively.\469\
This results in an effective LCOE for the integrated CSP of $104/MWh.
Assuming the integrated CSP is sized to provide 10 percent of the
maximum steam turbine output and the relative capacity factors of a
NGCC and the CSP (those capacity factors are 65 and 25 percent,
respectively) the overall annual generation due to the concentrating
solar thermal would be 3 percent of the hybrid EGU output. This would
result in a three percent reduction in the overall CO2
emissions and a one percent increase in the LCOE, without accounting
for any reduction in the steam turbine efficiency. However, these costs
do not account for potential reductions in the steam turbine efficiency
due to being oversized relative to a non-hybrid EGU. A 2011 technical
report by the National Renewable Energy Laboratory (NREL) cited
analyses indicating solar-augmentation of fossil power stations is not
cost-effective, although likely less expensive and containing less
project risk than a stand-alone solar thermal plant. Similarly, while
commenters stated that solar augmentation has been successfully
integrated at coal-fired plants to improve overall unit efficiency,
commenters did not provide any new information on costs or indicate
that such augmentation is cost-effective. The EPA is soliciting comment
on updated costs for hybrid power plants and if the use of hybrid power
plants could be incorporated as part of the BSER for base load
combustion turbines.
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\468\ EIA, Annual Energy Outlook 2018, February 6, 2018. https://www.eia.gov/outlooks/aeo/.
\469\ B. Alqahtani and D. Pati[ntilde]o-Echeverri, Duke
University, Nicholas School of the Environment, ``Integrated Solar
Combined Cycle Power Plants: Paving the Way for Thermal Solar,''
Applied Energy 169:927-936 (2016).
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In addition, solar thermal facilities require locations with
abundant sunshine and significant land area in order to collect the
thermal energy. Existing concentrated solar power projects in the U.S.
are primarily located in California, Arizona, and Nevada with smaller
projects in Florida, Hawaii, Utah, and Colorado. NREL's 2011 technical
report on the solar-augment potential of fossil-fired power plants
examined regions of the U.S. with ``good solar resource as defined by
their direct normal insolation (DNI)'' and identified sixteen States as
meeting that criterion: Alabama, Arizona, California, Colorado,
Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North
Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The
technical report explained that annual average DNI has a significant
effect on the performance of a solar-augmented fossil plant, with
higher average DNI translating into the ability of a hybrid power plant
to produce more steam for augmenting the plant. The technical report
used a points-based system and assigned the most points for high solar
resource values. An examination of a NREL-generated DNI map of the U.S.
reveals that States with the highest DNI values are located in the
southwestern U.S., with only portions of Arizona, California, Nevada,
New Mexico, and Texas (plus Hawaii) having solar resources that would
have been assigned the highest points by the NREL technical report (7
kWh/m2/day or greater).
The EPA is not proposing hybrid power plants as the BSER because of
gaps in the EPA's knowledge about costs, and concerns about the cost-
effectiveness of the technology, as noted above.
5. Subcategories
Stationary combustion turbines are defined in the 2015 NSPS to
include
[[Page 33318]]
both simple cycle and combined cycle EGUs. In addition, 40 CFR part 60,
subpart TTTT includes three subcategories for combustion turbines--
natural gas-fired base load EGUs, natural gas-fired non-base load EGUs,
and multi-fuel-fired EGUs. Base load EGUs are those that sell
electricity in excess of the site-specific electric sales threshold to
an electric distribution network on both a 12-operating-month and 3-
year rolling average basis. Non-base load EGUs are those that sell
electricity at or less than the site-specific electric sales threshold
to an electric distribution network on both a 12-operating-month and 3-
year rolling average basis. Multi-fuel-fired EGUs combust 10 percent or
more (by heat input) of fuels not meeting the definition of natural gas
on a 12-operating-month rolling average basis.
a. Legal Basis for Subcategorization
As noted in section V.C.1, CAA section 111(b)(2) provides that the
EPA ``may distinguish among classes, types, and sizes within categories
of new sources for the purpose of establishing . . . standards [of
performance].'' The D.C. Circuit has held that the EPA has broad
discretion in determining whether and how to subcategorize under CAA
section 111(b)(2). Lignite Energy Council, 198 F3d at 933. As also
noted in section V.C.1, in prior CAA section 111 rules, the EPA has
subcategorized on numerous bases, including, among other things, fuel
type and load.
b. Electric Sales Subcategorization (Low, Intermediate, and Base Load
Combustion Turbines)
As noted earlier, in the 2015 NSPS, the EPA established separate
standards for natural gas-fired base load and non-base load stationary
combustion turbines. The electric sales threshold distinguishing the
two subcategories is based on the design efficiency of individual
combustion turbines. A combustion turbine qualifies as a non-base load
turbine, and is thus subject to a less stringent standard of
performance, if it has net electric sales equal to or less than the
design efficiency of the turbine (not to exceed 50 percent) multiplied
by the potential electric output (80 FR 64601; October 23, 2015). If
the net electric sales exceed that level on both a 12-operating month
and 3 calendar year basis, then the combustion turbine is in the base
load combustion subcategory and is subject to a more stringent standard
of performance. Subcategory applicability can change on a month-to-
month basis since applicability is determined each operating month. For
additional discussion on this approach, see the 2015 NSPS (80 FR 64609-
12; October 23, 2015). The 2015 NSPS non-base load subcategory is broad
and includes combustion turbines that assure grid reliability by
providing electricity during periods of peak electric demand. These
peaking turbines tend to have low annual capacity factors and sell a
small amount of their potential electric output. The non-base load
subcategory in the 2015 NSPS also includes combustion turbines that
operate at intermediate annual capacity factors but are not considered
base load EGUs. These intermediate load EGUs provide a variety of
services, including providing dispatchable power to support variable
generation from renewable sources of electricity. The need for this
service has been expanding as the amount of electricity from wind and
solar continues to grow. In the 2015 NSPS, the EPA determined the BSER
for the non-base load subcategory to be the use of lower emitting fuels
(e.g., natural gas and Nos. 1 and 2 fuel oils). In 2015, the EPA
explained that efficient generation did not qualify as the BSER due in
part to the challenge of determining an achievable output-based
CO2 emissions rate for all combustion turbines in this
subcategory.
In this action, the EPA is proposing changes to the subcategories
in 40 CFR part 60, subpart TTTTa that will be applicable to sources
that commence construction or reconstruction after the date of this
proposed rulemaking. First, the Agency is proposing the definition of
design efficiency so that the heat input calculation of an EGU is based
on the higher heating value (HHV) of the fuel instead of the lower
heating value (LHV), as explained immediately below. It is important to
note that this would have the effect of lowering the electric sales
threshold. In addition, the EPA is proposing to further divide the non-
base load subcategory into separate intermediate and low load
subcategories.
i. Higher Heating Value as the Basis for Calculation of the Design
Efficiency
The heat rate is the amount of energy used by an EGU to generate
one kWh of electricity and is often provided in units of Btu/kWh. As
the thermal efficiency of a combustion turbine EGU is increased, less
fuel is burned per kWh generated and there is a corresponding decrease
in emissions of CO2 and other air pollutants. The electric
energy output as a fraction of the fuel energy input expressed as a
percentage is a common practice for reporting the unit's efficiency.
The greater the output of electric energy for a given amount of fuel
energy input, the higher the efficiency of the electric generation
process. Lower heat rates are associated with more efficient power
generating plants.
Efficiency can be calculated using the HHV or the LHV of the fuel.
The HHV is the heating value directly determined by calorimetric
measurement of the fuel in the laboratory. The LHV is calculated using
a formula to account for the moisture in the combustion gas (i.e.,
subtracting the energy required to vaporize the water in the flue gas)
and is a lower value than the HHV. Consequently, the HHV efficiency for
a given EGU is always lower than the corresponding LHV efficiency
because the reported heat input for the HHV is larger. For U.S.
pipeline natural gas, the HHV heating value is approximately 10 percent
higher than the corresponding LHV heating value and varies slightly
based on the actual constituent composition of the natural gas.\470\
The EPA default is to reference all technologies on a HHV basis,\471\
and the Agency is proposing to base the heat input calculation of an
EGU on HHV for purposes of the definition of design efficiency.
However, it should be recognized that manufacturers of combustion
turbines typically use the LHV to express the efficiency of combustion
turbines.\472\
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\470\ The HHV of natural gas is 1.108 times the LHV of natural
gas. Therefore, the HHV efficiency is equal to the LHV efficiency
divided by 1.108. For example, an EGU with a LHV efficiency of 59.4
percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV
ratio is dependent on the composition of the natural gas (i.e., the
percentage of each chemical species (e.g., methane, ethane, propane,
etc.)) within the pipeline and will slightly move the ratio.
\471\ Natural gas is also sold on a HHV basis.
\472\ European plants tend to report thermal efficiency based on
the LHV of the fuel rather than the HHV for both combustion turbines
and steam generating EGUs. In the U.S., boiler efficiency is
typically reported on a HHV basis.
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Similarly, the electric energy output for an EGU can be expressed
as either of two measured values. One value relates to the amount of
total electric power generated by the EGU, or gross output. However, a
portion of this electricity must be used by the EGU facility to operate
the unit, including compressors, pumps, fans, electric motors, and
pollution control equipment. This within-facility electrical demand,
often referred to as the parasitic load or auxiliary load, reduces the
amount of power that can be delivered to the transmission grid for
distribution and sale to customers. Consequently, electric energy
output may also be expressed in terms of net
[[Page 33319]]
output, which reflects the EGU gross output minus its parasitic
load.\473\
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\473\ It is important to note that net output values reflect the
net output delivered to the electric grid and not the net output
delivered to the end user. Electricity is lost as it is transmitted
from the point of generation to the end user and these ``line
loses'' increase the farther the power is transmitted. 40 CFR part
60, subpart TTTT provides a way to account for the environmental
benefit of reduced line losses by crediting CHP EGUs, which are
typically located close to large electric load centers. See 40 CFR
60.5540(a)(5)(i) and the definitions of gross energy output and net
energy output in 40 CFR 60.5580.
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When using efficiency to compare the effectiveness of different
combustion turbine EGU configurations and the applicable GHG emissions
control technologies, it is important to ensure that all efficiencies
are calculated using the same type of heating value (i.e., HHV or LHV)
and the same basis of electric energy output (i.e., MWh-gross or MWh-
net). Most emissions data are available on a gross output basis and the
EPA is proposing output-based standards based on gross output. However,
to recognize the superior environmental benefit of minimizing
auxiliary/parasitic loads, the Agency is proposing to include optional
equivalent standards on a net output basis. To convert from gross to
net-output based standards, the EPA used a 1 percent auxiliary load for
simple cycle turbines, a 2 percent auxiliary load for combined cycle
turbines, and a 7 percent auxiliary load for combined cycle EGUs using
90 percent CCS.
ii. Lowering the Threshold Between the Base Load and Non-Base Load
Subcategories
The subpart TTTT distinction between a base load and non-base load
combustion turbine is determined by the unit's actual electric sales
relative to its potential electric sales, assuming the EGU is operated
continuously (i.e., percent electric sales). Specifically, stationary
combustion turbines are categorized as non-base load and are
subsequently subject to a less stringent standard of performance, if
they have net electric sales equal to or less than their design
efficiency (not to exceed 50 percent) multiplied by their potential
electric output (80 FR 64601; October 23, 2015). Because the electric
sales threshold is based in part on the design efficiency of the EGU,
more efficient combustion turbine EGUs can sell a higher percentage of
their potential electric output while remaining in the non-base load
subcategory. This approach recognizes both the environmental benefit of
combustion turbines with higher design efficiencies and provides
flexibility to the regulated community. In the 2015 NSPS, it was
unclear how often high-efficiency simple cycle EGUs would be called
upon to support increased generation from variable renewable generating
resources. Therefore, the Agency determined it was appropriate to
provide maximum flexibility to the regulated community. To do this, the
Agency based the numeric value of the design efficiency, which is used
to calculate the electric sales threshold, on the LHV efficiency. This
had the impact of allowing combustion turbines to sell a greater share
of their potential electric output while remaining in the non-base load
subcategory.
For the reasons noted below, the EPA is proposing in 40 CFR part
60, subpart TTTTa that the design efficiency be based on the HHV
efficiency instead of LHV efficiency and that the 50 percent maximum
and 33 percent minimum restriction not be included. When determining
the potential electric output used in calculating the electric sales
threshold in 40 CFR part 60, subpart TTTT, design efficiencies of
greater than 50 percent are reduced to 50 percent and design
efficiencies of less than 33 percent are increased to 33 percent for
determining electric sales threshold subcategorization criteria. The 50
percent criterion was established to limit non-base load EGUs from
selling greater than 55 percent of their potential electric sales.\474\
The 33 percent criterion is included to be consistent with
applicability thresholds in the electric utility criteria pollutant
NSPS (40 CFR part 60, subpart Da). Neither of those criteria are
appropriate for 40 CFR part 60, subpart TTTTa, and the EPA is not
proposing that they be used to determine the electric sales threshold.
By basing the electric sales threshold on the HHV design efficiency,
the 50 percent restriction is no longer appropriate because currently
available combined cycle designs operating as intermediate load
combustion turbines would be limited to selling 55 percent of their
potential electric output. If this restriction were maintained, it
would reduce the regulatory incentive for manufacturers to invest in
programs to develop higher efficiency combustion turbines. The EPA is
also proposing to eliminate the 33 percent minimum design efficiency in
the calculation of the potential electric output. The EPA is unaware of
any new combustion turbines with design efficiencies of less than 33
percent; and this will likely have no cost or emissions impact.
However, this provides assurance that new combustion turbines will
maximize design efficiencies. Because of this relationship between the
electric sales threshold and the design efficiency of an individual
EGU, the proposed definition of design efficiency would have the effect
of lowering the electric sales threshold between the base load and non-
base load subcategories. For combined cycle EGUs, the current base load
electric sales threshold is 55 percent. Proposing the definition of the
design efficiency to be based on HHV would make the base load electric
sales threshold for combined cycle EGUs between 46 and 55 percent.\475\
The current electric sales threshold for simple cycle turbines (i.e.,
non-base load) peaks in a range of 40 to 49 percent of potential
electric sales. Under the proposed definition, simple cycle turbines
would be able to sell no more than between 33 and 40 percent of their
potential electric output without moving into the base load
subcategory. A design efficiency definition based on the HHV will have
the effect of decreasing the electric sales threshold in relative terms
by 19 percent and absolute terms by 7 to 9 percent.\476\ The EPA is
soliciting comment on whether the intermediate/base load electric sales
threshold should be reduced further. The EPA is considering a range
that would lower the base load electric sales threshold for simple
cycle combustion turbines to between 29 to 35 percent (depending on the
design efficiency) and to between 40 to 49 percent for combined cycle
combustion turbines (depending on the design efficiency). This would be
equivalent to reducing the design efficiency by 6 percent (e.g.,
multiplying by 0.94) when determining the electric sales threshold.
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\474\ While the design efficiency is capped at 50 percent on a
LHV basis, the base load rating (maximum heat input of the
combustion turbine) is on a HHV basis. This mixture of LHV and HHV
results in the electric sales threshold being 11 percent higher than
the design efficiency. The design efficiency of all new combined
cycle EGUs exceed 50 percent on a LHV basis.
\475\ The electric sales threshold for combined cycle EGUs with
the highest design efficiencies would remain at 55 percent.
\476\ The design efficiency appears twice in the equation used
to determine the electric sales threshold. Amending the design
efficiency to use the HHV numeric value results in a larger
reduction in the electric sales threshold than the difference
between the HHV and LHV design efficiency.
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The EPA determined that proposing to lower the electric sales
threshold is appropriate for new combustion turbines because, as will
be discussed later, the first component of BSER for both intermediate
load and base load turbines is based on highly efficient generation.
Combined cycle units are significantly more efficient than simple cycle
turbines; and therefore, in general,
[[Page 33320]]
the EPA should be focusing its determination of the BSER for base load
units on that more efficient technology. In the 2015 NSPS, the EPA used
a higher sales threshold because of the argument that less efficient
simple cycle turbine technology served a unique role that could not be
served by more efficient combined cycle technology. At the time, the
EPA determined that a BSER based exclusively on that more efficient
technology could exclude the building of simple cycle turbines that are
needed to maintain electric reliability. With improvements to the ramp
rates for combined cycle units and with integrated renewable/energy
storage projects becoming more common, these less efficient simple
cycle turbines are no longer the only technology that can serve this
purpose. Further, as EGUs operate more, they have more hours of steady
state operation relative to hours of startup/cycling. Amending the
electric sales threshold would result in GHG reductions by assuring
that the most efficient generating and lowest emitting combustion
turbine technology is used for each subcategory. Therefore, the
proposed change to calculate the design efficiency on a HHV basis will
result in additional emission reductions at reasonable costs.
Based on EIA 2022 model plants, combined cycle EGUs have a lower
levelized cost of electricity (LCOE) at capacity factors above
approximately 40 percent compared to simple cycle EGUs operating at the
same capacity factors. This supports the proposed base load electric
threshold of 40 percent for simple cycle turbines because it would be
cost effective for owners/operators of simple cycle turbines to add
heat recovery if they elected to operate their unit as a base load
unit. Furthermore, based on an analysis of monthly emission rates,
recently constructed combined cycle EGUs maintain a 12-operating-month
emissions rates at 12-operating-month capacity factors of less than 55
percent (the base load electric sales threshold in subpart TTTT)
relative to operation at higher capacity factors. Therefore, the base
load subcategory operating range could be expanded in subpart TTTTa
without impacting the stringency of the numeric standard. However, at
12-operating-month capacity factors of less than approximately 50
percent, emission rates of combined cycle EGUs increase relative to
operation at a higher capacity factor. It takes longer for a HRSG to
begin producing steam that can be used to generate additional
electricity than the time it takes a combustion engine to reach full
power. Under operating conditions with a significant number of starts
and stops, typical of intermediate and especially low load combustion
turbines, there may not be enough time for the HRSG to generate steam
that can be used for additional electrical generation. To maximize
overall efficiency, combined cycle EGUs often use combustion turbine
engines that are less efficient than the most efficient simple cycle
combustion turbine engines. Under operating conditions with frequent
starts and stops where the HRSG does not have sufficient time to begin
generating additional electricity, a combined cycle EGU may be no more
efficient than a highly efficient simple cycle EGU. Above capacity
factors of approximately 40 percent, the average run time per start for
combined cycle EGUs tends to increase significantly and the HRSG would
be available to contribute additional electric generation. For more
information on the impact of capacity factors on the emission rates of
combined cycle EGUs see the Efficient Generation at Combustion Turbine
Electric Generating Units TSD, which is available in the rulemaking
docket.
After the 2015 NSPS was finalized, some stakeholders expressed
concerns about the approach for distinguishing between base load and
non-base load turbines. They posited a scenario in which increased
utilization of wind and solar resources, combined with low natural gas
prices, would create the need for certain types of simple cycle
turbines to operate for longer time periods than had been contemplated
when the 2015 NSPS was being developed. Specifically, stakeholders have
claimed that in some regional electricity markets with large amounts of
variable renewable generation, some of the most efficient new simple
cycle turbines--aeroderivative turbines--could be called on to operate
at capacity factors greater than their design efficiency. However, if
those new simple cycle turbines were to operate at those higher
capacity factors, they would become subject to the more stringent
standard of performance for base load turbines. As a result, according
to these stakeholders, the new aeroderivative turbines would have to
curtail their generation and instead, less-efficient existing turbines
would be called upon to run by the regional grid operators, which would
result in overall higher emissions. The EPA evaluated the operation of
simple cycle turbines in areas of the country with relatively large
amounts of variable renewable generation and did not find a strong
correlation between the percentage of generation from the renewable
sources and the 12-operating-month capacity factors of simple cycle
turbines. In addition, the vast majority of simple cycle turbines that
commenced operation between 2010 and 2016 (the most recent simple cycle
combustion turbines not subject to 40 CFR part 60, subpart TTTT) have
operated well below the base load electric sales threshold in 40 CRF
part 60, subpart TTTT. Therefore, the Agency does not believe that the
concerns expressed by stakeholders necessitates any revisions to the
regulatory scheme. In fact, as noted above, the EPA is proposing that
the electric sales threshold can be lowered without impairing the
availability of simple cycle turbines where needed, including to
support the integration of variable generation. The EPA believes that
the proposed threshold is not overly restrictive since a simple cycle
turbine could operate on average for more than 8 hours a day.
iii. Low and Intermediate Load Subcategories
The EPA is proposing in 40 CFR part 60, subpart TTTTa to create a
low load subcategory to include combustion turbines that operate only
during periods of peak electric demand (i.e., peaking units) which
would be separate from the intermediate load subcategory. Low load
combustion turbines also provide ramping capability and other ancillary
serves to support grid reliability. The EPA evaluated the operation of
recently constructed simple cycle turbines to understand how they
operate and to determine at what electric sales level or capacity
factor their emissions rate is relatively steady. (Note that for
purposes of this discussion, we use the terms ``electric sales'' and
``capacity factor'' interchangeably.) Peaking units only operate for
short periods of time and potentially at relatively low duty
cycles.\477\ This type of operation reduces the efficiency and
increases the emissions rate, regardless of the design efficiency of
the combustion turbine or how it is maintained. For this reason, it is
difficult to establish a reasonable output-based standard of
performance for peaking units.
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\477\ The duty cycle is the average operating capacity factor.
For example, if an EGU operates at 75 percent of the fully rated
capacity, the duty cycle would be 75 percent regardless of how often
the EGU actually operates. The capacity factor is a measure of how
much an EGU is operated relative to how much it could potentially
have been operated.
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To determine the electric sales threshold--that is, to distinguish
[[Page 33321]]
between the intermediate load and low load subcategories--the EPA
evaluated capacity factor electric sales thresholds of 10 percent, 15
percent, 20 percent, and 25 percent. The EPA found the 10 percent level
problematic for two reasons. First, simple cycle combustion turbines
operating at that level or lower have highly variable emission rates,
and therefore it would be difficult for the EPA to establish a
meaningful output-based standard of performance. In addition, only one-
third of simple cycle turbines that have commenced operation since 2015
have maintained 12-operating-month capacity factors of less than 10
percent. Therefore, setting the threshold at this level would bring
most new simple cycle turbines into the intermediate load subcategory,
which would subject them to a more stringent emission rate which is
only achievable for simple cycle combustion turbines operating at
higher capacity factors. This could create a situation where simple
cycle turbines might not be able to comply with the intermediate load
standard of performance while operating at the low end of the
intermediate load capacity factor subcategorization criteria.
Importantly, based on the EPA's review of hourly emissions data,
above a 15 percent capacity factor, GHG emission rates for many simple
cycle combustion turbines begin to stabilize, see the Simple Cycle
Stationary Combustion Turbine EGUs TSD, which is available in the
rulemaking docket. At higher capacity factors, more time is typically
spent at steady state operation rather than ramping up and down; and,
emission rates tend to be lower while in steady state operation.
Approximately 60 percent of recently constructed simple cycle turbines
have maintained 12-operating-month capacity factors of 15 percent or
less while two-thirds of recently constructed simple cycle turbines
have operated at capacity factors of 20 percent or less; and, the
emission rates clearly stabilize for the majority of simple cycle
turbines operating at capacity factors of greater than 20 percent.
Nearly 80 percent of recently constructed simple cycle turbines
maintain maximum 12-operating-month capacity factors of 25 percent or
less. Based on this information, the EPA is proposing the low load
electric sales threshold--again, the dividing line to distinguish
between the intermediate- and low-load subcategories--to be 20 percent
and is soliciting comment on a range of 15 to 25 percent. The EPA is
also soliciting comment on whether the low load electric sales
threshold should be determined by a site-specific threshold based on
three quarters of the design efficiency of the combustion turbine.\478\
Under this approach, simple cycle combustion turbines selling less than
18 to 22 percent of their potential electric output (depending on the
design efficiency) would still be considered low load combustion
turbines. This ``sliding scale'' electric sales threshold approach is
similar to the approach the EPA used in the 2015 NSPS to recognize the
environmental benefit of installing the most efficient combustion
turbines for low load applications. Using this approach, combined cycle
EGUs would be able to sell between 26 to 31 percent of their potential
electric output while still being considered low load combustion
turbines.
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\478\ The calculation used to determine the electric sales
threshold includes both the design efficiency and the base load
rating. Since the base load rating stays the same when adjusting the
numeric value of the design efficiency for applicability purposes,
adjustments to the design efficiency has twice the impact.
Specifically, using three quarters of the design efficiency reduces
the electric sales threshold by half.
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Placing low load and intermediate load combustion turbines into
separate subcategories is consistent with how these units are operated
and how emissions from these units can be quantified and controlled.
Consistent with the 2015 NSPS, the BSER analysis for base load
combustion turbine EGUs assumes the use of combined cycle technology
and the BSER analysis for intermediate and low load combustion turbine
EGUs assumes the use of simple cycle technology. However, the Agency
notes that combined cycle EGUs can elect to operate at lower levels of
electric sales and be classified as intermediate or peaking EGUs. In
this case, owners/operators of combined cycle EGUs would be required to
comply with the standards of performance for intermediate or peaking
EGUs.
c. Multi-Fuel-Fired Combustion Turbines
40 CFR part 60, subpart TTTT subcategorizes multi-fuel-fired
combustion turbines as EGUs that combust 10 percent or more of fuels
not meeting the definition of natural gas on a 12-operating-month
rolling average basis. The BSER for this subcategory is the use of
lower emitting fuels with a corresponding heat input-based standard of
performance of 120 to 160 lb CO2/MMBtu, depending on the
fuel, for newly constructed and reconstructed multi-fuel-fired
stationary combustion turbines.\479\ Lower emitting fuels for these
units include natural gas, ethylene, propane, naphtha, jet fuel
kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The
definition of natural gas in 40 CFR part 60, subpart TTTT includes fuel
that maintains a gaseous state at ISO conditions, is composed of 70
percent by volume or more methane, and has a heating value of between
35 and 41 megajoules (MJ) per dry standard cubic meter (dscm, m\3\)
(950 and 1,100 British thermal units (Btu) per dry standard cubic
foot). Natural gas typically contains 95 percent methane and has a
heating value of 1,050 Btu/lb.\480\ A potential issue with the multi-
fuel subcategory is that owners/operators of simple cycle turbines can
elect to burn 10 percent non-natural gas fuels, such as Nos. 1 or 2
fuel oil, and thereby remain in that subcategory, regardless of their
electric sales. As a result, they would remain subject to the less
stringent standard that applies to multi-fuel-fired sources, the lower
emitting fuels standard. This could allow less efficient combustion
turbine designs to operate as base load units without having to improve
efficiency and could allow EGUs to avoid the need for efficient design
or best operating and maintenance practices. These potential
circumventions would result in higher GHG emissions.
---------------------------------------------------------------------------
\479\ Combustion turbines co-firing natural gas with other fuels
must determine fuel-based site-specific standards at the end of each
operating month. The site-specific standards depend on the amount of
co-fired natural gas. 80 FR 64616 (October 23, 2015).
\480\ Note that 40 CFR part 60, subpart TTTT combustion turbines
co-firing 25 percent hydrogen by volume could be subcategorized as
multi-fuel-fired EGUs because the percent methane by volume could
fall below 70 percent, the heating value could fall below 35 MJ/Sm3,
and 10 percent of the heat input could be coming from a fuel not
meeting the definition of natural gas.
---------------------------------------------------------------------------
To avoid these concerns, the EPA is proposing to eliminate the
multi-fuel subcategory for low, intermediate, and base load combustion
turbines in 40 CFR part 60, subpart TTTTa. This would mean that new
multi-fuel-fired turbines that commence construction or reconstruction
after the date of this proposal will fall within a particular
subcategory depending on their level of electric sales. The EPA also
proposes that the performance standards for each subcategory be
adjusted appropriately for multi-fuel-fired turbines to reflect the
application of the BSER for the subcategories to turbines burning fuels
with higher GHG emission rates than natural gas. To be consistent with
the definition of lower emitting fuels in the 2015 Rule, the maximum
allowable heat input-based emissions rate would be 160 lb
CO2/MMBtu. For example, a standard of performance based on
efficient generation would be 33 percent
[[Page 33322]]
higher for a fuel oil-fired combustion turbine compared to a natural
gas-fired combustion turbine. This would assure that the BSER, in this
case efficient generation, is applied, while at the same time
accounting for the use of multiple fuels. As explained in section
VII.F, in the second phase of the NSPS, the EPA is proposing to further
subcategorize base load combustion turbines based on whether the
combustion turbine is combusting hydrogen. During the first phase of
the NSPS, all base load combustion turbines would be in a single
subcategory. Table 2 summarizes the proposed electric sales
subcategories for combustion turbines.
Table 2--Proposed Sales Thresholds for Subcategories of Combustion
Turbine EGUs
------------------------------------------------------------------------
Electric sales threshold (percent of
Subcategory potential electric sales)
------------------------------------------------------------------------
Low Load.......................... <=20 percent.
Intermediate Load................. >20 percent and <=site-specific
value determined based on the
design efficiency of the affected
facility.
Between ~ 33 to 40 percent
for simple cycle combustion
turbines.
Between ~ 45 to 55 percent
for combined cycle combustion
turbines.
Base Load......................... >Site-specific value determined
based on the design efficiency of
the affected facility.
Between ~ 33 to 40 percent
for simple cycle combustion
turbines.
Between ~ 45 to 55 percent
for combined cycle combustion
turbines.
------------------------------------------------------------------------
G. Proposed Standards of Performance
Once the EPA has determined that a particular system or technology
represents BSER, the CAA authorizes the Administrator to establish
standards of performance for new units that reflect the degree of
emission limitation achievable through the application of that BSER. As
noted above, the EPA proposes that because the technology for reducing
GHG emissions from combustion turbines is advancing rapidly, a multi-
phase set of standards of performance, which reflect a multi-component
BSER, is appropriate for base load and intermediate load combustion
turbines. Under this approach, for the first phase of the standards,
which applies as of the effective date the final rule, the BSER is
highly efficient generation for both base load and intermediate load
combustion turbines. During this phase, owners/operators of EGUs will
be subject to a numeric standard of performance that is representative
of the performance of the best performing EGUs in the subcategory. For
the second phase of the standards, beginning in 2032 and 2035
respectively, the BSER for base load turbines includes either 30
percent low-GHG hydrogen co-firing or 90 percent capture CCS, and
beginning in 2032 the BSER for intermediate load EGUs includes 30
percent low-GHG hydrogen co-firing. The affected EGUs would be subject
to either an emissions rate that reflects continued use of highly
efficient generation coupled with CCS, or one that reflects continued
use of highly efficient generation coupled with co-firing low-GHG
hydrogen. For the third phase of the standards, beginning in 2038 for
base load turbines that began co-firing 30 percent low-GHG hydrogen in
2032, the BSER includes co-firing 96 percent low-GHG hydrogen. In
addition, the EPA is proposing a single component BSER, applicable from
the date of proposal, for low load combustion turbines.
1. Phase-1 Standards
The first component of the BSER is the use of highly efficient
combined cycle technology for base load EGUs in combination with the
best operating and maintenance practices, the use of highly efficient
simple cycle technology in combination with the best operating and
maintenance practices for intermediate load EGUs, and the use of lower
emitting fuels for low load EGUs.
For new and reconstructed natural gas-fired base load combustion
turbine EGUs, the EPA proposes to find that the most efficient
available combined cycle technology--which qualifies as the BSER for
base load combustion turbines--supports a standard of 770 lb
CO2/MWh-gross for large natural gas-fired EGUs (i.e., those
with a nameplate heat input greater than 2,000 MMBtu/h) and 900 lb
CO2/MWh-gross for natural gas-fired small EGUs (i.e., those
with a nameplate base load rating of 250 MMBtu/h). The proposed
standard of performance for natural gas-fired base load EGUs with base
load ratings between 250 MMBtu/h and 2,000 MMBtu/h would be between 900
and 770 lb CO2/MWh-gross and be determined based on the base
load rating of the combustion turbine.\481\ The EPA proposes to find
that the most efficient available simple cycle technology--which
qualifies as the BSER for intermediate load combustion turbines--
supports a standard of 1,150 lb CO2/MWh-gross for natural
gas-fired EGUs. For new and reconstructed low load combustion turbines,
the EPA proposes to find that the use of lower emitting fuels--which
qualifies as the BSER--supports a standard that ranges from 120 lb
CO2/MMBtu to 160 lb CO2/MMBtu depending on the
fuel burned. The EPA proposes these standards to apply at all times and
compliance to be determined on a 12-operating-month rolling average
basis.
---------------------------------------------------------------------------
\481\ A new small natural gas-fired base load EGU would
determine the facility emissions rate by taking the difference in
the base load rating and 250 MMBtu/h, multiplying that number by
0.0743 lb CO2/(MW * MMBtu), and subtracting that number
from 900 lb CO2/MWh-gross. The emissions rate for a NGCC
EGU with a base load rating of 1,000 MMBtu/h is 900 lb
CO2/MWh-gross minus 750 MMBtu/h (1,000 MMBtu/h-250 MMBtu/
h) times 0.0743 lb CO2/(MW * MMBtu), which results in an
emissions rate of 844 lb CO2/MWh-gross.
---------------------------------------------------------------------------
The EPA has determined that these standards of performance are
achievable specifically for natural gas-fired base load and
intermediate load combustion turbine EGUs. However, combustion turbine
EGUs burn a variety of fuels, including fuel oil during natural gas
curtailments. Owners/operators of combustion turbines burning fuels
other than natural gas would not necessarily be able to comply with the
proposed standards for base load and intermediate load natural gas-
fired combustion turbines using highly efficient generation. Therefore,
the Agency is proposing that owners/operators of combustion turbines
burning fuels other than natural gas may elect to use the ratio of the
heat input-based emissions rate of the specific fuel(s) burned to the
heat input-based emissions rate of natural gas to determine a site-
specific standard of performance for the operating period. For example,
the NSPS emissions rate for a large base load combustion turbine
burning 100 percent distillate oil during the 12-operaitng month period
would be 1,070 lb CO2/MWh-gross.\482\
---------------------------------------------------------------------------
\482\ The heat input-based emission rates of natural gas and
distillate oil are 117 and 163 lb CO2/MMBtu,
respectively. The ratio of the heat input-based emission rates
(1.39) is multiplied by the natural gas-fired standard of
performance (770 lb CO2/MWh) to get the applicable
emissions rate (1,070 lb CO2/MWh).
---------------------------------------------------------------------------
[[Page 33323]]
To determine what emission rates are currently achieved by existing
high-efficiency combined cycle EGUs and simple cycle EGUs, the EPA
reviewed 12-operating-month generation and CO2 emissions
data from 2015 through 2021 for all combined and simple cycle EGUs that
submitted continuous emissions monitoring system (CEMS) data to the
EPA's emissions collection and monitoring plan system (ECMPS). The data
were sorted by the lowest maximum 12-operating-month emissions rate for
each unit to identify long-term emission rates on a lb CO2/
MWh-gross basis that have been demonstrated by the existing combined
cycle and simple cycle EGU fleets. Since an NSPS is a never-to-exceed
standard, the EPA is proposing that use of long-term data are more
appropriate than shorter term data in determining an achievable
standard. These long-term averages account for degradation and variable
operating conditions, and the EGUs should be able to maintain their
current emission rates, as long as the units are properly maintained.
While annual emission rates indicate a particular standard is
achievable for certain EGUs in the short term, they are not necessarily
representative of emission rates that can be maintained over an
extended period using highly efficient generating technology in
combination with best operating and maintenance practices.
To determine the 12-operating-month average emissions rate that is
achievable by application of the BSER, the EPA calculated 12-month
CO2 emission rates by dividing the sum of the CO2
emissions by the sum of the gross electrical energy output over the
same period. The EPA did this separately for combined cycle EGUs and
simple cycle EGUs to determine the emissions rate for the base load and
intermediate load subcategories, respectively.
For base load combustion turbines, the EPA evaluated three emission
rates: 730, 770, and 800 lb CO2/MWh-gross. An emissions rate
of 730 lb CO2/MWh-gross has been demonstrated by a single
combined cycle facility--the Okeechobee Clean Energy Center. This
facility is a large 3-on-1 combined cycle EGU that commenced operation
in 2019 and uses a recirculating cooling tower for the steam cycle.
Each turbine is rated at 380 MW and the three HRSGs feed a single steam
turbine of 550 MW. The EPA is not proposing to use the emissions rate
of this EGU to determine the standard of performance, for multiple
reasons. The Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft
configuration but, many combined cycle EGUs use a 1-on-1 configuration.
Combined cycle EGUs using a 1-on-1 configuration can be designed such
that both the combustion turbine and steam turbine are arranged on one
shaft and drive the same generator. This configuration has potential
capital cost and maintenance costs savings and a smaller plant
footprint that can be particularly important for combustion turbines
enclosed in a building. In addition, a single shaft configuration has
higher net efficiencies when operated at part load than a multi-shaft
configuration. Basing the standard of performance on the performance of
multi-shaft combined cycle EGUs could limit the ability of owners/
operators to construct new combined cycle EGUs in space-constrained
areas (typically urban areas \483\) and combined cycle EGUs with the
best performance when operated as intermediate load EGUs.\484\ Either
of these outcomes could result in greater overall emissions from the
power sector. An advantage of multi-shaft (2-on-1 and 3-on-1)
configurations is that the turbine engine can be installed initially
and run as a simple cycle EGU, with the HRSG and steam turbines added
at a later date, all of which allows for more flexibility for the
regulated community. In addition, a single large steam turbine can
generate electricity more efficiently than multiple smaller steam
turbines, increasing the overall efficiency of comparably sized
combined cycle EGUs. According to Gas Turbine World 2021, multi-shaft
combined cycle EGUs have design efficiencies that are 0.7 percent
higher than single shaft combined cycle EGUs using the same turbine
engine.\485\
---------------------------------------------------------------------------
\483\ Generating electricity closer to electricity demand can
reduce stress on the electric grid, reducing line losses and freeing
up transmission capacity to support additional generation from
variable renewable sources. Further, combined cycle EGUs located in
urban areas could be designed as CHP EGUs, which have potential
environmental and economic benefits.
\484\ Power sector modeling projects that combined cycle EGUs
will operate at lower capacity factors in the future. Combined cycle
EGUs with lower base load efficiencies, but higher part load
efficiencies could have lower overall emission rates.
\485\ According to the data in Gas Turbine World 2021, while
there is a design efficiency advantage of going from a 1-on-1
configuration to a 2-on-1 configuration (assuming the same turbine
engine) there is no efficiency advantage of 3-on-1 configurations
compared to 2-on-1 configurations.
---------------------------------------------------------------------------
The efficiency of the Rankine cycle (i.e., HRSG plus the steam
turbine) is determined in part by the ability to cool the working fluid
(e.g., steam) after it has been expanded through the turbine. All else
equal, the lower the temperature that can be achieved, the more
efficient the Rankine cycle. The Okeechobee Clean Energy Center used a
recirculating cooling system, which can achieve lower temperatures than
EGUs using dry cooling systems and therefore would be more efficient
and have a lower emissions rate. However dry cooling systems have lower
water requirements and therefore could be the preferred technology in
arid regions or in areas where water requirements could have
significant ecological impacts. Therefore, the EPA proposes that the
efficient generation standard for base load EGUs should account for the
use of dry cooling.
Finally, the Okeechobee Clean Energy Center is a relatively new EGU
and full efficiency degradation might not be accounted for in the
emissions analysis. Therefore, the EPA is not proposing that an
emissions rate of 730 lb CO2/MWh-gross is an appropriate
nationwide standard. However, the EPA is soliciting comment on whether
the use of alternate working fluid, such as supercritical
CO2, or other potential efficiency improvements would make
this emissions rate an appropriate standard of performance for base
load combustion turbines.
An emissions rate of 770 lb CO2/MWh-gross has been
demonstrated by 14 percent of recently constructed combined cycle EGUs.
These turbines include combined cycle EGUs using 1-on-1 configurations
and dry cooling, are manufactured by multiple companies, and have long-
term emissions data that fully account for potential degradation in
efficiency. One of the best performing large combined cycle EGUs that
has maintained an emissions rate of 770 lb CO2/MWh-gross is
the Dresden plant, located in Ohio.\486\ This 2-on-1 combined cycle
facility, uses a recirculating cooling tower, and has maintained an
emissions rate of 765 lb CO2/MWh-gross, measured over 12
operating months with 99 percent confidence. The turbine engines are
rated at 2,250 MMBtu/h, which demonstrates that the standard of 770 lb
CO2/MWh-gross is achievable at a heat input rating of 2,000
MMBtu/h. In addition, while a 2-on-1 configuration and a cooling tower
are more efficient than a 1-on-1 configuration and dry cooling, the
Dresden Energy Facility does not use the most efficient combined cycle
design currently available. Multiple more efficient designs have been
developed since the
[[Page 33324]]
Dresden Energy Facility commenced operation a decade ago that more than
offset these efficiency losses. Therefore, the EPA proposes that while
the Dresden combined cycle EGUs uses a 2-on-1 configuration with a
cooling tower, it demonstrates that an emissions rate of 770 lb
CO2/MWh-gross is achievable for all new large combined cycle
EGUs. For additional information on the EPA analysis of emission rates
for high efficiency base load combined cycle EGUs, see the Efficient
Generation at Combustion Turbine Electric Generating Units TSD, which
is available in the rulemaking docket.
---------------------------------------------------------------------------
\486\ The Dresden Energy Facility is listed as being located in
Muskingum County, Ohio, as being owned by the Appalachian Power
Company, as having commenced commercial operation in late 2011. The
facility ID (ORISPL) is 55350 1A and 1B.
---------------------------------------------------------------------------
The EPA is not proposing an emissions rate of 800 lb
CO2/MWh-gross because it does not represent the most
efficient combined cycle EGUs designs. Nearly half of recently
constructed combined cycle EGUs have maintained an emissions rate of
800 lb CO2/MWh-gross. However, the EPA is soliciting comment
on whether this higher emissions rate is appropriate on grounds that it
would increase flexibility and reduce costs to the regulated community
by allowing more available designs to operate as base load combustion
turbines.
With respect to small combined cycle combustion turbines, the best
performing unit is the Holland Energy Park facility in Holland,
Michigan, which commenced operation in 2017 and uses a 2-on-1
configuration and a cooling tower.\487\ The 50 MW turbine engines have
individual heat input ratings of 590 MMBtu/h and serve a single 45 MW
steam turbine. The facility has maintained a 12-operating month, 99
percent confidence emissions rate of 870 lb CO2/MWh-gross.
This long-term data accounts for degradation and variable operating
conditions and demonstrates that a base load combustion turbine EGU
with a turbine rated at 250 MMBtu/h should be able to maintain an
emissions rate of 900 lb CO2/MWh-gross.\488\ In addition,
there is a commercially available HRSG that uses supercritical
CO2 instead of steam as the working fluid. This HRSG would
be significantly more efficient than the HRSG that uses dual pressure
steam, which is common for small combined cycle EGUs.\489\ When these
efficiency improvements are accounted for, a new small natural gas-
fired combined cycle EGU would be able to maintain an emissions rate of
850 lb CO2/MWh-gross. Therefore, the Agency is soliciting
comment on whether the small natural gas-fired base load combustion
turbine standard of performance should be 850 lb CO2/MWh-
gross.
---------------------------------------------------------------------------
\487\ The Holland Park Energy Center is a CHP system that uses
hot water in the cooling system for a snow melt system that uses a
warm water piping system to heat the downtown sidewalks to clear the
snow during the winter. Since this useful thermal output is low
temperature, it does not materially reduce the electrical efficiency
of the EGU. If the useful thermal output were accounted for, the
emissions rate of the Holland Energy Park would be lower. The
facility ID (ORISPL) is 59093 10 and 11.
\488\ To estimate an achievable emissions rate for an efficient
combined cycle EGU at 250 MMBtu/h the EPA assumed a linear
relationship for combined cycle efficiency with turbine engines with
base load ratings of less than 2,000 MMBtu/h.
\489\ If the combustion turbine engine exhaust temperature is
500[deg]C or greater, a HRSG using 3 pressure steam without a reheat
cycle could potentially provide an even greater increase in
efficiency (relative to a HRSG using 2 pressure steam without a
reheat cycle).
---------------------------------------------------------------------------
In summary, the Agency solicits comment on the following range of
potential standards of performance:
New and reconstructed natural gas-fired base load
combustion turbines with a heat input rating that is greater than 2,000
MMBtu/h: a range of 730-800 lb CO2/MWh-gross;
New and reconstructed natural gas-fired base load
combustion turbines with a heat input rating of 250 MMBtu/h: a range of
850 to 900 lb CO2/MWh-gross.
For intermediate load combustion turbines, the EPA evaluated the
performance of recently constructed high efficiency natural gas-fired
simple cycle EGUs. The EPA evaluated three emission rates for the
intermediate load standard of performance: 1,200, 1,150, and 1,100 lb
CO2/MWh-gross. Sixty two percent of recently constructed
intermediate load simple cycle EGUs have maintained an emissions rate
of 1,200 lb CO2/MWh-gross, 17 percent have maintained an
emissions rate of 1,150 lb CO2/MWh-gross, and 6 percent have
maintained an emissions rate of 1,100 lb CO2/MWh-gross.
However, the units that have maintained an emissions rate of 1,100 lb
CO2/MWh-gross generally have a single large aeroderivative
combustion turbine design. In contrast, the ones that have maintained
an emission rate of 1,150 lb CO2/MWh-gross have multiple
different designs, including an industrial frame combustion turbine
design, and are made by multiple manufacturers. Therefore, the EPA is
proposing an intermediate load standard of performance of 1,150 lb
CO2/MWh-gross. The Agency is soliciting comment on whether
the standard should be 1,100 lb CO2/MWh-gross, or whether
that would result in unacceptably high costs because currently only a
single design for a large aeroderivative simple cycle turbine would be
able to meet this standard. The Agency is also soliciting comment on a
standard of performance of 1,200 lb CO2/MWh-gross. While
this would achieve fewer GHG reductions, it would increase flexibility,
and potentially reduce costs, to the regulated community by allowing
the currently available designs to operate as intermediate load
combustion turbines. For additional information on the EPA analysis of
emission rates for high efficiency intermediate load simple cycle EGUs,
see the Efficient Generation at Combustion Turbine Electric Generating
Units TSD, which is available in the rulemaking docket
The EPA is also soliciting comment on whether the use of steam
injection is applicable to intermediate load combustion turbines. Steam
injection is the use of a relatively low cost HRSG to produce steam
that is injected into the combustion chamber of the combustion turbine
engine instead of using a separate steam turbine.\490\ Advantages of
steam injection include improved efficiency and increases the output of
the combustion turbine as well as reducing NOX emissions.
Combustion turbines using steam injection have characteristics in-
between simple cycle and combined cycle combustion turbines. They are
more efficient, but more complex and have higher capital costs than
simple cycle combustion turbines without steam injection. Combustion
turbines using steam injection are simpler and have lower capital costs
than combined EGUs but have lower efficiencies. The EPA is aware of a
single combustion turbine that is using steam injection that has
maintained a 12-operaitng month emission rates of less than 1,000 lb
CO2/MWh-gross. The EPA requests that commenters include
information on whether this technology would be applicable to
intermediate load combustion turbines and could be part of either the
first or second component of the BSER along with cost information.\491\
---------------------------------------------------------------------------
\490\ A steam injected combustion turbine would be considered a
combined cycle combustion turbine (for NSPS purposes) because energy
from the turbine engine exhaust is recovered in a HRSG and that
energy is used to generate additional electricity.
\491\ The second component of the BSER, 30 percent low-GHG
hydrogen co-firing, would reduce the emissions rate to 880 lb
CO2/MWh-gross.
---------------------------------------------------------------------------
2. Phase-2 Standards
The use of CCS and hydrogen co-firing are both approaches
developers are considering to reduce GHG emissions beyond highly
efficient generation. However, as noted above, these approaches apply
to different subcategories and are not applicable to
[[Page 33325]]
the same EGUs. The proposed phase-2 standards are in table 3.
Table 3--Phase-2 Standards of Performance
------------------------------------------------------------------------
Standard of
Subcategory BSER performance
------------------------------------------------------------------------
Low load........................ Lower emitting 120-160 lb CO2/
fuels. MMBtu.
Intermediate load............... Highly efficient 1,000 lb CO2/MWh-
simple cycle gross.
technology
coupled with co-
firing 30 percent
(by volume) low-
GHG hydrogen.
Base load adopting the CCS Highly efficient 90 lb CO2/MWh-
pathway. combined cycle gross.
technology
coupled with 90
percent CCS.
Base load adopting the low-GHG Highly efficient 680 lb CO2/MWh-
hydrogen co-firing pathway. combined cycle gross.
technology
coupled with co-
firing 30 percent
(by volume) low-
GHG hydrogen.
------------------------------------------------------------------------
Co-firing 30 percent by volume low-GHG hydrogen reduces emissions
by 12 percent. The EPA applied this percent reduction to the emission
rates for the intermediate load and base load units adopting the low-
GHG hydrogen co-firing pathway subcategories, to determine the phase-1
standards. For the base load combustion turbines adopting the CCS
subcategory, the EPA reduced the emissions rate by 89 percent to
determine the CCS based phase-2 standards.\492\ The CCS percent
reduction is based on a CCS system capturing 90 percent of the emitting
CO2 being operational anytime the combustion turbine is
operating. However, if the carbon capture equipment has lower
availability/reliability than the combustion turbine or the CCS
equipment takes longer to startup than the combustion turbine itself
there would be periods of operation where the CO2 emissions
would not be controlled by the carbon capture equipment. As noted in
section VII.F.3.b.iii(A)(2) of this preamble, the operating
availability (i.e., the amount of time a process operates relative to
the amount of time it planned to operate) of industrial processes is
usually less than 100 percent. Assuming that CO2 capture
achieves 90 percent capture when available to operate, that CCS is
available to operate 90 percent of the time the combustion turbine is
operating, and that the combustion turbine operates the same whether or
not CCS is available to operate, total emission reductions would be 81
percent. Higher levels of emission reduction could occur for higher
capture rates coupled with higher levels of operating availability
relative to operation of the combustion turbine. If the combustion
turbine were not permitted to operate when CCS was unavailable, there
may be local reliability consequences or issues during startup or
shutdown, and the EPA is soliciting comment on how to balance these
issues. Additionally, the EPA is soliciting comment on the range of
reduction in emission rate of 75 to 90 percent.
---------------------------------------------------------------------------
\492\ The 89 percent reduction from CCS accounts for the
increased auxiliary load of a 90 percent post combustion amine-based
capture system. Due to rounding, the proposed numeric standards of
performance do not necessarily match the standards that would be
determined by applying the percent reduction to the phase 1
standards.
---------------------------------------------------------------------------
The standards of performance for the intermediate and base load
combustion turbines would also be adjusted based on the uncontrolled
emission rates of the fuels relative to natural gas. For 100 percent
distillate oil-fired combustion turbines, the emission rates would be
1,300 lb CO2/MWh-gross, 120 lb CO2/MWh-gross, and
910 lb CO2/MWh-gross for the intermediate load, non low-GHG
hydrogen co-firing base load, and low-GHG hydrogen co-firing base load
subcategories respectively.
3. Phase-3 Standards
The third component of the BSER is applicable to owner/operators of
base load combustion turbines that elect to implement early GHG
reductions (i.e., comply with an emissions rate of 680 lb
CO2/MWh-gross starting in January 2032). The phase 3 BSER
standard of performance increases the GHG reduction requirements and is
based on co-firing 96 percent by volume low-GHG hydrogen in addition to
the use of highly efficient combined cycle technology in combination
with the best operating and maintenance practices. The proposed phase-3
standards are in table 4.
Table 4--Phase-3 Standards of Performance
------------------------------------------------------------------------
Standard of
Subcategory BSER performance
------------------------------------------------------------------------
Base load electing to implement Highly efficient 90 lb CO2/MWh-
early GHG reductions. combined cycle gross.
technology
coupled with co-
firing 89 percent
(by heat input)
low-GHG hydrogen.
------------------------------------------------------------------------
Co-firing 89 percent by heat input (96 percent by volume) low-GHG
hydrogen reduces GHG emissions by 89 percent. The EPA applied this
percent reduction to the emission rates for base load under phase 1 of
the BSER. Similar to the phase 1 and 2 standards of performance, the
numeric standard would be adjusted based on the uncontrolled emission
rates of the fuels relative to natural gas. For 100 percent distillate
oil-fired combustion turbines, the emission rates would be 120 lb
CO2/MWh-gross.
As a variation on proposing the date for meeting this standard as
2038, the EPA solicits comment on proposing the date as 2035, coupled
with authorizing an approach for crediting early reductions, under
which a source that achieves reductions due to co-firing low-GHG
hydrogen starting in 2032 may apply credit for those reductions to its
emission rate beginning in 2035. Another, more stringent, variation of
this approach would be to allow credit only for reductions below the
emission rate otherwise required by 2032. Other
[[Page 33326]]
variations would allow sources to generate credits from reductions from
co-firing low-GHG hydrogen, or from any other reductions below their
standard of performance, in any year before 2035. In this manner, the
source would be authorized to comply with its 2035 standard in part
through use of credits generated by making reductions beginning in
2032. Under such an approach, early credits could only be used by the
unit that generated those credits. For instance, a unit co-firing 30
percent low-GHG hydrogen prior to 2035 would be able to generate
credits that it could use in 2035 and beyond. This would allow a unit
co-firing low-GHG hydrogen to ramp up the amount it co-fired over time,
while still achieving the same amount of emission reductions that would
have been achieved had the unit co-fired enough low-GHG hydrogen (e.g.,
96 percent by volume) starting in 2035. Another variation on this
approach would be to treat such a crediting scheme as a compliance
alternative to the CCS BSER by showing equivalent emission reductions,
rather than the standard itself.
The EPA proposes the following mechanism to ensure that affected
sources in the base load subcategory comply with the applicable
standard of performance in the event that the EPA finalizes both the
CCS pathway (that is, the use of 90-percent-capture CCS by 2035) and
the low-GHG hydrogen pathway (that is, co-firing 30 percent low-GHG
hydrogen by 2032 and 96 percent by 2038). The EPA proposes that
affected sources must notify the EPA by January 1, 2031, which pathway
they are selecting, and thus which standard they intend to comply with.
If they select the low-GHG hydrogen pathway, they must comply with the
applicable standard based on co-firing 30 percent hydrogen (by volume)
in 2032 through 2037. In addition, in 2033 through 2037, they must be
prepared to demonstrate that they complied with the applicable standard
based on co-firing 30 percent low-GHG hydrogen in the preceding years,
beginning in 2032. In 2038, they must comply with the applicable
standard based on co-firing 96 percent (by volume) now-GHG hydrogen.
H. Reconstructed Stationary Combustion Turbines
In the previous sections, the EPA explained the background of and
requirements for new and reconstructed stationary combustion turbines
and evaluated various control technology configurations to determine
the BSER. Because the BSER is the same for new and reconstructed
stationary combustion turbines, the Agency is proposing to use the same
emissions analysis for both new and reconstructed stationary combustion
turbines. For each of the subcategories, the EPA is proposing that the
proposed BSER results in the same standard of performance for new
stationary combustion turbines and reconstructed stationary combustion
turbines. Since reconstructed turbines could likely incorporate
technologies to co-fire hydrogen as part of the reconstruction process
at little or no cost, the low-GHG hydrogen co-firing would likely to be
similar to those for newly constructed combustion turbines. For CCS,
the EPA approximated the cost to add CCS to a reconstructed combustion
turbine by increasing the capital costs of the carbon capture equipment
by 10 percent relative to the costs for a newly constructed combustion
turbine. This increases the capital cost from $949/kW to $1,044/
kW.\493\ Using a 12-year amortization period, a 90 percent-capture
amine-based post combustion CCS system increases the LCOE by $8.5/MWh
and has overall CO2 abatement costs of $25/ton ($28/metric
ton).
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\493\ The kW value used as reference for the costs is the output
from the combined cycle EGU prior to the installation of the CCS.
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A reconstructed stationary combustion turbine is not required to
meet the standards if doing so is deemed to be ``technologically and
economically'' infeasible.\494\ This provision requires a case-by-case
reconstruction determination in the light of considerations of economic
and technological feasibility. However, this case-by-case determination
would consider the identified BSER, as well as technologies the EPA
considered, but rejected, as BSER for a nationwide rule. One or more of
these technologies could be technically feasible and of reasonable
cost, depending on site-specific considerations and if so, would likely
result in sufficient GHG reductions to comply with the applicable
reconstructed standards. Finally, in some cases, equipment upgrades,
and best operating practices would result in sufficient reductions to
achieve the reconstructed standards.
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\494\ 40 CFR 60.15(b)(2).
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I. Modified Stationary Combustion Turbines
CAA section 111(a)(4) defines a ``modification'' as ``any physical
change in, or change in the method of operation of, a stationary
source'' that either ``increases the amount of any air pollutant
emitted by such source or . . . results in the emission of any air
pollutant not previously emitted.'' Certain types of physical or
operational changes are exempt from consideration as a modification.
Those are described in 40 CFR 60.2, 60.14(e).
In the 2015 NSPS, the EPA did not finalize standards of performance
for stationary combustion turbines that conduct modifications; instead,
the EPA concluded that it was prudent to delay issuing standards until
the Agency could gather more information (80 FR 64515; October 23,
2015). There were several reasons for this determination: few sources
had undertaken NSPS modifications in the past, the EPA had little
information concerning them, and available information indicated that
few owners/operators of existing combustion turbines would undertake
NSPS modifications in the future; and since the Agency eliminated
proposed subcategories for small EGUs in the 2015 NSPS, questions were
raised as to whether smaller existing combustion turbines that
undertake a modification could meet the final performance standard of
1,000 lb CO2/MWh-gross.
It continues to be the case that the EPA is aware of no evidence
indicating that owners/operators of combustion turbines intend to
undertake actions that could qualify as NSPS modifications in the
future. EPA is not proposing, or soliciting comment on whether it
should propose, standards of performance for modifications of
combustion turbines.
J. Startup, Shutdown, and Malfunction
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the U.S. Court of Appeals for the District of Columbia
Circuit (D.C. Circuit) vacated portions of two provisions in the EPA's
CAA section 112 regulations governing the emissions of HAP during
periods of SSM. Specifically, the court vacated the SSM exemption
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that, the
SSM exemption violates the requirement under section 302(k) of the CAA
that some CAA section 112 standard apply continuously. Consistent with
Sierra Club v. EPA, the EPA is proposing standards in this rule that
apply at all times. The NSPS general provisions in 40 CFR 60.11(c)
currently exclude opacity requirements during periods of startup,
shutdown, and malfunction and the provision in 40 CFR 60.8(c) contains
an exemption from non-opacity standards. These general provision
requirements would automatically apply to the standards set in an NSPS,
unless the regulation specifically overrides these general provisions.
The NSPS subpart TTTT (40
[[Page 33327]]
CFR part 60 subpart TTTT), does not contain an opacity standard, thus,
the requirements at 40 CFR 60.11(c) are not applicable. The NSPS
subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and requires that
sources comply with the standard(s) at all times. In reviewing NSPS
subpart TTTT and proposing the new NSPS subpart TTTTa, the EPA is
proposing to retain in subpart TTTTa the requirements that sources
comply with the standard(s) at all times. Therefore, the EPA is
proposing in table 3 of the new subpart TTTTa to override the general
provisions for SSM provisions. The EPA is proposing that all standards
in subpart TTTTa apply at all times.
The EPA has attempted to ensure that the general provisions we are
proposing to override are inappropriate, unnecessary, or redundant in
the absence of the SSM exemption. The EPA is specifically seeking
comment on whether we have successfully done so.
In proposing the standards in this rule, the EPA has taken into
account startup and shutdown periods and, for the reasons explained in
this section of the preamble, has not proposed alternate standards for
those periods. The EPA analysis of achievable standards of performance
used CEMS data that includes all period of operation. Since periods of
startup, shutdown, and malfunction were not excluded from the analysis,
the EPA is not proposing alternate standard for those periods of
operation.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead, they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
CAA section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting standards of performance,
nothing in CAA section 111 requires the Agency to consider malfunctions
as part of that analysis. The EPA is not required to treat a
malfunction in the same manner as the type of variation in performance
that occurs during routine operations of a source. A malfunction is a
failure of the source to perform in a ``normal or usual manner'' and no
statutory language compels the EPA to consider such events in setting
CAA section 111 standards of performance. The EPA's approach to
malfunctions in the analogous circumstances (setting ``achievable''
standards under CAA section 112) has been upheld as reasonable by the
D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606-610 (2016).
K. Testing and Monitoring Requirements
Because the NSPS reflects the application of the best system of
emission reduction under conditions of proper operation and
maintenance, in doing the NSPS review, the EPA also evaluates and
determines the proper testing, monitoring, recordkeeping and reporting
requirements needed to ensure compliance with the NSPS. This section
will include a discussion on the current testing and monitoring
requirements of the NSPS and any additions the EPA is proposing to
include in 40 CFR part 60, subpart TTTTa.
1. General Requirements
The current rule allows three approaches for determining compliance
with its emissions limits: Continuous measurement using CO2
CEMS and flow measurements for all EGUs; calculations using hourly heat
input and `F' factors \495\ for EGUs firing uniform oil or gas or non-
uniform fuels; or Tier 3 calculations using fuel use and carbon content
as described in GHGRP regulations for EGUs firing non-uniform fuels.
The first two approaches are in use for carbon dioxide by the Acid Rain
program (40 CFR part 75), to which most, if not all, of the EGUs
affected by NSPS subpart TTTT are already subject, while the last
approach is in use for carbon dioxide, nitrous oxide, and methane
reporting from stationary fuel combustion sources (40 CFR part 98,
subpart C).
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\495\ An F factor is the ratio of the gas volume of the products
of combustion to the heat content of the fuel.
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The EPA believes continuing the use of these familiar approaches
already in use by other programs represents a cost-effective means of
obtaining quality assured data requisite for determining carbon dioxide
mass emissions. Therefore, no changes to the current ways of collecting
carbon dioxide and associated data needed for mass determination, such
as flow rates, fuel heat content, fuel carbon content, and the like,
are proposed. Because no changes are proposed and because the cost and
burden for EGU owners or operators are already accounted for by other
rulemakings, this aspect of the proposed rule is designed to have
minimal, if any, cost or burden associated with carbon dioxide testing
and monitoring. In addition, the proposal contains no changes to
measurement and testing requirements for determining electrical output,
both gross and net, as well as thermal output, to current existing
requirements.
However, the EPA requests comment on whether continuous carbon
dioxide and flow measurements should become the sole means of
compliance for this rule. Such a switch would increase costs for those
EGU owners or operators who are currently relying on the oil- or gas-
fired or non-uniform fuel-fired calculation-based approaches for
compliance. By way of reference, the annualized cost associated with
adoption and use of continuous carbon dioxide and flow measurements
where none now exist is estimated to be about $52,000. To the extent
that the rule were to mandate continuous carbon dioxide and flow
measurements in accordance with what is currently allowed as one option
and that an EGU lacked this instrumentation, its owner or operator
would need to incur this annual cost to obtain such information and to
keep the instrumentation calibrated.
2. Requirements for Sources Implementing CCS
The CCS process is also subject to monitoring and reporting
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires
reporting of facility-level GHG data and other relevant information
from large sources and suppliers in the U.S. The ``suppliers of carbon
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires
those affected facilities with production process units that capture a
CO2 stream for purposes of supplying CO2 for
commercial applications or that capture and maintain custody of a
CO2 stream in order to sequester or otherwise inject it
underground to report the mass of CO2 captured and supplied.
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of
CO2 sequestered under the ``geologic sequestration of carbon
dioxide'' source category of the GHGRP (GHGRP subpart RR). In 2022, to
complement GHGRP subpart RR, the EPA proposed the ``geologic
sequestration of carbon dioxide with enhanced oil recovery (EOR) using
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide
an alternative method of
[[Page 33328]]
reporting geologic sequestration in association with
EOR.496 497 498
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\496\ 87 FR 36920 (June 21, 2022).
\497\ International Standards Organization (ISO) standard
designated as CSA Group (CSA)/American National Standards Institute
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil
Recovery (CO2-EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
\498\ As described in 87 FR 36920 (June 21, 2022), both subpart
RR and proposed subpart VV (CSA/ANSI ISO 27916:2019) require an
assessment and monitoring of potential leakage pathways;
quantification of inputs, losses, and storage through a mass balance
approach; and documentation of steps and approaches used to
establish these quantities. Primary differences relate to the terms
in their respective mass balance equations, how each defines
leakage, and when facilities may discontinue reporting.
---------------------------------------------------------------------------
The current rule leverages the regulatory requirements under GHGRP
subpart RR and does not reference GHGRP subpart VV. The EPA is
proposing that any affected unit that employs CCS technology that
captures enough CO2 to meet the proposed standard and
injects the captured CO2 underground must report under GHGRP
subpart RR or proposed GHGRP subpart VV. If the emitting EGU sends the
captured CO2 offsite, it must assure that the CO2
is managed at a facility subject to the GHGRP requirements, and the
facility injecting the CO2 underground must report under
GHGRP subpart RR or proposed GHGRP subpart VV. This proposal does not
change any of the requirements to obtain or comply with a UIC permit
for facilities that are subject to the EPA's UIC program under the Safe
Drinking Water Act.
The EPA also notes that compliance with the standard is determined
exclusively by the tons of CO2 captured by the emitting EGU.
The tons of CO2 sequestered by the geologic sequestration
site are not part of that calculation, though the EPA anticipates that
the quantity of CO2 sequestered will be substantially
similar to the quantity captured. However, to verify that the
CO2 captured at the emitting EGU is sent to a geologic
sequestration site, we are leveraging regulatory reporting requirements
under the GHGRP. The BSER is determined to be adequately demonstrated
based solely on geologic sequestration that is not associated with EOR.
However, EGUs also have the compliance option to send CO2 to
EOR facilities that report under GHGRP subpart RR or proposed GHGRP
subpart VV. We also emphasize that this proposal does not involve
regulation of downstream recipients of captured CO2. That
is, the regulatory standard applies exclusively to the emitting EGU,
not to any downstream user or recipient of the captured CO2.
The requirement that the emitting EGU assure that captured
CO2 is managed at an entity subject to the GHGRP
requirements is thus exclusively an element of enforcement of the EGU
standard. This will avoid duplicative monitoring, reporting, and
verification requirements between this proposal and the GHGRP, while
also ensuring that the facility injecting and sequestering the
CO2 (which may not necessarily be the EGU) maintains
responsibility for these requirements. Similarly, the existing
regulatory requirements applicable to geologic sequestration are not
part of the proposed rule.
3. Requirements for Sources Co-Firing Low-GHG Hydrogen
Because the EPA is basing its proposed definition of low-GHG
hydrogen consistent with IRC section 45V(b)(2)(D), it is reasonable, if
possible and practicable, for the EPA to adopt, in whole or in part,
the eligibility, monitoring, verification, and reporting protocols
associated with IRC section 45V(b)(2)(D) when finalized by Treasury for
the production of low-GHG hydrogen, and apply those protocols, as
applicable, to requirements the EPA establishes for the demonstration
by EGUs that they are using low-GHG hydrogen. Adopting very similar
requirements for demonstrations by EGUs that they are using low-GHG
hydrogen would help ensure there are not dueling eligibility
requirements for low-GHG hydrogen production with overall emissions
rates of 0.45 kg CO2e/kg H2 or less. Adopting
similar methods for assessing GHG emissions associated with hydrogen
production pathways would create clarity and certainty and reduce
confusion.
The EPA is taking comment on its proposal to closely follow
Treasury protocols in determining how EGUs demonstrate compliance with
the fuel characteristics required in this rulemaking. The EPA is taking
comment on what forms of acceptable mechanisms and documentary evidence
should be required for EGUs to demonstrate compliance with the
obligation to co-fire low-GHG hydrogen, including proof of production
pathway, overall emissions calculations or modeling results and input,
purchasing agreements, contracts, and energy attribute certificates.
Given the complexities of tracking produced hydrogen and the public
interest in such data, the EPA is also taking comment on whether EGUs
should be required to make fully transparent their sources of low-GHG
hydrogen and the corresponding quantities procured. The EPA is also
seeking comment on requiring that EGUs using low-GHG hydrogen
demonstrate that their hydrogen is exclusively from facilities that
only produce low-GHG hydrogen, as a means of reducing demonstration
burden and opportunities for double counting that could otherwise occur
for hydrogen purchased from facilities that produce multiple types of
hydrogen and the complex recordkeeping and documentation that would be
necessary to reliably verify that the hydrogen purchased from such
facilities qualifies. The EPA solicits comment on a mechanism to
operationalize such a provision.
Treasury is currently developing implementing rules for IRC section
45V. Congress specified that tax credit eligibility for the credit
tiers (45V(b)(2)(A), 45(V)(b)(2)(B), 45(b)(2)(C), and 45V(b)(2)(D))
should be based on an assessment of the estimated well-to-gate \499\
GHG emissions of hydrogen production, determined based on the most
recent Greenhouse gases, Regulated Emissions, and Energy use in
Transportation model (GREET model) or a successor model as determined
by the Secretary of Treasury. Consistent with its proposal to define
low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), the EPA is
also proposing that, for the purpose of demonstrating compliance with
the requirement to combust low-GHG hydrogen under this NSPS, the
maximum extent possible the same methodology specified in IRC section
45V and requirements currently under development should apply. One
example would be requiring that the owner/operator of the combustion
turbine obtain from the hydrogen producer from which they purchase low-
GHG hydrogen the hydrogen producer's calculation of GHG levels
associated with its hydrogen production using the GREET well-to-gate
analysis. The GREET model is well established, designed to adapt to
evolving knowledge, and capable of including technological advances.
The EPA solicits comment on whether the Agency should consider
unrelated or third-party verification as part of the standards required
for EGUs to demonstrate compliance. Given the
[[Page 33329]]
sequential timing of EPA and Treasury processes, the EPA may take
further action, after promulgation of this NSPS, to provide additional
guidance on application of Treasury's framework for IRC section 45V to
this particular context. The EPA requests comment on its proposal to
adopt as much as possible the methodology specified in IRC section 45V
and any associated implementing requirements established by Treasury,
once the methodology and implementing requirements are finalized, as
part of the obligations for EGUs to demonstrate compliance with the
requirement to combust low-GHG hydrogen under this NSPS.
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\499\ Well-to-gate analysis of lifecycle GHG emissions
represents a smaller scope than cradle-to-grave analysis. Well-to-
gate emissions of hydrogen production include those associated with
fossil fuel or electricity feedstock production and delivery to the
hydrogen facility; the hydrogen production process itself; and any
associated CCS applied at the hydrogen production facility. Well-to-
gate analysis does not consider emissions associated with the
manufacture or end-of-life of the hydrogen production facility or
facilities providing feedstock inputs to the hydrogen production
facility. Nor does it consider emissions associated with
transportation, distribution, and use of hydrogen beyond the
production facility.
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Although proposing to incorporate as much as possible Treasury's
eligibility, monitoring, reporting, and verification protocols, the EPA
recognizes that Treasury protocols concern hydrogen production, whereas
the EPA's proposed requirements apply to affected EGUs that use the
hydrogen to demonstrate compliance with the low-GHG hydrogen co-firing
obligations. The EPA is also taking comment on several underlying
policy issues relevant to ensuring that hydrogen used to comply with
this rule is low-GHG hydrogen. One reason that the EPA is considering
whether an alternative method to the Treasury guidance may be needed to
determine whether hydrogen meets the requirements to be considered low-
GHG is because hydrogen production facilities that begin construction
after 2032 will not be eligible for the tax credits. The EPA wants to
make sure a pathway exists for low-GHG hydrogen to be used for
compliance purposes even if the producer began construction after 2032
and is not receiving tax credits.
Given this and other uncertainties, the EPA is taking comment on
issues that would be relevant should the Agency develop its own
protocols for EGUs to demonstrate compliance with the overall emissions
rate in IRC section 45V(b)(2)(D) for co-firing as BSER in this
rulemaking.
The EPA is also taking comment on strategies the EPA could adopt to
inform its own eligibility, monitoring, reporting and verification
protocols for ensuring compliance with the 0.45 kg CO2e/kg
H2 or less emission rate for compliance with the low-GHG
provisions of this rule, if the EPA does not adopt Treasury's
protocols. The purpose of these strategies would be to ensure that EGUs
are using only low-GHG hydrogen, i.e., hydrogen that results in GHG
emissions of less than 0.45 kg CO2 per kg H2. The
EPA is taking comment on the appropriateness of requiring EGUs to
provide verification that the hydrogen they use complies with this
standard, as demonstrated by the GREET model for estimating the GHG
emissions associated with hydrogen production from well-to-gate, and to
what extent EGUs should be required to verify the accuracy of the
energy inputs and conclusions of the GREET model for the hydrogen used
by the EGU to comply with this rule.
Several important considerations with respect to determining
overall GHG emissions rates for hydrogen production pathways have been
raised by researchers and have been picked up in trade press
coverage.500 501 Given the importance of these issues, the
recent accumulation of relevant research, and the range of stakeholder
positions, the EPA is taking comment on the need for (and design of)
approaches and appropriate timeframes for allowing EGUs to meet
requirements for geographic and temporal alignment requirements to
verify that the hydrogen used by the EGU is compliant with this
rulemaking, recognizing that EPA's low-GHG standard for compliance
would not begin until 2032. The EPA is soliciting comment on these
issues, as they relate to co-firing low-GHG hydrogen in combustion
turbines and the requisite need to only utilize the lowest-GHG hydrogen
in these applications as specified in IRC section 45V, specifically IRC
section 45V(b)(2)(D). The EPA notes this is one of multiple forthcoming
opportunities for public comment on this suite of issues, and the EPA's
proposal is specific to low-GHG hydrogen in the context of qualifying a
co-firing fuel as part of BSER.
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\500\ Without Sufficient Guardrails, the Hydrogen Tax Credit
Could Increase Emissions--Union of Concerned Scientists. ucsusa.org.
\501\ Hydrogen's Power Grid Demands Under Scrutiny in Tax
Credit. bloomberglaw.com.
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It is important to note that the landscape for methane emissions
monitoring and mitigation is changing rapidly. For example, the EPA is
in the process of developing enhanced data reporting requirements for
petroleum and natural gas systems under its GHGRP, and is in the
process of finalizing requirements under New Source Performance
Standards and Emission Guidelines for the oil and gas sector that will
result in mitigation of methane emissions. With these changes, it is
expected that the quality of data to verify methane emissions will
improve and methane emissions rates will change over time. Adequately
identifying and accounting for overall emissions associated with
methane-based feedstocks is essential in the determination of accurate
overall emissions rates to comply with the low-GHG hydrogen standards
in this rule. The EPA is taking comment on how methane leak rates can
be appropriately quantified and conservatively estimated given the
inherent uncertainties and wide range of basin-specific
characteristics. The EPA is soliciting comment on whether EGUs should
be required to produce a demonstration of augmented in-situ monitoring
requirements to determine upstream emissions when methane feedstock is
used for low-GHG hydrogen used by the EGU for compliance with this
rule. The EPA is also taking comment on whether EGUs should use a
default assumption for upstream methane leak rates in the event
monitoring protocols are not finalized as part of this rulemaking, and
what an appropriate default leak rate should be, including what
evidence would be necessary for the EGU to deviate from that default
assumption. The EPA is also taking comment on the appropriateness of
requiring EGUs to provide CEMS data for SMR or ATR processes seeking to
produce qualifying low-GHG hydrogen for co-firing to ensure the amount
of carbon captured by CCS is properly and consistently monitored and
outage rates and times are recorded and considered. The EPA is
soliciting comment on providing EGUs with a representative and climate-
protective default assumption for carbon capture rates associated with
SMR and ATR hydrogen pathways, inclusive of outages, if CCS is used for
low-GHG hydrogen production as part of this rulemaking, including what
evidence would be necessary for the EGU to deviate from that default
assumption. These topics are particularly important to ensuring use of
low-GHG hydrogen given the DOE estimate that by 2050, reformation-based
production with CCS may account for 50-80 percent of total U.S.
hydrogen production.\502\ The EPA is taking comment on requiring
substantiation of energy inputs used in any overall GHG emissions
assessment for hydrogen production used by EGUs for compliance with
this requirement.
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\502\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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In comparison with petrochemical-based hydrogen production pathways
discussed above, electrolyzer-based hydrogen production has the
potential for lower-GHG hydrogen because the technology is based on
splitting water (H2O) molecules rather than splitting
hydrocarbons (e.g., CH4).\503\ For EGUs
[[Page 33330]]
relying on hydrogen produced using this pathway, the EPA is seeking
comment on the method for assuring that energy inputs to that
production are consistent with the low-GHG hydrogen standard that EGUs
would be required to meet under this rule. Specifically, the EPA is
taking comment on requiring EGUs to provide substantiation of low-GHG
energy inputs into any overall emissions assessment for electrolytic
hydrogen production pathways for hydrogen used by the EGUs to comply
with the low-GHG hydrogen standard in this rule. Energy Attribute
Certificates (EACs) (EACs from renewable sources are sometimes known as
Renewable Energy Credits or RECs) are produced for each megawatt hour
of low-GHG generation and therefore offer a measurable, auditable, and
verifiable approach for determining the GHG emissions associated with
the energy used to make the low-GHG hydrogen. EACs with specific
attributes are commonly used in the electricity markets to substantiate
corporate clean energy commitments and use, as well as for utility
compliance with State RPS and CES programs. The EPA is taking comment
on requiring EGUs to provide EAC verification for low-GHG emission
energy inputs into GHG emissions assessments for hydrogen used by that
EGU to comply with the low-GHG standard in this rule, for all hydrogen
pathways. The EPA is seeking comment on allowing EGUs to use EACs as
part of the documentation required for verifying the use of low-GHG
hydrogen.
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\503\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf.
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The EPA is taking comment on allowing EGUs to comply with the low-
GHG hydrogen standard in this rule if they demonstrate that the
hydrogen used is produced from: (1) dedicated low-GHG emitting
electricity from a generator sited on the utility side of a meter that
is contractually obligated to a electrolyzer, (2) a generator
collocated with an electrolyzer and sited behind a common utility
meter, or (3) a generator whereby the electrolyzer and generator are
collocated but not interconnected to the grid and have no grid
exchanges of power. The EPA is also taking comment on approaches for
EGUs to demonstrate that purchased hydrogen produced from an
electrolyzer could meet the low-GHG standard, in whole or part, through
an allotment of zero emitting electricity to a portion of the
electrolyzer's hydrogen output. Many announced hydrogen production
projects pair electrolyzers with renewable (including hydroelectric) or
nuclear energy, which are likely capable of producing low-GHG hydrogen.
Wind and solar renewable generation sources are variable, and nuclear
units go offline for refueling purposes. In these cases, and others,
grid-based electricity, which often has a high carbon intensity might
be pursued in combination with EACs for each megawatt hour of grid-
based energy used. Aligning the time and place (temporal and geographic
alignment) of EACs used to allocate and describe delivered grid-based
electricity consumed could potentially help ensure that hydrogen used
is low-GHG hydrogen.\504\ Some degree of alignment geographically, for
example delivery of power to the balancing authority in which the
electricity is consumed by the electrolyzer, could ensure that EACs
used are representative of the allocation of the energy mix consumed by
the electrolyzers. However, alignment could also entail trade-offs,
about which the EPA would like more information.
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\504\ ``How Can Hydrogen Producers Show That They Are
``Clean''?, Resources for the Future, October 27, 2022.
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In the case of temporal matching, the central issue is whether a
producer must obtain sufficient EACs to match the total electricity
demand of the electrolyzer on an annual basis corresponding to an
overall emissions rates of 0.45 kg CO2e/kg H2 or less, or
whether the producer must verify that it has obtained an EAC for low
carbon generation on a more granular timeframe, such as an hourly or
monthly basis, for each time period the electrolyzer is running. In
other words, how can book and claim methods for grid-connected systems
be developed to reliably claim total energy input emissions are
equivalent to a pure off-grid zero-carbon emitting system.
Considerations around how grid-based electricity can effectively assure
zero-carbon emitting energy inputs as validated by EACs have received
greater attention since passage of the IRA. Solutions offered by
researchers at Princeton University include requiring new grid-based
hydrogen producers to match 100 percent of electricity consumption on
an hourly basis with new carbon-free generation (substantiated through
EACs with hourly attributes), with an estimated cost impact of $1/
kg.\505\ Other research analyzing near-term emissions benefits of
hourly EAC alignment with respect to IRC section 45V implementation is
growing, with some divergent views about the emissions benefits of more
precise alignment requirements.\506\ Several research papers have
focused on the expense, trade-offs, and benefits of phasing in new and
hourly EAC alignment requirements.\507\ An MIT Energy Initiative
Working Paper examined emissions benefits of hourly alignment and
supported a `` `a phased approach'. . . annual matching in the near
term with a re-evaluation leaning towards hourly matching later on in
the decade''.\508\ A Rhodium Report found that while ``[r]equiring a
high degree of stringency across regional, temporal, and additionality
variables on day one . . . increases the total subsidized cost of
hydrogen production'' in the initial phase of the program, and
concludes that ultimately ``policymakers can't ignore the long-term
emissions risk'' and recommends, ``[t]o construct emissions guardrails,
the IRS can establish target dates for ratcheting up the certainty on
key implementation details like a transition to more temporally
granular matching. Such phase-in approaches give the hydrogen and power
industries the signposts they need to develop the tracking tools,
calculation approaches, contract language, and other key elements to
assure green hydrogen contributes to decarbonization.'' \509\ This
analysis did not consider potential system-wide emissions impacts if
costs present a near-term barrier to electrolytic hydrogen production,
and reformation-based methods continue to dominate hydrogen production
market share moving forward. Other research, for example from
Princeton, supports hourly time-matching, additionality, and location
requirements--arguing that all three pillars are important in ensuring
low-GHG outcomes and that additional costs are not unreasonable.
Research by Energy Innovation aligns with the Princeton study with
respect to locational and additionality requirements and diverges in
its recommendation of phasing in hourly EAC requirements by 2026.\510\
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\505\ Princeton Citation: Minimizing emissions from grid-based
hydrogen production in the United States--IOPscience January 2023.
\506\ American Council on Renewable Energy (ACORE), ``Analysis
of Hourly & Annual GHG Emissions: Accounting for Hydrogen
Production'', April 2023. acore.org.
\507\ Energy Futures Initiative, ``The Hydrogen Demand Action
Plan'', February 2023. https://energyfuturesinitiative.org/wp-content/uploads/sites/2/2023/02/EFI-Hydrogen-Hubs-FINAL-2-1.pdf.
\508\ MIT Energy Initiative, April 2023 ``Producing hydrogen
from electricity: How modeling additionality drives the emissions
impact of time-matching requirements'' Anna Cybulsky, Michael
Giovanniello, Tim Schittekatte, Dharik S. Mallapragada.
\509\ Rhodium Group, ``Scaling Green Hydrogen in a post-IRA
World'' March 16, 2023. https://rhg.com/research/scaling-clean-hydrogen-ira/.
\510\ https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-Hydrogen-Production-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.
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[[Page 33331]]
The European Commission proposed a phased-in approach to defining
what constitutes `renewable hydrogen' for the European Union (EU). The
EU framework includes multiple components including temporal alignment
requirements: monthly EAC alignment is required at the onset of the
program, and hourly EAC alignment requirements are phased-in by
2030.511 512 An impact assessment of the temporal alignment
requirements is to be completed in 2028 and could impact the timing of
the hourly EAC phase-in requirements. The EU hydrogen requirements and
conditions will apply to domestic producers and imports and do not
expire. EAC alignment requirements impact both new and existing
projects. Geographic alignment for EACs is required at the onset of the
EU program, whereas vintage requirements necessitating new zero-carbon
emitting energy source-based generation, often called `additional', are
phased in after 2028. The EU proposal was released in February and must
be approved by the European Parliament and the Council of the EU within
four months: amendments to the underlying policy are not permitted.
Notably, unlike the United States, the EU has a carbon policy for power
sector emissions that could help ensure that additional electricity
demand from hydrogen production does not result in additional power
sector CO2 emissions. The EU and stakeholders examining
costs and benefits of temporal EAC alignment requirements generally
find that hourly EAC alignment is preferred before the 2032 proposed
effective date of hydrogen co-firing requirements in this proposed
rule, with most converging on or before 2030.513 514
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\511\ C_2023_1087_1_EN_ACT_part1_v8.pdf. (europa.eu)
\512\ European Commission, ``Commission sets out rules for
renewable hydrogen'' Brussels, February 13, 2023. See: Hydrogen
(europa.eu), Delegated regulation on Union methodology for RFNBOs.
(europa.eu)
\513\ https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-Hydrogen-Production-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.
\514\ April 12, 2023, memorandum, ``How annual matching for the
Inflation Reduction Act's (IRA) 45V clean hydrogen tax credit can
accelerate progress towards the Biden administration's
decarbonization and clean hydrogen goals'' signed by 23 companies,
addressed to Treasury Secretary Janet Yellen, Energy Secretary
Jennifer Granholm and Senior Advisor to the President for Clean
Energy Innovation and Implementation Mr. John Podesta, indicated an
openness to examine hourly EAC requirements in 2032 or earlier and
asserted, ``recent studies warn that overly stringent temporal
matching would hinder the development of clean hydrogen industry.''
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The EPA is soliciting comment on requiring EGUs to use geographic
and temporal alignment approaches for EAC-related requirements and the
appropriate timing and trade-offs of such approaches. The EPA is
soliciting comment on the appropriateness of requiring geographic
alignment for EACs used in conjunction with energy inputs at the
balancing authority level at the onset of the compliance period for
BSER in 2032. Similarly, the EPA is soliciting comments on the
appropriateness of requiring hourly EAC alignment requirements at the
onset of the compliance period for BSER in 2032. Relatedly, the EPA is
taking comment on whether any hourly EAC alignment requirements should
affect both existing and new projects beginning in 2032, regardless of
when a project became operational and a recipient of IRC section 45V
credits.
Hourly tracking systems are evolving to meet this need in real
time. For example, PJM announced it would introduce EACs with hourly
data stamping for low-GHG generators in March 2023. M-RETS, a regional
attribute tracking system headquartered in the Midwest, has also
introduced the capability to track hourly energy attributes. While
several tracking systems are announcing or have started issuing hourly
EACs, standardized methods, and nationwide coverage is still
developing. Recognizing that the timing of EPA's proposed regulations
would not require such tracking systems to be fully functional until
the 2030s, the EPA is taking comment on the suitability of emerging and
differentiated tracking systems to provide the infrastructure for
hourly energy attribute tracking for EGUs complying with low-GHG
hydrogen standards. The EPA is also taking comment on the need for
energy attribute tracking systems to uniformly approach the issuance,
allocation, tracking and retirement of hourly EACs using similar
approaches to ensure a common and consistent national practice.
L. Mechanisms To Ensure Use of Actual Low-GHG Hydrogen
The EPA is soliciting comment on appropriate mechanisms to ensure
that the low-GHG hydrogen used by EGUs is actually low-GHG, and guard
against EGU use of hydrogen that is falsely claimed to be low-GHG
hydrogen. The EPA solicits comment on whether EGUs should be required
to provide an independent third-party verification that hydrogen the
EGU uses to comply with this regulation meets the requirements for low-
GHG hydrogen. EPA also solicits comment on whether any such verifying
third party must hold an active accreditation from an accrediting body,
such as the California Air Resources Board's Low Carbon Fuels Standards
Program or the International Standards Organization 14064 Code. EPA
seeks comment on any other mechanisms to ensure that hydrogen used by
EGUs meets the low-GHG standard and what the remedy should be if an EGU
uses hydrogen that is determined not to meet the definition of low-GHG
hydrogen.
M. Recordkeeping and Reporting Requirements
The current rule (subpart TTTT of 40 CFR part 60) requires EGU
owners or operators to prepare reports in accordance with the Acid Rain
Program's ECMPS and, for the EGUs relying on the compliance approaches
contained in Appendix G of 40 CFR part 75, with the reporting
requirements of that Appendix. Such reports are to be submitted
quarterly. The EPA believes all EGU owners and operators have extensive
experience in using the ECMPS and use of a familiar system ensures
quick and effective rollout of the program in today's proposal. Because
all EGUs are expected to be covered by and included in the ECMPS,
minimal, if any, costs for reporting are expected for this proposal. In
the unlikely event that a specific EGU is not already covered by and
included in the ECMPS, the estimated annual per unit cost would be
about $8,500.
The current rule's recordkeeping requirements at 40 CFR part
60.5560 rely on a combination of general provision requirements (see 40
CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and
an explicit list of items, including data and calculations; the EPA
proposes to retain those existing subpart TTTT of 40 CFR part 60
requirements in the new NSPS subpart TTTTa of 40 CFR part 60. The
annual cost of those recordkeeping requirements would be the same
amount as is required for subpart TTTT of 40 CFR part 60 recordkeeping.
As the recordkeeping in subpart TTTT of 40 CFR part 60 will be replaced
by similar recordkeeping in subpart TTTTa of 40 CFR part 60 upon
promulgation, this annual cost for recordkeeping will be maintained.
N. Additional Solicitations of Comment and Proposed Requirements
This section includes additional issues the Agency is specifically
soliciting comment on. It also provides a summary of some of the key
considerations the EPA is soliciting comment on with respect to the
[[Page 33332]]
proposed CAA section 111(b) requirements.
1. CCS and Co-Firing Low-GHG Hydrogen as BSER for the Base Load
Subcategory
As described above, the EPA is proposing to establish two
subcategories with different standards for the base load subcategory,
each based on a different BSER pathway. The first is based on a BSER of
CCS with 90 percent capture by 2035. The second is based on a BSER of
co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing
96 percent (by volume) by 2038. (Both pathways include efficient
equipment and operation and maintenance as an initial component of the
BSER.) In other sections of this preamble, the EPA solicits comment on
variations in the amount of emissions reduction and the dates for
compliance for each pathway.
The EPA believes that if it finalizes a subcategory approach with
different standards in which sources may choose between the two
standards and BSER pathways, each must achieve environmentally
comparable emission reductions. Thus, if the EPA determines based on
all of the statutory considerations that CCS with 90 percent capture
qualifies as the BSER for base load combustion sources, then co-firing
hydrogen could qualify as well only if it also achieves comparable
reductions. Because the emissions standards are technology neutral, if
the two pathways can achieve the same emissions reductions at the same
time, there would be no need to establish separate subcategories and
standards as sources could adopt either BSER pathway to meet the
standard. But the EPA also believes that these two technologies may
achieve comparable emissions reductions at slightly different times,
thus potentially necessitating two alternate standards. The EPA
solicits comment on the differences in emissions reductions in both
scale and time that would result from the two standards and BSER
pathways, including how to calculate the different amounts of emission
reductions, how to compare them, and what conclusions to draw from
those differences. From the perspective of an individual turbine, the
proposed co-firing with low-GHG hydrogen-based standard results in
earlier emission reductions because it takes effect in 2032, three
years before the CCS-based standard, but the low-GHG hydrogen-based
standard could also result in fewer total emission reductions because
the 90 percent emission rate reduction is not required until 2038,
three years after the CCS-based standard. Although early emission
reductions have value in addressing climate change, it is the
cumulative impact of the emission reductions that is of primary
importance given the short time-scale over which those early reductions
are occurring. The EPA also solicits comment on the potential benefits
of prescribing two separate standards for new base load combustion
turbines. Owners and operators of new combustion turbine EGUs are
currently pursuing both CCS and co-firing with low-GHG hydrogen as
approaches for reducing GHG emissions, and both require the development
of infrastructure that may proceed at a different pace and scale and
achieve emissions reductions on different timelines with respect to
each technology. Although both CCS and co-firing with low-GHG hydrogen
are, or are expected to be, broadly available throughout the United
States, the EPA solicits comment on whether individual locations where
new base load combustion turbines might be constructed might lend
themselves more to one technology than the other (based on pipeline
availability, proximity to hydrogen production or geologic
sequestration sites, etc.). The EPA recognizes that the design of CAA
section 111--whereby sources decide which emissions controls they use
to meet standards of performance--provides sources with operational
flexibility so long as they achieve the standard. A subcategory
approach, however, may allow the EPA to consider the potentially
differing scale and pace at which these technologies can achieve
environmentally equivalent emissions reductions and whether there are
characteristics of units that make one or the other pathways ``best''
for those types of units.
As an alternative to the proposed approach of two standards and
BSER pathways for the base load subcategory, the EPA is soliciting
comment on having a single standard, which would be based on CCS with
90 percent capture (along with efficiency as the initial component of
the BSER). Under this alternative, the EPA would not establish a
separate base load subcategory for combustion turbines that adopt the
low-GHG hydrogen co-firing pathway.
The EPA solicits comment on whether finalizing a single, CCS-based
standard for the baseload subcategory better reflects the more likely
uses of hydrogen as a source of fuel in new combustion turbines. The
EPA has proposed a standard for base load combustion turbines that
adopt the low-GHG hydrogen co-firing in part because the Agency
understands a number of power companies are actively developing
combustion turbines that are designed to co-fire hydrogen. However, the
Agency recognizes that power companies may ultimately come to utilize
low-GHG hydrogen as a storage fuel reserved for intermediate load
combustion turbines that support variable renewable generation, rather
than for combustion turbines that generate at base load. An approach in
which the EPA establishes a single CCS-based second phase standard for
base load combustion turbines, along with a second phase standard for
intermediate load combustion turbines that is based on low-GHG hydrogen
as a component of the BSER, would align with this potential scenario.
In addition, if an owner or operator of a new combustion turbine does
seek to utilize low-GHG hydrogen for base load generation, a single
CCS-based second phase standard for base load combustion turbines would
not preclude owners and operators from utilizing low-GHG hydrogen as a
means of compliance. Owners/operators could also comply with a CCS-
based standard by co-firing 96 percent (by volume) low-GHG hydrogen
from the outset of the second phase--rather than the proposed approach
that would delay requirements for this level of co-firing until 2038.
2. Co-Firing Low-GHG Hydrogen as BSER for Intermediate Load Combined
Cycle and Simple Cycle Subcategories
The EPA is also soliciting comment on subcategorizing intermediate
load combustion turbines into an intermediate load combined cycle
subcategory and an intermediate load simple cycle subcategory. The BSER
for both subcategories would be two components: (1) Highly efficient
generation (either combined cycle technology or simple cycle
technology, respectively) and (2) co-firing 30 percent (by volume) low-
GHG hydrogen, with the first component applying when the source
commences operation and the second component applying in the year 2032.
Dividing the intermediate load subcategory into these two subcategories
would assure that intermediate load combined cycle turbines would have
a more stringent standard of performance--that is, expressed in a lower
lb CO2/MWh--than intermediate load simple cycle turbines.
3. Integrated Onsite Generation and Energy Storage
Integrated equipment is currently included as part of the affected
facility and the EPA is soliciting comment on the best approach to
recognizing the
[[Page 33333]]
environmental benefits of onsite integrated non-emitting generation and
energy storage. The EPA is proposing regulatory text to clarify that
the output from integrated renewables is included as output when
determining the NSPS emissions rate. The EPA is also proposing that the
output from the integrated renewable generation is not included when
determining the net electric sales for applicability purposes. In the
alternative, the EPA is soliciting comment on whether instead of
exempting the generation from the integrated renewables from counting
toward electric sales, the potential output from the integrated
renewables would be included when determining the design efficiency of
the facility. Since the design efficiency is used when determining the
electric sales threshold this would increase the allowable electric
sales for subcategorization purposes. Including the integrated
renewables when determining the design efficiency of the affected
facility would have the impact of increasing the operational
flexibility of owners/operators of intermediate load combustion
turbines. Renewables typically have much lower 12-operating month
capacity factors than the intermediate electric sales threshold so
could allow the turbine engine itself to operate at a higher capacity
factor while still being considered an intermediate load EGU.
Conversely, if the integrated renewables operate at a 12-operating
month capacity factor of greater than 20 percent that would reduce the
ability of a peaking turbine engine to operate while still remaining in
the low load subcategory. However, even if a combustion turbine engine
itself were to operate at a capacity factor of less than 20 percent and
become categorized as an intermediate load combustion turbine when the
output form the integrated renewables are considered, the output from
the integrated renewables could lower the emissions rate such that the
affected facility would be in compliance with the intermediate load
standard of performance.
For integrated energy storage technologies, the EPA is soliciting
comment on including the rated output of the energy storage when
determining the design efficiency of the affected facility. Similar to
integrated renewables, this would increase the flexibility of owner/
operators to operate at higher capacity factors while remaining in the
low and intermediate load subcategories. The EPA is not proposing that
the output from the energy storage be considered in either determining
the NSPS emissions rate or as net electric sales for subcategorization
applicability purposes. While additional energy storage will allow for
integration of additional variable renewable generation, the energy
storage devices could be charged using grid supplied electricity that
is generated from other types of generation. Therefore, this is not
necessarily stored low-GHG electricity.
4. Definition of System Emergency
40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60,
subpart TTTTa) include a provision that electricity sold during hours
of operation when a unit is called upon to operate due to a system
emergency is not counted toward the percentage electric sales
subcategorization threshold.\515\ The EPA concluded that this exclusion
is necessary to provide flexibility, to maintain system reliability,
and to minimize overall costs to the sector (80 FR 64612; October 23,
2015). Some in the regulated community have informed the Agency that
additional clarification on a system emergency would need to be
determined and documented for compliance purposes. The intent is that
the local grid operator would determine which EGUs are essential to
maintain grid reliability. The EPA is soliciting comments on amending
the definition of system emergency to clarify how it would be
implemented. The current text is any abnormal system condition that the
RTO, Independent System Operators (ISO) or control area Administrator
determines requires immediate automatic or manual action to prevent or
limit loss of transmission facilities or generators that could
adversely affect the reliability of the power system and therefore call
for maximum generation resources to operate in the affected area, or
for the specific affected EGU to operate to avert loss of load.
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\515\ Electricity sold by units that are not called upon to
operate due to a system emergency (e.g., units already operating
when the system emergency is declared) is counted toward the
percentage electric sales threshold.
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5. Definition of Natural Gas
40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60,
subpart TTTTa) include a definition of natural gas. Natural gas is a
fluid mixture of hydrocarbons (e.g., methane, ethane, or propane),
composed of at least 70 percent methane by volume or that has a gross
calorific value between 35 and 41 megajoules (MJ) per dry standard
cubic meter (950 and 1,100 Btu per dry standard cubic foot), that
maintains a gaseous state under ISO conditions. Finally, natural gas
does not include the following gaseous fuels: Landfill gas, digester
gas, refinery gas, sour gas, blast furnace gas, coal-derived gas,
producer gas, coke oven gas, or any gaseous fuel produced in a process
which might result in highly variable CO2 content or heating
value. The EPA is soliciting comment on if the exclusions for specific
gases such as landfill gas, etc. are necessary of if they should be
deleted. If landfill gas, coal-derived gas, or other gases are
processed to meet the methane and heating value content of pipeline
quality natural gas they could be mixed into the pipeline network and
it is the intent that this mixture be considered natural gas for the
purposes of 40 CFR part 60, subpart TTTT and the proposed 40 CFR part
60, subpart TTTTa.
6. Summary of Solicitation of Comment on BSER Variations
This section summarizes the variations on the subcategories and on
BSER for combustion turbines on which the EPA is soliciting comment. It
is intended to highlight certain aspects of the proposal the Agency is
soliciting comment on and is not intended to cover all aspects of the
proposal.
For the low load subcategory, the EPA is soliciting comment on:
An electric sales threshold of between 15 to 25 percent
for all combustion turbines regardless of the specific design
efficiency.
An electric sales threshold based on three quarters of the
design efficiency of the combustion turbine. This would result in
electric sales thresholds of 18 to 22 percent for simple cycle turbines
and 26 to 31 percent for combined cycle turbines.
Applying a second component of BSER, co-firing 30 percent
(by volume) low-GHG hydrogen by 2032.
For the intermediate load subcategory, the EPA is soliciting
comment on:
An efficiency-based standard of performance of between
1,000 to 1,200 lb CO2/MWh-gross.
The use of steam injection as part of the first BSER
component.
An electric sales threshold based on 94 percent of the
design efficiency. This would result in electric sales thresholds of 29
to 35 percent for simple cycle turbines and 40 to 49 percent for
combined cycle turbines.
A hydrogen co-firing range of 30 to 50 percent by volume
as the second component of the BSER.
Beginning implementation of the second component of the
BSER (i.e., hydrogen co-firing) as early as 2030.
The second component of the BSER would establish separate
subcategories
[[Page 33334]]
for simple and combined cycle intermediate load combustion turbines,
both based on co-firing low-GHG hydrogen.
Adding a third phase standard based on higher levels of
low-GHG hydrogen co-firing by 2038.
For the base load subcategory, the EPA is soliciting comment on:
An efficiency-based standard of performance of between 730
to 800 lb CO2/MWh-gross for large combustion turbines.
An efficiency-based standard of performance of between 850
to 900 lb CO2/MWh-gross for small combustion turbines.
Beginning implementation of the second component of the
BSER (i.e., CCS or hydrogen co-firing) as early as 2030.
Beginning implementation of the third component of the co-
firing low-GHG hydrogen-based BSER earlier than 2038.
Whether the third component of the hydrogen BSER should be
96 percent by volume or a lower volume--note that if it is a lower
volume that raises issues as to whether the BSER would be appropriate
if EPA found that a CCS BSER of 90% for NGCCs was generally applicable
A hydrogen co-firing range of 30 to 50 percent as the
second component of the BSER for combustion turbines co-firing
hydrogen.
A single standard based on either a CCS-based BSER or a
co-firing low-GHG-hydrogen based BSER for all base load combustion
turbines.
A carbon capture rate of 90 to 95 percent as the second
component of the CCS-based BSER.
O. Compliance Dates
The EPA is proposing that affected sources that commenced
construction or reconstruction after May 23, 2023, would need to meet
the requirements of 40 CFR part 60, subpart TTTTa upon startup of the
new or reconstructed affected facility or the effective date of the
final rule, whichever is later. This proposed compliance schedule is
consistent with the requirements in section 111 of the CAA.
VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-
Fired Steam Generating Units
A. 2018 NSPS Proposal
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired
steam generating units in 2015. 80 FR 64510 (October 23, 2015). As
discussed in section V.B.2 of this preamble, on December 20, 2018, the
EPA proposed amendments that would revise the determination of the BSER
for control of GHG emissions from newly constructed coal-fired steam
generating units in 40 CFR part 60, subpart TTTT (83 FR 65424; December
20, 2018). The EPA is not reopening for comment or soliciting comment
on the 2018 NSPS Proposal, and intends to further address it in a
separate action.
1. Additional Amendments
The EPA is proposing multiple less significant amendments. These
amendments would be either strictly editorial and would not change any
of the requirements of 40 CFR part 60, subpart TTTT or are intended to
add additional compliance flexibility. The proposed amendments would
also be incorporated into the proposed subpart TTTTa. For additional
information on these amendments, see the redline strikeout version of
the rule showing the proposed amendments. First, the EPA is proposing
editorial amendments to define acronyms the first time they are used in
the regulatory text. Second, the EPA is proposing to add International
System of Units (SI) equivalent for owners/operators of stationary
combustion turbines complying with a heat input-based standard. Third,
the EPA is proposing to fix errors in the current 40 CFR part 60,
subpart TTTT regulatory text referring to part 63 instead of part 60.
Fourth, as a practical matter owners/operators of stationary combustion
turbines subject to the heat input-based standard of performance need
to maintain records of electric sales to demonstrate that they are not
subject to the output-based standard of performance. Therefore, the EPA
is proposing to add a specific requirement that owner/operators
maintain records of electric sales to demonstrate they did not sell
electricity above the threshold that would trigger the output-based
standard. Next, the EPA is proposing to update the ANSI, ASME, and ASTM
test methods to include more recent versions of the test methods.
Finally, the EPA is proposing to add additional compliance
flexibilities for EGUs either serving a common electric generator or
using a common stack. Specifically, for EGUs serving a common electric
generator, the EPA is soliciting comment on whether the Administrator
should be able to approve alternate methods for determining energy
output. For EGUs using a common stack, the EPA is soliciting comment on
whether specific procedures should be added for apportioning the
emissions and/or if the Administrator should be able to approve site-
specific alternate procedures.
B. Eight-Year Review of NSPS for Fossil Fuel-Fired Steam Generating
Units
1. New Construction and Reconstruction
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired
steam generating units in 2015. As noted in section IV.F, the EPA is
not aware of any plans by any companies to undertake new construction
of a new fossil fuel-fired steam generating unit, or to undertake a
reconstruction of an existing fossil fuel-fired steam generating unit,
that would be subject to the 2015 NSPS for steam generating units.
Accordingly, the EPA does not consider it necessary, nor a good use of
agency resources, to review the NSPS for new construction or
reconstruction. See ``New Source Performance Standards (NSPS) Review:
Advanced notice of proposed rulemaking,'' 76 FR 65653, 65658 (October
24, 2011) (suggesting it may not be necessary for the EPA to review an
NSPS when no new construction, modification, or reconstruction is
expected in the source category). Should events change and the EPA
learns that companies plan to undertake construction of a new fossil
fuel-fired steam generating unit or reconstruction of an existing
fossil fuel-fired steam generating unit, the EPA would consider
reviewing these standards.
2. Modifications
In the 2015 NSPS, the EPA issued final standards for a steam
generating unit that implements a ``large modification,'' defined as a
physical change, or change in the method of operation, that results in
an increase in hourly CO2 emissions of more than 10 percent
when compared to the source's highest hourly emissions in the previous
5 years. Such a modified steam generating unit is required to meet a
unit-specific CO2 emission limit determined by that unit's
best demonstrated historical performance (in the years from 2002 to the
time of the modification). The 2015 NSPS did not include standards for
a steam generating unit that implements a ``small modification,''
defined as a change that results in an increase in hourly
CO2 emissions of less than or equal to 10 percent when
compared to the source's highest hourly emissions in the previous 5
years. 80 FR 64514 (October 23, 2015).
In the 2015 NSPS, the EPA explained its basis for promulgating this
rule as follows. The EPA has historically been notified of only a
limited number of NSPS modifications involving fossil steam generating
units and therefore predicted that very few of these units
[[Page 33335]]
would trigger the modification provisions and be subject to the
proposed standards. Given the limited information that we have about
past modifications, the agency has concluded that it lacks sufficient
information to establish standards of performance for all types of
modifications at steam generating units at this time. Instead, the EPA
has determined that it is appropriate to establish standards of
performance at this time for larger modifications, such as major
facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that result
in substantial increases in a unit's hourly CO2 emissions
rate. The agency has determined, based on its review of public comments
and other publicly available information, that it has adequate
information regarding the types of modifications that could result in
large increases in hourly CO2 emissions, as well as on the
types of measures available to control emissions from sources that
undergo such modifications, and on the costs and effectiveness of such
control measures, upon which to establish standards of performance for
modifications with large emissions increases at this time. Id. at
64597-98. The EPA is not reopening any aspect of these determinations
concerning modifications in the 2015 NSPS, except, as noted below, for
the BSER and associated requirements for large modifications.
Because the EPA has not promulgated a NSPS for small modifications,
any existing steam generating unit that undertakes a change that
increases its hourly CO2 emissions rate by 10 percent or
less would continue to be treated as an existing source that is subject
to the CAA section 111(d) requirements being proposed today.
With respect to large modifications, we explained in the 2015 NSPS
that they are rare, but there is record evidence indicating that they
may occur. Id. at 64598. Because the EPA is proposing requirements for
existing sources that are, on their face, more stringent than the
requirements for large modifications, the EPA believes it is
appropriate to review and revise the latter requirements to minimize
the anomalous incentive that an existing source could have to undertake
a large modification for the purpose of avoiding the more stringent
requirements that it would be subject to if it remained an existing
source. Accordingly, the EPA is proposing to revise the BSER for large
modifications to mirror the BSER for the subcategory of coal-fired
steam generating units that plan to operate past December 31, 2039,
that is, the use of CCS with 90 percent capture of CO2. The
EPA believes that it is reasonable to assume that any existing source
that invests in a physical change or change in the method of operation
that would qualify as a large modification expects to continue to
operate past 2039. Accordingly, the EPA proposes that CCS with 90
percent capture qualifies as the BSER for such a source for the same
reasons that it qualifies as the BSER for existing sources that plan to
operate past December 31, 2039. The EPA discusses these reasons in
section X.D.1.a. The EPA is proposing to determine that CCS with 90
percent capture qualifies as the BSER for large modifications, and not
the controls determined to be the BSER in the 2015 NSPS, due to the
recent reductions in the cost of CCS. The EPA does not believe there
are any considerations relative to a source undertaking a large
modification that point towards a control system other than CCS with 90
percent capture qualifying as the BSER. The Agency solicits comment on
this issue.
By the same token, the EPA is proposing that the degree of emission
limitation associated with CCS with 90 percent capture is an 88.4
percent reduction in emission rate (lb CO2/MWh-gross basis),
the same as proposed for existing sources with CCS with 90 percent
capture. See section X.D.1.a.iv. Based on this degree of emission
limitation, the EPA is proposing that the standard of performance for
steam generating units that undertake large modifications after the
date of publication of this proposal is a unit-specific emission limit
determined by an 88.4 percent reduction in the unit's best historical
annual CO2 emission rate (from 2002 to the date of the
modification). The EPA is proposing that an owner/operator of a
modified steam generating unit comply with the proposed emissions rate
upon startup of the modified affected facility or the effective date of
the final rule, whichever is later. The EPA is proposing the same
testing, monitoring, and reporting requirements as are currently in 40
CFR part 60, subpart TTTT.
C. Projects Under Development
Finally, during the 2015 NSPS rulemaking, the EPA identified the
Plant Washington project in Georgia and the Holcomb 2 project in Kansas
as EGU ``projects under development'' based on representations by
developers that the projects had commenced construction prior to the
proposal of the 2015 NSPS and, thus, would not be new sources subject
to the final NSPS (80 FR 64542-43; October 23, 2015). The EPA did not
set a performance standard at the time but committed to doing so if new
information about the projects became available. These projects were
never constructed and are no longer expected to be constructed.
The Plant Washington project was to be an 850-MW supercritical
coal-fired EGU. The Environmental Protection Division (EPD) of the
Georgia Department of Natural Resources issued air and water permits
for the project in 2010 and issued amended permits in
2014.516 517 518 In 2016, developers filed a request with
the EPD to extend the construction commencement deadline specified in
the amended permit, but the director of the EPD denied the request,
effectively canceling the approval of the construction permit and
revoking the plant's amended air quality permit.\519\
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\516\ https://www.gpb.org/news/2010/07/26/judge-rejects-coal-plant-permits.
\517\ https://www.southernenvironment.org/press-release/court-rules-ga-failed-to-set-safe-limits-on-pollutants-from-coal-plant/.
\518\ https://permitsearch.gaepd.org/permit.aspx?id=PDF-OP-22139.
\519\ https://www.southernenvironment.org/wp-content/uploads/legacy/words_docs/EPD_Plant_Washington_Denial_Letter.pdf.
---------------------------------------------------------------------------
The Holcomb 2 project was intended to be a single 895-MW coal-fired
EGU and received permits in 2009 (after earlier proposals sought
approval for development of more than one unit). In 2020, after
developers announced they would no longer pursue the Holcomb 2
expansion project, the air permits were allowed to expire, effectively
canceling the project.
For these reasons, the EPA is proposing to remove these projects
under the applicability exclusions in subpart TTTT.
IX. Proposed ACE Rule Repeal
The EPA is proposing to repeal the ACE Rule. A general summary of
the ACE Rule, including its regulatory and judicial history, is
included in section V.B of this preamble. The repeal of the ACE Rule is
intended to stand alone and be severable from the other aspects of this
rule. The EPA proposes to repeal the ACE Rule on three grounds that
together, and each independently, justify the rule's repeal. First, as
a policy matter, the EPA believes that the suite of heat rate
improvements (HRI) the ACE Rule selected as the BSER should be
reexamined and are no longer an appropriate BSER for existing coal-
fired EGUs. The EPA concludes that the suite of HRI set forth in the
ACE Rule provide
[[Page 33336]]
negligible CO2 reductions at best and, in many cases, could
increase CO2 emissions because of the rebound effect, as
explained in section X.D.5.a. These concerns taken together, along with
new evidence, and the EPA's experience in implementing the ACE Rule,
cast doubt on the ACE Rule's minimal projected emission reductions and
increase the likelihood that the ACE Rule could make CO2
pollution worse. As a result, the EPA has determined it is appropriate
to repeal the rule, and to reevaluate whether other technologies
constitute the BSER.
Second, the ACE Rule rejected CCS and natural gas co-firing as the
BSER for reasons that no longer apply. This rule should be repealed so
that EPA may determine the BSER based on evaluating all the candidate
technologies. Since the ACE Rule was promulgated, changes in the power
industry, developments in the costs of controls, and new Federal
subsidies have made these other technologies more broadly available and
less expensive. The EPA is now proposing that these technologies are
the BSER for certain subcategories of sources, as described in section
X of this preamble.
Third, the EPA concludes that the ACE Rule conflicted with CAA
section 111 and the EPA's implementing regulations because it did not
specifically identify the BSER or the ``degree of emission limitation
achievable though application of the [BSER],'' but set forth an
indeterminate range of values. Thus, the rule did not provide the
States with adequate guidance on the degree of emission limitation that
must be reflected in the standards of performance so that a State plan
would be approvable by the EPA. Along with this, the ACE Rule also
improperly departed from the statutory framework of CAA section 111(d)
by categorically precluding States from allowing their sources to
comply with standards of performance by trading or averaging. Properly
construed, CAA section 111(d) gives States discretion to provide
sources with certain compliance flexibilities, including trading or
averaging in appropriate circumstances so long as the other
requirements of section 111 are met as described below.
A. Summary of Selected Features of the ACE Rule
The ACE Rule determined that the BSER for coal-fired EGUs was a
``list of `candidate technologies,' '' consisting of seven types of the
``most impactful HRI technologies, equipment upgrades, and best
operating and maintenance practices,'' (84 FR 32536; July 8, 2019),
including, among others, ``Boiler Feed Pumps'' and ``Redesign/Replace
Economizer.'' Id. at 32537 (table 1). The rule provided a range of
improvements in heat rate that each of the seven ``candidate
technologies'' could achieve if applied to coal-fired EGUs of different
capacities. For six of the technologies, the expected level of
improvement in heat rate ranged from 0.1-0.4 percent to 1.0-2.9
percent, and for the seventh technology, ``Improved Operating and
Maintenance (O&M) Practices,'' the range was ``0 to >2%.'' Id. The ACE
Rule explained that States must review each of their designated
facilities, on either a source-by-source or group-of-sources basis, and
``evaluate the applicability of each of the candidate technologies.''
Id. at 32550. States were to use the list of HRI technologies ``as
guidance but will be expected to conduct unit-specific evaluations of
HRI potential, technical feasibility, and applicability for each of the
BSER candidate technologies.'' Id. at 32538.
The ACE Rule emphasized that States had ``inherent flexibility'' in
undertaking this task with ``a wide range of potential outcomes.'' Id.
at 32542. The ACE Rule provided that States could conclude that it was
not appropriate to apply some technologies. Id. at 32550. Moreover, if
a State did decide to apply a particular technology to a particular
source, the State could determine the level of heat rate improvement
from the technology to be anywhere within the range that the EPA had
identified for that technology, or even outside that range. Id. at
32551. The ACE Rule stated that after the State evaluated the
technologies and calculated the amount of HRI in this way, it should
determine the standard of performance that the source could achieve,
Id. at 32550, and then adjust that standard further based on the
application of source-specific factors such as remaining useful life.
Id. at 32551.
The ACE Rule then identified the process by which States had to
take these actions. States must ``evaluat[e] each'' of the seven
candidate technologies and provide a summary, which ``include[s] an
evaluation of the . . . degree of emission limitation achievable
through application of the technologies.'' Id. at 32580. Then, the
State must provide a variety of information about each power plant,
including, the plant's ``annual generation,'' ``CO2
emissions,'' ``[f]uel use, fuel price, and carbon content,''
``operation and maintenance costs,'' ``[h]eat rates,'' ``[e]lectric
generating capacity,'' and the ``timeline for implementation,'' among
other information. Id. at 32581. The EPA explained that the purpose of
this data was to allow the Agency to ``adequately and appropriately
review the plan to determine whether it is satisfactory.'' Id. at
32558.
The ACE Rule projected a very low level of overall emission
reduction if States generally applied the set of candidate technologies
to their sources. The rule was projected to achieve a less-than-1-
percent reduction in power-sector CO2 emissions by
2030.\520\ Further, the EPA also projected that it would increase
CO2 emissions from power plants in 15 States and the
District of Columbia because of the ``rebound effect'' as sources
implemented HRI measures and became more efficient. This phenomenon is
explained in more detail in section X.D.5.a.\521\
---------------------------------------------------------------------------
\520\ ACE Rule RIA 3-11, table 3-3.
\521\ The rebound effect becomes evident by comparing the
results of the ACE Rule IPM runs for the 2018 reference case, EPA,
IPM State-Level Emissions: EPAv6 November 2018 Reference Case, EPA-
HQ-OAR-2017-0355-26720, and for the ``Illustrative ACE Scenario. IPM
State-Level Emissions: Illustrative ACE Scenario, EPA-HQ-OAR-2017-
0355-26724.
---------------------------------------------------------------------------
The ACE Rule considered several other control measures as the BSER,
including co-firing with natural gas and CCS, but rejected them. The
ACE Rule rejected co-firing with natural gas primarily on grounds that
it was too costly in general, and especially for sources that have
limited or no access to natural gas. 84 FR 32545 (July 8, 2019). The
rule also concluded that generating electricity by co-firing natural
gas in a utility boiler would be an inefficient use of the gas when
compared to combusting it in a combustion turbine. Id. The ACE Rule
rejected CCS on grounds that it was too costly. Id. at 32548. The rule
identified the high capital and operating costs of CCS and noted the
fact that the IRC 45Q tax credit, as it then applied, would provide
only limited benefit to sources. Id. at 32548-49.
In addition, the ACE Rule interpreted CAA section 111 to preclude
States from allowing their sources to trade or average to demonstrate
compliance with their standards of performance. Id. at 32556-57.
B. Developments Undermining ACE Rule's Projected Emission Reductions
The EPA's first basis for proposing to repeal the ACE Rule is that
there is doubt that the rule would achieve even the limited emissions
reductions projected at the time of promulgation if it were implemented
now, and implementation could increase CO2
[[Page 33337]]
emissions instead. Thus, the EPA concludes that as a matter of the
Agency's policy judgment it is appropriate to repeal the rule and
evaluate whether other technologies qualify as the BSER given new
factual developments. This action is consistent with the Supreme
Court's instruction in FCC v. Fox Television Stations, Inc., 556 U.S.
502 (2009), where the Supreme Court explained that an agency issuing a
new policy ``need not demonstrate to a court's satisfaction that the
reasons for the new policy are better than the reasons for the old
one.'' Instead, ``it suffices that the new policy is permissible under
the statute, that there are good reasons for it, and that the agency
believes it to be better, which the conscious change of course
adequately indicates.'' Id. at 514-16 (emphasis in original; citation
omitted).
Two factors, taken together, undermine the ACE Rule's projected
emission reductions and create the risk that implementation of the ACE
Rule could increase--rather than reduce--CO2 emissions from
coal-fired EGUs. First, HRI technologies achieve only limited GHG
emission reductions. The ACE Rule projected that if States generally
applied the set of candidate technologies to their sources, the rule
would achieve a less-than-1-percent reduction in power-sector
CO2 emissions by 2030.\522\ The EPA now doubts that even
these minimal reductions would be achieved. The ACE Rule's projected
benefits were premised in part on a 2009 technical report by Sargent &
Lundy that evaluated the effects of HRI technologies. In 2023, Sargent
& Lundy issued an updated report which details that the HRI selected as
the BSER in the ACE Rule would bring fewer emissions reductions than
estimated in 2009. The 2023 report concludes that, with few exceptions,
HRI technologies are less effective at reducing CO2
emissions than assumed in 2009. And most sources had already optimized
application of HRIs, and so there are fewer opportunities to reduce
emissions than previously anticipated.
---------------------------------------------------------------------------
\522\ ACE Rule RIA 3-11, table 3-3.
---------------------------------------------------------------------------
Second, for a subset of sources, HRI are likely to cause a rebound
effect leading to an increase in GHG emissions for those sources for
the reasons explained in section X.D.5.a. The estimate of the rebound
effect was quite pronounced in the ACE Rule's own analysis--the rule
projected that it would increase CO2 emissions from power
plants in 15 States and the District of Columbia. Specifically, the EPA
prepared modeling projections to understand the impacts of the ACE
Rule. These projections assumed that, consistent with the rule, sources
would impose a small degree of efficiency improvements. The modeling
showed that the rule would not result in absolute emissions reductions
across all affected sources, and some would instead increase absolute
emissions. See EPA, IPM State-Level Emissions: EPAv6 November 2018
Reference Case, EPA-HQ-OAR-2017-0355-26720 (providing ACE reference
case); IPM State-Level Emissions: Illustrative ACE Scenario, EPA-HQ-
OAR-2017-0355-26724 (providing illustrative scenario).
Despite the fact that the ACE Rule was projected to increase
emissions in many States, these States were nevertheless obligated
under the rule to assemble detailed State plans that evaluated
available technologies and the performance of each existing coal-fired
power plant, as described in section IX.A of this preamble. For
example, the State was required to analyze the plant's ``annual
generation,'' ``CO2 emissions,'' ``[f]uel use, fuel price,
and carbon content,'' ``operation and maintenance costs,'' ``[h]eat
rates,'' ``[e]lectric generating capacity,'' and the ``timeline for
implementation,'' among other information. 84 FR 32581 (July 8, 2019).
This evaluation and the imposition of standards of performance was
mandated even though the State plan would lead to an increase rather
than decrease CO2 emissions.
In this context, the data undermining the ACE Rule's limited,
projected emission reductions along with the risk that implementation
of the rule could increase CO2 pollution raises doubts that
the HRI satisfies the statutory criteria to constitute the BSER for
this category of sources. The core element of the BSER analysis is
whether the emission reduction technology selected reduces emissions.
See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 441 (D.C. Cir.
1973) (noting ``counter productive environmental effects'' questioned
whether the BSER selected was in fact the ``best'').
The EPA's experience in implementing the ACE Rule reinforces these
concerns. After the ACE Rule was promulgated, one State drafted a State
plan that set forth a standard of performance that allowed the affected
source to increase its emission rate. The draft partial plan would have
applied to one source, the Longview Power, LLC facility, and would have
established a standard of performance, based on the State's
consideration of the ``candidate technologies,'' that was higher (i.e.,
less stringent) than the source's historical emission rate. Thus, the
draft plan would not have achieved any emission reductions from the
source, and instead would have allowed the source to increase its
emissions, if it was finalized.\523\
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\523\ West Virginia CAA Sec. 111(d) Partial Plan for Greenhouse
Gas Emissions from Existing Electric Utility Generating Units
(EGUs), https://dep.wv.gov/daq/publicnoticeandcomment/Documents/Proposed%20WV%20ACE%20State%20Partial%20Plan.pdf.
---------------------------------------------------------------------------
Because there is doubt that the minimal reductions projected by the
ACE Rule would be achieved, and because the rebound effect could lead
to an increase in emissions for many sources in many States, the EPA
concludes that it is appropriate to repeal the ACE Rule and reevaluate
the BSER for this category of sources.
C. Developments Showing That Other Technologies Are the BSER for This
Source Category
Since the promulgation of the ACE Rule in 2019, the factual
underpinnings of the rule have changed in several ways, and lead EPA to
propose that HRI are not the BSER for coal-fired power plants.
Along with changes in the anticipated reductions from HRI, it makes
sense for the EPA to reexamine the BSER because the costs of two
control measures, co-firing with natural gas and CCS, have fallen
substantially for sources with longer-term operating horizons such that
the EPA may determine that these measures satisfy the requirements for
the BSER for the source categories identified below. As noted, the ACE
Rule rejected natural gas co-firing as the BSER on grounds that it was
too costly and would lead to inefficient use of natural gas. But as
discussed in section X.D.2.b.ii of this preamble, the costs of natural
gas co-firing have substantially decreased, and the EPA is proposing
that the costs of co-firing 40 percent by volume natural gas are
reasonable for existing coal-fired EGUs in the medium-term subcategory,
i.e., units that plan to operate during, in general, the 2032 to 2040
period. In addition, the changed circumstances, including that natural
gas is available in greater amounts, and there are fewer coal-fired
EGUs, mitigates the concerns the ACE Rule identified about inefficient
use of natural gas. See section X.D.2.b.iii(B).
Similarly, the ACE Rule rejected CCS as the BSER on grounds that it
was too costly. But as discussed in section X.D.1.b.ii of this
preamble, the costs of CCS have substantially declined, partly because
of developments in the technology that have lowered capital costs, and
partly because the IRA extended and increased the IRC section 45Q tax
credit so that it defrays a higher
[[Page 33338]]
portion of the costs of CCS. Accordingly, for coal-fired EGUs that will
continue to operate past 2040, the EPA is proposing that the costs of
CCS, which have fallen to approximately $7-$12/MWh, are reasonable.
The reductions from these two technologies are substantial. For
long-term coal-fired steam generating units, the BSER of 90 percent
capture CCS results in substantial CO2 emissions reductions
amounting to emission rates that are 88.4 percent lower on a lb/MWh-
gross basis and 87.1 percent lower on a lb/MWh-net basis compared to
units without capture, as described in section X.D.4 of this preamble.
And for the BSER for medium-term units, 40 percent natural gas co-
firing achieves reductions of 16 percent, as described in section
X.D.2.b.iv of this preamble.
Given the availability of more effective, cost-reasonable
technology, the EPA concludes that HRIs are not the BSER for all coal-
fired EGUs.
The EPA is thus proposing to adopt a new policy and change its
regulatory scheme for coal-fired power plants. As discussed in section
X.C.3 of this preamble, the EPA is proposing to subcategorize coal-
fired power plants according to the time that they will continue to
operate. For sources in the imminent-term and near-term subcategories--
which include sources that, in general, have federally enforceable
commitments to permanently cease operations by 2032 or 2035,
respectively--the EPA is proposing that the BSER is routine methods of
operation and maintenance, with associated presumptive standards of
performance that do not permit an increased emission rate and are not
anticipated to have a rebound effect; and the EPA is soliciting comment
on whether co-firing some amount of natural gas should be part of the
BSER. For sources in the medium-term subcategory--which includes
sources that are not in the other subcategories and that have a
federally enforceable commitment to permanently cease operations by
2040--the EPA is proposing that the BSER is co-firing 40 percent by
volume natural gas. The EPA concludes this control measure is
appropriate because it achieves substantial reductions at reasonable
cost. In addition, the EPA believes that because a large supply of
natural gas is available, devoting part of this supply for fuel for a
coal-fired steam generating unit in place of a percentage of the coal
burned at the unit is an appropriate use of natural gas and will not
adversely impact the energy system, as described in section
X.D.2.b.iii(B) of this preamble.
For sources in the long-term subcategory--which includes sources
that do not have a federally enforceable commitment to permanently
cease operations by 2040--the EPA is proposing that the BSER is CCS
with 90 percent capture of CO2. The EPA believes that this
control measure is appropriate because it achieves substantial
reductions at reasonable cost, as described in section X.D.1.c of this
preamble.
The EPA is not proposing HRI as the BSER for any coal-fired EGUs.
As discussed in section X.D.5.a, the EPA does not consider HRIs an
appropriate BSER for the imminent-term and near-term subcategories
because these technologies would achieve few, if any, emissions
reductions and may increase emissions due to the rebound effect. The
EPA is proposing to reject HRI as the BSER for the medium-term and
long-term subcategories because HRI could also lead to a rebound
effect. Most importantly, changed circumstances show that co-firing
natural gas and CCS are available at reasonable cost, and will achieve
more GHG emissions reductions. Accordingly, the EPA believes that HRI
do not qualify as the BSER for any coal-fired EGUs, and that other
approaches meet the statutory standard. For these reasons, the EPA
proposes to repeal the ACE Rule.
D. Insufficiently Precise Degree of Emission Limitation Achievable From
Application of the BSER
The third independent reason why the EPA is proposing to repeal the
ACE Rule is that the rule did not identify with sufficient specificity
the BSER or the degree of emission limitation achievable through the
application of the BSER. Thus, States lacked adequate guidance on the
BSER they should consider and level of emission reduction that the
standards of performance must achieve. The ACE Rule determined the BSER
to be a suite of HRI ``candidate technologies,'' but did not identify
with specificity the degree of emission limitation States should apply
in developing standards of performance for their sources. As a result,
the ACE Rule conflicted with CAA section 111 and the implementing
regulations, and thus failed to provide States adequate guidance so
that they could ensure that their State plans were satisfactory and
approvable by the EPA.
CAA section 111 and the EPA's long-standing implementing
regulations establish a clear process for the EPA and States to
regulate emissions of certain air pollutants from existing sources.
``The statute directs EPA to (1) `determine[ ],' taking into account
various factors, the `best system of emission reduction which . . . has
been adequately demonstrated,' (2) ascertain the `degree of emission
limitation achievable through the application' of that system, and (3)
impose an emissions limit on new stationary sources that `reflects'
that amount.'' West Virginia v. EPA, 142 S. Ct. 2587, 2601 (2022)
(quoting 42 U.S.C. 7411(d)). Further, ``[a]lthough the States set the
actual rules governing existing power plants, EPA itself still retains
the primary regulatory role in Section 111(d) . . . [and] decides the
amount of pollution reduction that must ultimately be achieved.'' Id.
at 2602.
Once the EPA makes these determinations, the State must establish
``standards of performance'' for its sources that are based on the
degree of emission limitation that the EPA determines in the emissions
guidelines. CAA section 111(a)(1) makes this clear through its
definition of ``standard of performance'' as ``a standard for emissions
of air pollutants which reflects the degree of emission limitation
achievable through the application of the [BSER].'' After the EPA
determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission
limitation achievable from application of the BSER, ``the States then
submit plans containing the emissions restrictions that they intend to
adopt and enforce in order not to exceed the permissible level of
pollution established by EPA.'' 142 S. Ct. at 2602 (citing 40 CFR
60.23, 60.24; 42 U.S.C. 7411(d)(1)).
The EPA then reviews the plan and approves it if the standards of
performance are ``satisfactory,'' under CAA section 111(d)(2)(A). The
EPA's long-standing implementing regulations make clear that the EPA's
basis for determining whether the plan is ``satisfactory'' includes
that the plan must contain ``emission standards . . . no less stringent
than the corresponding emission guideline(s).'' 40 CFR 60.24(c). The
EPA's revised implementing regulations contain the same requirement. 40
CFR 60.24a(c). In addition, under CAA section 111(d)(1), in ``applying
a standard of performance to any particular source'' a State may
consider, ``among other factors, the remaining useful life of the
existing source to which such standard applies.'' This is also known as
the RULOF provision and is discussed in section XII.D.2.
In the ACE Rule, the EPA recognized that the CAA required it to
determine the BSER and identify the degree of emission limitation
achievable through application of the BSER. 84 FR 32537
[[Page 33339]]
(July 8, 2019). But the rule did not make those determinations. Rather,
the ACE Rule described the BSER as a list of ``candidate
technologies.'' And the rule described the degree of emission
limitation achievable by application of the BSER as ranges of
reductions from the HRI technologies. The rule thus shifted the
responsibility for determining the BSER and degree of emission
limitation achievable from the EPA to the States. Accordingly, the ACE
Rule did not meet the CAA section 111 requirement that the EPA
determine the BSER or the degree of emission limitation from
application of the BSER.
As described above, the ACE Rule identified the HRI in the form of
a list of seven ``candidate technologies,'' accompanied by a wide range
of percentage improvements to heat rate that these technologies could
provide. Indeed, for one of them, improved O&M practices (that is,
operation and management practices), the range was ``0 to >2%'', which
is effectively unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE
Rule was clear that this list was simply the starting point for a State
to calculate the standards of performance for its sources. That is, the
seven sets of technologies were ``candidate[s]'' that the State could,
but was not required to, apply and if the State did choose to apply one
or more of them, the State could do so in a manner that yielded any
percentage of heat rate improvement within the range that the EPA
identified, or even outside that range, if the State chose. Thus, as a
practical matter, the ACE Rule did not determine the BSER or any degree
of emission limitation from application of the BSER, and so States had
no guidance on how to craft approvable State plans. In this way, EPA
effectively abdicated its responsibilities, and directed each State to
determine for its sources what the BSER would be (that is, which HRI
technologies should be applied to the source and with what intensity),
and, based on that, what the degree of emission limitation achievable
by application of the BSER. See 84 FR 32537-38 (July 8, 2019).
The only constraints that the ACE Rule imposed on the States were
procedural ones, and those did not give the EPA any benchmark to
determine whether a plan could be approved or give the States any
certainty on whether their plan would be approved. As noted above, when
a State submitted its plan, it needed to show that it evaluated each
candidate technology for each source or group of sources, explain how
it determined the degree of emission limitation achievable, and include
data about the sources. But because the ACE Rule did not identify a
BSER or include a degree of emission limitation that the standards must
reflect, the States lacked specific guidance on how to craft adequate
standards of performance, and the EPA had no benchmark against which to
evaluate whether a State's submission was ``satisfactory'' under CAA
section 111(d)(2)(A). Thus, the EPA's review of State plans was
essentially a standardless exercise, notwithstanding the Agency's
longstanding view that it was ``essential'' that ``EPA review . . .
[state] plans for their substantive adequacy.'' 40 FR 53342-43
(November 17, 1975). In 1975, the EPA explained that it was not
appropriate to limit its review based ``solely on procedural criteria''
because otherwise ``states could set extremely lenient standards . . .
so long as EPA's procedural requirements were met.'' Id. at 53343.
Finally, the ACE Rule's approach to determining the BSER and degree
of emission limitation departed from prior emission guidelines under
CAA section 111(d), in which the EPA included a numeric degree of
emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977)
(limiting emission rate of acid mist from sulfuric acid plants to 0.25
grams per kilogram of acid); 44 FR 29828, 29829 (May 22, 1979)
(limiting concentrations of total reduced sulfur from most of the
subcategories of kraft pulp mills, such as digester systems and lime
kilns, to 5, 20, or 25 ppm over 12-hour averages); 61 FR 9905, 9919
(March 12, 1996) (limiting concentration of non-methane organic
compounds from solid waste landfills to 20 parts per million by volume
or 98-percent reduction). In the ACE Rule, the EPA did not grapple with
this change in position as required by FCC v. Fox Television Stations,
Inc., 556 U.S. 502 (2009), or explain why it was appropriate to provide
a boundless degree of emission limitation achievable in this context.
For this reason, the EPA proposes to repeal the ACE Rule. Its
failure to determine the BSER and the associated degree of emission
limitation achievable from application of the BSER deviated from CAA
section 111 and the implementing regulations. Without these
determinations, the ACE Rule lacked any benchmark that would guide the
States in developing their State plans, and by which the EPA could
determine whether those State plans were satisfactory.
E. ACE Rule's Preclusion of Emissions Trading or Averaging
While not an independent basis for repeal, the ACE Rule also
interpreted CAA section 111(d) to bar States from allowing emissions
trading or averaging among their sources in all cases, which further
shows that the ACE Rule misconstrued section 111(d) and the appropriate
roles for the EPA and for the States. A trading program might allocate
allowances authorizing a particular level of emissions; a facility
would not need to reduce its emissions so long as it traded for
sufficient allowances. And an averaging program, for example, might
require a group of facilities to reduce their average emissions to a
particular level. So long as some facilities reduced their emissions
sufficiently below that level, it would not be necessary for every
facility to reduce its emissions. Cf. Chevron U.S.A., Inc. v. Natural
Res. Def. Council, Inc., 467 U.S. 837, 863 n.37 (1984) (explaining the
` ``bubble' or `netting' concept). CAA section 111(d) accords States
discretion in developing State plans, and allows States to include
compliance flexibilities like trading or averaging in circumstances the
EPA has determined are appropriate, as long as the plan achieves
equivalent emissions reductions to the EPA's emission guidelines. The
ACE Rule's legal interpretation that CAA section 111(d) always
precludes the State from adopting those flexibilities was incorrect.
Under CAA section 111, EPA promulgates emission guidelines that
identify the degree of emission limitation achievable through the
application of the BSER as determined by the Administrator. Each State
must then ``submit to the Administrator a plan'' to achieve the degree
of emission limitation identified by EPA. 42 U.S.C. 7411(d)(a). That
plan must ``establish[ ] standards of performance for any existing
source'' that emits certain air pollutants, and also ``provide[ ] for
the implementation and enforcement of such standards of performance.''
Under CAA section 111(a)(1), a ``standard of performance'' is defined
as ``a standard for emissions of air pollutants which reflects the
degree of emission limitation achievable through the application of the
[BSER].'' Although such standards of performance must ``reflect[ ] the
degree of emission limitation achievable through the application of the
[BSER],'' 42 U.S.C. 7411(a)(1), States need not compel regulated
sources to adopt the particular components of the BSER itself.
The ACE Rule interpreted CAA section 111(a)(1) and (d) to preclude
States from allowing their sources to trade or average to demonstrate
compliance with their standards of performance. 84 FR 32556-57 (July 8,
[[Page 33340]]
2019). The ACE Rule based this interpretation on its view that CAA
section 111 limits the type of ``system'' that the EPA may select as
the BSER to ``measures that apply at and to an individual source and
reduce emissions from that source.'' Id. at 32523-24. The ACE Rule also
concluded that the compliance measures the States include in their
plans ``should correspond with the approach used to set the standard in
the first place,'' and therefore must also be limited to measures that
apply at and to an individual source and reduce emissions from that
source. Id. at 32556.
In its recently published notice of proposed rulemaking to amend
the CAA section 111(d) implementing regulations, the EPA has proposed
to determine that the ACE Rule's legal interpretation as to the type of
``system'' that may be selected as a BSER, and the universal
prohibition of trading and averaging, was incorrect. ``Implementing
Regulations under 40 CFR part 60 Subpart Ba Adoption and Submittal of
State Plans for Designated Facilities: Proposed Rule,'' 87 FR 79176,
79207-79208 (December 23, 2022). As discussed in that document, no
provision in CAA section 111(d), by its terms, precludes States from
having flexibility in determining which measures will best achieve
compliance with the EPA's emission guidelines.
Specifically, the plain language of section 111(d) does not
affirmatively bar States from considering averaging and trading as a
compliance measure where appropriate for a particular emission
guideline. Under section 111(d)(1), States must ``establish[ ],''
``implement[ ],'' and ``enforce[ ]'' ``standards of performance for any
existing source.'' A State plan that specifies what each existing
source must do to satisfy plan requirements is naturally characterized
as establishing ``standards of performance for [each] existing
source,'' even if measures like trading and averaging are identified as
potential means of compliance. Trading and averaging programs may be
appropriate as a policy matter as well because, in some circumstances,
they can help to ensure that costs are reasonable by enabling market
force to identify the facilities whose emissions can be reduced most
cost-effectively. Nothing in the text of section 111 precludes States
from considering a source's acquisition of allowances in implementing
and enforcing a standard of performance for that particular source, so
long as the State plan achieves the required level of emission
reductions.
Further supporting this statutory interpretation, section 111(d)
requires a ``procedure similar to that provided by Section 7410.''
Consideration of the section 110 framework reinforces the absence of
any mandate that States consider only compliance measures that apply at
and to an individual source. ``States have `wide discretion' in
formulating their plans'' under section 110. Alaska Dep't of Envtl.
Conservation v. EPA, 540 U.S. 461, 470 (2004) (citation omitted); see
Union Elec. Co. v. EPA, 427 U.S. 246, 269 (1976) (``Congress plainly
left with the States, so long as the national standards were met, the
power to deter-mine which sources would be burdened by regulation and
to what extent.''); Train v. Natural Res. Def. Council, Inc., 421 U.S.
60, 79 (1975) (``[S]o long as the ultimate effect of a State's choice
of emission limitations is compliance with the national standards for
ambient air, the State is at liberty to adopt whatever mix of emission
limitations it deems best suited to its particular situation.'').
Exercising that discretion, States have included measures that do not
apply at or to a source in their section 1410 plans. For example,
States have employed NOX and SO2 trading programs
to comply with section 7410(a)(2)(D)(i)(I), the ``Good Neighbor
Provision.'' Section 110 thus does not distinguish between measures
that do or don't apply at or to a source for compliance, and there is
no sound reason to read section 111's comparably broad language
differently.
Such flexibility is consistent with the framework of cooperative
federalism that CAA section 111(d) establishes, which vests States with
substantial discretion. As the U.S. Supreme Court has explained, CAA
section 111(d) ``envisions extensive cooperation between federal and
state authorities, generally permitting each State to take the first
cut at determining how best to achieve EPA emissions standards within
its domain.'' American Elec. Power Co. v. Connecticut, 564 U.S. 410,
428 (2011) (citations omitted).
To be sure, as discussed above, EPA retains an important role in
reviewing State plans for adequacy. Under 111(d), each State must
``submit to the Administrator a plan'' to achieve the degree of
emission limitation identified by EPA. That plan must ``establish[ ]
standards of performance for any existing source for [the] air
pollutant'' and also ``provide[ ] for the implementation and
enforcement of such standards of performance.'' Id. If a State elects
not to submit a plan, or submits a plan that EPA does not find
``satisfactory,'' EPA must promulgate a plan that establishes Federal
standards of performance for the State's existing sources. 42 U.S.C.
7411(d)(2)(A). Thus, the flexibility that CAA section 111(d) grants to
States in adopting measures for their State plans is not unfettered. As
the Supreme Court stated in West Virginia, ``The Agency, not the
States, decides the amount of pollution reduction that must ultimately
be achieved.'' 142 S. Ct. at 2602. State plans then must contain
``emissions restrictions that they intend to adopt and enforce in order
not to exceed the permissible level of pollution established by EPA.''
Id. Thus, EPA bears the burden of ensuring that the permissible level
of pollution is not exceeded by any State plan. When a compliance
flexibility compromises the ability of the State plan to achieve the
necessary emission reductions, then the EPA may reasonably preclude
reliance on such measures, or otherwise conclude that the State plan is
not satisfactory.
Thus, the EPA proposed to disagree with the ACE Rule's conclusion
that State plan compliance measures must always apply at and to an
individual source and reduce emissions of that source. As noted in
section V.B.6, the U.S. Supreme Court in West Virginia v. EPA, 142 S.
Ct. 2587 (2022), did not address the scope of the States' compliance
flexibilities in developing State plans. The Court also declined to
address whether CAA section 111 limits the type of ``system'' the EPA
may consider to measures that apply substantially at and to an
individual source. See id. at 2615.
For these reasons, in its notice of proposed rulemaking to amend
the CAA section 111(d) implementing regulations, EPA proposes to
interpret CAA section 111 as permitting each State to adopt measures
that allow its sources to meet their emissions limits in the aggregate,
when the EPA determines, in any particular emission guideline, that it
is appropriate to do so, given, inter alia, the pollution, sources, and
standards of performance at issue. Thus, it is the EPA's proposed
position that CAA 111(d) authorizes the EPA to approve State plans
under particular emission guidelines that achieve the requisite
emission limitation through the aggregate reductions from those
sources, including through trading or averaging where appropriate for a
particular emission guideline and consistent with the intended
environmental outcomes of the guideline. As discussed in section XII.E,
the EPA is proposing to allow trading and averaging under the proposed
emission guidelines and requesting comment on whether and how such
compliance mechanisms could be
[[Page 33341]]
implemented to ensure equivalency with the emission reductions that
would be achieved if each affected source was achieving its applicable
standard of performance.
The ACE Rule's flawed legal interpretation that CAA section 111(d)
universally precludes States from emissions trading is incorrect and
adds to EPA's rationale for proposing to repeal the rule.
X. Proposed Regulatory Approach for Existing Fossil Fuel-Fired Steam
Generating Units
A. Overview
In this section of the preamble, the EPA explains the basis for its
proposed emission guidelines for GHG emissions from existing fossil
fuel-fired steam generating units for States' use in plan development.
This includes proposing different subcategories of designated
facilities, the BSER for each subcategory, and the degree of emission
limitation achievable by application of each proposed BSER. The EPA is
proposing subcategories for steam generating units based on the type
and amount of fossil fuel (i.e., coal, oil, and natural gas) fired in
the unit.
For existing coal-fired steam generating units that plan to operate
in the long-term, the EPA is proposing CCS with 90 percent capture as
BSER, based on a review of emission control technologies detailed
further in this section of the preamble and accompanying TSDs,
available in the docket. The EPA is soliciting comment on a range of
maximum capture rates (90 to 95 percent or greater) and, to potentially
account for the amount of time the capture equipment operates relative
to operation of the steam generating unit, a slightly lower achievable
degree of emission limitation (75 to 90 percent reduction in average
annual emission rate, defined in terms of pounds of CO2 per
unit of generation).
During the EPA's engagement with stakeholders to inform this
proposed rule, industry stakeholders noted that many coal-fired sources
have plans to permanently cease operation in the coming years, and that
GHG control technologies might not be cost reasonable for those units
operating on shorter timeframes. These stakeholders recommended that
the emission guidelines account for industry plans for permanently
ceasing operation of coal-fired steam generating units by establishing
a ``subcategory pathway'' with less stringent requirements.
Consistent with this stakeholder input, the EPA proposes to provide
subcategories for coal-fired steam generating units planning to
permanently cease operations in the 2030s. The EPA recognizes that the
cost reasonableness of GHG control technology options differ depending
on a coal-fired steam generating unit's expected operating time
horizon. Accordingly, the EPA is proposing to divide the subcategory
for coal-fired units into additional subcategories based on operating
horizon (i.e., dates for electing to permanently cease operation) and,
for one of those subcategories, load level (i.e., annual capacity
factor), with a separate BSER and degree of emission limitation
corresponding to each subcategory. For long-term coal-fired units, the
EPA is proposing that CCS satisfies the BSER criteria, as noted above.
For medium-term units, the EPA is proposing natural gas co-firing at 40
percent of annual heat input as BSER. The EPA is soliciting comment on
the percent of natural gas co-firing from 30 to 50 percent and the
degree of emission limitation defined by a reduction in emission rate
from 12 to 20 percent. For imminent-term and near-term coal-fired steam
generating units, the EPA is proposing a BSER of routine methods of
operation and maintenance. Because of differences in performance
between units, the EPA is proposing to determine the associated degree
of emission limitation as no increase in emission rate. For imminent-
term and near-term coal-fired steam generating units, the EPA is also
soliciting comment on a potential BSER based on low levels of natural
gas co-firing.
For natural gas- and oil-fired steam generating units, the EPA is
proposing a BSER of routine methods of operation and maintenance and a
degree of emission limitation of no increase in emission rate. Further,
the EPA is proposing to divide subcategories for oil- and natural gas-
fired units based on capacity and, in some cases, geographic location.
Because natural gas- and oil-fired steam generating units with similar
annual capacity factors perform similarly to one another, the EPA is
proposing presumptive standards of performance of 1,300 lb
CO2/MWh-gross for base load units (i.e., those with annual
capacity factors greater than 45 percent) and 1,500 lb CO2/
MWh-gross for intermediate load units (i.e., those with annual capacity
factors between 8 and 45 percent). Because natural gas- and oil-fired
steam generating units with low load have large variations in emission
rate, the EPA is not proposing a BSER or degree of emission limitation
for those units in this action. However, the EPA is soliciting comment
on a potential BSER of ``uniform fuels'' and degree of emission
limitation defined on a heat input basis by 120 to 130 lb
CO2/MMBtu for low load natural gas-fired steam generating
units and 150 to 170 lb CO2/MMBtu for low load oil-fired
steam generating units. Also, because non-continental oil-fired steam
generating units operate at intermediate and base load, and because
there are relatively few of those units for which to define a limit on
a fleet-wide basis, the EPA is proposing a degree of emission
limitation for those units of no increase in emission rate and
presumptive standards based on unit-specific emission rates, as
detailed in section XII of this preamble. The EPA is soliciting comment
on ranges of annual capacity factors to define the thresholds between
the load levels and ranges in the degrees of emission limitation, as
specified in section X.E of this preamble.
It should be noted that the EPA is proposing a compliance date of
January 1, 2030, as discussed in section XII of this preamble on State
plan development.
The remainder of this section is organized into the following
subsections. Subsection B describes the proposed applicability
requirements for existing steam generating units. Subsection C provides
the explanation for the proposed subcategories. Subsection D contains,
for coal-fired steam generating units, a summary of the systems
considered for the BSER, detailed discussion of the systems and other
options considered, and explanation and justification for the
determination of BSER and degree of emission limitation. Subsection E
contains, for natural gas- and oil-fired steam generating units, a
summary of the systems considered for the BSER, detailed discussion of
the systems and other options considered, and explanation and
justification for the determination of BSER and degree of emission
limitation.
B. Applicability Requirements for Existing Fossil Fuel-Fired Steam
Generating Units
For the emission guidelines, the EPA is proposing that a designated
facility \524\ is any fossil fuel-fired electric utility steam
generating unit (i.e., utility boiler or IGCC unit) that: (1) Was in
operation or had commenced construction on or
[[Page 33342]]
before January 8, 2014; \525\ (2) serves a generator capable of selling
greater than 25 MW to a utility power distribution system; and (3) has
a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of
fossil fuel (either alone or in combination with any other fuel).
Consistent with the implementing regulations, the term ``designated
facility'' is used throughout this preamble to refer to the sources
affected by these emission guidelines.\526\ For this action, consistent
with prior CAA section 111 rulemakings concerning EGUs, the term
``designated facility'' refers to a single EGU that is affected by
these emission guidelines. The rationale for this proposal concerning
applicability is the same as that for 40 CFR part 60, subpart TTTT (80
FR 64543-44; October 23, 2015). The EPA incorporates that discussion by
reference here.
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\524\ The term ``designated facility'' means ``any existing
facility . . . which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
\525\ Under CAA section 111, the determination of whether a
source is a new source or an existing source (and thus potentially a
designated facility) is based on the date that the EPA proposes to
establish standards of performance for new sources.
\526\ The EPA recognizes, however, that the word ``facility'' is
often understood colloquially to refer to a single power plant,
which may have one or more EGUs co-located within the plant's
boundaries.
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Section 111(a)(6) of the CAA defines an ``existing source'' as
``any stationary source other than a new source.'' Therefore, the
emission guidelines would not apply to any EGUs that are new after
January 8, 2014, or reconstructed after June 18, 2014, the
applicability dates of 40 CFR part 60, subpart TTTT. Moreover, because
the EPA is now proposing revised standards of performance for coal-
fired steam generating units that undertake a modification, a modified
source would be considered ``new,'' and therefore not subject to these
emission guidelines, if the modification occurs after the date this
proposal is published in the Federal Register. Any source that has
modified prior to that date would be considered an existing source that
is subject to these emission guidelines.
In addition, the EPA is proposing to include in the applicability
requirements of the emission guidelines the same exemptions as
discussed for 40 CFR part 60, subpart TTTT in section VII.E.1 of this
preamble. Designated EGUs that may be excluded from a State plan are:
(1) Units that are subject to 40 CFR part 60, subpart TTTT, as a result
of commencing a qualifying modification or reconstruction; (2) steam
generating units subject to a federally enforceable permit limiting
net-electric sales to one-third or less of their potential electric
output or 219,000 MWh or less on an annual basis and annual net-
electric sales have never exceeded one-third or less of their potential
electric output or 219,000 MWh; (3) non-fossil fuel units (i.e., units
that are capable of deriving at least 50 percent of heat input from
non-fossil fuel at the base load rating) that are subject to a
federally enforceable permit limiting fossil fuel use to 10 percent or
less of the annual capacity factor; (4) CHP units that are subject to a
federally enforceable permit limiting annual net-electric sales to no
more than either 219,000 MWh or the product of the design efficiency
and the potential electric output, whichever is greater; (5) units that
serve a generator along with other steam generating unit(s), where the
effective generation capacity (determined based on a prorated output of
the base load rating of each steam generating unit) is 25 MW or less;
(6) municipal waste combustor units subject to 40 CFR part 60, subpart
Eb; (7) commercial or industrial solid waste incineration units that
are subject to 40 CFR part 60, subpart CCCC; or (8) EGUs that derive
greater than 50 percent of the heat input from an industrial process
that does not produce any electrical or mechanical output or useful
thermal output that is used outside the affected EGU. The EPA solicits
comment on the proposed definition of ``designated facility'' and
applicability exemptions for fossil fuel-fired steam generating units.
The exemptions listed above at (4), (5), (6), and (7) are among the
current exemptions at 40 CFR 60.5509(b), as discussed in section
VII.E.1 of this preamble. The exemptions listed above at (2), (3), and
(8) are exemptions the EPA is proposing to revise for 40 CFR part 60,
subpart TTTT, and the rationale for proposing the exemptions is in
section VII.E.1 of this preamble. For consistency with the
applicability requirements in 40 CFR part 60, subpart TTTT, we are
proposing these same exemptions for the applicability of the emission
guidelines.
The EPA is, in general, proposing the same emission guidelines for
fossil fuel-fired steam generating units in non-continental areas
(i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the
Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non-
contiguous areas (non-continental areas and Alaska) as the EPA is
proposing for comparable units in the contiguous 48 States. However,
units in non-continental and non-contiguous areas operate on small,
isolated electric grids, may operate differently from units in the
contiguous 48 States, and may have limited access to certain components
of the proposed BSER due to their uniquely isolated geography or
infrastructure. Therefore, the EPA is soliciting comment on the
proposed BSER and degrees of emission limitation for units in non-
continental and non-contiguous areas, and the EPA is soliciting comment
on whether those units in non-continental and non-contiguous areas
should be subject to different, if any, requirements.
The EPA notes that existing IGCC units are included in the proposed
applicability requirements and that, in section X.C.1 of this preamble,
the EPA is proposing to include those units in the subcategory of coal-
fired steam generating units. IGCC units gasify coal or solid fossil
fuel (e.g., pet coke) to produce syngas (a mixture of carbon monoxide
and hydrogen), and either burn the syngas directly in a combined cycle
unit or use a catalyst for water-gas shift (WGS) to produce a pre-
combustion gas stream with a higher concentration of CO2 and
hydrogen, which can be burned in a hydrogen turbine combined cycle
unit. As described in section X.D of this preamble, the proposed BSER
for coal-fired steam generating units includes co-firing natural gas
and CCS, depending on their operating horizon. The few IGCC units that
now operate in the U.S. either burn natural gas exclusively--and as
such operate as natural gas combined cycle units--or in amounts near to
the 40 percent level of the natural gas co-firing BSER. Additionally,
IGCC units are suitable for pre-combustion CO2 capture.
Because the CO2 concentration in the pre-combustion gas,
after WGS, is high relative to coal-combustion flue gas, pre-combustion
CO2 capture for IGCC units can be performed using either an
amine-based capture process or a physical absorption capture process.
For these reasons, the EPA is not proposing to distinguish IGCC units
from other coal-fired steam generating EGUs, so that the BSER of co-
firing for medium-term coal-fired units and CCS for long-term coal-
fired units apply to IGCC units.\527\
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\527\ For additional details on pre-combustion CO2
capture, please see the GHG Mitigation Measures for Steam Generating
Units TSD.
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C. Subcategorization of Fossil Fuel-Fired Steam Generating Units
Steam generating units can have a broad range of technical and
operational differences. Based on these differences, they may be
subcategorized, and different BSER and degrees of emission limitation
may be applicable to different subcategories. Subcategorizing allows
for determining the most appropriate
[[Page 33343]]
control requirements for a given class of steam generating unit.
Therefore, the EPA is proposing subcategories for steam generating
units based on fossil fuel type, operating horizon and load level, and
is proposing different BSER and degrees of emission limitation for
those different subcategories. The EPA notes that in section XII.B of
this preamble comment is solicited on the compliance deadline (i.e.,
January 1, 2030), for imminent-term and near-term coal-fired steam
generating units, and different subcategories of natural gas- and oil-
fired steam generating units.
1. Subcategorization by Fossil Fuel Type
In this action, the EPA is proposing definitions for subcategories
of existing fossil fuel-fired steam generating units based on the type
and amount of fossil fuel used in the unit. The subcategory definitions
proposed for these emission guidelines are based on the definitions in
40 CFR part 63, subpart UUUUU, and using the fossil fuel definitions in
40 CFR part 60, subpart TTTT.
A coal-fired steam generating unit is an electric utility steam
generating unit or IGCC unit that meets the definition of ``fossil
fuel-fired'' and that burns coal for more than 10.0 percent of the
average annual heat input during the 3 calendar years prior to the
proposed compliance deadline (i.e., January 1, 2030), or for more than
15.0 percent of the annual heat input during any one of those calendar
years, or that retains the capability to fire coal after December 31,
2029.
An oil-fired steam generating unit is an electric utility steam
generating unit meeting the definition of ``fossil fuel-fired'' that is
not a coal-fired steam generating unit and that burns oil for more than
10.0 percent of the average annual heat input during the 3 calendar
years prior to the proposed compliance deadline (i.e., January 1,
2030), or for more than 15.0 percent of the annual heat input during
any one of those calendar years, and that no longer retains the
capability to fire coal after December 31, 2029.
A natural gas-fired steam generating unit is an electric utility
steam generating unit meeting the definition of ``fossil fuel-fired''
that is not a coal-fired or oil-fired steam generating unit and that
burns natural gas for more than 10.0 percent of the average annual heat
input during the 3 calendar years prior to the proposed compliance
deadline (i.e., January 1, 2030), or for more than 15.0 percent of the
annual heat input during any one of those calendar years, and that no
longer retains the capability to fire coal after December 31, 2029.
2. Subcategorization of Natural Gas- and Oil-Fired Steam Generating
Units by Load Level
The EPA is also proposing additional subcategories for oil-fired
and natural gas-fired steam generating units, based on load levels:
``low'' load, defined by annual capacity factors less than 8 percent;
``intermediate'' load, defined by annual capacity factors greater than
or equal to 8 percent and less than 45 percent; and ``base'' load,
defined by annual capacity factors greater than or equal to 45 percent.
In addition, the EPA is soliciting comment on a range from 5 to 20
percent to define the threshold value between low and intermediate load
and a range from 40 to 50 percent to define the threshold value between
intermediate and base load. Because non-continental oil-fired units may
operate differently, the EPA is proposing a separate subcategory for
intermediate and base load non-continental oil-fired units. The
rationale for the proposed load thresholds and other subcategories is
detailed in the description of the BSER for oil- and natural gas-fired
steam generating units in section X.E of this preamble.
3. Subcategorization of Coal-Fired Steam Generating Units by Operating
Horizon and Load Level
The EPA is proposing CCS with 90 percent capture as BSER for
existing coal-fired steam generating units that will operate in the
long-term (i.e., those that intend to operate on or after January 1,
2040), as detailed in section X.D of this preamble. CCS is adequately
demonstrated at coal-fired steam generating units, is cost reasonable,
achieves meaningful reductions in GHG emissions, and meets the other
criteria for the BSER. The EPA is soliciting comment on a range of
maximum capture rates (90 to 95 percent or greater) and, to potentially
account for the amount of time the capture equipment operates relative
to operation of the steam generating unit, a slightly lower achievable
degree of emission limitation (75 to 90 percent reduction in average
annual emission rate, defined in terms of pounds of CO2 per
unit of generation).
During the EPA's engagement with stakeholders to inform this
proposed rule, industry commenters to the pre-proposal docket noted
that many sources have plans to permanently cease operation in the
coming years, and that GHG control technologies might not be cost
reasonable for those units operating on shorter timeframes. Further,
industry stakeholders recommended that the emission guidelines account
for industry plans for permanently ceasing operation of coal-fired
steam generating units by establishing a ``subcategory pathway.''
Specifically, industry stakeholders requested that, ``[The] EPA should
provide a subcategory pathway for units to decommission/repower into
the early 2030s, which would include enforceable shutdown obligations,
as part of an approach to existing unit guidelines.'' The stakeholders
cited, as a precedent, the EPA's creation of--
targeted subcategories for unit closures in other contexts, most
notably the cessation of coal subcategory in the 2020 Clean Water
Act (CWA) steam electric effluent guidelines . . . that allows for
decommissioning/repowering by December 31, 2028. This subcategory
allows those facilities that have already filed closure commitments
to continue on a path to decommission/repower these assets without
installing additional control equipment that could extend the lives
of these units to support cost recovery.
EPA-HQ-OAR-2022-0723-0024. In subsequent comment, industry
stakeholders reiterated that, ``[The] EPA should proactively include a
subcategory that allows for units to opt-in to a federally enforceable
retirement commitment as part of compliance with regulations for
existing sources under CAA section 111(d).'' EPA-HQ-OAR-2022-0723-0038.
Thus, industry stakeholders recommended that EPA allow existing sources
that are on a path to near term retirement to continue on that path
without having to install additional control equipment.
The proposed emission guidelines are aligned with this
recommendation. Many fossil fuel-fired steam generating units have
plans to cease operations, are part of utilities with commitments to
net zero power by certain dates, or are in States or localities with
commitments to net zero power by certain dates. Over one-third of
existing coal-fired steam generating capacity has planned to cease
operation by 2032, and approximately half of the capacity has planned
to cease operations by 2040.\528\ These plans are part of the industry
trend, described in section IV.F and IV.I, in which owners and
operators of the nation's coal fleet, much of it aging, are replacing
their units with natural gas combustion turbines and, increasingly,
renewable energy.
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\528\ See the Power Sector Trends TSD.
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As industry stakeholders have pointed out, in previous rulemakings,
the EPA has allowed coal-fired EGUs with plans to voluntarily cease
operations in the near future to continue with their plans without
having to install pollution control equipment. In addition to the 2020
CWA steam electric
[[Page 33344]]
effluent guidelines these stakeholders cite, the EPA has also approved
regional haze State implementation plans in which coal-fired EGUs that
voluntarily committed to cease operations by a certain date were not
subject to more stringent controls.\529\
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\529\ See, e.g., 76 FR 12651, 12660-63 (March 8, 2011) (best
available retrofit technology requirements for Oregon source based
on enforceable retirement that were to be made federally enforceable
in state implementation plan).
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The EPA proposes to take the approach requested by industry
stakeholders in this rulemaking. The EPA recognizes that the cost
reasonableness of GHG control technology options differ depending on a
coal-fired steam generating unit's expected operating time horizon.
Certain technologies that are cost reasonable for EGUs that intend to
operate for the long term are less cost reasonable for EGUs with
shorter operating horizons because of shorter amortization periods and,
for CCS, less time to utilize the IRC section 45Q tax credit.
Accordingly, the EPA is proposing to divide the subcategory for
coal-fired units into additional subcategories based on operating
horizon (i.e., dates for electing to permanently cease operation) and,
for one of those subcategories, load level (i.e., annual capacity
factor), with a separate BSER and degree of emission limitation
corresponding to each subcategory. Coal-fired steam generating units
would be able to opt into these subcategories if they elect to commit
to permanently ceasing operations by a certain date (and, in the case
of one subcategory, elect to commit to an annual capacity factor
limitation), and also elect to make such commitments federally
enforceable and continuing by including them in the State plan.
Specifically, the EPA is proposing four subcategories for steam
generating units by operating horizon (i.e., enforceable commitments to
permanently cease operations) and, in one case, by load level (i.e.,
annual capacity factor) as well. ``Imminent-term'' steam generating
units are those that (1) Have elected to commit to permanently cease
operations prior to January 1, 2032, and (2) elect to make that
commitment federally enforceable and continuing by having it included
in the State plan.\530\ ``Near-term'' steam generating units are those
that (1) Have elected to commit to permanently cease operations by
December 31, 2034, as well as to adopt an annual capacity factor limit
of 20 percent, and (2) elect to make both conditions federally
enforceable and continuing by having them included in the State plan.
``Medium-term'' steam generating units are those that (1) Operate after
December 31, 2031, (2) have elected to commit to permanently cease
operations prior to January 1, 2040, (3) elect to make that commitment
federally enforceable and continuing by having it included in the State
plan, and (4) do not meet the definition of near-term units. ``Long-
term'' steam generating units are those that have not elected to commit
to permanently cease operations prior to January 1, 2040. Details
regarding the implementation of subcategories in State plans are
available in section XII.D of this preamble.
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\530\ Operating conditions that are within the control of a
source must, under a range of CAA programs, be made federally
enforceable in order for a source to rely on them as the basis for a
less stringent standard. See, e.g., 76 FR 12651, 12660-63 (March 8,
2011) (best available retrofit technology requirements for Oregon
source based on enforceable retirement that were to be made
federally enforceable in state implementation plan); Guidance on
Regional Haze State Implementation Plans for the Second
Implementation Period at 34, EPA-457/B-19-003, August 2019 (to the
extent a state relies on an enforceable shutdown date for a
reasonable progress determination, that measure would need to be
included in the SIP and/or be federally enforceable); 84 FR 32520,
32558 (July 8, 2019) (to the extent a state relies on a source's
retirement date for a standard of performance under 111(d), that
date must be included in the state plan and will thus be made
federally enforceable); 87 FR 79176, 79200-01 (December 23, 2022)
(proposed revisions to CAA section 111(d) implementing regulations
would require States to include operating conditions, including
retirements, in their state plans whenever the state seeks to rely
on that operating condition as the basis for a less stringent
standard).
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The EPA is proposing the imminent-term subcategory based on a 2-
year operating horizon from the proposed compliance deadline (January
1, 2030, see section XII.B for additional details). This proposed
subcategory is designed to accommodate units with operating horizons
short enough that no additional CO2 control measures would
be cost reasonable. The EPA is proposing the near-term subcategory to
provide an alternative option for units that intend to operate for a
slightly longer horizon but as peaking units, i.e., that intend to run
at lower load levels. The load level of 20 percent for the near-term
subcategory is based on spreading an average 2 years of generation
(i.e., 50 percent in each year, a typical load level) that would occur
under the imminent-term subcategory over the 5-year operating horizon
of the near-term subcategory. The EPA also solicits comment on whether
the existence of the near-term subcategory makes the imminent-term
subcategory unnecessary. More specifically, the EPA requests comment on
the potential to remove the imminent-term subcategory, which as
proposed includes coal-fired steam generating units that have elected
to commit to permanently cease operations prior to January 1, 2032. The
EPA is considering an option in which these units would instead be
included in the near-term subcategory (units that have elected to
commit to permanently cease operations before January 1, 2035 and
commit to adopt an annual capacity factor limit of 20 percent) or the
medium-term subcategory (units that have elected to commit to
permanently cease operations before January 1, 2040 and that are not
near-term units). The EPA further requests comment on an alternative,
modified approach for units in the imminent-term subcategory that could
take into account how units intending to cease operations operate in
practice in the period leading up to such cessation. For instance, in
their last few years of operation, those units may operate less than
they have historically operated, lowering their total CO2
mass emissions, but at the same time raising their emission rate
(because lower utilization may result in lower efficiency). The EPA
solicits comment on whether it would be appropriate for the imminent-
term units' standards of performance to reflect the reduced utilization
and higher emission rates through the use of an annual mass emission
limitation. Such a limitation would account for lower utilization, but
also allow greater flexibility with regard to hourly emission rate.
The EPA is proposing the 10-year operating horizon (i.e., January
1, 2040) as the threshold between medium-term and long-term
subcategories because long-term units will have a longer amortization
period and may be better able to fully utilize the IRC section 45Q tax
credit. For the analysis of BSER costs of CCS for long-term units, the
EPA assumes a 12-year amortization period as this is commensurate with
the time period the IRC section 45Q tax credit would be available.
Based on the cost analysis performed under that assumption, the EPA is
proposing the costs of CCS for long-term coal-fired units are
reasonable, as detailed in section X.D.1.a.ii of this preamble. To
support the 10-year operating horizon threshold, the costs for a 10-
year amortization period are shown here. For a 10-year amortization
period, assuming a 50 percent capacity factor, costs of CCS for a
representative unit are $31/ton of CO2 reduced or $27/MWh of
generation. Assuming a 70 percent capacity factor, costs of CCS for a
representative unit are $6/ton of CO2
[[Page 33345]]
reduced or $5/MWh of generation. For the population of units planning
to operate on or after January 1, 2030, the fleet average costs
assuming a 50 percent capacity factor are $24/ton of CO2
reduced or $22/MWh. For the population of units planning to operate on
or after January 1, 2030, the fleet average costs assuming a 70 percent
capacity factor are -$3/ton of CO2 reduced or -$2/MWh. Costs
vary depending on capacity factor assumptions, but are in either case
generally comparable to the costs detailed in section
VII.F.3.b.iii(B)(5) of this preamble of other controls on EGUs ($10.60
to $29.00/MWh) and less than the costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas source category of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015). The EPA is
soliciting comment on the dates and load levels used to define the
coal-fired subcategories and is seeking data and analysis on the impact
of those alternative dates and load levels on the compliance
requirements. As noted in section X.D.1.a.ii(C) of this preamble, the
costs for CCS may be reasonable for units with amortization periods as
short as 8 years. Therefore, the EPA is specifically soliciting comment
on an operating horizon of between 8 and 10 years (i.e., January 1,
2038, to January 1, 2040) to define the date for the threshold between
medium-term and long-term coal-fired steam generating units.
4. Legal Basis for Subcategorization
As noted in section V of this preamble, the EPA has broad authority
under CAA section 111(d) to identify subcategories. As also noted in
section V, the EPA's authority to ``distinguish among classes, types,
and sizes within categories,'' as provided under CAA section 111(b)(2)
and as we interpret CAA section 111(d) to provide as well, generally
allows the Agency to place types of sources into subcategories when
they have characteristics that are relevant to the controls that the
EPA may determine to be the BSER for those sources. One element of the
BSER is cost reasonableness. See CAA section 111(d)(1) (requiring the
EPA, in setting the BSER, to ``tak[e] into account the cost of
achieving such reduction''). As noted in section V, the EPA's long-
standing regulations under CAA section 111(d) explicitly recognize that
subcategorizing may be appropriate for sources based on the ``costs of
control.'' \531\ Subcategorizing on the basis of operating horizon is
consistent with a central characteristic of the coal-fired power
industry that is relevant for determining the cost reasonableness of
control requirements: A large percentage of the industry has announced,
or is expected to announce, dates for ceasing operation, and the fact
that many coal-fired steam generating units intend to cease operation
affects what controls are ``best'' for different subcategories. Whether
the costs of control are reasonable depends in part on the period of
time over which the affected sources can amortize those costs. Sources
that have shorter operating horizons will have less time to amortize
capital costs and the controls will thereby be less cost-effective and
therefore may not qualify as the BSER.\532\
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\531\ 40 CFR 60.22(b)(5), 60.22a(b)(5).
\532\ Steam Electric Reconsideration Rule, 85 FR 64650, 64679
(October 13, 2020) (distinguishes between EGUs retiring before 2028
and EGUs remaining in operation after that time).
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In addition, subcategorizing by length of period of continued
operation is similar to two other bases for subcategorization on which
the EPA has relied in prior rules, each of which implicates the cost
reasonableness of controls: The first is load level, noted in section
X.C of this preamble. For example, in the 2015 NSPS, the EPA divided
new natural gas-fired combustion turbines into the subcategories of
base load and non-base load. 80 FR 64510, 64602 (table 15) (October 23,
2015). The EPA did so because the control technologies that were
``best''-including consideration of feasibility and cost-
reasonableness--depended on how much the unit operated. The load level,
which relates to the amount of product produced on a yearly or other
basis, bears similarity to a limit on a period of continued operation,
which concerns the amount of time remaining to produce the product. In
both cases, certain technologies may not be cost reasonable because of
the capacity to produce product--i.e., because the costs are spread
over less product produced.
The second is fuel type, as also noted in section X.C of this
preamble. The 2015 NSPS provides an example of this type of
subcategorization as well. There, the EPA divided new combustion
turbines into subcategories on the basis of type of fuel combusted. Id.
Subcategorizing on the basis of the type of fuel combusted may be
appropriate when different controls have different costs, depending on
the type of fuel, so that the cost-reasonableness of the control
depends on the type of fuel. In that way, it is similar to
subcategorizing by operating horizon because in both cases, the
subcategory is based upon the cost reasonableness of controls.
Subcategorizing by fuel type presents an additional analogy to the
present case of subcategorizing on the basis of the length of time when
the source will continue to operate because this timeframe is
tantamount to the length of time when the source will continue to
combust the fuel. Subcategorizing on this basis may be appropriate when
different controls for a particular fuel have different costs,
depending on the length of time when the fuel will continue to be
combusted, so that the cost-reasonableness of controls depends on that
timeframe. Some prior EPA rules for coal-fired sources have made
explicit the link between length of time for continued operation and
type of fuel combusted by codifying federally enforceable retirement
dates as the dates by which the source must ``cease burning coal.''
\533\
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\533\ See 79 FR 5031, 5192 (January 30, 2014) (explaining that
``[t]he construction permit issued by Wyoming requires Naughton Unit
3 to cease burning coal by December 31, 2017 and to be retrofitted
to natural gas as its fuel source by June 30, 2018'' (emphasis
added)).
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It should be noted that subcategorizing on the basis of operating
horizon does not preclude a State from considering RULOF in applying a
standard of performance to a particular source. EPA's authority to set
BSER for a source category (including subcategories) and a State's
authority to invoke RULOF for individual sources within a category or
subcategory are distinct. EPA's statutory obligation is to determine a
generally applicable BSER for a source category, and where that source
category encompasses different classes, types, or sizes of sources, to
set generally applicable BSERs for subcategories accounting for those
differences. By contrast, States' authority to invoke RULOF is premised
on the State's ability to take into account the characteristics of a
particular source that may differ from the assumptions EPA made in
determining BSER generally. As noted above, the EPA is proposing these
subcategories in response to requests by power sector representatives
that this rule accommodate the fact that there is a class of sources
that plans to voluntarily cease operations in the near term. Although
the EPA has designed the subcategories to accommodate those requests, a
particular source may still present source-specific considerations--
whether related to its remaining useful life or other factors--that the
State may consider relevant for the application of that particular
source's standard of performance, and that the State should
[[Page 33346]]
address as described in section XII.D.2 of this preamble.
D. Determination of BSER for Coal-Fired Steam Generating Units
The EPA evaluated two primary control technologies as potentially
representing the BSER for existing coal-fired steam generating units:
CCS and natural gas co-firing. This section of the preamble discusses
each of these alternatives, based on the criteria described in section
V.C of this preamble.
The EPA is proposing CCS with 90 percent capture as BSER for long-
term coal-fired steam generating units, that is, ones that are expected
to continue to operate past 2039, because CCS can achieve an
appropriate amount of emission reductions and satisfies the other BSER
criteria. Because CCS is less cost reasonable for EGUs that do not plan
to operate in the long term, the EPA is proposing other measures as
BSER for the other subcategories of existing coal-fired steam
generating units.
Specifically, for medium-term units, that is, ones that have
elected to commit to permanently cease operations after December 31,
2031, and before January 1, 2040, and are not near-term units, the EPA
is proposing a BSER of 40 percent natural gas co-firing on a heat input
basis. However, the EPA is taking comment on the operating horizon
(i.e., between 8 and 10 years, instead of the proposed 10-year
operating horizon) that defines the threshold date between medium-term
and long-term coal-fired steam generating units, and it is possible
that the costs of CCS may be considered reasonable for some portion of
the units that may be covered by the medium-term subcategory as
proposed.
For imminent-term and near-term units, that is, ones that have
elected to commit to permanently cease operations before January 1,
2032, and between December 31, 2031, and January 1, 2035, coupled with
an annual capacity factor limit, respectively, the EPA is proposing a
BSER of routine methods of operation and maintenance that maintain
current emission rates. The EPA is also soliciting comment on a
potential BSER based on low levels of natural gas co-firing for
imminent- and near-term units.
1. Long-Term Coal-Fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS and natural
gas co-firing as potential BSER for long-term coal-fired steam
generating units.
The EPA is proposing CCS with 90 percent capture of CO2
at the stack as BSER for long-term coal-fired steam generating units.
The Agency is taking comment on the range of the amount of capture of
CO2 from 90 to 95 percent or greater. CCS achieves
substantial reductions in emissions and can capture and permanently
sequester more than 90 percent of CO2 emitted by coal-fired
steam generating units. The technology is adequately demonstrated, as
indicated by the facts that it has been operated at scale and is widely
applicable to sources, and there are vast sequestration opportunities
across the continental U.S. Additionally, the costs for CCS are
reasonable, in light of recent technology cost declines and policies
including the tax credit under IRC section 45Q. Moreover, the non-air
quality health and environmental impacts and energy requirements of CCS
are not unreasonably adverse. These factors provide the basis for
proposing CCS as BSER for these sources. In addition, determining CCS
as the BSER promotes this useful GHG emission control technology.
The EPA also evaluated natural gas co-firing at 40 percent of heat
input as a potential BSER for long-term coal-fired steam generating
units. While the unit level emission rate reductions of 16 percent
achieved by 40 percent natural gas co-firing are reasonable, those
reductions are substantially less than CCS with 90 percent capture of
CO2. Therefore, because CCS achieves more reductions at the
unit level and is cost reasonable, the EPA is not proposing natural gas
co-firing as the BSER for these units.
a. CCS
In this section of the preamble, the EPA evaluates the use of CCS
as the BSER for existing long-term coal-fired steam generating units.
This section incorporates by reference the parts of section
VII.F.3.b.iii of this preamble that discuss the aspects of CCS that are
common to new combustion turbines and existing steam generating units.
This section also discusses additional aspects of CCS that are relevant
for existing steam generating units and, in particular, long-term
units.
i. Adequately Demonstrated
The EPA is proposing that CCS is technically feasible and has been
adequately demonstrated, based on the utilization of the technology at
existing coal-fired steam generating units and industrial sources in
addition to combustion turbines. While the EPA would propose that CCS
is adequately demonstrated on those bases alone, this determination is
further corroborated by EPAct05-assisted projects.
The fundamental CCS technology has been in existence for decades,
and the industry has extensive experience with and knowledge about it.
Indeed, even without the requirements proposed here, the EPA projects
that 9 GW of coal-fired steam generating units would apply CCS by 2030.
Thus, the EPA will explain how existing and planned fossil fuel-fired
electric power plants and other industrial projects that have installed
or expect to install some or all of the components of CCS technology
support the EPA's proposed determination that CCS is adequately
demonstrated for existing coal-fired power plants, and the EPA will
explain how EPAct05-assisted projects support that proposed
determination, consistent with the legal interpretation of the EPAct05
in section VII.F.3.b.iii(A) of this preamble.
(A) CO2 Capture Technology
The technology of CO2 capture, in general, is detailed
in accompanying TSDs (available in the docket) and in section
VII.F.3.b.iii of this preamble. As noted there, solvent-based (i.e.,
amine-based) post-combustion CO2 capture is the technology
that is most applicable at existing coal-fired steam generating units.
Technology considerations specific to existing coal-fired steam
generating units, including energy demands, non-GHG emissions, and
water use and siting, are discussed in section X.D.1.a.iii of this
preamble. As detailed in section VII.F.3.b.iii(A) of this preamble, the
CO2 capture component of CCS has been demonstrated at
existing coal-fired steam generating units, industrial processes, and
existing combustion turbines. In particular, SaskPower's Boundary Dam
Unit 3 has demonstrated capture rates of 90 percent of the
CO2 in flue gas using solvent-based post-combustion capture
retrofitted to existing coal-fired steam generating units. While the
EPA would propose that the CO2 capture component of CCS is
adequately demonstrated on the basis of Boundary Dam Unit 3 alone,
CO2 capture has been further demonstrated at other coal-
fired steam generating units (CO2 capture from slipstreams
of AES's Warrior Run and Shady Point) and industrial processes (e.g.,
Quest CO2 capture project), detailed descriptions of which
are provided in section VII.F.3.b.iii(A)(2) of this preamble. The core
technology of CO2 capture applied to combustion turbines is
similar to that of coal-fired steam generating units (i.e., both may
use amine solvent-based methods); therefore the demonstration of
CO2 capture at combustion turbines (e.g., the Bellingham,
Massachusetts,
[[Page 33347]]
combined cycle unit), as detailed in section VII.F.3.b.iii(A)(3) of
this preamble, provide additional support for the adequate
demonstration of CO2 capture for coal-fired steam generating
units. Finally, EPAct05-assisted CO2 capture projects (e.g.,
Petra Nova) further corroborate the adequate demonstration of
CO2 capture.
(B) CO2 Transport
As discussed in section VII.F.3.b.iii of this preamble,
CO2 pipelines are available and their network is expanding
in the U.S., and the safety of existing and new supercritical
CO2 pipelines is comprehensively regulated by PHMSA.\534\
Other modes of CO2 transportation also exist.
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\534\ PHMSA additionally initiated a rulemaking in 2022 to
develop and implement new measures to strengthen its safety
oversight of CO2 pipelines following investigation into a
CO2 pipeline failure in Satartia, Mississippi in 2020.
For more information, see: https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
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Based on data from DOE/NETL studies of storage resources, 77
percent of existing coal-fired steam generating units that have planned
operation during or after 2030 are within 80 km (50 miles) of potential
saline sequestration sites, and another 5 percent are within 100 km (62
miles) of potential sequestration sites.\535\ Additionally, of the
coal-fired steam generating units with planned operation during or
after 2030, 90 percent are located within 100 km of one or more types
of sequestration formations, including deep saline, unmineable coal
seams, and oil and gas reservoirs. This distance is consistent with the
distances referenced in studies that form the basis for transport cost
estimates in this proposal.536 537 As noted in section
VII.F.3.b.iii(A)(5) of this preamble, areas without reasonable access
to pipelines for geologic sequestration can transport CO2 to
sequestration sites via other transportation modes such as ship, road
tanker, or rail tank cars.
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\535\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details
please see Chapter 6 of the IPM documentation available at: https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\536\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
\537\ Note that the determination that the BSER has been
adequately demonstrated does not require that every source in the
long-term coal-fired steam generating unit subcategory be within 100
km of CO2 storage.
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(C) Geologic Sequestration of CO2
Geologic sequestration (i.e., the long-term containment of a
CO2 stream in subsurface geologic formations) is well proven
and broadly available throughout the U.S. Geologic sequestration is
based on a demonstrated understanding of the processes that affect the
fate of CO2 in the subsurface. As discussed in section
VII.F.3.a.iii of this preamble, there have been numerous instances of
geologic sequestration in the U.S. and overseas, and the U.S. has
developed a detailed set of regulatory requirements to ensure the
security of sequestered CO2. This regulatory framework
includes the UIC Class VI well regulations, which are under the
authority of SDWA, and the GHGRP, under the authority of the CAA.
Geologic sequestration potential for CO2 is widespread
and available throughout the U.S. Through an availability analysis of
sequestration potential in the U.S. based on resources from the DOE,
the USGS, and the EPA, the EPA found that there are 43 States with
access to, or are within 100 km from, onshore or offshore storage in
deep saline formations, unmineable coal seams, and depleted oil and gas
reservoirs.
Sequestration potential as it relates to distance from existing
resources is a key part of the EPA's regular power sector modeling
development, using data from DOE/NETL studies.\538\ These data show
that of the coal-fired steam generating units with planned operation
during or after 2030, 60 percent are located within the boundary of a
saline reservoir, 77 percent are located within 40 miles (80 km) of the
boundary of a saline reservoir, and 82 percent are located within 62
miles (100 km) of a saline reservoir. Additionally, of the coal-fired
steam generating units with planned operation during or after 2030, 90
percent are located within 100 km of any of the considered formations,
including deep saline, unmineable coal seams, and oil and gas
reservoirs.539 540 As noted in section VII.F.3.b.iii(A)(5)
of this preamble, areas without reasonable access to pipelines for
geologic sequestration can transport CO2 to sequestration
sites via other transportation modes such as ship, road tanker, or rail
tank cars.
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\538\ For details, please see Chapter 6 of the IPM
documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\539\ The distance of 100 km is consistent with the assumptions
underlying the NETL cost estimates for transporting CO2
by pipeline.
\540\ Note that the determination that the BSER has been
adequately demonstrated does not require that every source in the
long-term coal-fired steam generating unit subcategory be within 100
km of CO2 storage.
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ii. Costs
The EPA has analyzed the costs of CCS for existing coal-fired long-
term sources, including costs for CO2 capture, transport,
and sequestration. The EPA is proposing that this analysis demonstrates
that the costs of CCS for these sources are reasonable. The EPA also
evaluated costs assuming a higher capacity factor of 70 percent
(resulting in lower costs) and different amortization periods, as
discussed in section X.D.1.a.ii(C) of this preamble. The EPA is
soliciting comment on the assumptions in the cost analysis,
particularly with respect to the capacity factor assumption. As
elsewhere in this section of the preamble, costs are presented in 2019
dollars.
The EPA assessed costs of CCS for a reference unit as well as the
average cost for the fleet of coal-fired steam generating units with
planned operation during or after 2030. The reference unit, which
represents an average unit in the fleet, has a 400 MW-gross nameplate
capacity and a 10,000 Btu/kWh heat rate. Applying CCS to the reference
unit with a 12-year amortization period and assuming a 50 percent
annual capacity factor--a typical value for the fleet--results in
annualized total costs that can be expressed as an abatement cost of
$14/ton of CO2 reduced and an incremental cost of
electricity of $12/MWh. Included in these estimates is the EPA's
assessment that the transport and storage costs are roughly $30/ton, on
average for the reference unit. For the fleet of coal-fired steam
generating units with planned operation during or after 2030, and
assuming a 12-year amortization period and 50 percent annual capacity
factor and including source specific transport and storage costs, the
average total costs of CCS are $8/ton of CO2 reduced and $7/
MWh. These total costs also account for the IRC section 45Q tax credit,
a detailed discussion of which is provided in section
VII.F.3.b.iii(B)(3) of this preamble. Compared to the representative
costs of controls detailed in section VII.F.3.b.iii(B)(5) of this
preamble (i.e., emission control costs on EGUs of $10.60 to $29/MWh and
the costs in the 2016 NSPS regulating GHGs for the Crude Oil and
Natural Gas source category of $98/ton of CO2e reduced (80
FR 56627; September 18, 2015)) the costs for CCS on long-term coal-
fired steam generating units are similar or better. Based on all of
these analyses, the EPA is proposing that for the purposes of the BSER
analysis, CCS is cost reasonable for long-term coal-fired steam
generating units. The EPA also evaluated costs of CCS under
[[Page 33348]]
various other assumptions of amortization period and annual capacity
factor. Finally, it is noted that these CCS costs are lower than those
in prior rulemakings due to the IRC section 45Q tax credit and
reductions in the cost of the technology.
(A) CO2 Capture Costs at Existing Coal-Fired Steam
Generating Units
A variety of sources provide information for the cost of CCS
systems, and they generally agree around a range of cost. The EPA has
relied heavily on information recently developed by NETL, in the U.S.
Department of Energy, in particular, ``Cost and Performance Baseline
for Fossil Energy Plants,'' \541\ and the ``Pulverized Coal Carbon
Capture Retrofit Database.'' \542\ In addition, the EPA developed an
independent engineering cost assessment for CCS retrofits, with support
from Sargent and Lundy.\543\
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\541\ https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
\542\ https://netl.doe.gov/energy-analysis/details?id=69db8281-593f-4b2e-ac68-061b17574fb8.
\543\ Detailed cost information, assessment of technology
options, and demonstration of cost reasonableness can be found in
the GHG Mitigation Measures for Steam Generating Units TSD.
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(B) CO2 Transport and Sequestration Costs
As discussed in section VII.F.3.b.iii of this preamble, NETL's
``Quality Guidelines for Energy System Studies; Carbon Dioxide
Transport and Sequestration Costs in NETL Studies'' is one of the more
comprehensive sources of information on CO2 transport and
storage costs available. The Quality Guidelines provide an estimation
of transport costs for a single point-to-point pipeline. Estimated
costs reflect pipeline capital costs, related capital expenditures, and
operations and maintenance costs.\544\ These Quality Guidelines also
provide an estimate of sequestration costs reflecting the cost of site
screening and evaluation, permitting and construction costs, the cost
of injection wells, the cost of injection equipment, operation and
maintenance costs, pore volume acquisition expense, and long-term
liability protection. NETL's Quality Guidelines model costs for a given
cumulative storage potential.\545\
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\544\ Grant, T., et al. ``Quality Guidelines for Energy System
Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
\545\ Details on CO2 transportation and sequestration
costs can be found in the GHG Mitigation Measures for Steam
Generating Units TSD.
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(C) Amortization Period and Annual Capacity Factor
In the EPA's cost analysis for long-term coal-fired steam
generating units, the EPA assumes a 12-year amortization period and a
50 percent annual capacity factor. The 12-year amortization period is
consistent with the period of time during which the IRC section 45Q tax
credit can be claimed and the 50 percent annual capacity factor is
consistent with the historical fleet average. However, increases in
utilization are likely to occur for units that apply CCS due to the
incentives provided by the IRC section 45Q tax credit. Therefore, the
EPA also assessed the costs for CCS retrofitted to existing coal-fired
steam generating units assuming a 70 percent annual capacity factor.
For a 70 percent annual capacity factor and a 12-year amortization
period, the costs for the reference unit are negative at -$8/ton of
CO2 reduced and -$7/MWh. The negative costs indicate that
the value of the 45Q tax credit more than offsets the costs to install
and operate CCS. For either capacity factor assumption, the $/MWh costs
are comparable to or less than the costs for other controls ($10.60-
$29.00/MWh) which are detailed in section VII.F.3.b.iii(B)(5) of this
preamble.
As noted in section X.C.3 of this preamble, the EPA is also taking
comment on the operating horizon that defines the threshold date
between the definition of medium-term and long-term coal-fired steam
generating units, specifically an operating horizon between 8 and 10
years (i.e., January 1, 2038 to January 1, 2040), instead of the
proposed 10-year operating horizon. For a 70 percent annual capacity
factor and an 8-year amortization period, annualized costs of applying
CCS for the reference unit are $24/ton of CO2 reduced and
$21/MWh, and it is possible that the cost of generation may be
reasonable relative to the representative cost for wet FGD. However,
CCS may be less cost favorable for units with shorter amortization
periods. For a 70 percent annual capacity factor and a 7-year
amortization period, costs for the reference unit are $39/ton of
CO2 reduced and $34/MWh. Additional details of the cost
analysis are available in the GHG Mitigation Measures for Steam
Generating Units TSD.
(D) Comparison to Costs for CCS in Prior Rulemakings
In the CPP and ACE Rule, the EPA determined that CCS did not
qualify as the BSER due to cost considerations. Two key developments
have led the EPA to reevaluate this conclusion: the costs of CCS
technology have fallen and the extension and increase in the IRC
section 45Q tax credit, as included in the IRA, in effect provide a
significant stream of revenue for sequestered CO2 emissions.
The CPP and ACE Rule relied on a 2015 NETL report estimating the cost
of CCS. NETL has issued updated reports to incorporate the latest
information available, most recently in 2022, which show cost
reductions. The 2015 report estimated incremental levelized cost of CCS
at a new pulverized coal facility relative to a new facility without
CCS at $74/MWh (2022$),\546\ while the 2022 report estimated
incremental levelized cost at $44/MWh (2022$).\547\ Additionally, the
IRA increased the IRC section 45Q tax credit from $50/metric ton to
$85/metric ton (and, in the case of EOR or certain industrial uses,
from $35/metric ton to $60/metric ton), assuming prevailing wage and
apprenticeship conditions are met. The IRA also enhanced the realized
value of the tax credit through the direct pay and transferability
monetization options described in section IV.E.1. The combination of
lower costs and higher tax credits significantly improves the cost
effectiveness of CCS for purposes of determining whether it qualifies
as the BSER.
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\546\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 3
(July 2015). https://www.netl.doe.gov/projects/files/CostandPerformanceBaselineforFossilEnergyPlantsVolume1aBitCoalPCandNaturalGastoElectRev3_070615.pdf.
\547\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A
(October 2022). https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
CCS for steam generating units is not expected to have unreasonable
adverse consequences related to non-air quality health and
environmental impacts or energy requirements. The EPA has considered
non-GHG emissions impacts, the water use impacts, the transport and
sequestration of captured CO2, and energy requirements
resulting from CCS. Because the non-air quality health and
environmental impacts are closely related to the energy requirements,
the latter are discussed first.
As noted in section VII.F.3.b.iii(C) of this preamble, stakeholders
have shared with the EPA concerns about the safety of CCS projects and
concerns that their communities may bear a
[[Page 33349]]
disproportionate environmental burden associated with CCS projects. The
EPA is committed to working with its fellow agencies to foster
meaningful engagement with communities and protect communities from
pollution through the responsible deployment of CCS. This can be
facilitated through the existing detailed regulatory framework for CCS
projects and further supported through robust and meaningful public
engagement early in the technological deployment process. CCS projects
undertaken pursuant to these emission guidelines will, if the EPA
finalizes proposed revisions to the CAA section 111 implementing
regulations,\548\ be subject to requirements for meaningful engagement
as part of the State plan development process. See section XII.F.1.b of
this preamble for additional details.
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\548\ 87 FR 79176, 79190-92 (December 23, 2022).
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(A) Energy Requirements
For a steam generating unit with 90 percent amine-based
CO2 capture, parasitic/auxiliary energy demand increases and
the net power output decreases. Amine-based CO2 capture is
an energy-intensive process. In particular, the solvent regeneration
process requires substantial amounts of heat in the form of steam and
CO2 compression requires a large amount of electricity. Heat
and power for the CO2 capture equipment can be provided
either by using the steam and electricity produced by the steam
generating unit or by an auxiliary cogeneration unit. However, any
auxiliary source of heat and power is part of the ``designated
facility,'' along with the steam generating unit. The standards of
performance apply to the designated facility. Thus, any CO2
emissions from the connected auxiliary equipment need to be captured or
they will increase the facility's emission rate.
Using integrated heat and power can reduce the capacity (i.e., the
amount of electricity that a unit can distribute to the grid) of an
approximately 474 MW-net (501 MW-gross) coal-fired steam generating
unit without CCS to approximately 425 MW-net with CCS and contributes
to a reduction in net efficiency of 23 percent.\549\ For retrofits of
CCS on existing sources, the ductwork for flue gas and piping for heat
integration to overcome potential spatial constraints are a component
of efficiency reduction. The EPA notes that slightly greater efficiency
reductions than in the 2016 NETL retrofit report are assumed for the
BSER cost analyses, as detailed in the GHG Mitigation Measures for
Steam Generating Units TSD, available in the docket. Despite decreases
in efficiency, IRC section 45Q tax credits provide an incentive for
increased generation with full operation of CCS because the credits are
proportional to the amount of captured and sequestered CO2
emissions and not to the amount of electricity generated. The Agency is
proposing that the energy penalty is relatively minor compared to the
GHG benefits of CCS and, therefore, does not disqualify CCS as being
considered the BSER for existing coal-fired steam generating units.
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\549\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016.https://www.netl.doe.gov/energy-analysis/details?id=d335ce79-84ee-4a0b-a27b-c1a64edbb866.
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Additionally, the EPA considered the impacts on the power sector,
on a nationwide and long-term basis, of determining CCS to be the BSER
for long-term coal-fired steam generating units. The EPA is proposing
that designating CCS as the BSER for existing long-term coal-fired
steam generating units would have limited and non-adverse impacts on
the long-term structure of the power sector. Absent the requirements
defined in this action, the EPA projects that 9 GW of coal-fired steam
generating units would apply CCS by 2030 and 35 GW of coal-fired steam
generating units, some without controls, would remain in operation in
2040. Designating CCS to be the BSER for existing long-term coal-fired
steam generating units would likely result in more of the coal-fired
steam generating unit capacity applying CCS. The time available before
the compliance deadline of January 1, 2030, provides for adequate
resource planning, including accounting for the downtime necessary to
install the CO2 capture equipment at long-term coal-fired
steam generating units. While the IRC 45Q tax credit is available,
long-term coal-fired steam generating units are anticipated to run at
base load conditions. Total generation from coal-fired steam generating
units in the other subcategories would gradually decrease over an
extended period of time through 2039, subject to the commitments those
units have chosen to adopt. Any decreases in the amount of generation
from coal-fired steam generating units, whether locally or more
broadly, are compensated for by increased generation from other
sources. Additionally, for the long-term units applying CCS, the EPA is
proposing the increase in the annualized cost of generation for those
units is reasonable. Therefore, the EPA is proposing that there would
be no unreasonable impacts on the reliability of electricity
generation. A broader discussion of reliability impacts of the proposed
actions is available in section XIV.F of this preamble. Finally,
changes in the amount of generation from coal-fired steam generating
units may contribute to additional generation from combined cycle
combustion turbines. Since these EGUs have lower GHG and criteria
pollutant emission rates than existing coal-fired steam generating
units, overall emissions from the power sector would likely decrease.
(B) Non-GHG Emissions
For amine-based CO2 capture retrofits to coal-fired
steam generating units, decreased efficiency and increased utilization
would otherwise result in increases of non-GHG emissions; however,
importantly, most of those impacts would be mitigated by the flue gas
conditioning required by the CO2 capture process and by
other control equipment that the units already have or may need to
install to meet other CAA requirements. Decreases in efficiency result
in increases in the relative amount of coal combusted per amount of
electricity generated and would otherwise result in increases in the
amount of non-GHG pollutants emitted per amount of electricity
generated. Additionally, increased utilization would otherwise result
in increases in total non-GHG emissions. However, substantial flue gas
conditioning, particularly to remove SO2, is critical to
limiting solvent degradation and maintaining reliable operation of the
capture plant. To achieve the necessary limits on SO2 levels
in the flue gas for the capture process, steam generating units will
need to add an FGD column, if they do not already have one, and may
need an additional polishing column (i.e., quencher). A wet FGD column
and a polishing column will also reduce the emission rate of
particulate matter. Additional improvements in particulate matter
removal may also be necessary to reduce the fouling of other components
(e.g., heat exchangers) of the capture process. NOX
emissions can cause solvent degradation and nitrosamine formation by
chemical absorption of NOX, depending on the chemical
structure of the solvent. The DOE's Carbon Management Pathway report
notes that monitoring and emission controls for such degradation
products are currently part of standard operating procedures for amine-
based CO2 capture systems.\550\
[[Page 33350]]
A conventional multistage water or acid wash and mist eliminator at the
exit of the CO2 scrubber is effective at removal of gaseous
amine and amine degradation products (e.g., nitrosamine)
emissions.551 552 NOX levels of the flue gas
required to avoid solvent degradation and nitrosamine formation in the
CO2 scrubber vary. For most units, the requisite limits on
NOX levels to assure that the CO2 capture process
functions properly may be met by the existing NOX combustion
controls, and those units may not need to install SCR for process
purposes. However, most existing coal-fired steam generating units
either already have SCR or will be covered by proposed Federal
Implementation Plan (FIP) requirements regulating interstate transport
of NOX (as an ozone precursors) from EGUs. See 87 FR 20036
(April 6, 2022). For units not otherwise required to have SCR, an
increase in utilization from a CO2 capture retrofit could
result in increased NOX emissions at the source that,
depending on the quantity of the emissions increase, may trigger major
NSR permitting requirements. Under this scenario, the permitting
authority may determine that the NSR permit requires the installation
of SCR for those units, based on applying the requirements of major
NSR. Alternatively, a State could, as part of its State plan, develop
enforceable conditions for a source expected to trigger major NSR that
would effectively limit the unit's ability to increase its emissions in
amounts that would trigger major NSR. Under this scenario, with no
major NSR requirements applying due to the limit on the emissions
increase, the permitting authority may conclude for minor NSR purposes
that installation of SCR is not required for the units. See section
XIII.A of this preamble for additional discussion of the NSR program.
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\550\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/uploads/2023/04/20230424-Liftoff-Carbon-Management-vPUB_update.pdf.
\551\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
\552\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
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(C) Water Use and Siting
Water consumption at the plant increases when applying carbon
capture, due to solvent water makeup and cooling demand. Water
consumption can increase by 36 percent on a gross basis.\553\ A
separate cooling water system dedicated to a CO2 capture
plant may be necessary. However, the amount of water consumption
depends on the design of the cooling system. For example, the cooling
system cited in the CCS feasibility study for SaskPower's Shand Power
station would rely entirely on water condensed from the flue gas and
thus would not require any increase in external water consumption.\554\
Regions with limited water supply may rely on dry or hybrid cooling
systems, although, in areas with adequate water, wet cooling systems
can be more effective.
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\553\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
\554\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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With respect to siting considerations, CO2 capture
systems have a sizeable physical footprint and a consequent land-use
requirement. The EPA is proposing that the water use and siting
requirements are manageable and therefore the EPA does not expect any
of these considerations to preclude coal-fired power plants generally
from being able to install and operate CCS. However, the EPA is
soliciting comment on these issues.
(D) Transport and Geologic Sequestration
As noted in section VII.F.3.b.iii of this preamble, PHMSA oversight
of supercritical CO2 pipeline safety protects against
environmental release during transport and UIC Class VI regulations
under the SDWA, in tandem with GHGRP subpart RR requirements, ensure
the protection of USDWs and the security of geologic sequestration.
iv. Extent of Reductions in CO2 Emissions
CCS can be applied to coal-fired steam generating units at the
source and reduce the CO2 emission rate by 90 percent or
more. Increased steam and power demand have a small impact on the
reduction in emission rate that occurs with 90 percent capture.
According to the 2016 NETL Retrofit report, 90 percent capture will
result in emission rates that are 88.4 percent lower on a lb/MWh-gross
basis and 87.1 percent lower on a lb/MWh-net basis compared to units
without capture.\555\ After capture, CO2 can be transported
and securely sequestered.\556\ Although steam generating units with
CO2 capture will have an incentive to operate at higher
utilization because the cost to install the CCS system is largely fixed
and the IRC section 45Q tax credit increases based on the amount of
CO2 captured and sequestered, any increase in utilization
will be far outweighed by the substantial reductions in emission rate.
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\555\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
\556\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
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v. Technology Advancement
The EPA considered the potential impact of designating CCS as the
BSER for long-term coal-fired steam generating units on technology
advancement, and the EPA is proposing that designating CCS as the BSER
will provide for meaningful advancement of CCS technology, for many of
the same reasons as noted in section VII.F.3.b.iii(F) of this preamble.
vi. Comparison With 2015 NSPS for Newly Constructed Coal-Fired EGUs
In the 2015 NSPS, the EPA determined that the BSER for newly
constructed coal-fired EGUs was based on CCS with 16-23 percent
capture, based on the type of coal combusted, and consequently, the EPA
promulgated standards of performance of 1,400 lb CO2/MWh-g. 80 FR 64512
(Table 1), 64513 (October 23, 2015). The EPA made those determinations
based on the costs of CCS at the time of that rulemaking. In general,
those costs were significantly higher than at present, due to recent
technology cost declines as well as related policies, including the IRC
section 45Q tax credit for CCS, which was not available at that time
for purposes of consideration during the development of the NSPS. Id.
at 64562 (Table 8). Based on of these higher costs, the EPA determined
that 16-23 percent capture qualified as the BSER, and not a
significantly higher percentage of capture. Given the substantial
differences in the cost of CCS during the time of the 2015 NSPS and the
present time, the capture percentage of the 2015 NSPS necessarily
differed from the capture percentage in this proposal, and, by the same
token, the associated degree of emission limitation and resulting
standards of performance necessarily differ as well.
b. Natural Gas Co-Firing
The EPA also evaluated natural gas co-firing at 40 percent of the
heat input as the potential BSER for long-term coal-fired steam
generating units. Because
[[Page 33351]]
the EPA is proposing natural gas co-firing as the BSER for medium-term
units, details that are common to medium-term and long-term units are
discussed in section X.D.2.b of the preamble. Based on the discussion
therein, the EPA is proposing that natural gas co-firing is adequately
demonstrated and that the non-air quality health and environmental
effects and energy requirements are not unreasonable. The costs of
natural gas co-firing for a long-term unit may also be reasonable. For
example, for a representative unit with a 10-year amortization period,
the cost of reductions is $53/ton of CO2. Finally, while 40
percent natural gas co-firing achieves unit-level emission rate
reductions of 16 percent, those reductions are less than CCS with 90
percent capture. Therefore, because CCS achieves more reductions at the
unit level and is proposed as cost reasonable for long-term units, the
EPA is not proposing natural gas co-firing as the BSER for long-term
coal-fired steam generating units.
c. Conclusion
The EPA proposes that CCS at a capture rate of 90 percent is the
BSER for long-term coal-fired steam generating units because CCS is
adequately demonstrated, as indicated by the facts that it has been
operated at scale and is widely applicable to sources and that there
are vast sequestration opportunities across the continental U.S.
Additionally, accounting for recent technology cost declines as well as
policies including the tax credit under IRC section 45Q, the costs for
CCS are reasonable. Moreover, any adverse non-air quality health and
environmental impacts and energy requirements of CCS, including impacts
on the power sector on a nationwide basis, are limited and are
outweighed by the benefits of the significant GHG emission reductions
at reasonable cost. In contrast, co-firing 40 percent natural gas would
achieve far fewer emission reductions without improving the cost
effectiveness of the control strategy. These considerations provide the
basis for proposing CCS as the best of the systems of emission
reduction for long-term coal-fired power plants. In addition,
determining CCS as the BSER promotes this useful control technology.
Although the EPA believes that long-lived coal-fired power plants will
generally be able to implement and operate CCS within the cost
parameters calculated as part of the BSER analysis, and therefore that
they would be able to meet a standard of performance based on CCS with
90 percent capture, the EPA solicits comment on whether particular
plants would be unable to do so, including details of the circumstances
that might make retrofitting with CCS unreasonable or infeasible.
2. Medium-Term Coal-Fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS and natural
gas co-firing as potential BSER for medium-term coal-fired steam
generating units.
In section X.D.1.a of this preamble, the EPA evaluated CCS with 90
percent capture of CO2 as the BSER for long-term coal-fired
steam generating units. Much of this evaluation is relevant for medium-
term units. However, because they have shorter operating horizons and,
as a result, a shorter period for amortization and for collecting the
IRC section 45Q tax credits, CCS would be less cost effective for those
units. Therefore, the EPA is not proposing CCS as BSER for medium-term
coal-fired steam generating units.
Instead, the EPA is proposing that 40 percent natural gas co-firing
on a heat input basis is the BSER for medium-term coal-fired steam
generating units. Co-firing 40 percent natural gas, on an annual
average heat input basis, results in a 16 percent reduction in
CO2 emission rate. The technology has been adequately
demonstrated, can be implemented at reasonable cost, does not have
adverse non-air quality health and environmental impacts or energy
requirements, and achieves meaningful reductions in CO2
emissions. Co-firing also advances useful control technology and has
acceptable national and long-term impacts on the energy sector, which
provide additional, although not essential, support for treating it as
the BSER.
a. CCS
In this section of the preamble, the EPA evaluates the use of CCS
as the BSER for existing medium-term coal-fired steam generating units.
This evaluation is much the same as the evaluation for long-term units,
with the important difference of costs.
For long-term units, as discussed earlier in this preamble, the
EPA's analysis used to evaluate the reasonableness of CCS costs employs
a 12-year amortization period, which is consistent with the period of
time during which the IRC section 45Q tax credit can be claimed.
However, existing coal-fired steam generating units that have elected
to commit to permanently cease operations prior to 2040--ones in the
medium-term subcategory, as well as in the near-term, and imminent-term
subcategories--would have a shorter period to amortize capital costs
and also would not be able to fully utilize the IRC section 45Q tax
credit. As a result, for these sources, the cost effectiveness of CCS
is less favorable. As noted in section X.D.1.a.ii(C) of this preamble,
for a 70 percent annual capacity factor and a 7-year amortization
period, costs for the reference unit are $39/ton of CO2
reduced and $34/MWh. This $/MWh generation cost is less favorable
relative to the representative cost ($/MWh) for wet FGD, the costs for
which are detailed in section VII.F.3.b.iii(B)(5). Due to the higher
incremental cost of generation, the EPA is not proposing CCS as the
BSER for medium-term coal-fired steam generating units.
While the EPA is not proposing CCS as BSER for the proposed
subcategory of medium-term units, the EPA is taking comment on the
operating horizon (i.e., between 8 and 10 years, instead of the
proposed 10-year operating horizon) that most appropriately defines the
threshold date between medium-term and long-term units and the EPA is
also taking comment on the level of costs of CCS that should be
considered reasonable.
b. Natural Gas Co-Firing
In this section of the preamble, the EPA evaluates natural gas co-
firing as potential BSER for medium-term coal-fired steam generating
units. Considerations that are common to the proposed subcategories of
existing coal-fired steam generating units are discussed in section
X.D.1.a of the preamble, in addition to considerations that are
specific to medium-term units.
For a coal-fired steam generating unit, the substitution of natural
gas for some of the coal, so that the unit fires a combination of coal
and natural gas, is known as ``natural gas co-firing.'' The EPA is
proposing natural gas co-firing at a level of 40 percent of annual heat
input as BSER for medium-term coal-fired steam generating units.
i. Adequately Demonstrated
The EPA is proposing to find that natural gas co-firing at the
level of 40 percent of annual heat input is adequately demonstrated for
coal-fired steam generating units. Many existing coal-fired steam
generating units already use some amount of natural gas, and several
have co-fired at relatively high levels at or above 40 percent of heat
input in recent years.
(A) Boiler Modifications
Most existing coal-fired steam generating units can be modified to
co-fire natural gas in any desired proportion with coal, up to 100
percent
[[Page 33352]]
natural gas. Generally, the modification of existing boilers to enable
or increase natural gas firing typically involves the installation of
new gas burners and related boiler modifications, including, for
example, new fuel supply lines and modifications to existing air ducts.
The introduction of natural gas as a fuel can reduce boiler efficiency
slightly, due in large part to the relatively high hydrogen content of
natural gas. However, since the reduction in coal can result in reduced
auxiliary power demand, the overall impact on net heat rate can range
from a 2 percent increase to a 2 percent decrease.
It is common practice for steam generating units to have the
capability to burn multiple fuels onsite, and of the 565 coal-fired
steam generating units operating at the end of 2021, 249 of them
reported consuming natural gas as a fuel or startup source. Coal-fired
steam generating units often use natural gas or oil as a startup fuel,
to warm the units up before running them at full capacity with coal.
While startup fuels are generally used at low levels (up to roughly 1
percent of capacity on an annual average basis), some coal-fired steam
generating units have co-fired natural gas at considerably higher
shares. Based on hourly reported CO2 emission rates from the
start of 2015 through the end of 2020, 29 coal-fired steam generating
units co-fired with natural gas at rates at or above 60 percent of
capacity on an hourly basis.\557\ The capability of those units on an
hourly basis is indicative of the extent of boiler burner modifications
and sizing and capacity of natural gas pipelines to those units, and
implies that those units are technically capable of co-firing at least
60 percent natural gas on a heat input basis on average over the course
of an extended period (e.g., a year). Additionally, during that same
2015 through 2020 period, 29 coal-fired steam generating units co-fired
natural gas at over 40 percent on an annual heat input basis. Because
of the number of units that have demonstrated co-firing above 40
percent of heat input, the EPA is proposing that co-firing at 40
percent is adequately demonstrated. A more detailed discussion of the
record of natural gas co-firing, including current trends, at coal-
fired steam generating units is included in the GHG Mitigation Measures
for Steam Generating Units TSD.
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\557\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. Available from EPA's Air Markets Program
Data website: https://campd.epa.gov.
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(B) Natural Gas Pipeline Development
In addition to any potential boiler modifications, the supply of
natural gas is necessary to enable co-firing at existing coal-fired
steam boilers. As discussed in the previous section, many plants
already have at least some access to natural gas. In order to increase
natural gas access beyond current levels, many will find it necessary
to construct natural gas supply pipelines.
The U.S. natural gas pipeline network consists of approximately 3
million miles of pipelines that connect natural gas production with
consumers of natural gas. To increase natural gas consumption at a
coal-fired boiler without sufficient existing natural gas access, it is
necessary to connect the facility to the natural gas pipeline
transmission network via the construction of a lateral pipeline. The
cost of doing so is a function of the total necessary pipeline capacity
(which is characterized by the length, size, and number of laterals)
and the location of the plant relative to the existing pipeline
transmission network. The EPA estimated the costs associated with
developing new lateral pipeline capacity sufficient to meet 60 percent
of the net summer capacity at each coal-fired steam generating unit. As
discussed in the GHG Mitigation Measures for Steam Generating Units
TSD, the EPA estimates that this lateral capacity would be sufficient
to enable each unit to achieve 40 percent natural gas co-firing on an
annual average basis.
The EPA considered the availability of the upstream natural gas
pipeline capacity to satisfy the assumed co-firing demand implied by
these new laterals. This analysis included pipeline development at all
EGUs that could be included in this subcategory. The EPA's assessment
reviewed the reasonableness of each assumed new lateral by determining
whether the peak gas capacity of that lateral could be satisfied
without modification of the transmission pipeline systems to which it
is assumed to be connected. This analysis found that most, if not all,
existing pipeline systems are currently able to meet the peak needs
implied by these new laterals in aggregate, assuming that each existing
coal-fired unit in the analysis co-fired with natural gas at a level
implied by these new laterals, or 60 percent of net summer generating
capacity. While this is a reasonable assumption for the analysis to
support this mitigation measure in the BSER context, it is also a
conservative assumption that overstates the amount of natural gas co-
firing expected under the proposed rule.
The maximum amount of pipeline capacity, if all coal-fired steam
capacity in the medium-term subcategory implemented the proposed BSER
by co-firing 40 percent natural gas, would be a fraction of the
pipeline capacity constructed recently. The EPA estimates that this
maximum total capacity would be about 17.3 billion cubic feet per day,
which would require almost 4,000 miles of pipeline costing roughly
$13.3 billion. Over 5 years, this maximum total incremental pipeline
capacity would amount to 800 miles per year and approximately $2.7
billion per year in capital expenditures, on average. By comparison,
based on data collected by EIA, the total annual mileage of natural gas
pipelines constructed over the 2017-2021 period ranged from
approximately 1,000 to 2,500 miles per year, with a total capacity of
10 to 25 billion cubic feet per day. This represents an estimated
annual investment of up to nearly $15 billion. These historical annual
values are much higher than the maximum annual values that could be
expected under this proposed BSER measure--which, as noted above,
represent a conservative estimate that overstates the amount of co-
firing that the EPA projects would occur under this proposed rule.
These conservatively high estimates of pipeline requirements also
compare favorably to industry projections of future pipeline capacity
additions. Based on a review of a 2018 industry report, titled ``North
America Midstream Infrastructure through 2035: Significant Development
Continues,'' investment in midstream infrastructure development is
expected to average about $37 billion per year through 2035, which is
lower than historical levels. Approximately $10 to $20 billion annually
is expected to be invested in natural gas pipelines through 2035. This
report also projects that an average of over 1,400 miles of new natural
gas pipeline will be built through 2035, which is similar to the
approximately 1,670 miles that were built on average from 2013 to 2017.
These values are considerably greater than the average annual
expenditure of $2.7 billion on 800 miles per year of new pipeline
construction that would be necessary for the entire operational fleet
of coal-fired steam generating units to co-fire with natural gas. The
actual pipeline investment for this subcategory would be substantially
lower.
ii. Costs
The capital costs associated with the addition of new gas burners
and other necessary boiler modifications depend on the extent to which
the current boiler is already able to co-fire with some
[[Page 33353]]
natural gas and on the amount of gas co-firing desired. The EPA
estimates that, on average, the total capital cost associated with
modifying existing boilers to operate at up to 100 percent of heat
input using natural gas is approximately $52/kW. These costs could be
higher or lower, depending on the equipment that is already installed
and the expected impact on heat rate or steam temperature.
While fixed O&M (FOM) costs can potentially decrease as a result of
decreasing the amount of coal consumed, it is common for plants to
maintain operation of one coal pulverizer at all times, which is
necessary for maintaining several coal burners in continuous service.
In this case, coal handling equipment would be required to operate
continuously and therefore natural gas co-firing would have limited
effect on reducing the coal-related FOM costs. Although, as noted,
coal-related FOM costs have the potential to decrease, the EPA does not
anticipate a significant increase in impact on FOM costs related to co-
firing with natural gas.
In addition to capital and FOM cost impacts, any additional natural
gas co-firing would result in incremental costs related to the
differential in fuel cost, taking into consideration the difference in
delivered coal and gas prices, as well as any potential impact on the
overall net heat rate. The EPA's post-IRA 2022 reference case projects
that in 2030, the average delivered price of coal will be $1.47/MMBtu
and the average delivered price of natural gas will be $2.53/MMBtu.
Thus, assuming the same level of generation and no impact on heat rate,
the additional fuel cost would be above $1/MMBtu on average in 2030.
The total additional fuel cost could increase or decrease depending on
the potential impact on net heat rate. An increase in net heat rate,
for example, would result in more fuel required to produce a given
amount of generation and thus additional cost. In the GHG Mitigation
Measures for Steam Generating Units TSD, the EPA's cost estimates
assume a 1 percent increase in net heat rate.
Finally, for plants without sufficient access to natural gas, it is
also necessary to construct new natural gas pipelines (``laterals'').
Pipeline costs are typically expressed in terms of dollars per inch of
pipeline diameter per mile of pipeline distance (i.e., dollars per
inch-mile), reflecting the fact that costs increase with larger
diameters and longer pipelines. On average, the cost for lateral
development within the contiguous U.S. is approximately $280,000 per
inch-mile (2019$), which can vary based on site-specific factors. The
total pipeline cost for each coal-fired steam generating unit is a
function of this cost, as well as a function of the necessary pipeline
capacity and the location of the plant relative to the existing
pipeline transmission network. The pipeline capacity required depends
on the amount of co-firing desired as well as on the desired level of
generation--a higher degree of co-firing while operating at full load
would require more pipeline capacity than a lower degree of co-firing
while operating at partial load. It is reasonable to assume that most
plant owners would develop sufficient pipeline capacity to deliver the
maximum amount of desired gas use in any moment, enabling higher levels
of co-firing during periods of lower fuel price differentials. Once the
necessary pipeline capacity is determined, the total lateral cost can
be estimated by considering the location of each plant relative to the
existing natural gas transmission pipelines as well as the available
excess capacity of each of those existing pipelines. For purposes of
the cost reasonableness estimates as follows, the EPA assumes pipeline
costs of $92/kW, which is the median value of all unit-level pipeline
cost estimates, as explained in the GHG Mitigation Measures for Steam
Generating Units TSD. The range in costs reflects a range in the
amortization period of the capital costs over 6 to 10 years, which is
consistent with the amount of time over which the units in the medium-
term subcategory could be operational.
The EPA sums the natural gas co-firing costs as follows: For a
typical base load coal-fired steam generating unit in 2030, the EPA
estimates that the cost of co-firing with 40 percent natural gas on an
annual average basis is approximately $53 to $66/ton CO2
reduced, or $9 to $12/MWh, respective to amortization periods of 10 to
6 years. This estimate is based on the characteristics of a typical
coal-fired unit in 2021 (400 MW capacity and an average heat rate of
10,500 Btu/kWh) operating at a typical capacity factor of about 50
percent, and it assumes a pipeline cost of $92/kW, as discussed earlier
in this preamble.
Based on the coal-fired steam generating units that existed in 2021
and that do not have known plans to cease operations or convert to gas
by 2030, and assuming that each of those units continues to operate at
the same level in 2030 as it operated in 2017-2021, on average, the EPA
estimates that the weighted average cost of co-firing with 40 percent
natural gas on an annual average basis is approximately $64 to $78/ton
CO2 reduced, or $11 to $14/MWh. The $/ton cost estimate is
lower than average for approximately 82 GW, and the $/MWh cost estimate
is lower than average for 86 GW (about 69 percent and 72 percent,
respectively, of the relevant coal fleet). These estimates and all
underlying assumptions are explained in detail in the GHG Mitigation
Measures for Steam Generating Units TSD.
As was described in section X.D.1 of this preamble, the EPA has
compared the estimated costs discussed in section X.D.2 of this
preamble to costs that coal-fired steam generating units have incurred
to install controls that reduce other air pollutants, such as
SO2. Compared to the representative costs of controls
detailed in section VII.F.3.b.iii(B)(5) of this preamble (i.e.,
emission control costs on EGUs of $10.60 to $29/MWh and the costs in
the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source
category of $98/ton of CO2e reduced (80 FR 56627; September
18, 2015)), both estimates of annualized costs of natural gas co-firing
(approximately $53-$66/ton or $9-$12/MWh for a typical unit and $64-
$78/ton or $11-$14/MWh on average)) are comparable or lower. The range
of cost effectiveness estimates presented in this section is lower than
previously estimated by the EPA in the proposed CPP, for several
reasons. Since then, the expected difference between coal and gas
prices has decreased significantly, from over $3/MMBtu to about $1/
MMBtu in this proposal. Additionally, a recent analysis performed by
Sargent and Lundy for the EPA supports a considerably lower capital
cost for modifying existing boilers to co-fire with natural gas. The
EPA also recently conducted a highly detailed facility-level analysis
of natural gas pipeline costs, the median value of which is slightly
lower than the value used by the EPA previously to approximate the cost
of co-firing at a representative unit.
Based on the cost analysis presented in this section, the EPA is
proposing that the costs of natural gas co-firing are reasonable for
the medium-term coal-fired steam generating unit subcategory.
iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Natural gas co-firing for steam generating units is not expected to
have any significant adverse consequences related to non-air quality
health and environmental impacts or energy requirements.
[[Page 33354]]
(A) Non-GHG Emissions
Non-GHG emissions are reduced when steam generating units co-fire
with natural gas because less coal is combusted. SO2,
PM2.5, acid gas, mercury and other hazardous air pollutant
emissions that result from coal combustion are reduced proportionally
to the amount of natural gas consumed, i.e., under this proposal, by 40
percent. Natural gas combustion does produce NOX emissions,
but in lesser amounts than from coal-firing. However, the magnitude of
this reduction is dependent on the combustion system modifications that
are implemented to facilitate natural gas co-firing.
Additionally, sufficient regulations exist related to natural gas
pipelines and transport that assure natural gas can be safely
transported with minimal risk of environmental release. PHMSA develops
and enforces regulations for the safe, reliable, and environmentally
sound operation of the nation's 2.6 million mile pipeline
transportation system. Recently, PHMSA finalized a rule that will
improve the safety and strengthen the environmental protection of more
than 300,000 miles of onshore gas transmission pipelines.\558\ PHMSA
also recently promulgated a rule covering natural gas
transmission,\559\ as well as a rule that significantly expanded the
scope of safety and reporting requirements for more than 400,000 miles
of previously unregulated gas gathering lines.\560\ Additionally, FERC
oversees the development of new natural gas pipelines.
---------------------------------------------------------------------------
\558\ Pipeline Safety: Safety of Gas Transmission Pipelines:
Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments (87
FR 52224; August 24, 2022).
\559\ Pipeline Safety: Safety of Gas Transmission Pipelines:
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other
Related Amendments (84 FR 52180; October 1, 2019).
\560\ Pipeline Safety: Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments (86 FR 63266; November
15, 2021).
---------------------------------------------------------------------------
(B) Energy Requirements
The introduction of natural gas co-firing will cause steam boilers
to be slightly less efficient due to the high hydrogen content of
natural gas. Co-firing at levels between 20 percent and 100 percent can
be expected to decrease boiler efficiency between 1 percent and 5
percent. However, despite the decrease in boiler efficiency, the
overall net output efficiency of a steam generating unit that switches
from coal- to natural gas-firing may change only slightly, in either a
positive or negative direction. Since co-firing reduces coal
consumption, the auxiliary power demand related to coal handling and
emissions controls typically decreases as well. While a site-specific
analysis would be required to determine the overall net impact of these
countervailing factors, generally the effect of co-firing on net unit
heat rate can vary within approximately plus or minus 2 percent.
The EPA previously determined in the ACE Rule (84 FR 32520 at
32545; July 8, 2019) that ``co-firing natural gas in coal-fired utility
boilers is not the best or most efficient use of natural gas and [. .
.] can lead to less efficient operation of utility boilers.'' That
determination was informed by the more limited supply of natural gas,
and the larger amount of coal-fired EGU capacity and generation, in
2019. Since that determination, the expected supply of natural gas has
expanded considerably, and the capacity and generation of the existing
coal-fired fleet has decreased, reducing the total mass of natural gas
that might be required for sources to implement this measure.
Additionally, the natural gas co-firing measure is now being proposed
for a medium-term coal-fired steam generating unit subcategory, a group
of units that will operate at most for 10 years following the
compliance date, which would further reduce the total amount of
required natural gas.
Furthermore, regarding the efficient operation of boilers, the ACE
determination was based on the observation that ``co-firing can
negatively impact a unit's heat rate (efficiency) due to the high
hydrogen content of natural gas and the resulting production of water
as a combustion by-product.'' That finding does not consider the fact
that the effect of co-firing on net unit heat rate can vary within
approximately plus or minus 2 percent, and therefore the net impact on
overall utility boiler efficiency for each steam generating unit is
uncertain.
For all of these reasons, the EPA is proposing that natural gas co-
firing at medium-term coal-fired steam generating units does not result
in any significant adverse consequences related to energy requirements.
Additionally, the EPA considered longer term impacts on the energy
sector, and the EPA is proposing these impacts are reasonable.
Designating natural gas co-firing as the BSER for medium-term coal-
fired steam generating units would not have significant adverse impacts
on the structure of the energy sector. Steam generating units that
currently are coal-fired would be able to remain primarily coal-fired.
The replacement of some coal with natural gas as fuel in these sources
would not have significant adverse effects on the price of natural gas
or the price of electricity.
iv. Extent of Reductions in CO2 Emissions
One of the primary benefits of natural gas co-firing is emission
reduction. CO2 emissions are reduced by approximately 4
percent for every additional 10 percent of co-firing. When shifting
from 100 percent coal to 60 percent coal and 40 percent natural gas,
CO2 stack emissions are reduced by approximately 16 percent.
Non-CO2 emissions are reduced as well, as noted earlier in
this preamble.
v. Technology Advancement
Natural gas co-firing is already well-established and widely used
by coal-fired steam boiler generating units. As a result, this proposed
rule is not likely to lead to technological advances or cost reductions
in the components of natural gas co-firing, including modifications to
boilers and pipeline construction. However, greater use of natural gas
co-firing may lead to improvements in the efficiency of conducting
natural gas co-firing and operating the associated equipment.
c. Conclusion
The EPA proposes that natural gas co-firing at 40 percent of heat
input is the BSER for medium-term coal-fired steam generating units
because natural gas co-firing is adequately demonstrated, as indicated
by the facts that it has been operated at scale and is widely
applicable to sources. Additionally, the costs for natural gas co-
firing are reasonable. Moreover, any adverse non-air quality health and
environmental impacts and energy requirements of natural gas co-firing
are limited and are outweighed by the benefits of the emission
reductions at reasonable cost. In contrast, CCS, although achieving
greater emission reductions, would be less cost-effective, in general,
for the proposed subcategory of medium-term units.
While the EPA is not proposing CCS as BSER for the proposed
subcategory definition of medium-term units, the EPA is taking comment
on the operating horizons that define the threshold date between
medium-term and long-term units (i.e., between 8 and 10 years, instead
of the proposed 10-year operating horizon) and on what amount of costs
should be considered reasonable.
[[Page 33355]]
3. Imminent-Term and Near-Term Coal-Fired Steam Generating Units
In this section of the preamble, the EPA evaluates CCS, natural gas
co-firing, low levels of natural gas co-firing, and routine methods of
operation and maintenance as the BSER for imminent-term and near-term
coal-fired steam generating units. Primarily because of the effect of a
short operating horizon on the cost of controls for these units, the
EPA proposes routine methods of operation and maintenance as the BSER.
a. CCS
As noted in section X.D.2.a of this preamble, the EPA is not
proposing CCS for medium-term units due to $/MWh costs being less
favorable based on the appropriate cost metrics. Because of the shorter
operating horizons for imminent-term and near-term coal-fired steam
generating units, CCS is less cost favorable for them than for medium-
term units. Therefore, the EPA is not proposing CCS as BSER for
imminent-term or near-term coal-fired steam generating units.
Additional details of cost values for amortization periods
representative of imminent-term and near-term units are available in
the GHG Mitigation Measures for Steam Generating Units TSD.
b. Natural Gas Co-Firing
i. Natural Gas Co-Firing at 40 Percent
Much of the discussion of natural gas co-firing in section X.D.2.b
of this preamble for medium-term units is relevant for imminent-term
and near-term units, except that natural gas co-firing is less cost
effective for the latter units because of their short operating
horizons, particularly on a $/ton of CO2 reduced basis. For
a 2-year amortization period, annualized costs for the representative
unit are $130/ton of CO2 reduced and $23/MWh of generation.
Therefore, the EPA is not proposing natural gas co-firing as BSER for
imminent-term or near-term units. Additional details of cost are
available in the GHG Mitigation Measures for Steam Generating Units
TSD.
ii. Natural Gas Co-Firing at Low Levels of Heat Input
Although higher levels of natural gas co-firing may be less cost
effective for imminent-term and near-term units, it is possible that
lower levels of natural gas co-firing may be cost reasonable. Many
units have demonstrated the ability to co-fire with natural gas over
short periods of time and operating with those same levels of natural
gas co-firing over longer periods of time (i.e., annually) may achieve
emission reductions. A low level of natural gas co-firing (up to 10
percent of annual heat input) is adequately demonstrated and may be
broadly achievable, may achieve reductions in GHG emissions, may be of
reasonable cost, and is unlikely to cause unreasonable adverse non-air
quality health and environmental impacts or result in substantial
energy requirements. Therefore, the EPA is soliciting comment on low
levels of natural gas co-firing as a potential component of the BSER
for imminent-term and near-term coal-fired steam generating units.
The EPA recognizes that different coal-fired units may be already
capable of different natural gas co-firing rates (as discussed in
section X.D.2.b.i of this preamble) and is therefore soliciting comment
on defining a potential BSER on the basis of the maximum hourly heat
input of natural gas fired in the unit (MMBtu/hr) relative to the
maximum hourly heat input the unit is capable of (i.e., the nameplate
capacity on an MMBtu/hr basis). Alternatively, the EPA is soliciting
comment on a fixed value of annual heat input percentage that
represents a low level of natural gas co-firing, as well as the
definition of a low level of natural gas co-firing that is based on the
characteristics of an existing facility (e.g., the capacity of the
existing pipeline). The EPA is also soliciting comment on a degree of
emission limitation resulting from low levels of natural gas co-firing,
as detailed in section X.D.4.c of this preamble.
(1) Adequately Demonstrated
For many of the same reasons stated in section X.D.2.b.i of this
preamble for natural gas co-firing at higher levels, natural gas co-
firing at low levels is adequately demonstrated. The EPA also
identified that 369 of the 565 EGUs operating at the end of 2021 have
either reported natural gas as a fuel source, are located at a plant
with a natural gas generator, and/or are located at a plant with a
natural gas pipeline connection. A large percentage of the existing
fleet of coal-fired steam generating units would therefore likely be
able to co-fire natural gas at low levels without having to make boiler
modifications or build additional pipelines.
(2) Costs
The costs of low levels of natural gas co-firing may be reasonable
because low levels of natural gas co-firing likely require little, if
any, capital investment. Additionally, the relatively small increase in
natural gas fuel use would only result in a modest increase in total
fuel cost.
(3) Non-Air Quality Health and Environmental Impact and Energy
Requirements
For many of the same reasons stated in section X.D.2.b.iii of this
preamble, low levels of natural gas co-firing are unlikely to cause
unreasonable adverse non-air quality health and environmental impacts
or result in substantial energy requirements. Furthermore, low levels
of natural gas co-firing may require only limited construction of
additional infrastructure as existing pipeline laterals to the units
should be of sufficient size to achieve low levels of natural gas co-
firing.
(4) Extent of Reductions in CO2 Emissions
The emission reductions achieved at the unit from low levels of
natural gas co-firing of 1 to 10 percent may be relatively low at
around 0.4 to 4 percent, respectively. However, these are likely on
average greater than the emission reductions that could be achievable
by other technologies, such as HRI. Furthermore, because the efficiency
of the unit is not increased as with HRI, the unit likely does not move
up in dispatch order, and it is likely the unit would not be subject to
the rebound effect. See section X.D.5 of this preamble for a discussion
of HRI.
(5) Technology Advancement
Low levels of natural gas co-firing do not advance useful control
technology, for reasons similar to those discussed in section X.D.2.b.v
of this preamble.
c. Routine Methods of Operation and Maintenance
For the imminent-term and near-term coal-fired steam generating
units, the EPA is proposing that the BSER is routine methods of
operation and maintenance already occurring at the unit, so as to
maintain the current unit-specific CO2 emission rates
(expressed as lb CO2/MWh).
Routine methods of operation and maintenance are adequately
demonstrated because units already operate by those methods. They will
not result in additional costs from any controls, and will not create
adverse non-air quality health and environmental impacts or energy
requirements. They will not achieve CO2 emission reductions
at the unit level relative to current performance, but they can prevent
worsening of emission rates over time. Although they do not advance
useful control technology, they do not have adverse impacts on the
energy sector from a nationwide or long-term perspective.
[[Page 33356]]
4. Degree of Emission Limitation
Under CAA section 111(d), once the EPA determines the BSER, it must
determine the ``degree of emission limitation'' achievable by the
application of the BSER. States then determine standards of performance
and include them in the State plans, based on the specified degree of
emission limitation. Proposed presumptive standards of performance are
detailed in section XII.D of this preamble. There is substantial
variation in emission rates among coal-fired steam generating units--
the range is, approximately, from 1,700 lb CO2/MWh-gross to
2,500 lb CO2/MWh-gross--which makes it challenging to
determine a single, uniform emission limit. Accordingly, for each of
the four subcategories of coal-fired steam generating units, the EPA is
proposing to determine the degree of emission limitation by a
percentage change in emission rate, as follows:
a. Long-Term Coal-Fired Steam Generating Units
As discussed earlier in this preamble, the EPA is proposing the
BSER for long-term coal-fired steam generating units as ``full-
capture'' CCS, defined as 90 percent capture of the CO2 in
the flue gas. The degree of emission limitation achievable by applying
this BSER can be determined on a rate basis. A capture rate of 90
percent results in reductions in the emission rate of 88.4 percent on a
lb CO2/MWh-gross basis, and this reduction in emission rate
can be observed over an extended period (e.g., an annual calendar-year
basis). Therefore, the EPA is proposing that the degree of emission
limitation for long-term units is an 88.4 percent reduction in emission
rate on a lb CO2/MWh-gross basis over an extended period
(e.g., an annual calendar-year basis).
As noted in section X.D.1.a of this preamble, new CO2
capture retrofits on existing coal-fired steam generating units may
achieve capture rates greater than 90 percent, and the EPA is taking
comment on a range of capture rates that may be achievable. As noted in
section VII.F.3.b.iii(A)(2) of this preamble, the operating
availability (i.e., the amount of time a process operates relative to
the amount of time it planned to operate) of industrial processes is
usually less than 100 percent. Assuming that CO2 capture
achieves 90 percent capture when available to operate, that CCS is
available to operate 90 percent of the time the coal-fired steam
generating unit is operating, and that the steam generating unit
operates the same whether or not CCS is available to operate, total
emission reductions would be 81 percent. Higher levels of emission
reduction could occur for higher capture rates coupled with higher
levels of operating availability relative to operation of the steam
generating unit. If the steam generating unit were not permitted to
operate when CCS was unavailable, there may be local reliability
consequences, and the EPA is soliciting comment on how to balance these
issues. Additionally, the EPA is soliciting comment on a range of the
degree of emission limitation achievable, in the form of a reduction in
emission rate of 75 to 90 percent when determined over an extended
period (e.g., an annual calendar-year basis).
b. Medium-Term Coal-Fired Steam Generating Units
As discussed earlier in this preamble, the BSER for medium-term
coal-fired steam generating units is 40 percent natural gas co-firing.
The application of 40 percent natural gas co-firing results in
reductions in the emission rate of 16 percent. Therefore, the degree of
emission limitation for these units is a 16 percent reduction in
emission rate on a lb CO2/MWh-gross basis over an extended
period (e.g., an annual calendar-year basis).
c. Imminent-Term and Near-Term Coal-Fired Steam Generating Units
As discussed above, the BSER for imminent-term and near-term coal-
fired steam generating units is routine methods of operation and
maintenance. Application of this BSER results in no increase in
emission rate. Thus, the degree of emission limitation corresponding to
the application of the BSER is no increase in emission rate on a lb
CO2/MWh-gross basis over an extended period (e.g., an annual
calendar-year basis).
Because the EPA is soliciting comment on low levels of natural gas
co-firing as a potential BSER for imminent-term and near-term units,
the EPA is also soliciting comment on the degree of emission limitation
that may be achievable by application of low levels of natural gas co-
firing. The EPA is soliciting comment on degrees of emission limitation
defined by reductions in emission rate on a lb CO2/MWh-gross
basis that are equal to the percent of heat input times 0.4, the
percent of reduction in emission rate that may be achieved for each
percent of natural gas heat input. For example, for natural gas co-
firing at 1 to 10 percent, this results in a degree of emission
limitation of 0.4 to 4 percent reduction in emission rate on a lb
CO2/MWh-gross basis (over an extended period of time). More
specifically, the EPA solicits comment on the degree of emission
limitation based on the calculation method defined in the preceding
text up to a 4 percent reduction in emission rate (lb CO2/
MWh-gross) over an extended period of time. Alternatively, as the EPA
is also soliciting comment on a fixed percent of low levels of natural
gas co-firing, the EPA is additionally soliciting comment on a fixed
degree of emission limitation based on the same calculation method.
Because the reductions in GHG emissions from low levels of natural gas
co-firing are relatively low and may be challenging to measure, the EPA
is also soliciting comment on a degree of emission limitation defined
on a percent of heat input basis, although the EPA also recognizes that
measurement of fuel flow may also have challenges.
5. Other Emission Reduction Measures
a. Heat Rate Improvements
Heat rate is a measure of efficiency that is commonly used in the
power sector. The heat rate is the amount of energy input, measured in
Btu, required to generate one kWh of electricity. The lower an EGU's
heat rate, the more efficiently it operates. As a result, an EGU with a
lower heat rate will consume less fuel and emit lower amounts of
CO2 and other air pollutants per kWh generated as compared
to a less efficient unit. HRI measures include a variety of technology
upgrades and operating practices that may achieve CO2
emission rate reductions of 0.1 to 5 percent for individual EGUs. The
EPA considered HRI to be part of the BSER in the CPP and to be the BSER
in the ACE Rule. However, the reductions that may be achieved by HRI
are small relative to the reductions from natural gas co-firing and
CCS. Also, some facilities that apply HRI would, as a result of their
increased efficiency, increase their utilization and therefore increase
their CO2 emissions (as well as emissions of other air
pollutants), a phenomenon that the EPA has termed the ``rebound
effect.'' Therefore, the EPA is not proposing HRI as a part of BSER.
i. CO2 Reductions From HRI in Prior Rulemakings
In the CPP, the EPA quantified emission reductions achievable
through heat rate improvements on a regional basis by an analysis of
historical emission rate data, taking into consideration operating load
and ambient temperature. The Agency concluded that EGUs can achieve on
average a 4.3 percent improvement in the Eastern Interconnection, a 2.1
[[Page 33357]]
percent improvement in the Western Interconnection, and a 2.3 percent
improvement in the Texas Interconnection. See 80 FR 64789 (October 23,
2015). The Agency then applied all three of the building blocks to 2012
baseline data and quantified, in the form of CO2 emission
rates, the reductions achievable in each interconnection in 2030, and
then selected the least stringent as a national performance rate. Id.
at 64811-19. The EPA noted that building block 1 measures could not by
themselves constitute the BSER because the quantity of emission
reductions achieved would be too small and because of the potential for
an increase in emissions due to increased utilization (i.e., the
``rebound effect'').
A description of the ACE Rule is detailed in section IX of this
preamble.
ii. Updated CO2 Reductions From HRI
The HRI measures include improvements to the boiler island (e.g.,
neural network system, intelligent sootblower system), improvements to
the steam turbine (e.g., turbine overhaul and upgrade), and other
equipment upgrades (e.g., variable frequency drives). Some regular
practices that may recover degradation in heat rate to recent levels--
but that do not result in upgrades in heat rate over recent design
levels and are therefore not HRI measures--include practices such as
in-kind replacements and regular surface cleaning (e.g., descaling,
fouling removal). Specific details of the HRI measures are described in
the GHG Mitigation Measures for Steam Generating Units TSD and an
updated 2023 Sargent and Lundy HRI report (Heat Rate Improvement Method
Costs and Limitations Memo), available in the docket. Most HRI upgrade
measures achieve reductions in heat rate of less than 1 percent. In
general, the 2023 Sargent and Lundy HRI report, which updates the 2009
Sargent and Lundy HRI report, shows that HRI achieve less reductions
than indicated in the 2009 report, and shows that several HRI either
have limited applicability or have already been applied at many units.
Steam path overhaul and upgrade may achieve reductions up to 5.15
percent, with the average being around 1.5 percent. Different
combinations of HRI measures do not necessarily result in cumulative
reductions in emission rate (e.g., intelligent sootblowing systems
combined with neural network systems). Some of the HRI measures (e.g.,
variable frequency drives) only impact heat rate on a net generation
basis by reducing the parasitic load on the unit and would thereby not
be observable for emission rates measured on a gross basis. Assuming
many of the HRI measures could be applied to the same unit, adding
together the upper range of some of the HRI percentages could yield an
emission rate reduction of around 5 percent. However, the reductions
that the fleet could achieve on average are likely much smaller. As
noted, the 2023 Sargent and Lundy HRI report notes that, in many cases,
units have already applied HRI upgrades or that those upgrades would
not be applicable to all units. The unit level reductions in emission
rate from HRI are small relative to CCS or natural gas co-firing. In
the CPP and ACE Rule, the EPA viewed CCS and natural gas co-firing as
too costly to qualify as the BSER; those costs have fallen since those
rules and, as a result, CCS and natural gas co-firing do qualify as the
BSER for the long-term and medium-term subcategories, respectively.
iii. Potential for Rebound in CO2 Emissions
Reductions achieved on a rate basis from HRI may not result in
overall emission reductions and could instead cause a ``rebound
effect'' from increased utilization. A rebound effect would occur
where, because of an improvement in its heat rate, a steam generating
unit experiences a reduction in variable operating costs that makes the
unit more competitive relative to other EGUs and consequently raises
the unit's output. The increase in the unit's CO2 emissions
associated with the increase in output would offset the reduction in
the unit's CO2 emissions caused by the decrease in its heat
rate and rate of CO2 emissions per unit of output. The
extent of the offset would depend on the extent to which the unit's
generation increased. The CPP did not consider HRI to be BSER on its
own, in part because of the potential for a rebound effect. Analysis
for the ACE Rule, where HRI was the entire BSER, observed a rebound
effect for certain sources in some cases. In this action, where
different subcategories of units are proposed to be subject to
different BSER measures, steam generating units in a hypothetical
subcategory with HRI as BSER could experience a rebound effect. Because
of this potential for perverse GHG emission outcomes resulting from
deployment of HRI at certain steam generating units, coupled with the
relatively minor overall GHG emission reductions that would be expected
from this measure, the EPA is not proposing HRI as the BSER for any
subcategory of existing coal-fired steam generating units.
E. Natural Gas-Fired and Oil-Fired Steam Generating Units
In this section of the preamble, the EPA is addressing natural gas-
and oil-fired steam generating units. The EPA is proposing the BSER and
degree of emission limitation achievable by application of the BSER for
those units and identifying the associated emission rates that States
may apply to these units. For the reasons described here, the EPA is
proposing subcategories based on load level (i.e., annual capacity
factor), specifically, units that are base load, intermediate load, and
low load. At this time, the EPA is not proposing requirements for low
load units but is taking comment on a BSER of lower emitting fuels for
those units. The EPA is proposing routine methods of operation and
maintenance as BSER for intermediate and base load units. Applying that
BSER would not achieve emission reductions but would prevent increases
in emission rates. The EPA is proposing presumptive standards of
performance that differ between intermediate and base load units due to
their differences in operation, as detailed in section XII.D.1.b.v of
this preamble. The EPA is also proposing a separate subcategory for
non-continental oil-fired steam generating units, which operate
differently from continental units, with presumptive standards of
performance detailed in section XII.D.1.b.vi of this preamble.
Natural gas- and oil-fired steam generating units combust natural
gas or distillate fuel oil or residual fuel oil in a boiler to produce
steam for a turbine that drives a generator to create electricity. In
non-continental areas, existing natural gas- and oil-fired steam
generating units may provide base load power, but in the continental
U.S., most existing units operate in a load-following manner. There are
approximately 200 natural gas-fired steam generating units and fewer
than 30 oil-fired steam generating units in operation in the
continental U.S. Fuel costs and inefficiency relative to other
technologies (e.g., combustion turbines) result in operation at lower
annual capacity factors for most units. Based on data reported to EIA
and CAMD for the contiguous U.S., for natural gas-fired steam
generating units in 2019, the average annual capacity factor was less
than 15 percent and 90 percent of units had annual capacity factors
less than 35 percent. For oil-fired steam generating units in 2019, no
units had annual capacity factors above 8 percent. Additionally, their
load-following method of operation results in frequent cycling and a
greater proportion of time
[[Page 33358]]
spent at low hourly capacities, when generation is less efficient.
Furthermore, because startup times for most boilers are usually long,
natural gas steam generating units may operate in standby mode between
periods of peak demand. Operating in standby mode requires combusting
fuel to keep the boiler warm, and this further reduces the efficiency
of natural gas combustion.
Unlike coal-fired steam generating units, the CO2
emission rates of oil- and natural gas-fired steam generating units
that have similar annual capacity factors do not vary considerably
between units. This is partly due to the more uniform qualities (e.g.,
carbon content) of the fuel used. However, the emission rates for units
that have different annual capacity factors do vary considerably, as
detailed in the Natural Gas- and Oil-fired Steam Generating Unit TSD.
Low annual capacity factor units cycle frequently, have a greater
proportion of CO2 emissions that may be attributed to
startup, and have a greater proportion of generation at inefficient
hourly capacities. Intermediate annual capacity factor units operate
more often at higher hourly capacities, where CO2 emission
rates are lower. High annual capacity factor units operate still more
at base load conditions, where units are more efficient and
CO2 emission rates are lower. Based on these performance
differences between these load levels, the EPA is, in general,
proposing to divide natural gas- and oil-fired steam generating units
into three subcategories each--low load, intermediate load, and base
load--as specified in section X.C.2 of this preamble: ``low'' load is
defined by annual capacity factors less than 8 percent,
``intermediate'' load is defined by annual capacity factors greater
than or equal to 8 percent and less than 45 percent, and ``base'' load
is defined by annual capacity factors greater than 45 percent.
1. Options Considered for BSER
The EPA has considered various methods for controlling
CO2 emissions from natural gas- and oil-fired steam
generating units to determine whether they meet the criteria for BSER.
Co-firing natural gas cannot be the BSER for these units because
natural gas- and oil-fired steam generating units already fire large
proportions of natural gas. Most natural gas-fired steam generating
units fire more than 90 percent natural gas on a heat input basis, and
any oil-fired steam generating units that would potentially operate
above an annual capacity factor of around 15 percent would combust
natural gas as a large proportion of their fuel as well. Nor is CCS a
candidate for BSER. The utilization of most gas-fired units, and likely
all oil-fired units, is relatively low, and as a result, the amount of
CO2 available to be captured is low. However, the capture
equipment would still need to be sized for the nameplate capacity of
the unit. Therefore, the capital and operating costs of CCS would be
high relative to the amount of CO2 available to be captured.
Additionally, again due to lower utilization, the amount of IRC section
45Q tax credits that owner/operators could claim would be low. Because
of the relatively high costs and the relatively low cumulative emission
reduction potential for these natural gas- and oil-fired steam
generating units, the EPA is not proposing CCS as the BSER for them.
The EPA has reviewed other possible controls but is not proposing
any of them as the BSER for natural gas- and oil-fired units either.
Co-firing hydrogen in a boiler is technically possible, but, for the
same reasons discussed in section VII of this preamble, the only
hydrogen that could be considered for the BSER would be low-GHG
hydrogen, and there is limited availability of that hydrogen now and in
the near future. Additionally, for natural gas-fired steam generating
units, setting a future standard based on hydrogen would have limited
GHG reduction benefits given the low utilization of natural gas- and
oil-fired steam generating units. Lastly, HRI for these types of units
would face many of the same issues as for coal-fired steam generating
units; in particular, HRI could result in a rebound effect that would
increase emissions.
However, the EPA recognizes that natural gas- and oil-fired steam
generating units could possibly, over time, operate more, in response
to other changes in the power sector. Additionally, some coal-fired
steam generating units have converted to 100 percent natural gas-fired,
and it is possible that more may do so in the future. Moreover, in part
because the fleet continues to age, the plants may operate with
degrading emission rates. In light of these possibilities, identifying
the BSER and degrees of emission limitation for these sources would be
useful to provide clarity and prevent backsliding in GHG performance.
Therefore, the EPA is proposing BSER for intermediate and base load
natural gas- and oil-fired steam generating units to be routine methods
of operation and maintenance, such that the sources could maintain the
emission rates (on a lb/MWh-gross basis) currently maintained by the
majority of the fleet across discrete ranges of annual capacity factor.
The EPA is proposing this BSER for intermediate load and base load
natural gas- and oil-fired steam generating units, regardless of the
operating horizon of the unit.
A BSER based on routine methods of operation and maintenance is
adequately demonstrated because units already operate with those
practices. There are no or negligible additional costs because there is
no additional technology that units are required to apply and there is
no change in operation or maintenance that units must perform.
Similarly, there are no adverse non-air quality health and
environmental impacts or adverse impacts on energy requirements. Nor do
they have adverse impacts on the energy sector from a nationwide or
long-term perspective. The EPA's initial modeling, which supports this
proposed rule, indicates that by 2040, a number of natural gas-fired
steam generating units have remained in operation since 2030, although
at reduced annual capacity factors. There are no CO2
reductions that may be achieved at the unit level, but applying the
BSER should preclude increases in emission rates. Routine methods of
operation and maintenance do not advance useful control technology, but
this point is not significant enough to offset their benefits.
The EPA is also taking comment on, but not proposing, a BSER of
lower emitting fuels for low load natural gas- and oil-fired steam
generating units. As noted earlier in this preamble, non-coal fossil
fuels combusted in utility boilers typically include natural gas,
distillate fuel oil (i.e., fuel oil No. 1 and No. 2), and residual fuel
oil (i.e., fuel oil No. 5 and No. 6). The EPA previously established
heat-input based fuel composition as BSER in the 2015 NSPS (termed
``clean fuels'' in that rulemaking) for new non-base load natural gas-
and multi-fuel-fired stationary combustion turbines (80 FR 64615-17;
October 23, 2015), and the EPA is similarly proposing lower emitting
fuels as BSER for new low load combustion turbines as described in
section VII of this preamble. For low load natural gas- and oil-fired
steam generating units, the high variability in emission rates
associated with the variability of load at the lower-load levels limits
the benefits of a BSER based on routine maintenance and operation. That
is because the high variability in emission rates would make it
challenging to determine an emission rate (i.e., on a lb
CO2/MWh-gross basis) that could serve as the presumptive
standard of performance that would reflect application of a BSER of
routine operation and maintenance.
[[Page 33359]]
On the other hand, for those units, a BSER of ``uniform fuels'' and an
associated presumptive standard of performance based on a heat input
basis, as described in section XII.D of this preamble, may be
reasonable. The EPA is soliciting comment on the fuel types that would
constitute ``uniform fuels'' specific to low load natural gas- and oil-
fired steam generating units.
2. Degree of Emission Limitation
As discussed above, because the proposed BSER for base load and
intermediate load natural gas- and oil-fired steam generating plants is
routine operation and maintenance, which the units are, by definition,
already employing, the degree of emission limitation by application of
this BSER is no increase in emission rate on a lb CO2/MWh-
gross basis over an extended period of time (e.g., an annual calendar
year).
F. Summary
The EPA has evaluated options for BSER for GHG emissions for fossil
fuel-fired steam generating units. The EPA is proposing
subcategorization of steam generating units by the type of fossil fuel
fired in the unit, and, for each fuel type, further levels of
subcategorization. For each subcategory, the EPA is proposing a BSER
and resulting degree of emission limitation achievable by application
of that BSER, as summarized in table 5, with presumptively approvable
standards of performance for use in State plan development (see section
XII of this preamble for details) included for completeness. For coal-
fired steam generating units that plan to operate in the long-term, the
EPA is proposing a BSER of CCS with 90 percent capture of
CO2. In response to industry stakeholder input and
recognizing that the cost effectiveness of controls depends on a unit's
expected operating time horizon, which dictates the amortization period
for the capital costs of the controls, the EPA is proposing other BSER
for coal-fired units with shorter operating horizons while taking
comment on what dates most appropriately define the thresholds between
these different subcategories. For the different subcategories of
natural gas- and oil-fired units, the EPA is proposing BSERs based on
routine methods of operation and maintenance. The EPA solicits comment
on the proposed BSER and degrees of emission limitation, as well as the
proposed subcategorization, including the potential to remove the
imminent-term subcategory and include units with earlier commitments to
permanently cease operations in either the near-term or medium-term
subcategory. It is noted that for imminent-term and near-term coal-
fired steam generating units, the EPA is also soliciting comment on
potential BSERs based on co-firing low levels of natural gas.
---------------------------------------------------------------------------
\561\ Presumptive standards of performance are discussed in
detail in section XII of the preamble. While States establish
standards of performance for sources the EPA provides presumptively
approvable standards of performance based on the degree of emission
limitation achievable through application of the BSER for each
subcategory. Inclusion in this table is for completeness.
Table 5--Summary of Proposed BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Presumptively Ranges in values on
Affected EGUs Subcategory definition BSER Degree of emission approvable standard which the EPA is
limitation of performance \561\ soliciting comment
--------------------------------------------------------------------------------------------------------------------------------------------------------
Long-term existing coal-fired steam Coal-fired steam CCS with 90 percent 88.4 percent 88.4 percent The achievable
generating units. generating units that capture of CO2. reduction in reduction in annual capture rate from 90
have not elected to emission rate (lb emission rate (lb to 95 percent or
commit to permanently CO2/MWh-gross). CO2/MWh-gross) from greater and the
cease operations by the unit-specific achievable degree of
January 1, 2040. baseline. emission limitation
defined by a
reduction in
emission rate from
75 to 90 percent.
Medium-term existing coal-fired Coal-fired steam Natural gas co-firing A 16 percent A 16 percent The percent of
steam generating units. generating units that at 40 percent of the reduction in reduction in annual natural gas co-
have elected to heat input to the emission rate (lb emission rate (lb firing from 30 to 50
commit to permanently unit. CO2/MWh-gross). CO2/MWh-gross) from percent and the
cease operations the unit-specific degree of emission
after December 31, baseline. limitation from 12
2031, and before to 20 percent.
January 1, 2040, and
that are not near-
term units.
Near-term existing coal-fired steam Coal-fired steam Routine methods of No increase in An emission rate The presumptive
generating units. generating units that operation. emission rate (lb limit (lb CO2/MWh- standard: 0 to 2
have elected to CO2/MWh-gross). gross) defined by standard deviations
commit to permanently the unit-specific in annual emission
cease operations baseline. rate above or 0 to
after December 31, 10 percent above the
2031, and before unit-specific
January 1, 2035, and baseline.
commit to adopt an
annual capacity
factor limit of 20
percent.
Imminent-term existing coal-fired Coal-fired steam Routine methods of No increase in An emission rate The presumptive
steam generating units. generating units that operation. emission rate (lb limit (lb CO2/MWh- standard: 0 to 2
have elected to CO2/MWh-gross). gross) defined by standard deviations
commit to permanently the unit-specific in annual emission
cease operations baseline. rate above or 0 to
before January 1, 10 percent above the
2032. unit-specific
baseline.
[[Page 33360]]
Base load continental existing oil- Oil-fired steam Routine methods of No increase in An annual emission The threshold between
fired steam generating units. generating units with operation and emission rate (lb rate limit of 1,300 intermediate and
an annual capacity maintenance. CO2/MWh-gross). lb CO2/MWh-gross. base load from 40 to
factor greater than 50 percent annual
or equal to 45 capacity factor; the
percent. degree of emission
limitation from
1,250 lb CO2/MWh-
gross to 1,800 lb
CO2/MWh-gross.
Intermediate load continental Oil-fired steam Routine methods of No increase in An annual emission The degree of
existing oil-fired steam generating units with operation and emission rate (lb rate limit of 1,500 emission limitation
generating units. an annual capacity maintenance. CO2/MWh-gross). lb CO2/MWh-gross. from 1,400 lb CO2/
factor greater than MWh-gross to 2,000
or equal to 8 percent lb CO2/MWh-gross.
and less than 45
percent.
Low load (continental and non- Oil-fired steam None proposed......... ..................... ..................... The threshold between
continental) existing oil-fired generating units with low and intermediate
steam generating units. an annual capacity load from 5 to 20
factor less than 8 percent annual
percent. capacity factor.
Intermediate and base load non- Non-continental oil- Routine methods of No increase in An emission rate The presumptive
continental existing oil-fired fired steam operation and emission rate (lb limit (lb CO2/MWh- standard: 0 to 2
steam generating units. generating units with maintenance. CO2/MWh-gross). gross) defined by standard deviations
an annual capacity the unit-specific in annual emission
factor greater than baseline. rate above or 0 to
or equal to 8 percent. 10 percent above the
unit-specific
baseline.
Base load existing natural gas- Natural gas-fired Routine methods of No increase in An annual emission The threshold between
fired steam generating units. steam generating operation and emission rate (lb rate limit of 1,300 intermediate and
units with an annual maintenance. CO2/MWh-gross). lb CO2/MWh-gross. base load from 40 to
capacity factor 50 percent annual
greater than or equal capacity factor; The
to 45 percent. acceptable standard
from 1,250 lb CO2/
MWh-gross to 1,400
lb CO2/MWh-gross.
Intermediate load existing natural Natural gas-fired Routine methods of No increase in An annual emission The acceptable
gas-fired steam generating units. steam generating operation and emission rate (lb rate limit of 1,500 standard from 1,400
units with an annual maintenance. CO2/MWh-gross). lb CO2/MWh-gross. lb CO2/MWh-gross to
capacity factor 1,600 lb CO2/MWh-
greater than or equal gross.
to 8 percent and less
than 45 percent.
Low load existing natural gas-fired Natural gas-fired None proposed......... ..................... ..................... The threshold between
steam generating units. steam generating low and intermediate
units with an annual load from 5 to 20
capacity factor less percent annual
than 8 percent. capacity factor.
--------------------------------------------------------------------------------------------------------------------------------------------------------
XI. Proposed Regulatory Approach for Emission Guidelines for Existing
Fossil Fuel-fired Stationary Combustion Turbines
A. Overview
Because the EPA has established NSPS for GHG emissions from new
fossil fuel-fired stationary combustion turbines under CAA section
111(b), it has an obligation to also establish emission guidelines for
GHG emissions from existing fossil-fuel fired stationary combustion
turbines under CAA section 111(d). Existing fossil fuel-fired
stationary combustion turbines already represent a significant share of
GHG emissions from EGUs and are quickly becoming the largest source of
GHG emissions from the power sector. As other fossil fuel-fired EGUs
reduce utilization or retire, at least some of this generation may
shift to the existing combustion turbine fleet with significant GHG
emission implications, particularly if the latter is not subject to
limits on GHG emissions. For these reasons, the EPA intends to
discharge its obligation to prescribe emission guidelines for these
sources as expeditiously as practicable. In this document, the EPA is
proposing emission guidelines for certain existing fossil fuel-fired
stationary combustion turbines and soliciting comment on approaches
that could be used to establish emission guidelines for the remaining
units in the fleet.
In considering how to address this problem, the EPA believes there
are at least two key factors to consider. The first is that determining
the BSER and issuing emission guidelines covering these units sooner
rather than later is important to address the GHG emissions from this
growing portion of the inventory. The second is related to the size of
the affected fleet and the implications for the feasibility and timing
of implementing potential candidates for BSER. As discussed later in
this section, there are at least three technologies that could be
applied to reduce GHGs from existing combustion turbines (CCS, hydrogen
co-firing, and heat rate improvements), all of which are available
today and are being pursued to at least some degree by owners and
operators of these sources. Although the EPA believes that these
technologies are available and adequately demonstrated at the level of
individual existing combustion turbines, emission guidelines for these
sources must also consider how much of the fleet could reasonably
implement
[[Page 33361]]
one or more of these potential BSER approaches in a given time frame.
Furthermore, the EPA is aware that grid operators and power
companies currently rely on existing fossil fuel-fired combustion
turbines as a flexible and readily dispatchable resource that plays a
key role in fulfilling resource adequacy and operational reliability
needs. Although advancements in energy storage and accelerated
development and deployment of zero-emitting resources may diminish
reliance on existing fossil fuel-fired combustion turbines for
reliability purposes over time, it is imperative that emission
guidelines for these sources not impair the reliability of the bulk
power system. For these reasons, the EPA believes that it is important
that a BSER determination and associated emission guidelines for
existing fossil fuel-fired combustion turbines rely on GHG control
options that can be feasibly and cost-effectively implemented at a
scale commensurate with the size of the regulated fleet, and provide
sufficient operational flexibility and lead time to allow for smooth
implementation of the GHG emission limitations that preserves system
reliability.
Given the large size of the existing combustion turbine fleet and
the lead time required to develop CCS and hydrogen-related
infrastructure, the EPA believes the BSER for this category entails
significant lead time for application of CCS or low-GHG hydrogen co-
firing. As a result, the EPA is planning to break the existing
combustion turbine category into two segments, and is focusing this
proposal on the largest and most frequently operated (e.g., base load)
existing combustion turbines that have the highest GHG emissions on an
annual basis. For these large and frequently operated existing
combustion turbines, the EPA is proposing to determine that the BSER
consists of either application of CCS by 2035, or application of low-
GHG hydrogen co-firing beginning in 2032, based on an evaluation of the
statutory BSER criteria that mirrors EPA's evaluation of the BSER for
new base load combustion turbines. This focused approach will limit GHG
emissions from the highest-emitting existing natural gas combustion
turbines, while allowing sufficient lead time for application of CCS or
low-GHG hydrogen co-firing and limiting the amount of affected capacity
to a degree that is consistent with the availability of these two GHG
mitigation technologies. The EPA intends to undertake a separate
rulemaking as expeditiously as practicable that addresses emissions
from the remaining combustion turbines.
In this document, the EPA is soliciting comment on both the scope
of these proposed emission guidelines (in other words, the
applicability thresholds that would determine which existing combustion
turbines are in the first segment) as well as the BSER for units
covered in this rulemaking. In section XII of this preamble, the EPA is
also taking comment on the associated State plan requirements
associated with the BSER for existing fossil fuel-fired turbines.
As described in more detail below, the EPA is proposing to
determine that the BSER for large and frequently operated existing
stationary combustion turbines is the same as for the proposed second
phase of requirements for new base load combustion turbines.
Accordingly, the EPA is proposing emission guidelines for these
existing stationary combustion turbines that would require either that
these sources achieve a degree of emission limitation consistent with
the use of CCS by 2035, or achieve a degree of emission limitation
reflecting the utilization of 30 percent low-GHG hydrogen by volume by
2032 (increasing to 96 percent low-GHG hydrogen by volume by 2038).
The EPA believes that it is important to stagger CCS requirements
for existing coal-fired units and new and existing fossil fuel-fired
turbines to allow time for both deployment of CCS infrastructure and to
accommodate increased demand for specialized engineering and
construction labor needed to build CCS equipment. The EPA also believes
that because coal-fired units emit more CO2/MWh, that to the
extent that there are limitations to the amount of CCS that can be
installed by 2030 it makes sense to focus a CCS BSER on those coal-
fired units first. A 2035 compliance timeframe would allow for
staggering of resources needed to install CCS while still allowing
existing turbines to take advantage of the IRC section 45Q tax credits
to make CCS controls more cost-effective or to use hydrogen, produced
at facilities eligible for the 45V tax credits, making hydrogen co-
firing more cost effective.\562\ In the rest of this section, the EPA
proposes regulations for the first segment and solicits comment on
specific elements of the approach. This section also briefly discusses
what BSER might look like for units in the second rulemaking, and
requests comments that could inform the development of a rulemaking
defining BSER, degrees of emission limitation, compliance deadlines and
other elements of an emission guideline for those units at a later
date.
---------------------------------------------------------------------------
\562\ CCS projects that commence construction as late as
December 31, 2032 can qualify for the 45Q tax credit.
---------------------------------------------------------------------------
As explained in more detail later in this section, the EPA is
proposing that the first segment it would cover would be units greater
than 300 MW with an annual capacity factor of greater than 50 percent.
The EPA projects that 37 GW of capacity would meet these criteria in
2035, representing 14 percent of the projected existing combustion
turbine capacity and 23 percent of the projected generation from
existing combustion turbines in 2035. As is explained further below,
the EPA is proposing this capacity factor and capacity threshold after
weighing the quantity of emissions from these units and considerations
about the feasibility of installing significant amounts of CCS and/or
hydrogen co-firing. In short, these units offer the best opportunity to
achieve significant emissions reduction consistent with what the EPA
believes these technologies will be capable of on a national scale.
Similar to its proposal for new base load turbines, the EPA is
proposing that BSER for those existing sources be both pathways, that
is CCS with 90 percent capture in 2035 and clean hydrogen combusting 30
percent by volume in 2032 and 96 percent by volume in 2038.
Alternatively, as with the proposal for new base load turbines, the EPA
is taking comment on whether to finalize a BSER with a single pathway
based on application of CCS with 90 percent capture, which could also
be met by co-firing with low-GHG hydrogen as a compliance option, or
vice-versa. The EPA is also taking comment on whether the compliance
date should begin earlier, including as early as 2030.\563\
---------------------------------------------------------------------------
\563\ If we finalize one of these variations, the state plan
requirements may change accordingly.
---------------------------------------------------------------------------
The EPA has promulgated several prior rulemakings under both CAA
section 111(b) and section 111(d) that provide the regulated sector
with lead time to accommodate the time needed to deploy control
technology. Section VII.F.3.a of this preamble discusses, in the
section 111(b) context, precedent for rulemakings that provide such
lead time. For additional examples under CAA section 111(d), see 70 FR
28606, 28619 (May 18, 2005) (establishing emission guidelines for
electric utility steam generating units, with a 13-year compliance
timeframe for a second control phase); 61 FR 9905, 9919 (March 12,
1996) (establishing emission guidelines for municipal solid waste
landfills, with a 2.5-year compliance
[[Page 33362]]
timeframe); 62 FR 48348, 48381 (September 15, 1997) (establishing
emission guidelines for hospital/medical/infectious waste incinerators,
with up to 3 years after State plan approval for facilities to install
control equipment). Section XI.B provides background information
concerning the composition of the current fossil fuel-fired stationary
combustion turbine fleet and how it is expected to change in the near
future. In section XI.C, the EPA proposes an approach for units covered
in this rulemaking and in section XI.D, the EPA summarizes the key
topics for which we are soliciting comment relative to existing
combustion turbines. Finally, section XI.E, outlines a potential
approach for units covered in a second rulemaking
B. The Existing Stationary Combustion Turbine Fleet
In 2021, existing combustion turbines represented 37 percent of the
GHG emissions from the power sector and 40 percent of the generation
from the power sector. In the EPA's updated baseline projections for
the power sector, they represent 74 percent of the GHG emissions and 25
percent of the generation in 2035. In EPA's modeling of the 2035
control case, in which both existing fossil fuel-fired EGUs and new
stationary combustion turbine EGUs are subject to the emissions
limitations proposed in this action but existing combustion turbine
EGUs are left uncontrolled, load shifting from those two categories of
sources to the existing combustion turbines results in an increase in
the share of the emissions from existing combustion turbines (including
combined cycle and simple cycle combustion turbines) to 82 percent
while their share of generation remains 25 percent. Moreover, in that
control case, existing combined cycle combustion turbines are
responsible for 71 percent of the CO2 emissions from the
power sector.
In the EPA's modeling in support of these rules, we see two trends
that are important relative to existing combustion turbines. First, the
EPA's analysis of the reference case (which includes the impacts of IRA
without considering the GHG limitation requirements proposed in these
rules) projects a long-term decline in generation and emissions from
existing combustion turbines relative to current generation and
emissions. In this reference case, combined cycle generation falls in
each model run year from 2028 through 2050, and it falls by more than
50 percent between 2030 and 2045. Generation from existing simple cycle
combustion turbines is projected to peak in 2030 before declining by
more than 70 percent by 2045. While generation falls from turbines,
this is primarily caused by declining capacity factors, not through
retirements.
Historical data shows a wide range of variation in both the heat
rate and the GHG emission rates among both existing combined cycle
combustion turbines and existing simple cycle combustion turbines. The
GHG emission rates for existing combined cycle units range from as low
as 644 lb CO2/MWh-gross to as high as 1,891 lb
CO2/MWh-gross, and annual capacity factors range from as low
as 1 percent to as high as 85 percent. While there is some correlation
between units with low-GHG emission rates (e.g., more efficient units)
and utilization, some low efficiency combined cycle units have
historically operated at very high capacity factors. For instance, two
of the highest operating units (at 85 percent capacity utilization)
have GHG emission rates of nearly 1,200 lb/MWh-gross.
C. BSER for Base Load Turbines Over 300 MW
As noted earlier, the EPA is adopting an approach in which existing
combustion turbines would be regulated in two segments. The proposed
emission guidelines presented in this document focus on the first
segment, which comprises the base load units (e.g., those operated at
capacity factors of greater than 50 percent) over 300 MW. The EPA
intends to undertake a separate rulemaking to address the second
segment, comprising the remainder of the existing fossil fuel-fired
stationary combustion fleet, as expeditiously as practicable.
Because the first segment would be focused on the largest most
frequently used units, the EPA is proposing that the BSER for these
units would be CCS or a BSER based upon burning low-GHG hydrogen. As is
the case for new base load combustion turbines, each of these sets of
controls is adequately demonstrated, of reasonable cost, and consistent
with the other criteria to qualify as the BSER.
Because the second segment would include both smaller more
frequently used units and less frequently used units, in that action,
the EPA anticipates considering a broader range of technologies
including heat rate improvements. This approach recognizes the
imperatives (the urgent need to reduce greenhouse gases), the
opportunities (including the availability of IRC section 45Q tax
credits incentivizing CCS installation as long as sources commence
construction by January 1, 2033), and the need for infrastructure for
CCS and co-firing low-GHG hydrogen to be deployed at a broader scale if
these BSER technologies are to be deployed broadly at smaller and less
frequently operated existing combustion turbines.
The EPA is proposing emission guidelines for units with a capacity
factor greater than 50 percent and a capacity of greater than 300 MW,
but is also taking comment on whether that capacity factor threshold or
capacity threshold should be lower (for instance 40 percent for the
capacity factor and 200 MW or 100 MW for the capacity). The EPA is
proposing that 300 MW is the appropriate threshold for applicability
because it focuses on the units with the highest emissions where CCS is
likely to be most cost effective. As an important first step towards
abating emissions from the existing turbine fleet and recognizing that
at least some project developers are considering the use of clean
hydrogen in base load turbines \564\ and recognizing that there are
likely limits to the clean hydrogen supply in the mid-term, the EPA
believes that it is appropriate to also propose a clean hydrogen BSER
for the same set of units. Table 6 provides information from IPM
detailing the amount of capacity and generation from the 2035 IPM
projected control case that would be covered under various capacity
thresholds.
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\564\ As one developer notes, ``the plant will be capable of
supporting a balanced and diverse power generation portfolio in the
future; from energy storage capable of accommodating seasonal
fluctuations from renewable energy, to cost effective, dispatchable
intermediate and baseload power.'' https://www.longridgeenergy.com/news/2020-10-13-long-ridge-energy-terminal-partners-with-new-fortress-energy-and-ge-to-transition-power-plant-to-zero-carbon-hydrogen.
[[Page 33363]]
Table 6--Key Characteristics for Baseload Combined Cycle Units of
Various Capacities
------------------------------------------------------------------------
Percentage Percentage
NGCC units projected to run at a of total of total
capacity factor of greater than Capacity NGCC NGCC
50 percent and at a capacity size (GW) capacity generation
greater than (%) (%)
------------------------------------------------------------------------
100 MW........................... 134 49 78
200 MW........................... 85 31 51
300 MW........................... 37 14 23
400 MW........................... 12 4 10
500 MW........................... 6 2 7
------------------------------------------------------------------------
The EPA believes this approach would ensure that GHG emissions
limitations are implemented first at the subset of existing fossil
fuel-fired combustion turbines that contributes the most to GHG
emissions, and where the benefits of implementing GHG controls would be
greatest.
The EPA believes there are three sets of controls that could
potentially qualify as the BSER for the group of large and frequently-
operated combustion turbines covered in the first rulemaking. Those
controls are heat rate/efficiency improvements, co-firing low-GHG
hydrogen, and use of CCS. We discuss each of these below, and in the
course of each discussion explain why we are proposing that the
following controls qualify as the BSER: co-firing with low-GHG hydrogen
in the amounts of 30 percent (by volume) by 2032 and 96 percent (by
volume) by 2038, and the use of CCS with 90 percent capture by 2035.
1. Heat-Rate Improvements
The EPA believes that heat rate improvements for existing
combustion turbines are broadly applicable today. Heat rate/efficiency
improvements can be divided into two types. The first type involves
smaller scale improvements to existing combustion turbines. The second
type involves more comprehensive upgrades of the combustion turbines.
Smaller scale efficiency improvements can include measures such as
inlet fogging and inlet cooling. Both of these techniques can achieve
about 2 percent improvements in heat rate. Inlet chilling costs
approximately $19/kW and is also accompanied by a capacity increase of
11 percent. Inlet fogging is approximately $0.93/kW and is accompanied
by a capacity increase of 6 percent.\565\ These small-scale efficiency
improvements would likely result in an average 2 percent improvement in
the heat rate of affected existing combustion turbines.
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\565\ https://www.andovertechnology.com/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
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More comprehensive efficiency upgrades to combustion turbines are
also possible. An upgrade to the combustion turbine can result in a
heat rate improvement of 3.0 percent and a capacity increase of 13
percent for $172/kW, while an upgrade to the steam turbine can result
in a heat rate improvement of 3.2 percent with a capacity increase of 3
percent for $130/kW. These more comprehensive efficiency improvements
would likely result in an average efficiency improvement of 6 percent
for affected existing stationary combustion turbines. The EPA is not
proposing HRI improvements for units greater than 300 MW because they
achieve significantly less emission reductions than either CCS or co-
firing hydrogen, but believes that some units may choose to make these
upgrades as part of their response to installing CCS and/or co-firing
hydrogen. The EPA is taking comment on whether HRI should be considered
BSER (or a component of BSER) for combined cycle units with a capacity
factor of greater than 50 percent and a capacity of less than 300 MW as
part of this initial rulemaking.
2. Co-Firing Low-GHG Hydrogen
a. Overview
The EPA is proposing that for existing combined cycle combustion
turbines that operate at capacity factors of greater than 50 percent
and that are greater than 300 MW, co-firing 30 percent low-GHG hydrogen
by 2032 and 96 percent by 2038 qualifies as the BSER, for largely the
same reasons that apply to new combined cycle turbines, as discussed in
section VII.F.3.c.vii of this preamble. Co-firing hydrogen at these
levels is adequately demonstrated, as indicated by announced plans of
manufacturers and generators to undertake retrofit projects for
hydrogen co-firing. These plans also indicate that the costs of
retrofitting are reasonable. The analysis concerning the costs of low-
GHG hydrogen for existing turbines is comparable to the analysis for
new turbines. See section VII.F.3.c.vii.(B) of this preamble. Co-firing
with low-GHG hydrogen at existing turbines also has comparable non-air
quality environmental impacts and energy requirements, and comparable
emissions reductions as co-firing with low-GHG hydrogen at new
turbines. See sections VII.F.3.c.vii.(C)-(D) of this preamble. For
these reasons, the EPA is proposing that co-firing with low-GHG
hydrogen qualifies as the BSER. The fact that doing so will also
advance the development and deployment of this low-emitting technology
further supports this proposal.
b. Adequately Demonstrated
Co-firing with low-GHG hydrogen is feasible in combustion turbines
that are currently being produced. Manufacturers have developed
retrofits to allow existing combustion turbines to combust up to 100
percent hydrogen, and some companies have announced plans to retrofit
their existing turbines to combust hydrogen. In section VII.F.3.c of
this preamble, the EPA proposes co-firing of low-GHG hydrogen as BSER
for certain new base load combustion turbines. A number of the examples
that the EPA cites as evidence that companies are developing combined
cycle turbines to co-fire hydrogen either are existing turbines that
companies are planning to retrofit to burn hydrogen or are already
under construction, and would, therefore, be classified as existing
turbines under this rule. Because new combined cycle turbines that
operate at capacity factors of greater than 50 percent are similar to
existing combined cycle turbines that operate at capacity factors of
greater than 50 percent, the EPA is proposing a similar BSER pathway
for existing combustion turbines, based upon co-firing 30 percent (by
volume) low-GHG hydrogen in 2032 and ramping up thereafter to 96
percent (by volume) low-GHG hydrogen in 2038.
There are two key questions related to whether co-firing low-GHG
hydrogen in existing combustion turbines is
[[Page 33364]]
adequately demonstrated. The first question is whether existing
combustion turbines are capable of co-firing significant amounts of
hydrogen and/or if they can be retrofitted to do so. The second
question is whether there will be an adequate supply of low-GHG
hydrogen. These points are discussed below.
i. Capability of Existing Turbines To Co-Fire Hydrogen
There are at least three lines of evidence that demonstrate that
co-firing low-GHG hydrogen in existing turbines is possible today (with
a number of them already able to fire 100 percent hydrogen) and that by
approximately 2030, many additional turbine models will have the
capability to co-fire 100 percent hydrogen. First, information from
turbine vendors indicates that they already have significant experience
in operating turbines with hydrogen; some of their existing turbine
models can co-fire hydrogen; and/or they are currently engaged in
projects to upgrade existing turbines to co-fire hydrogen. Second, test
burns have been completed on several existing utility turbines. Third,
several utilities have indicated plans to retrofit existing turbines to
co-fire hydrogen.
Existing turbine vendors including GE, Mitsubishi, and Siemens have
indicated that their turbines can currently co-fire some amounts of
hydrogen; and, they have plans to expand those capabilities. GE has
indicated that most of their product line can currently be configured
to co-fire significant amounts of hydrogen.\566\ Siemens is currently
offering retrofit packages for many of its existing turbines that will
allow them to combust up to 75 percent hydrogen.\567\ Mitsubishi also
offers retrofit packages that could allow for up to 100 percent firing
of hydrogen.\568\
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\566\ https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gas-turbines?utm_campaign=h2&utm_medium=cpc&utm_source=google&utm_content=eta&utm_term=Ge%20gas%20turbine%20hydrogen&gad=1&gclid=EAIaIQobChMIqMaL6IXG_gIVhsjjBx2gPgb-EAAYASAAEgK61PD_BwE and https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
\567\ https://assets.siemens-energy.com/siemens/assets/api/uuid:66b2b6a3-7cdc-404d-9ab0-ddcfbe4adf02/hydrogenflyer.pdf?ste_sid=81945e06dd4f27fd626614f9b954e3f4.
\568\ https://solutions.mhi.com/clean-fuels/hydrogen-gas-turbine/.
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Section VII.F.3.c.vii(A) of this preamble includes discussion of
how retrofitting existing turbines to co-fire with increasing amounts
of hydrogen is adequately demonstrated. Several turbines currently in
operation have the capability to co-fire hydrogen up to 30 percent
without modifications. Other existing turbine models would need
modifications to enable co-firing between 50 and 100 percent.
Moreover, several existing combined cycle turbines have
demonstrated the ability to co-fire some amounts of hydrogen. The Long
Ridge Energy Terminal tested 5 percent hydrogen co-firing at the 485-MW
combined cycle plant on a GE HA-class (GE 7HA.02) in 2022. The turbine
is designed to enable a transition to 100 percent hydrogen fuel. This
example is particularly salient given the large capacity of the unit.
No modifications should be required for this turbine model, which has
been available since 2017, to operate with between 5 and 20 percent
hydrogen co-firing. Higher hydrogen co-firing concentrations will
require some modification.\569\
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\569\ https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-marks-triumph-for-ge/.
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Southern Company has also demonstrated hydrogen co-firing on a
Mitsubishi, M501G turbine. The demonstration involved co-firing 20
percent hydrogen (by volume), was successful at both full and partial
load, and demonstrated compliance with emissions requirements without
impacting maintenance intervals.\570\ Other test burns have
demonstrated the ability to fire up to 80 percent hydrogen without
emissions excursions.\571\
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\570\ https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/.
\571\ https://www.ccj-online.com/real-world-experience-firing-hydrogen-natural-gas-mixtures/.
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Several utilities are exploring the use of hydrogen in their
existing turbine fleet. For example, Constellation Energy, which owns a
fleet of 23 gas-fired turbines with a combined total capacity of 8.6
GW, asserts that retrofitting existing turbines to co-fire hydrogen is
technically feasible with existing turbine models: ``Based on our
assessments, retrofits using available technology can allow hydrogen
blending at 50-100 percent by volume in select generators. These
retrofits, which include burner and additional balance-of-plant
modifications, allow for more substantial CO2 emissions
reductions.'' \572\ Florida Power and Light (FPL) intends to convert 16
GW of existing turbine capacity to run on 100 percent hydrogen by
2045.\573\ They are currently developing a 25 MW electrolyzer project
at the Cavendish Energy Center.\574\
---------------------------------------------------------------------------
\572\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units.
\573\ https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-for-florida-power-light/.
\574\ https://dailyenergyinsider.com/news/34040-florida-power-light-taps-cummins-for-its-green-hydrogen-facility/.
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One concern with hydrogen co-firing is that, because it burns at a
higher temperature, it has the potential to generate more thermal NOx.
The most commonly used NOX combustion control for base load
combined cycle turbines is dry low NOX (DLN) combustion.
Even though the ability to co-fire hydrogen in combustion turbines that
are using DLN combustors to reduce emissions of NOX is
currently more limited, all major combustion turbine manufacturers have
developed DLN combustors for utility EGUs that can co-fire
hydrogen.\575\ Moreover, the major combustion turbine manufacturers are
designing combustion turbines that will be capable of combusting 100
percent hydrogen by approximately 2030, with DLN designs that assure
acceptable levels of NOX emissions.576 577
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\575\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
\576\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power
plants by 2030. https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
\577\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas
Turbines. https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
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ii. Availability of Low-GHG Hydrogen
The EPA is proposing that the BSER for existing combustion turbines
includes co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and
96 percent (by volume) by 2038. The EPA is proposing to define low-GHG
hydrogen as hydrogen that is produced with overall carbon emissions of
less than 0.45 kg CO2e/kgH2 from well-to-gate. Electrolytic
hydrogen produced using zero-carbon emitting energy sources is the most
likely, but not the only, form of hydrogen anticipated to meet this
proposed definition.\578\
---------------------------------------------------------------------------
\578\ DOE, Pathways to Commercial Liftoff: Clean Hydrogen (March
2023).
---------------------------------------------------------------------------
Suitable volumes of low-GHG hydrogen are expected to be produced by
the 2032 and 2038 timeframes to satisfy the demand driven by this
proposed rule. As referenced throughout this proposal, DOE's clean
hydrogen production estimates are 10 MMT annually of clean hydrogen by
2030, and 20 MMT annually by 2040. There is reason to believe actual
produced
[[Page 33365]]
low-GHG hydrogen will exceed those levels. Announced clean hydrogen
production projects total 12 MMT annually for 2030.\579\ In fact,
hydrogen production could outpace DOE's projections if demand markets
across sectors, including the power sector, grow rapidly and emerge
simultaneously with cost declines across the value chain.\580\ Over
time, the emergence of the self-sustaining low-GHG hydrogen markets are
predicted to be established as demand for low-GHG solidifies and
anchors the market, ensuring low-GHG production even after the PTC
sunsets. Given the magnitude of the PTC for low-GHG hydrogen, $3/kg,
electrolytic hydrogen production is expected to accelerate, accounting
for between 70 and 95 percent of hydrogen production in 2030, and
between 30 and 50 percent in 2040.\581\
---------------------------------------------------------------------------
\579\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 8 of the
Liftoff Report represents compiled clean hydrogen projects with
aggregated 2030 production exceeding 12 MMT annually.
\580\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 13 presents
modeling of hydrogen production volumes under various scenarios,
including projections of 20MMT in 2030, and 42 MMT in 2040 based on
high end of ranges for end use demand which assumes additional ramp
up in policy support for decarbonization--which is consistent with
this proposal to reduce emissions from the power sector, as well as
EPA's proposed Greenhouse Gas Emissions Standards for Heavy-Duty
Vehicle.
\581\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 14 of the
Liftoff report projects the split of hydrogen production in future
years between electrolytic and SMR.
---------------------------------------------------------------------------
Further, multiple utilities are pursuing projects to secure
supplies of electrolyzer-based hydrogen for their power projects. As
mentioned earlier in this proposal, Intermountain Power is working with
partners to develop an integrated hydrogen turbine, a hydrogen
production facility, and a hydrogen storage facility in Delta, Utah.
All three components of the project are under construction and are
scheduled to be operational by 2025, with the turbine combusting 30
percent (by volume) low-GHG hydrogen at startup.\582\ FPL has announced
plans to build 30 GW of excess solar to supply clean hydrogen
production to power its turbines and to sell to other customers.\583\
Entergy has entered into multiple agreements to explore the use of
existing and new renewable generating assets and transmission to supply
zero GHG electricity to developers of hydrogen production plants.\584\
Multiple US utilities are collaborating to develop hydrogen hubs.\585\
---------------------------------------------------------------------------
\582\ https://www.ipautah.com/ipp-renewed/.
\583\ https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-for-florida-power-light/.
\584\ https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/
and https://www.entergynewsroom.com/news/entergy-texas-monarch-energy-collaborate-advance-southeast-texas-energy-infrastructure-1323187465/.
\585\ https://news.duke-energy.com/releases/major-southeast-utilities-establish-hydrogen-hub-coalition.
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c. Costs
The fact that existing sources are already planning to combust low-
GHG hydrogen, even in the absence of a regulatory requirement, is an
indication that the costs of co-firing are reasonable.
The EPA has also developed a more specific description of the
costs, which follows. It incorporates some components of the analysis
of costs of co-firing low-GHG hydrogen for new turbines, as discussed
in section VII.F.3.c.vii(B) of this preamble.
There are three sets of potential costs associated with
retrofitting combustion turbines to co-fire hydrogen: (1) Capital costs
of retrofitting combustion turbines to have the capability of co-firing
hydrogen; (2) pipeline infrastructure to deliver hydrogen; and (3) the
fuel costs related to production of low-GHG hydrogen. While many
combustion turbines are able to fire lower volume blends of hydrogen
with natural gas, not all have the capacity or on-site infrastructure
necessary to blend higher volumes of hydrogen. The primary costs that
combustion turbines would incur would be the fuel costs for low-GHG
hydrogen, along with limited capital retrofit costs, in order to co-
fire hydrogen at the 30 percent and 96 percent levels that the EPA is
proposing as the BSER.
One company, Constellation Energy Corporation, has estimated the
costs to retrofit existing plants to co-fire hydrogen and has indicated
that they are reasonable: ``We expect $10-$60/kW in retrofit costs to
achieve 30-60% hydrogen blending by volume at our power plants. At
blend levels in the range of 60-100%, OEMs have suggested pricing of
roughly $100/kW.'' \586\ The EPA estimates that if low-GHG hydrogen is
available at a delivered price of $1/kg,\587\ co-firing 30 percent
hydrogen in a combined cycle EGU operating at a capacity factor of 65
percent would increase the levelized cost of electricity (LCOE) by
$2.9/MWh and a 96 percent co-firing rate would increase the LCOE by
$21/MWh.\588\ Regardless of the level of hydrogen co-firing, the
CO2 abatement cost is $64/ton ($70/metric ton) at the
affected facility.\589\ For an aeroderivative simple cycle combustion
turbine operating at a capacity factor of 40 percent, the EPA estimates
co-firing 30 percent low-GHG hydrogen would increase the LCOE by $4.1/
MWh, and a 96 percent co-firing rate would increase the LCOE by $30/
MWh. At a delivered price of $0.75/kg, the CO2 abatement
costs for co-firing hydrogen would be $32/ton ($35/metric ton). For a
combined cycle EGU, the EPA estimates the LCOE increase would be $1.4/
MWh and $11/MWh for the 30 percent and 96 percent cases, respectively.
For a simple cycle EGU, the EPA estimates the LCOE increase would be
$2.1/MWh and $15/MWh for the 30 percent and 96 percent cases,
respectively.
---------------------------------------------------------------------------
\586\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units Docket ID No. EPA-HQ-OAR-2022-0289, June 6, 2022).
\587\ The delivered price includes the purchase cost of the fuel
and its transportation costs and the 45V tax credit.
\588\ The EIA long-term natural gas price for utilities is
$3.69/MMBtu.
\589\ The abatement cost of co-firing low-GHG hydrogen is
determined by the relative delivered cost of the low-GHG hydrogen
and natural gas.
---------------------------------------------------------------------------
The EPA is soliciting comment on what additional costs would be
required to ensure that combustion turbines are able to co-fire between
30 to 96 percent low-GHG hydrogen and if there are efficiency impacts
from co-firing hydrogen. Retrofits to add the capacity to combust
higher volumes of hydrogen could include retrofitting the combustor,
increasing the size of the fuel piping, and upgrades to minimize fuel
leakage, hydrogen storage and blending equipment, upgraded control
systems, modification to the continuous emissions monitoring system,
safety upgrades and leakage detectors, modification of the HRSG to
accept higher temperature exhaust, and NOX control
modifications (e.g., upgraded premix combustion technologies).\590\
According to model plant estimates in EPRI's US-REGEN model, the heat
rate of a hydrogen-fired combustion turbine is 5 percent higher than a
comparable natural gas-fired combustion turbine. Furthermore, for
hydrogen-fired combustion turbines relative to a comparable natural
gas-fired combustion turbine, the capital costs are
[[Page 33366]]
approximately $70/kW higher, the fixed operating costs are
approximately $1/year per kW higher, and the non-fuel variable
operating costs are approximately $0.5/MWh higher.\591\ While these
costs are for new combustion turbines, the amounts could be higher for
retrofits to combustion turbines. To the extent it is appropriate to
account for additional costs associated with a hydrogen co-firing BSER
for existing combustion turbines, the EPA is soliciting comment on
whether capital and fixed costs should be increased by 9 percent,
consistent with the NETL estimated retrofit costs of CCS relative to
new combustion turbines.
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\590\ Simon, Nima, Retrofitting Gas Turbine Facilities for
Hydrogen Blending. November 2, 2022. https://www.icf.com/insights/energy/retrofitting-gas-turbines-hydrogen-blending.
\591\ https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#new-generation-capacity.
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The EPA is proposing to determine that the increase in operating
costs from a BSER based on low-GHG hydrogen is reasonable.
d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
The co-firing of hydrogen in combustion turbines in the amounts
that the EPA proposes as the BSER would not have adverse non-air
quality health and environmental impacts. It would potentially result
in increased production of NOX, but those NOX
emissions can be controlled, as described in sections VII.F.3.c.vii.(A)
and XI.C.2.b.i of this preamble.
In addition, co-firing hydrogen in the amounts proposed would not
have adverse impacts on energy requirements, including either the
requirements of the combustion turbines to obtain fuel or on the energy
sector more broadly, particularly with respect to reliability. As
discussed in sections VII.F.3.c.vii.(A)-(B) and XI.C.2.b.-c. of this
preamble, combustion turbines can be constructed to co-fire high
volumes of hydrogen in lieu of natural gas, and the EPA expects that
low-GHG hydrogen will be available in sufficient quantities and at
reasonable cost. Any impact on the energy sector would be further
mitigated by the large amounts of existing generation that would not be
subject to requirements in this rule and the projected new capacity in
the base case modeling.
e. Extent of Reductions in CO2 Emissions
The site-specific reduction in CO2 emissions achieved by
a combustion turbine co-firing hydrogen is dependent on the volume of
hydrogen blended into the fuel system. Due to the lower energy density
by volume of hydrogen compared to natural gas, an affected source that
combusts 30 percent by volume hydrogen with natural gas would achieve
approximately a 12 percent reduction in CO2 emissions versus
firing 100 percent natural gas.\592\ A source combusting 100 percent
hydrogen would have zero CO2 stack emissions because
hydrogen contains no carbon, as previously discussed. A source co-
firing 96 percent by volume hydrogen (approximately 89 percent by heat
input) would achieve an approximate 90 percent CO2 emission
reduction, which is roughly equivalent to the emission reduction
achieved by sources utilizing 90 percent CCS.
---------------------------------------------------------------------------
\592\ The energy density by volume of hydrogen is lower than
natural gas.
---------------------------------------------------------------------------
f. Promotion of the Development and Implementation of Technology
Determining co-firing 30 percent (by volume) low-GHG hydrogen by
2032 and co-firing 96 percent (by volume) to be components of the BSER
would generally advance technology development in both the production
of low-GHG hydrogen and the use of hydrogen in combustion turbines, for
the same reasons discussed with respect to new combustion turbines in
section VII.F.3.c.vii.(E) of this preamble.
g. Summary
The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032
and 96 percent by 2038 qualify as a BSER pathway for large and
frequently-used existing combustion turbines. For the reasons discussed
above, the EPA proposes that co-firing low-GHG hydrogen on that pathway
is adequately demonstrated in light of the capability of combustion
turbines to co-fire hydrogen and the EPA's reasonable expectation that
adequate quantities of low-GHG hydrogen will be available by 2032 and
2038 and at reasonable cost. Moreover, combusting hydrogen will achieve
reductions because it does not produce GHG emissions and will not have
adverse non-air quality health or environmental impacts or energy
requirements, including on the nationwide energy sector. Primarily
because the production of low-GHG hydrogen generates the fewest GHG
emissions, the EPA proposes that co-firing low-GHG hydrogen, and not
other types of hydrogen, qualify as the ``best'' system of emission
reduction. See section VII.F.3.c.vii(F) of this preamble. The fact that
co-firing low GHG hydrogen creates market demand for, and advances the
development of, low-GHG hydrogen, a fuel that is useful for reducing
emissions in the power sector and other industries, provides further
support for this proposal.
Similar to new base load combined cycle turbines, the EPA is also
taking comment on an alternative approach in which the BSER for these
units would be based on CCS with 90 percent capture, for the reasons
discussed next, but units could follow a pathway that would enable them
to achieve the same reductions using low-GHG hydrogen.
3. CCS
a. Overview
The EPA believes that CCS is an effective mitigation measure for
existing combustion turbines and that it would be most cost-effective
for units that are frequently operating. As discussed in section
VII.F.3.b.iii.(A) of this preamble, multiple companies are considering
adding CCS to existing fossil fuel-fired power plants and multiple
companies have performed FEED studies evaluating the feasibility of
installing CCS on an existing combined cycle unit. As also discussed
there, CO2 pipelines are available and their network is
expanding in the U.S., the safety of existing and new supercritical
CO2 pipelines is comprehensively regulated by PHMSA, and
areas without reasonable access to pipelines for geologic sequestration
can transport CO2 to sequestration sites via other
transportation modes. As also discussed there, geologic sequestration
of CO2 is well proven, broadly available throughout the
U.S., and there is a detailed set of regulatory requirements to ensure
the security of sequestered CO2. For these reasons, the EPA
proposes that CCS with 90 percent capture is adequately demonstrated
for existing combustion turbines.
The EPA further proposes that CCS is cost-reasonable for existing
turbines that are greater than 300 MW and operate at greater than 50
percent capacity. The EPA believes that many existing combined cycle
units are likely to be able to install and operate CCS within the costs
that the EPA found to be reasonable for new stationary combustion
turbines and existing coal-fired steam generating units. Certain parts
of the cost calculation should be much the same as for new sources,
including the costs for transportation and sequestration as well as the
availability of the IRC section 45Q tax credit, although the costs for
retrofitting capture equipment may in some cases be higher. See section
VII.F.3.b.iii.(B) of this preamble. NETL estimates that the capital
cost of CCS retrofits on combined cycle EGUs is 9 percent
[[Page 33367]]
higher than for new combined cycle EGUs.\593\ The additional capital
costs increase the LCOE of the retrofit CCS by an additional $1.5/MWh
compared to an installation at a new combined cycle EGU, which is
consistent with control costs that EPA has found to be reasonable in
other rulemakings, as noted in section VII.F.3.b.iii.(B)(5).
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\593\ Tommy Schmitt, Sally Homsy, National Energy Technology
Laboratory, Cost and Performance of Retrofitting NGCC Units for
Carbon Capture--Revision 3, March 17, 2023 (DOE/NETL-2023/3848).
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The ability to cost-effectively apply CCS was a significant
consideration in the EPA's selection of proposed capacity and
utilization thresholds to determine which existing turbines would be
covered by these proposed emission guidelines. The EPA considered two
primary factors in evaluating an appropriate capacity threshold. The
first is emission reduction potential. As the capacity threshold
decreases a larger amount of the existing fleet is covered and overall
emission reduction potential increases. For instance, at a 500 MW
threshold, only 2 percent of the capacity and 7 percent of the
emissions are covered. The second factor the EPA considered was
capacity to build CCS. In 2030, the EPA projects that approximately 12
GW of coal-fired generation will likely install CCS (including both CCS
being installed to meet requirements of this rule and CCS that EPA
projects would occur even without the requirements proposed here).
There are likely to also be a number of other CCS projects for other
industries developed in the 2023 through 2030 timeframe. Multiple
industries including the ethanol industry and the hydrogen production
sector have announced post combustion CCS projects in response to the
IRA.
The EPA believes it is reasonable to assume therefore that by 2035
there will be a larger capability to build CCS retrofits than in 2030.
Had the EPA proposed capacity thresholds of 400 MW or 500 MW, they
would have only resulted in the need for a maximum of 12 GW or 6 GW of
CCS capacity respectively by 2035 for existing gas turbines covered by
this proposal, which is less than the CCS capacity the EPA projects in
2030 to meet the existing coal BSER. That would likely mean foregoing
feasible, cost-effective emissions reductions. By contrast, the 300 MW
cutpoint that EPA is proposing would require up to 37 GW of CCS in
2035. While this is approximately 3 times the amount of CCS that the
EPA is projecting for coal-fired units in 2030, the EPA believes that
300 MW is a reasonable threshold primarily because there will be
significant time to deploy the needed infrastructure, a total of eleven
years from the likely finalization of these guidelines. In addition, it
is unlikely that all of the units that EPA projects would be affected
in 2035 would choose to install CCS; some would likely choose to co-
fire low-GHG hydrogen.\594\ For these reasons, the EPA believes that
there will be adequate capability to build enough CCS for the existing
combustion turbine EGUs subject to a CCS BSER at a capacity threshold
of 300 MW, given the amount of time provided.
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\594\ Approximately 6 GW of the capacity projected to operate at
a capacity factor of greater than 50 percent in the EPA's modeling
is owned by NextERA who has already announced intentions to convert
much of their combined cycle turbines to co-fire increasing amounts
of hydrogen.
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The EPA also considered a capacity threshold of 200 MW and of 100
MW. According to the EPA's projections, a threshold of 200 MW would
affect a total of 85 GW, and a threshold of 100 MW would affect 134 GW
of existing combustion turbine capacity. While the EPA believes that it
is possible that the industry could install that amount of CCS on this
timeline, the EPA believes it is important to gather more information
on the question of how quickly CCS can be deployed and is therefore
taking comment on, but not proposing, a lower capacity threshold of 200
MW or 100 MW, and taking comment on whether it would be feasible to
install CCS and or co-fire hydrogen for the 85 GW or 134 GW of units it
projects would be covered under those thresholds and a capacity factor
of greater than 50 percent.
Historical rates of emission control technology retrofits at
existing coal-fired power plants, such as flue gas desulfurization
(FGD), indicate that rapid deployments of such technologies in response
to regulatory requirements have proven feasible historically in the
United States and elsewhere. FGD was rapidly deployed in the United
States in response to various regulatory requirements, including the
1971 NSPS addressing SO2 emissions. Although other
compliance options were available, FGD--a wholly new technology--was
installed on 48 GW of coal-fired power plants between 1973 and
1984,\595\ while the number of technology vendors went from 1 to
16.\596\ Similarly, Germany subsequently increased its share of FGD
from 10 to 79 percent in four years.597 598 It should be
noted that as FGD became a more familiar technology, installation rates
accelerated, reaching nearly 30 GW a year in the United States.\599\ A
very rapid ramp up happened after the Clean Air Interstate Rule, for
example, where the installed capacity increased from 131 GW in 2007 to
200 GW in under four years.\600\ There are many differences between FGD
and CCS, but the history of the rapid build-out of FGD generally
supports the EPA's view that companies with the expertise to install
complex emission control equipment can rapidly ramp up capacity in
response to a regulatory driver.
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\595\ Van Ewijk, S., McDowall, W. Diffusion of flue gas
desulfurization reveals barriers and opportunities for carbon
capture and storage. Nat Commun 11, 4298, Figure 1 and Source Data
(2020), available at https://doi.org/10.1038/s41467-020-18107-2.
\596\ Taylor, et al., Regulation as Mother of Innovation, 27 Law
& Pol'y 348, 356 (2005).
\597\ Van Ewijk, S., McDowall, W. Diffusion of flue gas
desulfurization reveals barriers and opportunities for carbon
capture and storage. Nat Commun 11, 4298 (2020). https://doi.org/10.1038/s41467-020-18107-2.
\598\ Similarly, in response to regulatory requirements over 100
GW of coal-fired generation installed selective catalytic reduction
(SCR) between 1999 and 2009, ramping from very low levels. Healey,
Scaling and Cost Dynamics of Pollution Control Technologies, at 7,
Figure 3 (2013). https://core.ac.uk/download/pdf/44737055.pdf.
\599\ Markussan, Scaling up and Deployment of FGD in the US
(CCS--Releasing the Potential) (2012) at v, 24.
\600\ Electric Power Annual 2015, https://www.eia.gov/electricity/annual/archive/pdf/03482015.pdf.
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The EPA seeks comment on the feasibility of setting a threshold of
100 or 200 MW and a 40 percent capacity factor in light of these
examples and other relevant considerations. As further described below,
the EPA further proposes that CCS with 90 percent capture for existing
combustion turbines greater than 300 MW and operating at more than 50
percent capacity meets the other criteria to qualify as the BSER, for
the same reasons as it does for new combustion turbines in the baseload
subcategory:
b. Adequately Demonstrated
Section VII.F.3.b of this preamble includes discussion of how CCS
with a 90 percent capture rate has been adequately demonstrated and is
technically feasible based on the demonstration of the technology at
existing coal-fired steam generating units and industrial sources in
addition to combustion turbines. Notably, the function, design, and
operation of post-combustion CO2 capture equipment is
similar, although not identical, for both steam generating units and
combustion turbines. As a result, application of CO2 capture
at existing coal-fired steam generating units helps show that it is
adequately demonstrated for combustion turbines as well.
[[Page 33368]]
In the retrofit context, SaskPower's Boundary Dam Unit 3, a 110 MW
lignite-fired unit in Saskatchewan, Canada, has demonstrated
CO2 capture rates of 90 percent using an amine-based post-
combustion capture system retrofitted to the existing steam generating
unit. The capture plant, which began operation in 2014, was the first
full-scale CO2 capture system retrofit on an existing coal-
fired power plant.\601\ Other references detailed in section
VII.F.3.b.iii.(A).(2) provide additional support for the demonstration
of CO2 capture retrofits.
---------------------------------------------------------------------------
\601\ Giannaris, S., et al., Proceedings of the 15th
International Conference on Greenhouse Gas Control Technologies
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
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Moreover, section VII.F.3.b.iii.(A)(3) of this preamble describes
how CCS has been successfully applied to a combined cycle EGU (the
Bellingham Energy Center in south central Massachusetts) and how
several other projects are in development. Both section
VII.F.3.b.iii.(A)(3) of this preamble and the TSD on GHG Mitigation
Measures--Carbon Capture and Storage for Combustion Turbines discuss
several CCS projects under development involving retrofits to existing
NGCC units.
In addition to CO2 capture, the CO2 transport
and geologic storage aspects of CCS systems are also adequately
demonstrated, as discussed in section VII.F.3.b and section X.D.1.a of
this preamble and in the GHG Mitigation Measures for Steam Generating
Units TSD. Geologic sequestration potential for CO2 is
widespread and available throughout the U.S. Nearly every State in the
U.S. has or is in close proximity to formations with geologic
sequestration potential, including areas offshore. These areas include
deep saline formation, unmineable coal seams, and oil and gas
reservoirs. Additionally, the U.S. CO2 pipeline network has
steadily expanded (with 5,339 miles in operation in 2021, a 13 percent
increase in CO2 pipeline miles since 2011), and appears
primed to continue expanding, with several major projects recently
announced across the country. Areas without reasonable access to
pipelines for geologic sequestration can transport CO2 to
sequestration sites via other transportation modes such as ship, road
tanker, or rail tank cars.
c. Costs
The EPA is proposing that the costs of CCS are reasonable for
existing combustion turbines that are large and frequently used. As
further discussed in the Regulatory Impact Analysis and the GHG
Mitigation Measures--Carbon Capture and Storage for Combustion Turbines
TSD, the EPA's approach relies on cost and performance assumptions
consistent with the IPM post-IRA 2022 reference case.\602\ The EPA's
baseline shows that 7 GW of existing natural gas combined cycle
capacity retrofits with CCS in 2030, rising to 10 GW in 2035. The
significant deployment of CCS on combined cycle natural gas EGUs in the
absence of emission standards reinforces the cost reasonableness and
feasibility of the proposed standards.
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\602\ These assumptions are detailed at: https://www.epa.gov/system/files/documents/2023-03/Chapter%206%20-%20CO2%20Capture%2C%20Storage%2C%20and%20Transport.pdf.
_____________________________________-
Section VII.F.3.b.iii.(B) and section X.D.1.a.ii of this preamble
discuss the cost-reasonableness of CCS technology in the context of new
combustion turbines and existing coal-fired steam generating units.
Additionally, a March 2023 NETL report estimates that the capital cost
of CCS retrofits on combined cycle EGUs is 9 percent higher than for
installation of CCS equipment on new greenfield combined cycle
EGUs.\603\ The higher retrofit costs account for the cost premium for
design, construction, and tie-in constraints imposed by existing plant
layout and operation. The additional capital costs increase the LCOE of
the retrofit CCS by an additional $2.2/MWh compared to an installation
at a new combined cycle EGU.\604\ Assuming the same model plant, a 90
percent-capture retrofit amine-based post combustion CCS system
increases the LCOE by $8.6/MWh and has overall CO2 abatement
costs of $26/ton ($28/metric ton). Similar to NETL estimates for
greenfield CCS projects, costs at a specific plant would be expected to
vary somewhat from this estimate, as it does not include site and
plant-specific considerations such as seismic conditions, local labor
costs, or local environmental regulations.
---------------------------------------------------------------------------
\603\ Cost and Performance of Retrofitting NGCC Units for Carbon
Capture--Revision 3 (DOE/NETL-2023/3848, March 17, 2023). https://www.netl.doe.gov/projects/files/CostandPerformanceofRetrofittingNGCCUnitsforCarbonCaptureRevision3_031723.pdf.
\604\ These calculations use the NETL F-Class turbine, a service
life of 12 years, an interest rate of 7.0 percent, a natural gas
price of $3.69/MMBtu, a capacity factor of 75 percent, a transport,
storage, and monitoring cost of $10/metric ton, and a 45Q tax credit
of $85/metric ton.
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d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
As in the context of new NGCC units and existing coal-fired steam
generating units (discussed in section VII.F.3.b.iii.(C) and section
X.D.1.a.iii of this preamble), the EPA does not expect the use of CCS
at large, frequently used existing combustion turbines to have
unreasonable adverse consequences related to non-air quality health and
environmental impact or to energy requirements.
Regarding energy requirements, upon retrofitting an NGCC plant with
CCS, a derate in the net plant electrical output will be incurred due
to the parasitic/auxiliary energy demand required to run the CCS
system, as well as steam extraction from the steam cycle to satisfy the
CCS reboiler duty.\605\ As discussed in the TSD on GHG Mitigation
Measures--Carbon Capture and Storage for Combustion Turbines, a recent
NETL report has estimated that the resulting derates for 90 percent
CO2 capture retrofits range from an 11.5 to 11.8 percent
loss of net MWe.
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\605\ Cost and Performance of Retrofitting NGCC Units for Carbon
Capture--Revision 3. (DOE/NETL--2023/3848, March 17, 2023). https://www.osti.gov/biblio/1961845.
---------------------------------------------------------------------------
Despite decreases in efficiency, IRC section 45Q tax credits
provide an incentive for increased generation with full operation of
CCS because the credits are proportional to the amount of captured and
sequestered CO2 emissions and not to the amount of
electricity generated. The EPA is proposing that the energy penalty is
relatively minor compared to the GHG benefits of CCS. The EPA does not
believe that determining CCS to be BSER for large, frequently operated
combustion turbines will cause reliability concerns. This is because of
the limited increase in costs and energy penalty due to CCS, coupled
with the amounts of smaller or lower capacity generation that would not
be subject to these requirements and the projected new capacity in the
base case modeling. For the estimated 37 GW of facilities that would
face requirements under this proposal, if they all installed CCS
retrofit the reduction in available capacity would be approximately 4.3
GW, or less than 1% of the total modeled available natural gas capacity
in 2035. Grid planners, operators, and market participants can address
the potential, marginal impact, through development of a similarly
small increment of accredited capacity, whether from new natural gas
simple cycle turbine
[[Page 33369]]
deployment, new energy storage, or new sources of clean energy.
Regarding non-air quality health and environmental impact, criteria
or hazardous air pollutant emissions would in general be mitigated or
adequately controlled by equipment needed to meet other CAA
requirements, and the EPA's assessment is that the additional cooling
water requirements from CCS at NGCC units are reasonable, as discussed
in section VII.F.3.v.iii.(C). The EPA is committed to working with its
fellow agencies to foster meaningful engagement with communities and
protect communities from pollution. This can be facilitated through the
existing detailed regulatory framework for CCS projects and further
supported through robust and meaningful public engagement early in the
technological deployment process. CCS projects undertaken pursuant to
these emission guidelines will, if the EPA finalizes proposed revisions
to the CAA section 111 implementing regulations,\606\ be subject to
requirements for meaningful engagement as part of the State plan
development process. See section XII.F.1.b of this preamble for
additional details.
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\606\ 87 FR 79176, 79190-92 (December 23, 2022).
---------------------------------------------------------------------------
e. Extent of Reductions in CO2 Emissions
Designating CCS with 90 percent capture as a component of the BSER
for large and frequently-operated combustion turbines prevents large
amounts of CO2 emissions. According to the NETL baseline
report, adding a 90 percent CO2 capture system increases the
EGU's gross heat rate by 7 percent and the unit's net heat rate by 13
percent. Since more fuel would be consumed in the CCS case, the gross
and net emissions rates are reduced by 89.3 percent and 88.7 percent
respectively.
f. Promotion of the Development and Implementation of Technology
The EPA also considered whether determining CCS to be a component
of the BSER for existing large and frequently operated combustion
turbines will advance the technological development of CCS and
concluded that this factor supports our BSER determination. Combined
with the availability of 45Q tax credits and investments in supporting
CCS infrastructure from the IIJA, this requirement should incentivize
additional use of CCS, which should, in turn, incentivize cost
reductions through the development and use of better performing
solvents or sorbents. While solvent-based CO2 capture has
been adequately demonstrated at the commercial scale, a determination
of the BSER for certain existing combustion turbines (along with new
baseload combustion turbines and long term coal-fired steam generating
units) is the use of CCS will also likely incentivize the deployment of
alternative CO2 capture techniques at scale. Moreover, as
noted above, the cost of CCS has fallen in recent years and is expected
to continue to fall; and further implementation of the technology can
be expected to lead to additional cost reductions, due to added
experience and cost efficiencies through scaling.
The EPA seeks comment on the feasibility of setting a threshold for
inclusion in the existing combustion turbine segment to be addressed by
the emission guidelines proposed here of 100 or 200 MW and a 40 percent
capacity factor in light of the examples of other historic deployment
of pollution controls and other relevant considerations. DOE recently
released a report discussing the State of carbon management
technology.\607\ In that report, DOE states that with policy support
(either via regulation or incentives) or technology premiums for low-
carbon products (e.g., low embodied carbon steel and concrete) the
scale up of CCS technologies and pipeline and storage infrastructure
would proceed much faster for the power sector than will proceed absent
additional policy support or market demand.\608\ In the report, DOE
states that regulatory developments, in particular, could play a
dramatic role in accelerating the pathways described for industries
with lower-purity CO2 streams such as power plants. The
report states that absent additional incentives, CCS technology for the
power sector is likely to significantly scale between 2030-2040 with
pilot and demonstration technologies occurring now. As detailed in the
report, several incentives have recently become available or been
significantly increased that will accelerate the deployment of CCS for
the power sector. The 45Q tax credit for CCS is a strong incentive, and
DOE is already investing heavily through the Bipartisan Infrastructure
Law at further demonstrating lower-purity CCS technologies such as
those used in the power sector, which will help to decrease costs and
establish repeatable commercial arrangements.
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\607\ DOE Carbon Management Demonstration and Deployment
Pathway, April 2023, https://liftoff.energy.gov/
\608\ The Federal Buy Clean Task Force and the First Mover's
Coalition are both seeking to provide a clear demand signal for low
embodied emissions products.
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As the DOE report discusses, CO2 pipelines also need to
be further built out for CCS technologies to scale. CO2
pipelines are the most mature, and often the most cost-effective
CO2 transport technology for high volumes and will likely
form the backbone of CO2 transport. PHMSA reported that
5,339 miles of CO2 pipelines were in operation in 2021.\609\
Analogous historical build out of inter- and intrastate natural gas
transmission pipelines demonstrates that similar levels of
CO2 pipeline deployment are feasible. Data reported by EIA
indicates that from 1997 to 2008 over 25,000 miles of natural gas
transmission pipeline was constructed, averaging over 2,000 miles per
year.\610\ Other analyses indicate that the size of CO2
pipeline network necessary to capture over 1,000 million metric tons
per year of CO2 emissions from large, frequently operated
coal and natural gas EGUs ranges from 20,000 miles to 25,000
miles.\611\ This is in line with the historical maximum deployment of
natural gas transmission pipelines, and also does not account for any
economies of scale from pipeline systems developed for capture from
other non-power CO2 sources.
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\609\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
\610\ https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx.
\611\ Middleton, Richard and Bennett, Jeffrey and Ellett, Kevin
and Ford, Michael and Johnson, Peter and Middleton, Erin and Ogland-
Hand, Jonathan and Talsma, Carl, Reaching Zero: Pathways to
Decarbonize the US Electricity System with CCS (August 30, 2022).
Proceedings of the 16th Greenhouse Gas Control Technologies
Conference (GHGT-16) 23-24 Oct 2022. https://ssrn.com/abstract=4274085 or https://dx.doi.org/10.2139/ssrn.4274085.
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D. Areas That the EPA Is Seeking Comment on Related to Existing
Combustion Turbines
The EPA is seeking comment on four general areas related to
selecting the BSER for existing combustion turbines. First, the EPA is
soliciting comment on general assumptions about potential future
utilization of combustion turbines. Second, the EPA is soliciting
comment on assumptions about the appropriate group of existing
combustion turbine units to be addressed in this rulemaking. Third, the
EPA is requesting comment on the appropriate BSER for those turbines.
Fourth, the EPA is requesting comment
[[Page 33370]]
on the timing of BSER requirements for existing combustion turbines.
The EPA is seeking comment on a number of issues related to how its
consideration of projected future utilization of combined cycles
informed its consideration of a potential BSER for existing combustion
turbines. First, the EPA is taking comment on its projections of how
combustion turbines will operate in the future and the key factors that
influence those changes in operation. While the EPA modeling shows that
there is some increase in emissions from these units in all years
following imposition of CAA section 111 standards on existing coal-
fired steam generating units and new stationary combustion turbines,
that increase is much smaller in the later years. The EPA believes the
magnitude of these trends is significantly impacted by the rate at
which new low emitting generation comes on-line, in part incentivized
by IRA and IIJA. The EPA is taking comment on all aspects of these
assumptions including: the speed at which new low-emitting generation
will come on-line and the impact that it has on likely capacity factors
for combined cycle units (in particular the projection that capacity
factors will grow in the 2028/30 timeframe but decrease in later
years).
With regard to the size and definition of the category to be
covered in a first rulemaking covering only part of the existing
turbine category, the EPA is also taking comment on how its assumptions
about the potential operation of combustion turbines in future years
coupled with considerations about the availability of infrastructure
should inform which units should be covered in a first rulemaking. More
specifically, the EPA is requesting comment on how to consider the rate
of CCS (and potentially hydrogen) infrastructure development in
determining a BSER that could potentially impact hundreds of sources.
If, for instance, increased renewable generation and storage capacity
were to lead to a smaller number of units operating at capacity factors
of greater than 50 percent, the proposed BSER would not affect as many
units and a smaller size threshold might be possible without expanding
the amount of infrastructure needed. Conversely, if more units were
likely to operate at a higher capacity factor, a higher capacity
threshold might be appropriate. If the number of units likely to be
covered by a 50 percent threshold were sufficiently small, it might be
reasonable to include units in the intermediate category (e.g., units
with capacity factors of between 20 percent and 50 percent) in a first
rulemaking addressing the existing fossil fuel-fired turbine category.
The EPA is also taking comment on a lower capacity factor threshold
(e.g., 40 percent) and a lower capacity threshold (200 MW or 100 MW,
and capacities between 100 and 300 MW). With regards to units with a
capacity factor of greater than 50 percent that are under 300 MW and
units with a capacity factor of 50 percent or less the EPA is taking
comment on the appropriateness of CCS and/or hydrogen as a BSER. With
regards to hydrogen, the EPA is taking comment on the appropriate level
of and timing for hydrogen co-firing. More generally, EPA is requesting
comment on any feasibility issues related to broader CCS deployment
should those thresholds be adjusted such that more coal capacity is
affected, and how such issues could be addressed.
With regards to the BSER itself, the EPA is soliciting comment on
the applicability of CCS retrofits to existing combustion turbines and
its focus on base load turbines (e.g., those with a capacity factor of
greater than 50 percent). This solicitation includes comment on whether
particular plants would be unable to retrofit CCS, including details of
the circumstances that might make retrofitting with CCS unreasonable or
infeasible.
The EPA is also taking comment on the role of low-GHG hydrogen as
part of BSER. More specifically, the EPA is requesting comment on the
appropriateness of low-GHG hydrogen as a BSER for combustion turbines
larger than 300 MW with capacity factors of greater than 50 percent.
While, as has been noted earlier in this section, a number of turbines
already exist or are under construction that owners of combustion
turbines have indicated may burn large amounts of hydrogen in a base
load mode, the EPA is also aware that other proponents of low-GHG
hydrogen use in turbines focus on it primarily as an energy storage
device, storing renewable energy to provide electricity in times where
renewable energy was not available. The EPA is interested in the
question of whether, in this case, it would be likely that a combined
cycle turbine burning low-GHG hydrogen would operate near base load,
and whether it be prudent to have an alternative BSER or an alternative
compliance pathway for units combusting low-GHG hydrogen and solicits
comments on these questions. Similar to the NSPS for base load
combustion turbines, the EPA is also taking comment on whether to
finalize both the proposed low-GHG hydrogen BSER and the proposed CCS
with 90 percent capture BSER, or finalize a BSER with a single pathway,
such as based on application of CCS with 90 percent capture, which
could also be met by co-firing with low-GHG hydrogen.
With regard to the timing for BSER, the EPA is taking comment on a
2035 CCS based BSER standard and whether that standard could reasonably
be applied earlier. Similarly, the EPA is taking comment on the timing
of a low-GHG hydrogen based BSER and whether a 30 percent low-GHG
hydrogen standard could be implemented earlier than 2032, or if low-GHG
hydrogen supply infrastructure development suggests it should be later.
The EPA is taking comment on the same questions with regard to a 96
percent low-GHG hydrogen co-firing BSER in 2038.
E. BSER for Remaining Combustion Turbines
While the EPA believes that emission guidelines for units covered
in the first rulemaking, proposed above, can achieve important emission
reductions from the most frequently operating combustion turbines, the
EPA believes that limits to infrastructure and capability to build
carbon capture systems or co-fire large amounts of hydrogen caution
against a first rulemaking addressing emissions from existing turbines
covering all combustion turbines. In this section, the EPA discusses
how developing a BSER for units in a second rulemaking could address
units that do not meet the applicability requirements for the first
rulemaking.
As noted above, the EPA is taking comment on what units should be
part of whatever action the EPA finalizes as a result of the proposal.
Based on the units that the EPA has proposed be included, units that
might remain uncovered include smaller baseload units (e.g., those less
than or equal to 300 MW) and all units operating less than or equal to
a capacity factor of 50 percent. Particularly for the remainder of the
baseload units, the EPA is interested in whether any other units should
have a BSER based on CCS. The EPA is also interested in the timing of
such a requirement recognizing the tensions between an earlier
requirement that would both achieve earlier reductions and the need to
allow time for infrastructure to develop to support growing amounts of
CCS.
For intermediate turbines, the EPA is taking comment on a BSER
similar to that for new turbines. In particular, the EPA is interested
in comment about an appropriate pathway and timing for a BSER that
would ultimately require 96 percent low-GHG hydrogen by volume.
[[Page 33371]]
Finally, for peaking turbines, the EPA is interested in comment about
whether a clean hydrogen BSER would be appropriate, what the timing of
such a requirement should be and whether there should be any phasing.
The EPA is also interested in any comments related to: potential
changes in operational patterns for turbines, particularly as more
renewables and storage enter the grid. For instance, the EPA is
interested in comments as to whether improvements in energy storage
will reduce reliance on intermediate and peaking turbines. The EPA is
also interested in comments on any potential technology developments
that could impact its determination of BSER. For instance, the EPA is
aware that in addition to electrolyzer based hydrogen and natural gas
based hydrogen, there are other means of hydrogen production receiving
significant attention such as naturally occurring hydrogen, and
solicits comments on whether any of these potential technology
developments should impact the EPA's consideration of the appropriate
BSER for the remaining turbines.
XII. State Plans for Proposed Emission Guidelines for Existing Fossil
Fuel-Fired EGUs
A. Overview
State plan submissions under these emission guidelines are governed
by the requirements of 40 CFR part 60, subpart Ba (subpart Ba).\612\
The EPA proposed to revise certain aspects of 40 CFR part 60, subpart
Ba, in its December 2022 proposal, ``Adoption and Submittal of State
Plans for Designated Facilities: Implementing Regulations Under Clean
Air Act Section 111(d)'' (proposed subpart Ba).\613\ The Agency intends
to finalize revisions to 40 CFR part 60, subpart Ba, before
promulgating these emission guidelines. Therefore, State plan
development and State plan submissions under these proposed emission
guidelines would be subject to the requirements of subpart Ba as
revised in that future final action, including any changes the EPA
makes to the proposal in response to public comments. To the extent the
EPA is proposing to add to, supersede, or otherwise vary the
requirements of subpart Ba for the purposes of these particular
emission guidelines, those proposals are explicitly addressed in this
section of the preamble. Unless expressly amended or superseded in
these proposed emission guidelines, the provisions of subpart Ba, as
revised by the EPA's forthcoming final rule, would apply.
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\612\ 40 CFR 60.20a-60.29a.
\613\ See 87 FR 79176 (December 23, 2022); see also id., Docket
ID No. EPA-HQ-OAR-2021-0527-0002 (memorandum to docket containing
proposed revisions to 40 CFR part 60, subpart Ba).
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This section provides information on several aspects of State plan
development, including compliance deadlines, a presumptive methodology
for establishing standards of performance for affected EGUs, compliance
flexibilities, and State plan components and submission. In sections X
and XI of this preamble, the EPA is soliciting comment on ranges for
dates and values for defining subcategories, BSER, and degrees of
emission limitation; those solicitations for comment extend to the
proposed values and dates discussed in this section of the preamble. In
section XII.B, the EPA proposes and explains its reasoning for
compliance deadlines for affected steam generating units and affected
combustion turbines. In section XII.C, the EPA describes its
requirement that State plans achieve equivalent stringency to the EPA's
BSER. Section XII.D proposes a presumptive methodology for calculating
the standards of performance for affected EGUs based on subcategory as
well as requirements related to invoking RULOF to apply a less
stringent standard of performance than results from the EPA's
presumptive methodology. Section XII.D also describes proposed
requirements for increments of progress for affected EGUs in certain
subcategories and milestones for affected EGUs, as well as testing and
monitoring requirements. In section XII.E, the EPA proposes that States
would be permitted to include trading and averaging as compliance
measures for affected EGUs in their State plans, so long as plans
demonstrate equivalence to the stringency that would result if each
affected EGU was individually achieving its standard of performance.
Finally, section XII.F describes what must be included in State plans,
including plan components specific to these emission guidelines and
requirements for conducting meaningful engagement.
In this section of the preamble, the term ``affected EGU'' means
any existing fossil fuel-fired steam generating unit or existing fossil
fuel-fired combustion turbine EGU that meets the applicability criteria
described in sections X and XI of this preamble. Affected EGUs would be
covered by the proposed emission guidelines under 40 CFR part 60
subpart UUUUb.
B. Compliance Deadlines
The EPA is proposing a compliance date of January 1, 2030, for
affected steam generating units. The proposed compliance date for the
CCS combustion turbine subcategory is January 1, 2035. The proposed
compliance dates for the first phase and second phase for the affected
hydrogen co-fired combustion turbine subcategory are January 1, 2032,
and January 1, 2038, respectively. This means that starting on the
applicable compliance date, affected EGUs would be subject to standards
of performance and other State plan requirements under these emission
guidelines and would be required to start demonstrating compliance with
those requirements.
The EPA is proposing that January 1, 2030, is the soonest that
affected steam generating units could reasonably commence compliance
with standards of performance given the proposed State plan submission
timeline (24 months; see section XII.F.2 of this preamble) and the
amount of time affected EGUs in the long-term and medium-term coal-
fired steam generating unit subcategories will need to install CCS or
natural gas co-firing, respectively. For consistency, the EPA is also
proposing a January 1, 2030, compliance date for imminent- and near-
term coal-fired units as well as the different subcategories of natural
gas- and oil-fired steam generating units.
However, the EPA recognizes that the BSERs for some subcategories
of affected steam-generating EGUs are routine methods of operation and
maintenance, which do not require the installation of any or
significant control equipment and can thus be applied earlier.\614\
Therefore, the EPA is soliciting comment on compliance dates defined by
the date of approval of the State plan or January 1, 2030, whichever is
earlier, for imminent-term coal-fired steam generating units, near-term
coal-fired steam generating units, and the different subcategories of
natural gas- and oil-fired steam generating units.
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\614\ The EPA is also taking comment in section X.D.3.b.ii on
potential BSER options for imminent- and near-term affected coal-
fired steam generating units based on low levels of natural gas co-
firing.
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The proposed compliance timeframe for affected steam-generating
EGUs in these proposed emission guidelines is based on the amount of
time the EPA believes is needed to comply with standards of performance
based on implementation of natural gas co-firing or CCS. Each of these
systems would require several years to plan, permit, and construct.
However, as explained further in section XII.F.2 of this preamble, the
EPA is proposing to
[[Page 33372]]
adjust the State plan submission deadline so that certain necessary
planning and design steps for natural gas co-firing or CCS
implementation can take place as part of the State plan development
process. That is, we expect that some of the planning and design steps
described below would take place prior to State plan submission. The
EPA believes that coordinating State plan development, submission, and
implementation in this manner reflects how the owners/operators of
affected EGUs and States would actually undertake the steps leading to
ultimate deployment of a control technology and compliance with a
standard of performance.
The GHG Mitigation Measures for Steam Generating Units TSD
discusses the timeframes for implementation of natural gas co-firing
and CCS at existing coal-fired steam generating EGUs. Based on this
analysis, it is clear that the time needed to design and implement CCS
is an important aspect for setting a compliance date under these
emission guidelines. CCS projects will include planning, design, and
construction of both the carbon capture system and the transport and
storage system; the EPA believes that all of these steps can be
completed within roughly 5 years.\615\
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\615\ GHG Mitigation Measures for Steam Generating Units TSD,
chapter 4.7.1. See Table 5 in chapter 4.7.1 for visual
representation of the CCS and co-firing project timelines described
in this section.
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Deployment of a carbon capture system starts with a technical and
economic feasibility evaluation, including a Front End Engineering
Design (FEED) study. The owner/operator of an affected EGU would then
proceed to making technical and commercial arrangements, including
arranging project financing and permitting. These initial steps do not
need to be undertaken sequentially and may be completed in 3 years or
less. As noted above, the EPA also believes that at least some of these
project design and development steps, including feasibility evaluations
and FEED studies, can and will be completed prior to State plan
submission. The EPA believes that the commencement of CCS project
implementation activities, including more detailed engineering work and
procurement, construction of the carbon capture system, and startup and
testing, will overlap with the final steps of the initial project
design and development phase. These project implementation steps take
approximately 3 years to complete.
In addition to planning and implementing a carbon capture system,
the owners/operators of affected EGUs will also have to design and
construct a system for transporting and storing captured
CO2. The necessary steps for implementing transport and
storage of captured CO2 can be undertaken simultaneously
with development of the CO2 capture system, and some of the
steps necessary for transport and storage can additionally overlap with
each other. The EPA thus believes design and implementation of
CO2 transport and storage can be completed within 5 years.
The EPA believes that the initial phases of planning and design for
CO2 transport and storage, including site characterization
and pipeline feasibility and design activities, can and will occur
prior to State plan submission, i.e., as part of the State plan
development process. First, the owner/operator of an affected EGU would
undertake a feasibility analysis associated with CO2
transport and storage, as well as site characterization and permitting
of potential storage areas. These steps can overlap with each other and
the EPA anticipates that, in total, feasibility analyses, site
characterization, and permitting of potential storage areas will take
2-3 years to complete. The EPA believes there is significant
opportunity to overlap the design and planning phase for CO2
transport and storage with the engineering and construction phase for
transport and storage, which is anticipated to take 2-3 years. Based on
the potential to conduct many of the design, planning, permitting,
engineering, and construction steps, the EPA thus believes that
affected EGUs will need approximately 5 years, from start to finish, to
be ready to implement CO2 transport and storage.
The EPA expects that implementation of natural gas co-firing
projects for affected coal-fired steam-generating EGUs, including any
necessary construction of natural gas pipelines, can be completed in
approximately 3.5 years. As discussed in the GHG Mitigation Measures
for Steam Generating Units TSD,\616\ any necessary boiler modifications
to accommodate natural gas co-firing can be completed within 3 years.
The process of planning, permitting, and construction for boiler
modifications can occur simultaneously with the steps that owners/
operators of affected EGUs would need to undertake if construction of a
new natural gas pipeline is needed. The time required to develop and
construct natural gas laterals can be broken into three phases:
planning and design; permitting and approval; and construction. It is
reasonable to assume that the planning and design phase can typically
be completed in a matter of months and will often be finalized in less
than a year. The time required to complete the permitting and approval
phase can vary. Based on a review of recent FERC data, the average time
for pipeline projects similar in scope to the projects considered in
this TSD is about 1.5 years and would likely not exceed 4 years. The
EPA notes that these data may not reflect that pipeline projects may be
completed more expeditiously in the presence of a regulatory deadline.
Finally, the actual construction could likely be completed in less than
1 year. Based on a sum of these estimates, the EPA believes that 3.5
years is a reasonable timeframe for pipeline projects.
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\616\ GHG Mitigation Measures for Steam Generating Units TSD,
chapters 3.2.1.4, 3.2.2.3, and 4.7.1.
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The EPA expects that final emission guidelines will be published in
June 2024 and is proposing a State plan submission deadline that is 24
months from publication, which would be June 2026. The proposed
compliance date for affected steam generating units is January 1, 2030.
The EPA requests comment on whether using a period of 3.5 years after
State plan submission is appropriate for establishing a compliance
deadline for these emission guidelines. As explained above, the EPA is
basing this proposed timeframe on the expectation that some of the
initial evaluation and planning steps for both natural gas co-firing
and CCS would take place as part of State plan development, i.e.,
before the State plan submission deadline. The EPA is also requesting
comment on potential compliance dates between 1.5 and 5.5 years after
State plan submission (i.e., January 1, 2028, to January 1, 2032),
including on the feasibility of completing all the steps to implement
natural gas co-firing and CCS within a shorter or longer timeframe. To
the extent that commenters believe more or less time after State plan
submission is more appropriate than the proposed 3.5 years, the EPA
requests that commenters provide information supporting the provision
of a different compliance date. Additionally, the proposed State plan
submission date and proposed compliance date are based on the EPA's
anticipation that it will publish final emission guidelines for
affected EGUs in June 2024. Should the actual date of publication of
the final emission guidelines differ from this target, the EPA will
adjust the State plan submission and compliance dates accordingly.
As discussed in section XI.C of this preamble, the EPA is proposing
to subcategorize affected existing,
[[Page 33373]]
frequently used combustion turbines that are covered under these
emission guidelines into two subcategories: one subcategory for
affected combustion turbine EGUs that adopt the pathway with a standard
of performance based on CCS, referred to as the ``CCS subcategory'' and
one subcategory for affected combustion turbine EGUs that adopt the
pathway with a standard of performance based on hydrogen co-firing,
referred to as the ``hydrogen co-fired subcategory.'' For affected
combustion turbines in the CCS subcategory, the EPA is proposing a
compliance date of January 1, 2035, which is the soonest the Agency
believes these sources can comply with standards of performance based
on installation and operation of CCS, given the timeframes for planning
and construction of carbon capture and CO2 transport and
storage systems along with other demands on the infrastructure and
resources needed to implement CCS throughout the power sector and the
broader economy. For affected combustion turbines in the hydrogen co-
fired subcategory, the EPA is proposing a two-phase standard of
performance, with a proposed compliance date for the first phase of
January 1, 2032, and for the second phase of January 1, 2038.
For combustion turbine EGUs in the CCS subcategory, the same
timeframes and considerations discussed for the planning and
construction of CCS for affected coal-fired steam generating units
apply. That is, the EPA expects that the owners or operators of
affected combustion turbines will be able to complete the design,
planning, permitting, engineering, and construction steps for the
carbon capture and transport and storage systems within 5 years. As
with affected coal-fired steam generating units, the EPA believes that
States and owners or operators can and would take several of the
initial steps in the design and planning processes for combustion
turbine EGUs as part of State plan development, i.e., prior to the
proposed State plan submission deadline in approximately June 2026.
However, as noted in section XI.C of this preamble, the EPA is
projecting approximately 12 GW of coal-fired generation will likely
retrofit with CCS in order to meet the proposed January 1, 2030,
compliance date for affected long-term coal-fired steam generating
units. These and other CCS projects that are likely to be occurring in
response to the IRA may take up a significant amount of the capacity to
plan and build CCS between 2023 and 2030. The EPA anticipates that
additional pipeline capacity will be constructed ahead of January 1,
2030, for CO2 transport as well as for natural gas pipeline
laterals that may be needed for affected coal-fired steam generating
units that will co-fire with natural gas as a control strategy. Due to
these and other overlapping demands on the capacity to design,
construct, and operate carbon systems as well as pipeline systems, the
EPA is proposing to find that a January 1, 2030, compliance date for
affected combustion turbine EGUs in the CCS subcategory, although
feasible for an individual unit, would not be the most reasonable
deadline for all of the units that would need to install CCS.
Therefore, the EPA is proposing to provide a compliance date for
affected combustion turbine EGUs in the CCS subcategory that is 5 years
after the compliance date for long-term coal-fired steam generating
units, or January 1, 2035. The EPA requests comment on its proposed
compliance deadline for combustion turbine EGUs in the CCS subcategory,
including on whether an earlier or later compliance date would be more
reasonable given the time needed to analyze, design, and construct
carbon capture and CO2 transport and storage systems and the
overlapping timeframes for installation of CCS on EGUs under the
proposed CAA section 111(b) standards of performance for new combustion
turbines and on existing coal-fired steam generating units under these
proposed emission guidelines.
For affected combustion turbine EGUs in the hydrogen co-fired
subcategory, the EPA is proposing a compliance deadline for the first
phase of January 1, 2032. As discussed in sections VII.F.3.c.v and vi
of this preamble, currently the vast majority of hydrogen is not low-
GHG hydrogen. Midstream infrastructure limitations and the adequacy and
availability of hydrogen storage facilities currently present obstacles
and increase prices for delivered low-GHG hydrogen. However, given the
growth in the hydrogen sector and Federal funding for DOE's H2Hubs,
which will explicitly explore and incentivize hydrogen distribution,
the EPA believes hydrogen distribution and storage infrastructure will
not present a barrier to access for new combustion turbines opting to
co-fire 30 percent hydrogen by volume in 2032. Legislative actions
including the IIJA and IRA, utility initiatives, and industrial sector
production and infrastructure projects indicate that sufficient low-GHG
hydrogen and sufficient distribution infrastructure can reasonably be
expected to be available by this time. On this basis, the EPA is
proposing that compliance with the first phase of the standard, which
is based on an affected EGU co-firing 30 percent (by volume) low-GHG
hydrogen, will commence on January 1, 2032.
The proposed compliance date of January 1, 2038, for the second
phase of the standard of performance for combustion turbine EGUs in the
hydrogen co-fired subcategory, which is based on a proposed BSER of 96
percent (by volume) co-firing low-GHG hydrogen, is also based on an
assessment of when sufficient quantities of such hydrogen will be
available, as well as when turbine vendors are anticipated to have the
equipment necessary for higher percentages of hydrogen co-firing
available. As discussed in section VII.F.3 of this preamble, the EPA
expects that based on technology advances, growing demand for low-GHG
hydrogen, and the hydrogen production tax credits available under IRC
45V(b)(2), there will be continued expansion of the hydrogen production
and transmission network between 2032 and 2038. The EPA also notes
that, based on the current ages of the existing combustion turbine
fleet, the number of units that would be expected to meet their
standards of performance in 2038 by co-firing 96 percent hydrogen (by
volume) is likely to decline. Therefore, the EPA believes it is
reasonable to expect that there will be sufficient low-GHG hydrogen in
2038 to provide the quantities needed for both new and affected
existing combustion turbines in the hydrogen co-fired subcategory to
meet their applicable standards of performance. The EPA requests
comment on this assessment, as well as on whether compliance dates
other that January 1, 2032, and January 1, 2038, would be more
reasonable for the first and second phases of the standards for
affected units in the hydrogen co-fired subcategory, and why.
C. Requirement for State Plans To Maintain Stringency of the EPA's BSER
Determination
As explained in section V.C of this preamble, CAA section 111(d)(1)
requires the EPA to establish requirements for State plans that, in
turn, must include standards of performance for existing sources. Under
CAA section 111(a)(1), a standard of performance is ``a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the best system of
emission reduction which . . . the Administrator determines has been
adequately demonstrated.'' That is, the
[[Page 33374]]
EPA has the responsibility to determine the best system of emission
reduction for a given category or subcategory of sources and to
determine the degree of emission limitation achievable through
application of the BSER to affected sources.\617\ The level of emission
performance required under CAA section 111 is reflected in the EPA's
presumptive standards of performance.
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\617\ See, e.g., West Virginia v. EPA, 142 S. Ct. 2587, 2607
(2022) (``In devising emissions limits for power plants, EPA first
`determines' the `best system of emission reduction' that--taking
into account cost, health, and other factors--it finds `has been
adequately demonstrated.' The Agency then quantifies `the degree of
emission limitation achievable' if that best system were applied to
the covered source.'') (internal citations omitted).
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States use the EPA's presumptive standards of performance as the
basis for establishing requirements for affected sources in their State
plans. In order for the EPA to find a State plan ``satisfactory,'' that
plan must address each affected source within the State and achieve the
level of emission performance that would result if each affected source
was achieving its presumptive standard of performance, after accounting
for any application of RULOF.\618\ That is, while States have the
discretion to establish the applicable standards of performance for
affected sources in their State plans, the structure and purpose of CAA
section 111 require that those plans achieve equivalent stringency as
applying the EPA's presumptive standards of performance to each of
those sources (again, after accounting for any application of RULOF).
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\618\ As explained in section XI.D.2 of this preamble, States
may invoke RULOF to apply a less stringent standard of performance
to a particular affected EGU when the state demonstrates that the
EGU cannot reasonably apply the BSER to achieve the degree of
emission limitation determined by the EPA. In this case, the state
plan may not necessarily achieve the same stringency as each source
achieving the EPA's presumptive standards of performance because
affected EGUs for which RULOF has been invoked would have standards
of performance less stringent than the EPA's presumptive standards.
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The EPA's December 2022 proposed revisions to the CAA section 111
implementing regulations (40 CFR part 60, subpart Ba) would provide
that States are permitted, in appropriate circumstances, to adopt
compliance measures that allow their sources to meet their standards of
performance in the aggregate.\619\ As with the establishment of
standards of performance for affected sources, CAA section 111 requires
that State plans that include such flexibilities for complying with
standards of performance demonstrate equivalent stringency as would be
achieved if each affected source was achieving its standard of
performance.
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\619\ 87 FR 79176, 79207-08 (December 23, 2015).
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The requirement that State plans achieve equivalent stringency to
the EPA's BSER and degree of emission limitation is borne out of the
structure and purpose of CAA section 111, which is to mitigate air
pollution that is reasonably anticipated to endanger public health or
welfare. It achieves this purpose by requiring source categories that
cause or contribute to dangerous air pollution to operate more cleanly.
Unlike the Clean Air Act's NAAQS-based programs, section 111 is not
designed to reach a level of emissions that has been deemed ``safe'' or
``acceptable''; there is no air-quality target that tells States and
sources when emissions have been reduced ``enough.'' Rather, CAA
section 111 requires affected sources to reduce their emissions to the
level that the EPA has determined is achievable through application of
the best system of emission reduction, i.e., to achieve emission
reductions consistent with the applicable presumptive standard of
performance. Consistent with the statutory purpose of requiring
affected sources to operate more cleanly, the EPA typically expresses
presumptive standards of performance as rate-based emission
limitations.
In the course of complying with a rate-based standard of
performance under a State plan, an affected source may take an action
that removes it from the source category, e.g., by permanently ceasing
operations. In this case, the source is no longer subject to the
emission guidelines. An affected source may also choose to change its
operating characteristics in a way that impacts its overall emissions,
e.g., by changing its utilization; however, the source is still
required to meet its rate-based standard. In either instance, the
changes to one affected source do not implicate the obligations of
other affected sources. Although such changes may reduce emissions from
the source category, they do not absolve the remaining affected EGUs
from the statutory obligation to improve their emission performance
consistent with the level that the EPA has determined is achievable
through application of the BSER. This fundamental statutory requirement
applies regardless of whether a standard of performance is expressed or
implemented as a rate- or mass-based emission limitation, or whether
standards of performance are achieved on a source-specific or aggregate
basis.
In sum, consistent with the respective roles of the EPA and States
under CAA section 111, States have discretion to establish standards of
performance for affected sources in their State plans, and to provide
flexibilities for affected sources to use in complying with those
standards. However, State plans must demonstrate that they ultimately
provide for equivalent stringency as would be achieved if each affected
source was achieving the applicable presumptive standard of
performance, after accounting for any application of RULOF.
D. Establishing Standards of Performance
CAA section 111(d)(1)(A) provides that ``each State shall submit to
the Administrator a plan which establishes standards of performance for
any existing source''; that plan must also ``provide[ ] for the
implementation and enforcement of such standards of performance.'' That
is, States must use the BSER and stringency in the EPA's emission
guidelines to establish standards of performance for each existing
affected EGU through a State plan.
To assist States in developing State plans that achieve the level
of stringency required by the statute, it has been the EPA's
longstanding practice to provide presumptively approvable standards of
performance or a methodology for establishing such standards. For the
purpose of these emission guidelines, the EPA is proposing a
methodology for States to use in establishing presumptively approvable
standards of performance for affected existing EGUs. Per CAA section
111(a)(1), the basis of this methodology is the degree of emission
limitation the EPA has determined is achievable through application of
the BSER to each subcategory. The EPA anticipates and intends for most
States to apply the presumptive standards of performance to affected
EGUs.
Additionally, CAA section 111(d)(1)(B) permits States to take into
consideration a particular affected EGU's RULOF when applying a
standard of performance to that source. The EPA's proposed revisions to
the CAA section 111 implementing regulations at 40 CFR part 60, subpart
Ba provide that a State would be able to apply a less stringent
standard of performance to an affected EGU when the State can
demonstrate that the source cannot reasonably apply the BSER to achieve
the degree of emission limitation determined by the EPA. Proposed
subpart Ba describes the conditions that would warrant application of a
less stringent RULOF standard under these emission guidelines and how a
RULOF standard
[[Page 33375]]
would be determined. Further detail about how the EPA proposes to
implement the RULOF provision in the context of this rulemaking is
provided in section XII.D.2 of this preamble.
States also have the authority to apply standards of performance to
affected EGUs that are more stringent than the EPA's presumptively
approvable standards of performance.\620\
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\620\ 40 CFR 60.24a(f). The EPA has proposed to revise this
provision to clarify that it has the obligation and authority to
review and approve state plans that contain the more stringent
requirements. 87 FR 79176, 79204 (December 23, 2022).
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1. Application of Presumptive Standards
This section of the preamble describes the EPA's approach to
providing presumptive standards of performance for each of the
subcategories of affected EGUs under these emission guidelines,
including establishing baseline emission performance. Under this
proposal, each subcategory with a proposed BSER and degree of emission
limitation would have a corresponding methodology for establishing
presumptively approvable standards of performance (also referred to as
``presumptive standards of performance'' or ``presumptive standards'').
A State, when establishing standards of performance for affected
EGUs in its plan, would identify each affected EGU in the State and
specify into which subcategory each EGU falls. The EPA is proposing
that the State would then use the corresponding methodology for the
given subcategory to calculate and apply the presumptively approvable
standard of performance for each affected EGU.
States also have the authority to deviate from the methodology for
presumptively approvable standards, in order to apply a more stringent
standard of performance through increasing the degree of emission
limitation beyond what the EPA has determined to be achievable for
units as a general matter (e.g., a State decides that an EGU in the
medium-term coal-fired subcategory should co-fire 50 percent natural
gas instead of 40 percent). Deviations to increase stringency do not
trigger use of the RULOF mechanism, which requires States to
demonstrate that an affected EGU cannot reasonably apply the BSER to
achieve the degree of emission limitation determination by the
EPA.\621\ The EPA proposes to presume that standards of performance
that are more stringent than the EPA's presumptive standards are
``satisfactory'' for the purposes of CAA section 111(d).
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\621\ 87 FR 79176, 79199 (December 23, 2022).
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a. Establishing Baseline Emission Performance for Presumptive Standards
For each subcategory, the proposed methodology to calculate a
standard of performance entails establishing a baseline of
CO2 emissions and corresponding electricity generation for
an affected EGU and then applying the degree of emission limitation
achievable through the application of the BSER (as established in
section X.D and XI.C of this preamble). The methodology for
establishing baseline emission performance for an affected EGU is
identical in each of the subcategories but will result in a value that
is unique to each affected EGU. To establish baseline emission
performance for an affected EGU, the EPA is proposing that a State will
use the CO2 mass emissions and corresponding electricity
generation data for a given affected EGU from any continuous 8-quarter
period from 40 CFR part 75 reporting within the 5 years immediately
prior to the date the final rule is published in the Federal Register.
This proposed period is based on the NSR program's definition of
``baseline actual emissions'' for existing electric steam generating
units. See 40 CFR 52.21(b)(48)(i). Eight quarters of 40 CFR part 75
data corresponds to a 2-year period, but the EPA is proposing 8
quarters of data as that corresponds to quarterly reporting according
to 40 CFR part 75. Functionally, the EPA expects States to utilize the
most representative 8-quarter period of data from the 5 years
immediately preceding the date the final rule is published in the
Federal Register. For the 8 quarters of data, the EPA is proposing that
a State would divide the total CO2 emissions (in the form of
pounds) over that continuous time period by the total gross electricity
generation (in the form of MWh) over that same time period to calculate
baseline CO2 emission performance in lb CO2 per
MWh. As an example, a State establishing baseline emission performance
in the year 2023 would start by evaluating the CO2 emissions
and electricity generation data for each of its affected EGUs for 2018
through 2022 and choosing, for each affected EGU, a continuous 8-
quarter period that it deems to be the best representation of the
operation of that affected EGU. While the EPA will evaluate the choice
of baseline periods chosen by States when reviewing State plan
submissions, the EPA intends to defer to a State's reasonable exercise
of discretion as to which 8-quarter period is representative.
The EPA is proposing to require the use of 8 quarters during the 5-
year period prior to the date the final rule is published in the
Federal Register as the relevant period for the baseline methodology
for a few reasons. First, each affected EGU has unique operational
characteristics that affect the emission performance of the EGU (load,
geographic location, hours of operation, coal rank, unit size, etc.),
and the EPA believes each affected EGU's emission performance baseline
should be representative of the source-specific conditions of the
affected EGU and how it has typically operated. Additionally, allowing
a State to choose (likely in consultation with the owners or operators
of affected EGUs) the 8-quarter period for assessing baseline
performance can avoid situations in which a prolonged period of
atypical operating conditions would otherwise skew the emissions
baseline. Relatedly, the EPA believes that by using total mass
CO2 emissions and total electric generation for an affected
EGU over an 8-quarter period, any relatively short-term variability of
data due to seasonal operations or periods of startup and shutdown, or
other anomalous conditions, will be averaged into the calculated level
of baseline emission performance. The baseline-setting approach of
using total CO2 mass emissions and total electric generation
over an 8-quarter period also aligns with the reporting and compliance
requirements. The EPA is proposing that compliance would be
demonstrated annually based on the lb CO2/MWh emission rate
derived by dividing the total reported CO2 mass emissions by
the total reported electric generation for an affected EGU during the
compliance year, which is consistent with the expression of the degree
of emission limitation proposed for each subcategory in sections X.D.4,
X.E.2, and XI.C. The EPA believes that using total mass CO2
emissions and total electric generation provides a simple and
streamlined approach for calculating baseline emission performance
without the need to sort and filter non-representative data; any minor
amount of non-representative data will be subsumed and accounted for
through implicit averaging over the course of the 8-quarter period.
Moreover, this approach, by not sorting or filtering the data,
eliminates any need for discretion in assessing whether the data is
appropriate to use.
The EPA is soliciting comment on the proposed baseline-setting
approach and specifically on the applicability of such an approach for
each of the different subcategories. The EPA is proposing a continuous
8-quarter period to better average out operating variability but
[[Page 33376]]
solicits comment on whether a different time period would be more
appropriate for assessing baseline emission performance, as well as on
the 5-year window from which the period for baseline emission
performance is chosen. The EPA also solicits comment on the use of
total mass CO2 emissions and total electric generation over
a consecutive 8-quarter time period as representative and on whether
the EPA's proposed approach is appropriate.
The EPA believes that using the proposed baseline-setting approach
as the basis for establishing presumptively approvable standards of
performance will provide certainty for States, as well as transparency
and a streamlined process for State plan development. While this
approach is specifically designed to be flexible enough to accommodate
unit-specific circumstances, States retain the ability to deviate from
the methodologies the EPA is proposing for establishing baselines of
emission performance for affected EGUs. The EPA believes that the
instances in which a State may need to use an alternate baseline-
setting methodology will be limited to anticipated changes in
operation, i.e., circumstances in which historical emission performance
is not representative of future emission performance. The EPA is
proposing that States wishing to vary the baseline calculation for an
affected EGU based on anticipated changes in operation, when those
changes result in a less stringent standard of performance, must use
the RULOF mechanism, which is designed to address such contingencies.
b. Presumptive Standards for Steam Generating Units
As described in section X.C of this preamble, the EPA is proposing
to first subcategorize affected existing steam generating units by fuel
type: coal-fired and oil- or natural gas-fired steam generating units.
The EPA is proposing further subcategorization into four subcategories
for coal-fired steam generating units and seven subcategories for oil-
and natural gas-fired steam generating units. As explained in section
X.C.3, the EPA is proposing that an affected coal-fired steam
generating unit's operating horizon determines the applicable
subcategory in three of the four subcategories; in the case of the
near-term subcategory, the operating horizon and load level establish
applicability.
The EPA notes that, as explained in section X.C.3 of this preamble,
where the owners or operators of affected coal-fired steam-generating
units have elected to commit to permanently cease operation (and, in
the case of near-term operating horizon units, to limit their capacity
factor) and have also elected to make any such commitments federally
enforceable through inclusion in a State plan, a State may rely on such
commitments to subcategorize coal-fired steam generating units under
these emission guidelines. To be included in a State plan a commitment
to cease operations or to limit capacity factor must be enforceable by
the State, whether through State rule, agreed order, permit, or other
legal instrument.\622\ Upon EPA approval of the State plan, that
commitment will become federally enforceable.
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\622\ 40 CFR 60.26a.
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For affected oil- and natural gas-fired steam generating units,
subcategories are defined by load level and the type of fuel fired, as
well as locality (i.e., continental and non-continental U.S.). There
are four subcategories for oil-fired steam generating units based on
different combinations of load level (base load, intermediate load, and
low load) and locality, and three subcategories for natural gas-fired
steam generating units based on load level (base load, intermediate,
and low).
i. Long-Term Coal-Fired Steam Generating Units
This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
long-term coal-fired steam generating units. Affected coal-fired steam
generating units that have either (1) Elected to commit to permanently
cease operations on January 1, 2040, or later, or (2) that have not
elected to commit to permanently cease operations as part of the
State's plan submission, fall within this subcategory and have a
proposed BSER of CCS with 90 percent capture and a proposed degree of
emission limitation of 90 percent capture of the mass of CO2
in the flue gas (i.e., the mass of CO2 after the boiler but
before the capture equipment) over an extended period of time and an
88.4 percent reduction in emission rate on a gross basis over an
extended period of time. The EPA is proposing that where States use the
methodology described here to establish standards of performance for an
affected EGU in this subcategory, those established standards would be
presumptively approvable when included in a State plan submission. In
section X of this preamble, for the long-term coal-fired subcategory,
the EPA is soliciting comment on a capture rate of 90 to 95 percent and
a degree of emission limitation defined by a reduction in emission rate
on a gross basis from 75 to 90 percent.
Establishing a standard of performance for an affected coal-fired
EGU in this subcategory consists of two steps: establishing a source-
specific level of baseline emission performance (as described above);
and applying the level of stringency, based on the application of the
BSER, to that level of baseline emission performance. Implementation of
CCS with a capture rate of 90 precent translates to a level of
stringency of an 88.4 percent reduction in CO2 emission rate
(see section X.D.4.a of this preamble) compared to the baseline level
of emission performance. Using the complement of 88.4 percent (i.e.,
11.6 percent) and multiplying it by the baseline level of emission
performance results in the presumptively approvable standard of
performance. For example, if a long-term coal-fired EGU's level of
baseline emission performance is 2,000 lbs per MWh, it will have a
presumptively approvable standard of performance of 232 lbs per MWh
(2,000 lbs per MWh multiplied by 0.116).
The EPA is also proposing that affected coal-fired EGUs in the
long-term subcategory comply with federally enforceable increments of
progress, which are described in section XII.D.3.a of this preamble.
The EPA solicits comments on this proposed methodology for
calculating presumptively approvable standards of performance for long-
term coal-fired steam generating units.
ii. Medium-Term Coal-Fired Steam Generating Units
This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
medium-term coal-fired steam generating units. Affected coal-fired
steam generating units that have elected to commit to permanently cease
operations after December 31, 2031, and before January 1, 2040, have a
proposed BSER of 40 percent co-firing of natural gas. The EPA is
proposing that where States use the methodology described here to
establish standards of performance for an affected EGU in this
subcategory, those established standards of performance would be
presumptively approvable when included in a State plan submission.
Establishing a standard of performance for an affected EGU in this
subcategory consists of two steps: establishing a source-specific level
of baseline emission performance (as described earlier in this
preamble); and applying the level of emission reduction
[[Page 33377]]
stringency, based on the application of the BSER, to that level of
baseline emission performance. Implementation of natural gas co-firing
at a level of 40 percent of total annual heat input translates to a
level of stringency of a 16 percent reduction in CO2
emissions (see section X.D.4.b of this preamble) compared to the
baseline level of emission performance. Using the complement of 16
percent (i.e., 84 percent) and multiplying it by the baseline level of
emission performance results in the presumptively approvable standard
of performance for the affected EGU. For example, if a medium-term
coal-fired EGU's level of baseline emission performance is 2,000 lbs
per MWh, it will have a presumptively approvable standard of
performance of 1,680 lbs per MWh (2,000 lbs per MWh multiplied by
0.84). In section X of this preamble, for the medium-term coal-fired
subcategory, the EPA is soliciting comment on a natural gas co-firing
level of 30 to 50 percent and a degree of emission limitation from 12
to 20 percent.
For medium-term coal-fired steam generating units that have an
amount of co-firing that is reflected in the baseline operation, the
EPA is proposing that States account for such preexisting co-firing in
adjusting the degree of emission limitation. If, for example, an EGU
co-fires natural gas at a level of 10 percent of the total annual heat
input during the applicable 8-quarter baseline period, the
corresponding degree of emission limitation would be adjusted to 12
percent (i.e., an additional 30 percent of natural gas by heat input)
to reflect the preexisting level of natural gas co-firing. This results
in a standard of performance based on the degree of emission limitation
achieving an additional 30 percent co-firing beyond the 10 percent that
is accounted for in the baseline. The EPA believes this approach is a
more straightforward mathematical adjustment than adjusting the
baseline to appropriately reflect a preexisting level of co-firing.
However, the EPA solicits comment on whether the adjustment of a
standard of performance based on preexisting levels of natural gas co-
firing should be done through the baseline. To adjust the baseline to
account for preexisting natural gas co-firing, the State would need to
calculate a baseline of emission performance for an EGU that removes
the mass emissions and electric generation that are attributable to the
natural gas portion of the fuel. With this adjusted baseline that
removes the natural gas-fired portion, the presumptive standard of
performance would be calculated by multiplying the adjusted baseline by
the degree of emission limitation factor that reflects 40 percent co-
firing. The EPA is not proposing this methodology, because parsing the
attributable emissions and electric generation associated with natural
gas co-firing from the attributable emissions and electric generation
associated with coal-fired generation requires manipulation of the
emissions and electric generation data. However, the EPA solicits
comment on whether baseline adjustment is more appropriate and also why
that may be so.
The standard of performance for the medium-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, to qualify for inclusion in the subcategory an
affected coal-fired steam generating unit must have elected to commit
to permanently cease operations prior to January 1, 2040. If a State
decides to rely on such a commitment to place an affected EGU into the
medium-term coal-fired subcategory by making it an enforceable element
of its State plan, the commitment to cease operations will become
federally enforceable upon EPA approval of the plan.
The EPA is proposing that affected coal-fired EGUs that elect to
commit to dates to permanently cease operations for subcategory
applicability, including EGUs in the medium-term coal-fired
subcategory, have corresponding federally enforceable milestones with
which they must comply. The EPA intends these milestones to assist
affected EGUs in ensuring they are completing the necessary steps to
comply with their State plan and commitments to dates to permanently
cease operations. These milestones are described in detail in section
XII.D.3.b of this preamble. Affected EGUs in this subcategory would
also be required to comply with the federally enforceable increments of
progress described in section XII.D.3.a of this preamble.
The EPA solicits comment on the proposed methodology for
calculating presumptively approvable standards of performance for
medium-term coal-fired steam generating units, including on the
proposed approach for adjusting a presumptively approvable standard of
performance to accommodate preexisting natural gas co-firing.
iii. Imminent-Term Coal-Fired Steam Generating Units
This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
imminent-term coal-fired steam generating units. Affected coal-fired
steam generating units that elect to commit to permanently cease
operations before January 1, 2032, have a proposed BSER of routine
methods of operation and maintenance. Therefore, the proposed
presumptively approvable standard of performance is not to exceed the
baseline emission performance of the affected EGU (as described in
section XII.D.1.a of this preamble).
Unlike the proposed standards of performance for the long-term and
medium-term coal-fired steam generating units, establishing a standard
of performance for an affected EGU in the imminent-term subcategory
consists of just one step. The EPA is proposing that where States use
the methodology described in section XII.D.1.a of this preamble to
establish the baseline level of emission performance for an affected
EGU, the emission rate described by that baseline would constitute the
presumptively approvable standard of performance. This standard of
performance reflects that the proposed BSER for these affected EGUs is
routine methods of operation and maintenance and a degree of emission
limitation equivalent to no increase in emission rate from the baseline
level of emission performance. This also ensures that the affected EGU
will not backslide in its emission performance.
Although the EPA believes that the baseline performance level
adequately accounts for variability in annual emission rate, the EPA is
also soliciting comment on a methodology for a presumptive standard
above the baseline emission performance. For the imminent-term coal-
fired subcategory, the EPA is soliciting comment on a presumptive
standard that is defined by 0 to 2 standard deviations in annual
emission rate (using the 5-year period of data) above the baseline
emission performance, or that is 0 to 10 percent above the baseline
emission performance.
Because the EPA is soliciting comment on a potential BSER for this
subcategory based on low levels of natural gas co-firing, as described
in section X.D.3.b.ii, comment is also being solicited on the
presumptively approvable standards for that potential BSER. The BSER is
based on the maximum hourly heat input of natural gas fired in the unit
(MMBtu/hr) relative to the maximum hourly heat input the
[[Page 33378]]
unit is capable of (i.e., the nameplate capacity on an MMBtu/hr basis).
The EPA is soliciting comment on the baseline natural gas co-firing
level being determined from the 5 years of data preceding the
publication of the final rule, or based on engineering limitations
(i.e., extent of startup guns or size of pipeline to unit). That
percent of heat input results in percent reductions from the emission
performance baseline equivalent to the percent of heat input times 0.4.
Adjustments relative to current co-firing levels may be accounted for
in a manner consistent with section XII.D.1.b.ii. Alternatively, the
EPA is soliciting comment on a degree of emission limitation on a fuel
heat input basis. For a potential BSER of low levels of natural gas co-
firing, the EPA is therefore also soliciting comment on a presumptively
approvable standard defined on a heat input basis.
The standard of performance for the imminent-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, to qualify for inclusion in the subcategory an
affected coal-fired EGU must have elected to commit to permanently
cease operations prior to January 1, 2032. If a State decides to rely
on such a commitment to place an affected EGU into the imminent-term
coal-fired subcategory by making it an enforceable element of its State
plan, the commitment to cease operations will become federally
enforceable upon EPA approval of the plan.
The EPA is also proposing that affected coal-fired steam generating
units that have elected to commit to dates to permanently cease
operations for subcategory applicability, including EGUs in the
imminent-term coal-fired subcategory, have corresponding federally
enforceable milestones with which they must comply. The EPA intends
these milestones to assist affected EGUs in ensuring they are
completing the necessary steps to comply with these dates in their
State plan. These milestones are described in detail in section
XII.D.3.b of this preamble.
The EPA solicits comment on the proposed methodology for
establishing presumptively approvable standards of performance for
imminent-term coal-fired steam generating units.
iv. Near-Term Coal-Fired Steam Generating Units
Similar to the proposed approach for establishing presumptively
approvable standards of performance for affected EGUs in the imminent-
term coal-fired subcategory, the EPA is proposing that affected EGUs in
the near-term coal-fired subcategory have a presumptively approvable
standard of performance based on the baseline emission performance of
the affected EGU (as described in section XII.D.1.a of this preamble).
The near-term subcategory includes affected coal-fired steam generating
units that have elected to commit to permanently cease operations after
December 31, 2031, and before January 1, 2035, and that have elected to
adopt an annual capacity factor limitation of 20 percent.
The EPA is proposing that where States use the methodology
described in section XII.D.1.a of this preamble to establish the
baseline level of emission performance for an affected EGU, the
emission rate described by that baseline would constitute the
presumptively approvable standard of performance. This standard of
performance reflects the proposed BSER of routine methods of operation
and maintenance and a degree of emission limitation equivalent to no
increase in emission rate. This also ensures that the affected EGU will
not backslide in its emission performance.
For the near-term coal-fired subcategory, the EPA is soliciting
comment on a presumptive standard that is defined by 0 to 2 standard
deviations in annual emission rate (using the 5-year period of data)
above the baseline emission performance, or that is 0 to 10 percent
above the baseline emission performance.
Because the EPA is soliciting comment on a potential BSER for this
subcategory based on low levels of natural gas co-firing, as described
in section X.D.3.b.ii, comment is also being solicited on the
presumptively approvable standards for that potential BSER. The BSER is
based on the maximum hourly heat input of natural gas fired in the unit
(MMBtu/hr) relative to the maximum hourly heat input the unit is
capable of (i.e., the nameplate capacity on an MMBtu/hr basis). The EPA
is soliciting comment on the baseline natural gas co-firing level being
determined from the 5 years of data preceding the publication of the
final rule, or based on engineering limitations (i.e., extent of
startup guns or size of pipeline to unit). That percent of heat input
results in percent reductions from the emission performance baseline
equivalent to the percent of heat input times 0.4. Adjustments relative
to current co-firing levels may be accounted for in a manner consistent
with section XII.D.1.b.ii. Alternatively, the EPA is soliciting comment
on a degree of emission limitation on a fuel heat input basis. For a
potential BSER of low levels of natural gas co-firing, the EPA is
therefore also soliciting comment on a presumptively approvable
standard defined on a heat input basis.
The standard of performance for the near-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, to qualify for inclusion in the subcategory an
affected coal-fired EGU must have elected to commit to permanently
cease operations after December 31, 2031, and before January 1, 2035,
and must have elected to adopt an annual capacity factor limitation of
20 percent. If a State decides to rely on such commitments to place an
affected EGU into the near-term coal-fired subcategory by making them
enforceable elements of its State plan, the commitments to cease
operations and to limit its capacity factor will become federally
enforceable upon EPA approval of the plan.
The EPA is also proposing that affected coal-fired EGUs that have
elected to commit to dates to permanently cease operations for
subcategory applicability, including EGUs in the near-term coal-fired
subcategory, have corresponding federally enforceable milestones with
which they must comply. The EPA intends these milestones to assist
affected EGUs in ensuring they are completing the necessary steps to
comply with these dates in their State plan. These milestones are
described in detail in section XII.D.3.b of this preamble.
The EPA solicits comment on the proposed methodology for
establishing presumptively approvable standards of performance for
near-term coal-fired steam generating units.
v. Natural Gas-Fired Steam Generating Units and Continental Oil-Fired
Steam Generating Units
This section describes the EPA's proposed methodology for
presumptively approvable standards of performance for affected natural
gas-fired and continental oil-fired steam generating units: low load
natural gas-fired steam generating units, intermediate load natural
gas- fired steam generating units, base load natural gas-fired steam
generating units, low load oil-fired steam generating units,
intermediate load continental oil-fired steam generating units, and
base load continental oil-fired steam
[[Page 33379]]
generating units. It does not address non-continental intermediate oil-
fired and non-continental base load oil-fired steam generating units,
which are described in section XII.D.1.b.vi of this preamble. The
proposed definitions of these subcategories are discussed in section
X.C.2 of this preamble. The proposed presumptive standards of
performance are based on degrees of emission limitation that units are
currently achieving, consistent with the proposed BSER of routine
methods of operation and maintenance, which amounts to a proposed
degree of emission limitation of no increase in emission rate.
Unlike the approach to establishing presumptive standards of
performance for coal-fired EGUs in these proposed emission guidelines,
the EPA is proposing presumptive standards of performance for affected
natural gas-fired and continental oil-fired steam generating units in
lieu of methodologies that States would use to establish presumptive
standards of performance. This is largely because the low variability
in emissions data at intermediate and base load for these units and
relatively consistent performance between these units at those load
levels, as discussed in section X.E of this preamble and detailed in
the Natural Gas- and Oil-fired Steam Generating Unit TSD, allows for
the identification of a generally applicable standard of performance.
However, for natural gas- or oil-fired steam generating units with
low annual capacity factors, annual emission rates can be high (greater
than 2,500 lb CO2/MWh-gross) and can vary considerably
across units and from year to year. Despite their relatively high
emission rates, though, overall emissions from these units are low.
Based on these considerations, the EPA is not proposing a BSER or that
States establish standards of performance for these units at this time.
However, as noted above, the EPA is soliciting comment on determining a
BSER of uniform fuels for these units. In addition, the EPA is
soliciting comment on a presumptive standard of performance for these
units based on heat input. Specifically, the EPA is soliciting comment
on a range of presumptive standards of performance from 120 to 130 lb
CO2/MMBtu for low load natural gas-fired steam generating
units, and from 160 to 170 lb CO2/MMBtu for low load oil-
fired steam generating units.
For intermediate load natural gas-fired units (annual capacity
factors greater than or equal to 8 percent and less than 45 percent),
annual emission rates are less than 1,500 lb CO2/MWh-gross
for about 90 percent of the units. Therefore, the EPA is proposing the
presumptive standard of performance of an annual calendar-year emission
rate of 1,500 lb CO2/MWh-gross for these units.
For base load natural gas-fired units (annual capacity factors
greater than or equal to 45 percent), annual emission rates are less
than 1,300 lb CO2/MWh-gross for about 80 percent of units.
Therefore, the EPA is proposing the presumptive standard of performance
of an annual calendar-year emission rate of 1,300 lb CO2/
MWh-gross for these units.
In the continental U.S., there are few if any oil-fired steam
generating units that operate with intermediate or high utilization.
Liquid-oil-fired steam generating units with 24-month capacity factors
less than 8 percent do qualify for a work practice standard in lieu of
emission requirements under the Mercury and Air Toxics Standards rule
(MATS) (40 CFR 63, subpart UUUUU). If oil-fired units operated at
higher annual capacities, it is likely they would do so with
substantial amounts of natural gas firing and have emission rates that
are similar to steam generating units that fire only natural gas at
those levels of utilization. There are a few natural gas-fired steam
generating units that are near the threshold for qualifying as oil-
fired units (i.e., firing more than 15 percent oil in a given year) but
that on average fire more than 90 percent of their heat input from
natural gas. Therefore, the EPA is proposing the same presumptive
standards of performance for oil-fired steam generating units as for
natural gas-fired units, noted above.
The EPA is also taking comment on a range of presumptive standards
of performance for natural gas- and oil-fired steam generating units.
Specifically, the EPA is soliciting comment on standards between (1)
1,400 and 1,600 lb CO2/MWh-gross for intermediate load
natural gas-fired units, (2) 1,250 and 1,400 lb CO2/MWh-
gross for base load natural gas-fired units, (3) 1,400 and 2,000 lb
CO2/MWh-gross for intermediate load oil-fired units, and (4)
1,250 and 1,800 lb CO2/MWh-gross for base load oil-fired
units. The upper end of the ranges for oil-fired units is higher
because of the limited data available for oil-fired units that operate
at those annual capacity factors.
vi. Non-Continental Oil-Fired Steam Generating Units
The EPA is proposing that for affected EGUs in the non-continental
intermediate oil-fired and non-continental base load oil-fired
subcategory, a presumptively approvable standard of performance would
be based on baseline emission performance, consistent with the EPA's
proposed BSER determination of routine methods of operation and
maintenance and the proposed degree of emission limitation of no
increase in emission rate. The EPA is proposing that where States use
the methodology described in section XII.D.1.a of the preamble to
establish unit-specific baseline levels of emission performance for
affected EGUs in this subcategory, those emission rates would
constitute presumptively approvable standards of performance when
included in a State plan submission. This standard of performance would
ensure no increase in the unit-specific emission rate from the baseline
level of emission performance.
For the intermediate and base load non-continental oil-fired
subcategory, the EPA is soliciting comment on a presumptive standard
that is defined by 0 to 2 standard deviations in annual emission rate
(using the 5-year period of data) above the baseline emission
performance, or that is 0 to 10 percent above the baseline emission
performance.
The EPA solicits comment on the proposed methodology for
establishing presumptively approvable standards of performance for non-
continental oil-fired steam generating units in the intermediate and
base load subcategories.
c. Presumptive Standards for Combustion Turbines
As described in section XI.C, the EPA is proposing to define
affected existing combustion turbines under these emission guidelines
as units with a capacity greater than 300 MW and an annual capacity
factor of greater than 50 percent. Within this set of units, the EPA is
proposing two subcategories based on the type of fuel used: existing
combustion turbines that adopt the pathway with a standard of
performance based on CCS, referred to as the ``CCS subcategory'' and
existing combustion turbines that adopt the pathway with a standard of
performance based on hydrogen co-firing, referred to as the ``hydrogen
co-fired subcategory.'' States, in their State plan submissions, would
be required to assign existing combustion turbine EGUs with capacities
greater than 300 MW and the ability to operate at an annual capacity
factor of greater than 50 percent to one
[[Page 33380]]
subcategory or the other.\623\ States would then be required to include
in their plans the presumptive standard of performance corresponding to
the appropriate subcategory for each affected existing combustion
turbine EGU. As discussed in section XII.D.2 of this preamble, States,
in applying a standard of performance to a particular affected existing
combustion turbine EGU, also have discretion to consider that EGU's
remaining useful life and other factors.
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\623\ As explained in section XI.D of this preamble, the EPA is
soliciting comment on, inter alia, whether to finalize both the CCS
and hydrogen co-fired pathways for existing combustion turbines or
whether to finalize a BSER determination with a single pathway. If
the EPA does not finalize the proposed two-pathway approach, the
state plan requirements for existing combustion turbines in this
section XII of the preamble will be updated accordingly for the
final rule.
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However, the EPA anticipates that some existing combustion turbine
EGUs that are greater than 300 MW do not intend to operate at an annual
capacity factor of greater than 50 percent starting in 2032 (the first
proposed compliance date for affected existing combustion turbine EGUs
under these emission guidelines). Such an EGU may elect to commit to an
enforceable annual capacity factor limitation of less than or equal to
50 percent. If a State elects to include such an enforceable commitment
in its State plan, the State would not be required to have a standard
of performance for that particular combustion turbine EGU in its plan.
Otherwise, each affected existing combustion turbine that is greater
than 300 MW and that has the ability to operate at an annual capacity
factor of greater than 50 percent must have a subcategory designation
and standard of performance in the State plan.
The EPA is proposing that States may structure the requirements for
affected combustion turbine EGUs in their State plans so that the
applicable standard of performance must be met for years in which the
unit operates above the 50 percent annual capacity factor threshold.
States and the owners or operators of affected EGUs that have such
contingent standards of performance would be required to ensure that an
affected EGU has complied with its standard of performance for each
calendar year in which it has operated at an annual capacity factor of
greater than 50 percent. The EPA expects that if the owner or operator
of an affected combustion turbine EGU that has a standard of
performance believes there is a chance the EGU will operate at an
annual capacity factor of greater than 50 percent in the upcoming
compliance period, it will plan to meet that standard. Given this
practical reality, the EPA is taking comment on whether it should
require that once an affected existing combustion turbine EGU has
exceeded the 50 percent annual capacity factor threshold and triggered
application of its standard of performance for a given compliance
period, that EGU must continue to meet its standard in subsequent
compliance periods.
i. Carbon Capture and Storage Existing Combustion Turbine Generating
Units
This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
existing combustion turbine EGUs that adopt the pathway with a standard
of performance based on CCS. Affected EGUs that are assigned to this
subcategory have a proposed BSER of CCS with 90 percent capture and a
proposed degree of emission limitation of 90 percent capture of the
mass of CO2 in the flue gas (i.e., the mass of
CO2 after the turbine but before the capture equipment) over
an extended period of time and an 89 percent reduction in emission rate
on a gross basis over an extended period of time. The EPA is proposing
that where States use the methodology described here to establish
standards of performance for an affected EGU in this subcategory, those
established standards would be presumptively approvable when included
in a State plan submission.
Establishing a standard of performance for an affected combustion
turbine EGU in this subcategory consists of two steps: establishing a
source-specific level of baseline emission performance (as described
above); and applying the level of stringency, based on the application
of the BSER, to that level of baseline emission performance.
Implementation of CCS with a capture rate of 90 precent translates to a
level of stringency of an 89 percent reduction in CO2
emission rate (see section XI.C of this preamble) compared to the
baseline level of emission performance. Using the complement of 89
percent (i.e., 11 percent) and multiplying it by the baseline level of
emission performance results in the presumptively approvable standard
of performance. For example, if a combustion turbine EGU in this
subcategory has a baseline level of emission performance of 1,000 lbs
per MWh, it will have a presumptively approvable standard of
performance of 110 lbs per MWh (1,000 lbs per MWh multiplied by 0.11).
The EPA is also proposing that affected combustion turbines in this
subcategory comply with federally enforceable increments of progress,
which are described in section XII.D.3.a of this preamble.
The EPA solicits comments on this proposed methodology for
calculating presumptively approvable standards of performance for
existing combustion turbines in the CCS subcategory.
ii. Hydrogen Co-Fired Existing Combustion Turbine Generating Units
This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
existing combustion turbines that adopt the pathway with a standard of
performance based on hydrogen co-firing. Affected combustion turbine
EGUs in this subcategory have a proposed BSER of hydrogen co-firing
with two phases of stringency. In the first phase, affected EGUs in
this subcategory co-fire hydrogen at a level of 30 percent by volume
with a proposed degree of emission limitation of 12 percent reduction
in emission rate on a gross basis over an extended period of time. In
the second phase, affected EGUs in this subcategory co-fire hydrogen at
a level of 96 percent by volume with a proposed degree of emission
limitation of 88.4 percent reduction in emission rate on a gross basis
over an extended period of time. As described in section XII.B,
compliance with the first phase commences on January 1, 2032, and
compliance with the second phase commences on January 1, 2038. The EPA
is proposing that where States use the methodology described here to
establish standards of performance for this subcategory, those
established standards of performance would be presumptively approvable
when included in a State plan submission.
Establishing a standard of performance for an affected EGU in this
subcategory consists of three steps: first, establishing a source-
specific level of baseline emission performance (as described earlier
in this preamble); and second, applying the level of emission reduction
stringency for the first phase, based on the application of the first
phase BSER, to that level of baseline emission performance; and third,
applying the level of emission reduction stringency for the second
phase, based on the application of the second phase BSER, to that level
of baseline emission performance.
Implementation of hydrogen co-firing at a level of 30 percent by
volume translates to a level of stringency of a 12 percent reduction in
CO2 emissions (see
[[Page 33381]]
section XI.C of this preamble) compared to the baseline level of
emission performance. Using the complement of 12 percent (i.e., 88
percent) and multiplying it by the baseline level of emission
performance results in the presumptively approvable standard of
performance for the affected EGU. For example, if a combustion turbine
EGU that co-fires 30 percent hydrogen (by volume) has a baseline level
of emission performance of 1,000 lbs per MWh, it will have a
presumptively approvable standard of performance of 880 lbs per MWh
(1,000 lbs per MWh multiplied by 0.88) for the first phase.
Implementation of hydrogen co-firing at a level of 96 percent by
volume translates to a level of stringency of an 88.4 percent reduction
in CO2 emissions (see section XI.C of this preamble)
compared to the baseline level of emission performance. Using the
complement of 88.4 percent (i.e., 11.6 percent) and multiplying it by
the baseline level of emission performance results in the presumptively
approvable standard of performance for the affected EGU. For example,
if a combustion turbine EGU that co-fires 96 percent hydrogen (by
volume) has a baseline level of emission performance of 1,000 lbs per
MWh, it will have a presumptively approvable standard of performance of
116 lbs per MWh (1,000 lbs per MWh multiplied by 0.116) for the second
phase.
The EPA is proposing that affected combustion turbine EGUs in this
subcategory that meet their standards of performance using hydrogen co-
firing must co-fire with low-GHG hydrogen. States must make this an
enforceable part of their State plans, as described in further detail
in section XII.F.1.b.i.
The EPA is also proposing that affected combustion turbines in this
subcategory comply with federally enforceable increments of progress,
which are described in section XII.D.3.a of this preamble.
The EPA solicits comment on the proposed methodology for
calculating presumptively approvable standards of performance for
existing combustion turbine EGUs in the hydrogen co-fired subcategory.
2. Remaining Useful Life and Other Factors
Under CAA section 111(d), the EPA is required to promulgate
regulations under which States submit plans applying standards of
performance to affected EGUs. While States establish the standards of
performance, there is a fundamental obligation under CAA section 111(d)
that such standards reflect the degree of emission limitation
achievable through the application of the BSER, as determined by the
EPA.\624\ The EPA identifies this degree of emission limitation as part
of its emission guideline. 40 CFR 60.22a(b)(5). Thus, as described in
section X.D of this preamble, the EPA is providing proposed
methodologies for States to follow in determining and applying
presumptively approvable standards of performance to affected EGUs in
each of the subcategories covered by these emission guidelines.
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\624\ West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022) (``In
devising emissions limits for power plants, EPA first `determines'
the `best system of emission reduction' that--taking into account
cost, health, and other factors--it finds `has been adequately
demonstrated.' The Agency then quantifies `the degree of emission
limitation achievable' if that best system were applied to the
covered source.'') (internal citations omitted).
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While standards of performance must generally reflect the degree of
emission limitation achievable through application of the BSER as
determined by the EPA, CAA section 111(d)(1) also requires that the EPA
regulations permit the States, in applying a standard of performance to
a particular designated facility, to ``take into consideration, among
other factors, the remaining useful life of the existing sources to
which the standard applies.'' The EPA's implementing regulations under
40 CFR 60.24a thus allow a State to consider a particular designated
facility's remaining useful life and other factors in applying to that
facility a standard of performance that is less stringent than the
presumptive level of stringency given in an emission guideline.
In December 2022, the EPA proposed to clarify the existing
requirements in subpart Ba governing what a State must demonstrate in
order to invoke RULOF and provide a less stringent standard of
performance when submitting a State plan.\625\ Specifically, the EPA
proposed to require the State to demonstrate that a particular facility
cannot reasonably achieve the degree of emission limitation achievable
through application of the BSER based on one or more of three
delineated circumstances, and proposed to clarify those three
circumstances. The EPA also proposed additions and further
clarifications to the process of invoking RULOF and determining a
standard of performance based on RULOF, to ensure that use of the
provision does not undermine the overall presumptive level of
stringency of the BSER, as well as to provide a clear analytical
framework for States and the regulated community as they seek to craft
satisfactory plans that the EPA can ultimately approve.\626\
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\625\ 87 FR 79176, 79196-79206 (December 23, 2022).
\626\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002.
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The EPA is not soliciting comment in this rulemaking on the
proposed revisions to the RULOF provisions in subpart Ba, which are
subject to a separate rulemaking process. As noted in section XII.A of
this preamble, the EPA intends to finalize revisions to subpart Ba
prior to finalizing these emission guidelines. Those revised RULOF
provisions, including any changes made in response to public comments,
will apply to these emission guidelines. While the EPA is not taking
comment on the proposed provisions of subpart Ba themselves, the EPA is
requesting comment on how each of the RULOF provisions that the EPA
proposed in December 2022 would be implemented in the context of these
particular emission guidelines.
The remainder of this section of the preamble addresses how the
requirements associated with RULOF, as the EPA has proposed to revise
them, would apply to States and State plans under these emission
guidelines. First, it addresses the threshold requirements for
considering RULOF and how those requirements would apply to an affected
EGU under these emission guidelines. Second, it addresses how, if a
State has appropriately invoked RULOF for a particular affected EGU
under the previous step, it would be required to determine a source-
specific BSER and calculate a standard of performance for that affected
EGU. Third, it discusses the proposed requirement for plans that apply
less stringent standards of performance pursuant to RULOF to consider
the potential pollution impacts and benefits of control to communities
most affected by and vulnerable to emissions from the affected EGU.
Fourth, this section addresses the proposed provisions for the standard
for EPA review of State plans that include RULOF standards of
performance. And, finally, it discusses the EPA's proposed
interpretation of the Clean Air Act as laid out in the proposed
revisions to subpart Ba that the Act allows states to adopt and enforce
standards of performance more stringent than required by an applicable
emission guideline, and that the EPA has the ability and authority to
approve such standards of performance into State plans.
a. Threshold Requirements for Considering RULOF
As discussed earlier in this preamble, CAA section 111(d)(1)
expressly
[[Page 33382]]
requires the EPA to permit states to consider RULOF when applying a
standard of performance to a particular affected EGU. The EPA's
proposed revisions to the regulations governing states' use of RULOF
would provide a clear analytical framework to ensure that its use to
apply less stringent standards of performance for particular sources is
consistent across states. The proposed revisions would also ensure that
the use of RULOF does not undermine the overall presumptive level of
stringency and the emission reduction benefits of an emission
guideline, or undermine and render meaningless the EPA's BSER
determination. Such a result would be contrary to the overarching
purpose of CAA section 111(d), which is generally to achieve meaningful
emission reductions from designated facilities, in this case affected
EGUs, based on the BSER in order to mitigate pollution that endangers
public health and welfare.
To this end, proposed subpart Ba would provide that a State may
apply a less stringent standard of performance to a particular
facility, taking into consideration remaining useful life and other
factors, provided that the State demonstrates with respect to that
facility (or class of facilities) that it cannot reasonably apply the
BSER to achieve the degree of emission limitation determined by the
EPA. Invocation of RULOF would be required to be based on one or more
of three circumstances: (1) Unreasonable cost of control resulting from
plant age, location, or basic process design, (2) physical
impossibility or technical infeasibility of installing necessary
control equipment, or (3) other circumstances specific to the facility
that are fundamentally different from the information considered in the
determination of the BSER in the emission guidelines.\627\
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\627\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (containing proposed revisions to RULOF provisions at
40 CFR 60.24a(e)-(n)).
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A State wishing to invoke RULOF in order to apply a less stringent
standard to a particular affected EGU would be required to demonstrate
that there are fundamental differences between that EGU and the EPA's
BSER determination, based on consideration of the BSER factors that the
EPA considered in its analysis. In determining the BSER and the degree
of emission reductions achievable through application of the BSER in
these proposed emission guidelines, the EPA considered whether a system
of emission reduction is adequately demonstrated for the subcategory
based on the physical possibility and technical feasibility of applying
that system, the costs of a system of emission reduction, the non-air
quality health and environmental impacts and energy requirements
associated with a system of emission reduction, and the extent of
emission reductions from a system.\628\
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\628\ The EPA also considered impacts on the energy sector as
part of its BSER determinations. However, because this consideration
does not apply at the level of a particular affected EGU, it would
not be appropriate basis for invoking RULOF.
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For each subcategory, the EPA evaluated certain metrics related to
each of these BSER factors. For example,\629\ in evaluating the costs
associated with CCS and natural gas co-firing for existing coal-fired
steam generating units, the EPA considered both $/ton CO2
reduced and increases in levelized costs expressed as dollars per MWh
electricity generation. A State wishing to invoke RULOF for a
particular affected EGU in the long-term coal-fired subcategory based
on unreasonable cost of control would also be required to consider the
cost as $/ton of CO2 reduced and $/MWh electricity
generated. The State would further have to demonstrate that the costs,
as represented by these two metrics, for the particular affected EGU
are fundamentally different, i.e., significantly higher, than costs the
EPA determines to be reasonable due to that EGU's age, location, or
basic process design.
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\629\ The examples are only for illustrative purposes and should
not be interpreted to represent the difference that must exist to
demonstrate a fundamental difference between the EPA's BSER
determination and a particular affected EGU's circumstances.
---------------------------------------------------------------------------
The RULOF provision, currently and as the EPA has proposed to
revise it, also allows states to invoke RULOF based on other
circumstances specific to an affected EGU. As an illustrative example,
a State may wish to invoke RULOF for a medium-term coal-fired steam
generating unit that is extremely isolated (e.g., on a small island
more than 200 miles offshore) such that it would require construction
of an LNG terminal and shipping of LNG by barge to have natural gas
available to fire at the unit. In the EPA's evaluation of natural gas
co-firing as the potential BSER for medium-term coal-fired steam
generating units, the EPA considered the distance and cost of lateral
pipeline builds in proposing natural gas co-firing as BSER. If a State
can demonstrate that something unique to the source's being on a remote
island--something that the EPA did not consider in evaluating the
BSER--results in the affected EGU not being able to reasonably achieve
the standard of performance, then it may be reasonable to invoke RULOF
for that source.
Under the EPA's proposed approach, states would not be able to
invoke RULOF based on minor, non-fundamental differences between a
particular affected EGU and what the EPA determined was reasonable for
the BSER. There could be instances in which an affected EGU may not be
able to implement the presumptively approvable standard of performance
in accordance with the precise metrics (e.g., at exactly the same $/ton
CO2 reduced or exactly the same distance from a pipeline
connection) of the BSER determination but is able to do so within a
reasonable margin. In such instances, it would not be reasonable for a
State to apply a less stringent standard of performance.
Many of the factors the EPA considers in its BSER determination,
and therefore many of the factors states might consider in determining
whether to invoke RULOF for any particular source, are reflected in the
cost consideration. As noted previously in this section, the EPA is
providing a range of cost evaluations for CCS and natural gas co-firing
based on different assumptions regarding amortization period and
capacity factor. For example, the EPA is proposing to determine that
the cost of CCS for long-term coal-fired steam generating units is
reasonable based on the following calculations: for a reference unit
with a 12-year amortization period and 50 percent capacity factor the
cost is $14/ton CO2 reduced or $12/MWh, and that the average
cost for the fleet under the same assumptions is $8/ton CO2
or $7/MWh. For natural gas co-firing for medium-term coal-fired steam
generating units, the EPA is proposing to find the following costs are
reasonable: for a reference unit with a 50 percent capacity factor and
an amortization period ranging from 6 to 10 years, a cost of $53-$66/
ton CO2 or $9-$12/MWh. The average cost for the fleet under
the same assumptions is $64-$78/ton CO2 or $11-$14/MWh.
Any costs associated with any BSER for affected EGUs that the EPA
determines are reasonable under these emission guidelines cannot be a
basis for invoking RULOF. Additionally, costs that are not
fundamentally different from costs that the EPA has determined are or
could be reasonable for sources cannot be a basis for invoking RULOF.
Thus, costs that are not fundamentally different from, e.g., $29/MWh
(the cost for installation of wet-FGD on a 300 MW coal-fired steam
generating unit, used for cost comparison in section X.D.1.a.ii
[[Page 33383]]
of this preamble and detailed in section VII.F.3.b.iii(B)(5) of this
preamble) are not a basis for invoking RULOF under these emission
guidelines. On the other hand, costs that constitute outliers, e.g.,
that are greater than the 95th percentile of costs on a fleetwide basis
(assuming a normal distribution) or that are the same as costs the EPA
has determined are unreasonable elsewhere under these emission
guidelines would likely represent a valid demonstration of a
fundamental difference and could be the basis of invoking RULOF.
Importantly, the costs evaluated in the BSER determination are, in
general, for representative, average units or are based on average
values across the fleet of steam generating units. Those BSER cost
analysis values represent the average of a distribution of costs
including costs that are above or below the average representative
value. On that basis, implicit in the proposed determination that those
average representative values are reasonable is a proposed
determination that a significant portion of the unit-specific costs
around those average representative values are also reasonable,
including some portion of those unit-specific costs that are above but
not significantly different than the average representative values.
Another example of a fundamental difference between the EPA's BSER
determination and a particular affected EGU's circumstances could be a
difference based on physical impossibility or technical infeasibility.
In making BSER determinations, the EPA must find that a system is
adequately demonstrated; among other things, this means that the BSER
must be technically feasible for the source category. For long-term
coal-fired steam generating units and combustion turbine EGUs in the
CCS subcategory, the EPA determined that CCS is adequately demonstrated
because its components can be and have been applied to the source
category and because it is generally geographically available to
affected EGUs. However, it may be possible that a particular affected
EGU is physically unable to implement CCS due to, e.g., the
impossibility of constructing a pipeline or establishing other means
for CO2 transport. If a State can demonstrate that it is
physically impossible or technically infeasible for this affected EGU
to apply CCS because there are no other options to transport captured
CO2, there is a fundamental difference between the EPA's
BSER determination and the circumstances of this particular affected
EGU and the State may invoke RULOF.
The EPA has proposed under 40 CFR part 60, subpart Ba that states
may invoke RULOF if they can demonstrate that a source cannot apply the
BSER to achieve the degree of emission limitation determined by the EPA
based on one or more of the three circumstances discussed earlier in
this preamble.\630\ It thus follows that states would be able to invoke
RULOF under these emission guidelines if they can demonstrate that an
affected EGU can apply the BSER but cannot achieve the degree of
emission limitation that the EPA determined is possible for the source
category generally.
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\630\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(e)).
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However, the EPA has also proposed in subpart Ba \631\ that a State
may not invoke RULOF to provide a less stringent standard of
performance for a particular source if that source cannot apply the
BSER but can reasonably implement a different system of emission
reduction to achieve the degree of emission limitation required by the
EPA's BSER determination. While a State may be able to demonstrate that
the source cannot reasonably apply the BSER based on one of the three
circumstances, it would be inappropriate to invoke RULOF to apply a
less stringent standard of performance because the source can still
reasonably achieve the presumptive degree of emission limitation. In
this instance, providing a less stringent standard of performance would
be inconsistent with the purpose of CAA section 111(d) and these
emission guidelines.
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\631\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(g)).
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States' consideration of the remaining useful life of a particular
source for affected coal-fired EGUs, in particular, will also be
informed by the structure of the EPA's proposed subcategories, each of
which has its own BSER determination under these emission guidelines.
Under CAA section 111(d)(1) and the EPA's proposed RULOF provisions,
states may consider an affected EGU's remaining useful life in
determining whether application of the BSER to achieve the presumptive
level of stringency would result in unreasonable cost resulting from
plant age.\632\ In determining the BSER, the EPA considers costs and,
in many instances, specifically considers annualized costs associated
with payment of the total capital investment of the technology
associated with the BSER. However, plant age can have considerable
variability within a source category and the annualized costs can
change significantly based on an affected EGU's remaining useful life
and associated length of the capital recovery period. Thus, the costs
of applying the BSER to an affected EGU with a short remaining life may
differ fundamentally from the costs that the EPA found were reasonable
in making its BSER determination.
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\632\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(e)(1)).
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As explained in section X of this preamble, these proposed emission
guidelines include BSER determinations and presumptive standards of
performance for affected coal-fired EGUs in four subcategories:
imminent-term, near-term, medium-term, and long-term. Owing to the
basis of these subcategories, the EPA's proposed BSER determinations
for each of these subcategories already consider costs amortized
consistent with the operating horizons of sources within each
subcategory. The EPA therefore does not anticipate that states would be
likely to demonstrate the need to invoke RULOF based on a particular
coal-fired EGU's remaining useful life, although doing so is not
prohibited under these emission guidelines. The proposed requirements
for states and affected EGUs invoking RULOF based on remaining useful
life are addressed in the next subsection.
Conversely, the proposed subcategories for existing combustion
turbines do not consider affected EGUs' operating horizons. The useful
life of a combined cycle unit is approximately 25 to 30 years.\633\
More than 151 GW of combined cycle units came on-line in the 2000 to
2010 timeframe,\634\ meaning that many of these units could potentially
be at or nearing the end of their remaining useful lives in the 2035 to
2040 timeframe. If an affected combustion turbine EGU has decided to
cease operations and elects to make that cessation enforceable, the
period over which controls would be amortized, depending on what that
period of time is, may be short enough to invoke RULOF based on
unreasonable cost of control.
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\633\ https://sargentlundy.com/wp-content/uploads/2017/05/Combined-Cycle-PowerPlant-LifeAssessment.pdf.
\634\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.
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The EPA is proposing to allow states to use the RULOF mechanism to
provide a different compliance deadline for a source that can meet the
presumptive standard of performance
[[Page 33384]]
for the applicable subcategory but cannot do so by the final compliance
date under these emission guidelines. In such cases, a State may be
able to demonstrate that there are ``other circumstances specific to
the facility . . . that are fundamentally different from the
information considered in the determination of the best system of
emission reduction in the emission guidelines'' \635\ that make timely
compliance impossible. However, given the relatively long lead times
and compliance timeframes proposed in these emission guidelines, the
EPA anticipates that these circumstances will be rare. Under the
proposed revisions to subpart Ba, RULOF demonstrations, including those
in support of extending a compliance deadline, would have to be based
on information from reliable and adequately documented sources and be
applicable to and appropriate for the affected facility.\636\
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\635\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(e)(3)).
\636\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(j)).
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Additionally, as discussed in section XII.D.1.a of this preamble,
the EPA is proposing a methodology for calculating an affected EGU's
baseline emissions as part of determining its presumptively approvable
standard of performance. The EPA explained that while the proposed
methodology should be flexible enough to accommodate most unit-specific
circumstances, it may not be appropriate to use recent historical
emissions data to represent baseline emission performance when an
affected EGU anticipates that its future operating conditions will
change significantly. Consistent with the proposed subpart Ba, the EPA
is proposing that states wishing to rely on an affected EGU's
anticipated change in operating conditions as the basis for using a
different methodology to set an emissions baseline would be required to
use the RULOF mechanism described in this section of the preamble.
The EPA solicits comment on the application of the RULOF provisions
of proposed subpart Ba, both in sum and as individual, segregable
pieces, to these emission guidelines. In particular, the EPA requests
comment on factual circumstances in which it may or may not be
appropriate for states to invoke RULOF for affected EGUs, given the
proposed BSER determinations and presumptive standards of performance,
and the EPA's proposed ``fundamental difference'' standard in the
subpart Ba rulemaking. For the consideration of cost, the EPA requests
comment on whether it should provide further guidance or requirements
for determining when the costs of a control technology for a particular
source are ``fundamentally different'' from the Agency's BSER
determination and thus a basis for invoking RULOF. The EPA additionally
seeks comment on any source category-specific considerations for
invoking RULOF for affected EGUs, including any additional or different
requirements that might be necessary to ensure that use of RULOF does
not undermine the presumptive stringency of these emission guidelines.
b. Calculation of a Standard That Accounts for RULOF
Subpart Ba, both the presently applicable requirements and as the
EPA has proposed to revise them, provides that, if a State has
demonstrated that accounting for RULOF is appropriate for a particular
affected EGU, the State may then apply a less stringent standard to
that EGU. The EPA's proposed revisions to subpart Ba would require
that, in doing so, the State must determine a source-specific BSER by
identifying all the systems of emission reduction available for the
source and evaluating each system using the same factors and evaluation
metrics that the EPA considered in determining the BSER for the
applicable subcategory.\637\ As part of determining source-specific
BSER, the State would also have to determine the degree of emission
limitation that can be achieved by applying this source-specific BSER
to the particular source. The State would then calculate and apply the
standard of performance that reflects this degree of emission
limitation.\638\
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\637\ To the extent that a state seeks to apply RULOF to a class
of affected EGUs that the state can demonstrate are similarly
situated in all meaningful ways, the EPA proposes to permit the
state to conduct an aggregate analysis of the BSER factors for the
entire class of EGUs for which RULOF has been invoked.
\638\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(f)).
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Consistent with these proposed requirements in subpart Ba, the EPA
is proposing that states invoking RULOF would be required to evaluate
certain controls as appropriate for subcategories of affected EGUs. The
EPA believes these proposed requirements are necessary to ensure that
states reasonably consider the controls that may qualify as the best
system of emission reduction. Additionally, the EPA is proposing to
provide the order in which states must evaluate controls. A list of
controls, ordered from more to less stringent, can provide useful
streamlining as states may reasonably choose to conduct a less in-depth
evaluation of controls further down the list if they determine a more
stringent control is the best system of emission reduction for a
particular source. The EPA also believes that providing a list of
controls for evaluation will provide states with clarity and certainty
about what the Agency will find is a satisfactory source-specific BSER
analysis pursuant to the RULOF mechanism. However, the EPA is also
requesting comment on whether to provide lists of controls to be
evaluated in a source-specific BSER analysis as a presumptively
approvable approach, as opposed to requirements. Regardless of how the
EPA finalizes the approach to controls for source-specific analyses,
states would retain discretion to evaluate additional types of controls
as part of a source-specific BSER determination for sources pursuant to
RULOF.
The EPA is proposing to require states invoking RULOF for affected
coal-fired EGUs in the long-term subcategory to evaluate natural gas
co-firing as a potential source-specific BSER. Additionally, if an EGU
in the long-term subcategory can implement CCS but cannot achieve the
degree of emission limitation prescribed by the presumptive standard of
performance, the EPA is proposing that the State evaluate CCS with a
source-specific degree of emission limitation as a potential BSER. The
EPA is also proposing that states invoking RULOF for affected long-term
and medium-term coal-fired EGUs must evaluate different levels of
natural gas co-firing. For example, for a source in the medium-term
subcategory that cannot reasonably co-fire 40 percent natural gas, the
State must then evaluate lower levels of natural gas co-firing unless
it has demonstrated that natural gas co-firing at any level is
physically impossible or technically infeasible at the source.
Similarly, if a State invoking RULOF for an affected EGU in the long-
term subcategory demonstrates that the EGU cannot co-fire with natural
gas at 40 percent, the EPA is proposing that the State must then
evaluate lower levels of co-firing as potential BSERs for the source,
unless the State can demonstrate that it is physically impossible or
technically infeasible for the source to co-fire natural gas. States
may also consider additional potential source-specific BSERs for
affected EGUs in either subcategory.
For states invoking RULOF for affected existing combustion turbine
EGUs, the EPA is similarly proposing a requirement to evaluate certain
control
[[Page 33385]]
strategies as part of a source-specific BSER analysis. As a preliminary
step, for sources in either the CCS combustion turbine subcategory or
the hydrogen co-fired combustion turbine subcategory, the EPA is
proposing that a State would first have to demonstrate why the affected
EGU cannot reasonably participate in the other subcategory and meet
that other subcategory's presumptive standard of performance. If a unit
can reasonably comply with the presumptive standard of performance for
the alternate source category, it must do so.
For combustion turbines in the CCS subcategory that cannot
reasonably comply with the presumptive standards of performance for
either that subcategory or the hydrogen co-fired subcategory, the EPA
is proposing that, unless a State has demonstrated that it is
physically impossible or technically infeasible for a unit to implement
CCS, the State must evaluate CCS with lower rates of carbon capture as
a potential BSER. If CCS with lower rates of capture is not the BSER,
the State would then be required to consider comprehensive turbine
upgrades, and finally smaller scale efficiency improvements. For
hydrogen co-fired combustion turbines that cannot reasonably comply
with the presumptive standards of performance for either subcategory, a
State would first analyze lower percentages of hydrogen co-firing,
followed by comprehensive turbine upgrades, and lastly smaller scale
efficiency improvements. States would also be free to analyze
additional potential source-specific BSERs for affected combustion
turbine EGUs in either subcategory.
The EPA requests comment on the proposed requirement to consider
certain control technologies as part of source-specific BSER
determinations, and specifically on whether the Agency should require
this approach as proposed or, in the alternative, provide it as a
presumptively approvable approach to conducting a source-specific BSER
analysis.
The EPA notes again that, under both the proposed subpart Ba and
CAA section 111(d),\639\ an affected EGU that cannot reasonably apply
the EPA's BSER but can achieve the degree of emission limitation for
the applicable subcategory through other reasonable systems of emission
reduction cannot be given a less stringent standard of performance. In
this case, the affected EGU's standard of performance would still
reflect the degree of emission limitation achievable through
application of the EPA's BSER.
---------------------------------------------------------------------------
\639\ As discussed earlier in this preamble, permitting a state
to apply a less stringent standard to an affected EGU that can
achieve the degree of emission limitation the EPA determined is
required would be inconsistent with CAA section 111(d). See also 87
FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed revisions to RULOF provisions at 40 CFR 60.24a(g)).
---------------------------------------------------------------------------
The EPA has proposed in its revisions to subpart Ba that specific
requirements would apply when invoking RULOF based on an affected
source's remaining useful life.\640\ Among other requirements, the EPA
in an emission guideline would have to either identify the outermost
date to cease operations for the relevant source category that
qualifies for consideration of remaining useful life or provide a
methodology and considerations for states to use in establishing such
an outermost date. Proposed subpart Ba also provides that an affected
source with a date to cease operations that is both imminent and prior
to the outermost date could be eligible for a standard of performance
that reflects that source's BAU. The EPA is proposing to supersede the
application of subpart Ba for coal-fired steam generating units with
respect to the proposed requirements to establish outermost and
imminent dates to cease operations for invoking RULOF based on an
affected EGU's remaining useful life. As explained earlier in this
section of the preamble, the EPA has designed the subcategories for
coal-fired affected EGUs under these emission guidelines to accommodate
sources' self-identified operating horizons. This approach to
subcategorization obviates the need to establish an outermost date to
cease operations to guide states' and affected EGUs' consideration of
remaining useful life. Additionally, the EPA is proposing to establish
an imminent-term subcategory with a proposed BSER determination of
routine operation and maintenance, which serves the same purpose as
establishing an imminent date to cease operations under the RULOF
provision. Although it is not anticipated that states will have a
reason to invoke RULOF due to a coal-fired EGU's imminent date to cease
operations based on the structure of the subcategories under these
emission guidelines, states are not precluded from doing so based on
unit-specific circumstances.
---------------------------------------------------------------------------
\640\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(h), (i)).
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Because of the small number of sources in the oil- and natural gas-
fired steam generating unit subcategories and the diversity of
circumstances in which they operate, the EPA is not proposing to
establish outermost or imminent dates to cease operations for the
purpose of considering remaining useful life for these sources.
Regardless, because the proposed BSER determinations for these EGUs is
routine methods of operation and maintenance (other than for low-load
oil- and natural gas-fired steam generating units), the EPA does not
anticipate that states will find it necessary to invoke RULOF for these
sources.
The EPA is also proposing to supersede the requirement in subpart
Ba to establish imminent and outermost dates for the consideration of
remaining useful life for affected combustion turbine EGUs. While, as
discussed above in this section of the preamble, it is likely that some
portion of the existing combustion turbine fleet will be reaching the
end of its remaining useful life in the 2035 to 2040 timeframe, the
structure of the proposed subcategories, the length of time between
State plan submission and the compliance dates for the subcategories,
and the staggered compliance dates for the two subcategories make it
difficult to set a widely-applicable date or dates that represent an
imminent cessation of operations. States would not be precluded from
demonstrating that an affected combustion turbine EGU's remaining
useful life is so short that it qualifies for a business-as-usual
standard of performance (i.e., that its remaining useful life is so
short that the cost of any control would be unreasonably high).
Similarly, based on the proposed BSERs for the subcategories and the
staggered nature of the proposed compliance dates for combustion
turbine EGUs, the EPA does not believe it is helpful to set an
outermost date for the considering of remaining useful life for these
units. The EPA requests comment on its proposal to supersede the
requirements in subpart Ba to set imminent and outermost dates for the
consideration of remaining useful life for affected combustion turbine
EGUs. If commenters believe such dates would be useful to guide states'
consideration of remaining useful life for affected existing combustion
turbines, the EPA further requests input on what those dates could be,
and why.
The proposed subpart Ba would require that any plan that applies a
less stringent standard to a particular affected EGU based on remaining
useful life must include the date by which the EGU commits to
permanently cease operations as an enforceable
[[Page 33386]]
requirement.\641\ The plan would also have to include measures that
provide for the implementation and enforcement of such a commitment.
The EPA is not proposing to supersede this proposed requirement for the
purpose of this emission guideline; states that include a RULOF
standard based on an affected EGU's remaining useful life must make the
source's voluntary commitment to permanently cease operations by a date
certain enforceable in the State plan.
---------------------------------------------------------------------------
\641\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(h), (i)(3)).
---------------------------------------------------------------------------
Similarly, subpart Ba would require that if a State seeks to rely
on a source's operating conditions, such as its restricted capacity, as
the basis for invoking RULOF and setting a less stringent standard, the
State plan must include that operating condition as an enforceable
requirement.\642\ This requirement would apply to operating conditions
that are within an affected EGU's control and is necessary to ensure
that a source's standard of performance matches what that source can
reasonably achieve and does not undermine the stringency of these
emission guidelines.
---------------------------------------------------------------------------
\642\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(h)).
---------------------------------------------------------------------------
The proposed presumptively approvable standards of performance for
affected EGUs in these emission guidelines are expressed in the form of
rate-based emission limitations, specifically, as lb CO2/
MWh. Therefore, to ensure transparency and to enable the EPA, states,
and stakeholders to ensure that RULOF standards do not undermine the
presumptive stringency of these emission guidelines, the EPA is
proposing to require that standards of performance determined through
this RULOF mechanism be in the same form of rate-based emission
limitations.\643\
---------------------------------------------------------------------------
\643\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(f)(3)).
---------------------------------------------------------------------------
The EPA seeks comment on implementation of the proposed subpart Ba
requirements pertaining to determining a source-specific BSER and
calculating a less stringent standard for sources invoking RULOF under
these emission guidelines. It also seeks comment on the proposed
requirements that are specific to these emission guidelines, including
but not limited to the proposed requirement that states evaluate
certain control options for affected coal-fired steam generating units
in the long-term and medium-term subcategories and for affected
combustion turbine EGUs as part of their source-specific BSER
determination, the proposal to not provide outermost or imminent dates
to cease operations for the consideration of remaining useful life, and
the proposal to require RULOF standards of performance to be in the
form of lb CO2/MWh emission limitations.
c. Consideration of Impacted Communities
While the consideration of RULOF may warrant application of a less
stringent standard of performance to a particular affected EGU, such
standards have the potential to result in disparate health and
environmental impacts to communities most affected by and vulnerable to
impacts from those EGUs. Those communities could be put in the position
of bearing the brunt of the greater health and environmental impacts
resulting from an affected EGU implementing a less stringent standard
of performance than would otherwise have been required pursuant to the
emission guidelines. A lack of consideration of such potential outcomes
would be antithetical to the public health and welfare goals of CAA
section 111(d).
Therefore, the proposed subpart Ba revisions would require that
states applying less stringent standards of performance consider the
potential pollution impacts and benefits of control to communities most
affected by and vulnerable to emissions from the affected EGU in
determining source-specific BSERs and the degree of emission limitation
achievable through application of such BSERs.\644\ The State will have
identified these communities as pertinent stakeholders in the process
of meaningful engagement, which is discussed in section XII.F.1.b of
this preamble.
---------------------------------------------------------------------------
\644\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(k)).
---------------------------------------------------------------------------
If the EPA finalizes the requirement under subpart Ba to consider
the potential pollution impacts and benefits of control to the
communities most affected by and vulnerable to emissions from a RULOF
source communities as proposed, State plan submissions under these
emission guidelines would have to demonstrate that the State considered
such impacts and benefits in applying a less stringent standard of
performance to such a source. The EPA expects that states' meaningful
engagement with pertinent stakeholders on the State plan development
generally will include engagement on any potential use of RULOF to
apply less stringent standards of performance. The proposed requirement
that states consider the potential pollution impacts and benefits of
control in the context of a source-specific BSER analysis for a
particular source is intended to provide for states' consideration of
health and environmental effects on the communities that are most
affected by and vulnerable to emissions from that particular source. As
an example, the State plan submission could include a comparative
analysis assessing potential BSER options for an affected EGU and the
corresponding potential benefits to the identified communities under
each option. If the comparative analysis shows that emissions from an
affected EGU could be controlled at a higher cost but that such control
benefits the communities that would otherwise be adversely impacted by
a less stringent standard of performance, the State could balance these
considerations and determine that a higher cost is warranted for the
source-specific BSER.
The plan submission under these emission guidelines must clearly
identify the communities most affected by and vulnerable to emissions
from the designated facility. The EPA is proposing that, in evaluating
potential source-specific BSERs, a State must document any health or
environmental impacts and benefits of control options and describe how
it considered those impacts on the identified communities. Pursuant to
the proposed meaningful engagement requirements discussed in section
XII.F.1.b of this preamble, states' plan submissions would also be
required to include a summary of the meaningful engagement the State
conducted and a summary of stakeholder input received, including any
engagement and input on RULOF sources and the calculation of less-
stringent standards of performance.
The EPA solicits comments on additional ways in which states might
consider potential pollution impacts and benefits of control to
communities most affected by and vulnerable to emissions from affected
EGUs when determining a less-stringent standard pursuant to RULOF. In
particular, the Agency is requesting comment on metrics or information
concerning health and environmental impacts from affected EGUs that
states can consider in source-specific RULOF determinations. As
discussed in section XII.F.1.b, the EPA is also requesting comment on
tools and methodologies for identifying communities that are most
affected by and vulnerable to emissions from affected EGUs under these
emission guidelines.
[[Page 33387]]
d. The EPA's Standard of Review of State Plans Invoking RULOF
Under CAA section 111(d)(2), the EPA has the obligation to
determine whether a State plan submission is ``satisfactory.'' This
obligation extends to all aspects of a State plan, including the
application of less stringent standards of performance that account for
RULOF. Pursuant to CAA section 111(d) and the proposed subpart Ba
provisions,\645\ states carry the burden of making the demonstrations
required under the RULOF mechanism and have the obligation to justify
any accounting for RULOF in support of standards of performance that
are less stringent than the proposed presumptively approvable standards
in these emission guidelines. While the EPA has the discretion to
supplement a State's demonstration, the EPA may also find that
inadequacies in a State plan's demonstration are a basis for concluding
that the plan is not ``satisfactory'' and may therefore disapprove the
plan.
---------------------------------------------------------------------------
\645\ CAA section 111(d)(2), 87 FR 79176 (December 23, 2022),
Docket ID No. EPA-HQ-OAR-2021-0527-0002 (proposed revisions to RULOF
provisions at 40 CFR 60.24a(j)).
---------------------------------------------------------------------------
As a general matter, a less stringent standard of performance
pursuant to RULOF must meet all other applicable requirements of
subpart Ba and these emission guidelines.\646\
---------------------------------------------------------------------------
\646\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(l)).
---------------------------------------------------------------------------
In determining whether a State has met its burden in providing a
less stringent standard of performance based on RULOF, the EPA will
consider, among other things, the applicability and appropriateness of
the information on which the State relied. Both a demonstration that a
particular affected EGU meets the threshold requirements to invoke
RULOF and the determination of a source-specific standard of
performance entail the use of technical, cost, engineering, and other
information. The proposed subpart Ba revisions would require states to
use information that is applicable to and appropriate for the
particular source at issue.\647\ This means that, when available, the
State must use source- and site-specific information. This is
consistent with the premise that invoking RULOF is appropriate for a
particular source when there are fundamental differences between the
EPA's BSER and that source's specific circumstances.
---------------------------------------------------------------------------
\647\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(j)(1)).
---------------------------------------------------------------------------
In some instances, site-specific information may not be available.
In such cases, it may be reasonable for a State to use information
from, e.g., cost, engineering, and other analyses the EPA has provided
to support this rulemaking. The EPA is proposing that states using non-
site-specific information must explain why that information is
reasonable to rely on to determine a less stringent standard of
performance based on RULOF. Regardless of the information used, it must
come from reliable and adequately documented sources, which the
proposed subpart Ba revisions explain presumptively include sources
published by the EPA, permits, environmental consultants, control
technology vendors, and inspection reports.\648\
---------------------------------------------------------------------------
\648\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(j)(2)).
---------------------------------------------------------------------------
The EPA solicits comment on the types of source-specific and other
information that states should be required to provide to support the
inclusion of standards of performance based on RULOF in State plans, as
well as on any additional sources of information that may be
appropriate for states to use in this context.
e. Authority To Apply More Stringent Standards as Part of State Plans
As explained in the subpart Ba notice of proposed rulemaking, the
EPA reevaluated its interpretation of CAA sections 111(d) and 116 and,
consistent with its revised interpretation, has proposed revisions to
subpart Ba to clarify that states may consider RULOF to include more
stringent standards of performance in their State plans.\649\ The
allowance in CAA section 111(d)(1) that states may consider ``other
factors'' does not limit states to considering only factors that may
result in a less stringent standard of performance; other factors that
states may wish to account for in applying a more stringent standard
than provided in these emission guidelines include, but are not limited
to, effects on local communities, the availability of control
technologies that allow a particular source to achieve greater emission
reductions, and local or State policies and requirements.
---------------------------------------------------------------------------
\649\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions to RULOF provisions at 40
CFR 60.24a(m), (n)).
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Pursuant to proposed subpart Ba, states seeking to apply a more
stringent standard of performance based on other factors would have to
adequately demonstrate that the standard is in fact more stringent than
the presumptively approvable standard of performance for the applicable
subcategory. However, a State would not be required to conduct a
source-specific BSER evaluation for the purpose of applying a more
stringent standard of performance, so long as the standard will achieve
equivalent or better emission reductions. In this case, the EPA
believes it is appropriate to defer to the State's discretion to impose
a more stringent standard on an individual source because such a
standard does not have the potential to undermine the presumptive
stringency of these emission guidelines.
More stringent standards of performance must meet all applicable
statutory and regulatory requirements, including that they are
adequately demonstrated.\650\ As for all standards of performance, the
State plan must include requirements that provide for the
implementation and enforcement of a more stringent standard. The EPA
has the ability and authority to review more stringent standards of
performance and to approve them provided that the minimum requirements
of subpart Ba and these emission guidelines are met, rendering them
federally enforceable.
---------------------------------------------------------------------------
\650\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions to RULOF provisions at 40
CFR 60.24a(m)).
---------------------------------------------------------------------------
The EPA requests comment on the implementation of the proposed
subpart Ba provisions pertaining to more stringent standards of
performance in the context of these particular emission guidelines.
3. Increments of Progress and Milestones for Affected EGUs That Have
Elected To Commit To Cease Operations
The EPA's long-standing CAA section 111 implementing regulations at
40 CFR part 60, subpart Ba \651\ provide that State plans must include
legally enforceable increments of progress to achieve compliance for
each designated facility when the compliance schedule extends more than
a specified length of time from the State plan submission date.\652\
The EPA's December 2022 proposed revisions to subpart Ba would require
increments of progress when the compliance date is more than 16 months
after the State plan submission deadline.\653\ Under these proposed
emission guidelines, the State plan submission date would be 24 months
(see section XII.F.2 of this preamble) from promulgation of the
emission
[[Page 33388]]
guidelines, which the EPA is currently anticipating will be June 2026.
The proposed compliance dates for affected EGUs within the proposed
subcategories all fall on or after January 1, 2030, which is more than
16 months after the State plan submission deadline. The EPA is
therefore proposing to require that State plans include increments of
progress as discussed in this section. For the purpose of these
emission guidelines, the EPA refers to pre-compliance date, federally
enforceable requirements associated with the planning, construction,
and operation of natural gas or hydrogen co-firing infrastructure and
CCS as increments of progress. The EPA is also proposing separate,
federally enforceable ``milestones'' associated with activities
surrounding enforceable dates to permanently cease operations for steam
generating EGUs in the imminent-term, near-term, and medium-term
subcategories. These additional State plan requirements are intended to
ensure that affected coal-fired steam generating units can complete the
steps necessary to qualify for a subcategory with a less stringent BSER
and to provide the public assurance that those steps will be concluded
in a timely manner.
---------------------------------------------------------------------------
\651\ See also 40 CFR 60.21(h).
\652\ 40 CFR 60.24a(d).
\653\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions at 40 CFR 60.24a(d)).
---------------------------------------------------------------------------
a. Increments of Progress
The EPA is proposing to adopt emission guideline-specific
implementation of the five generic increments specified in the CAA
section 111(d) implementing regulations at 40 CFR 60.21a(h). These five
increments of progress are: (1) Submittal of a final control plan for
the designated facility to the appropriate air pollution control
agency; (2) Awarding of contracts for emission control systems or for
process modifications, or issuance of orders for the purchase of
component parts to accomplish emission control or process modification;
(3) Initiation of on-site construction or installation of emission
control equipment or process change; (4) Completion of on-sites
construction or installation of emission control equipment or process
change; and (5) Final compliance. To this end, the EPA is proposing
that State plans must include specified enforceable increments of
progress as required elements for coal-fired EGUs that use natural gas
co-firing to meet the standard of performance for the medium-term
existing coal-fired steam generating subcategory and for natural gas-
fired combustion turbine EGUs that use hydrogen co-firing to meet the
standard of performance for hydrogen co-fired combustion turbine
subcategory. The EPA is additionally proposing that State plans must
include enforceable increments of progress for units that use CCS to
meet the standard of performance for the long-term existing coal-fired
steam generating subcategory or for the CCS combustion turbine
subcategory.
Some increments have been adjusted to more closely align with
planning, engineering, and construction steps anticipated for
designated facilities that will be complying with standards of
performance with natural gas or hydrogen co-firing or CCS, but they
retain the basic structure and substance of the increments in the
general implementing regulations. In addition, consistent with 40 CFR
60.24a(d), the EPA is proposing similar additional increments of
progress for the long-term and medium-term coal-fired subcategories as
well as both combustion turbine subcategories to ensure timely progress
on the planning, permitting, and construction activities related to
pipelines that may be required to enable full compliance with the
applicable standard of performance. The EPA is also proposing an
additional increment of progress related to the identification of an
appropriate sequestration site for the long-term coal-fired subcategory
and the CCS combustion turbine subcategory. Finally, the proposed
emission guidelines include an additional increment of progress that
that applies solely to the hydrogen co-fired combustion turbine
subcategory related to securing sufficient hydrogen contract capacity
to meet the standard of performance.
The EPA notes that affected EGUs do not necessarily have to
implement the EPA's BSER technology to comply with their applicable
standards of performance. For example, affected EGUs in the medium- and
long-term coal-fired steam generating unit subcategories may meet their
standards of performance using approaches other than natural gas co-
firing and CCS, respectively. Where the owners or operators of affected
EGUs select compliance approaches that deviate from the BSER technology
associated with a subcategory requiring increments of progress, the EPA
proposes that the State plan would be required to specify increments of
progress for the relevant affected EGUs that are consistent with the
increments in 40 CFR 60.21a(h), as well as dates for achieving each
increment.
The EPA is proposing that final compliance with the applicable
standard of performance, also defined as the final increment of
progress at 40 CFR 60.21a(h)(5), must occur no later than January 1,
2030 for steam generating units in the medium-term and long-term
subcategories, no later than January 1, 2035 for combustion turbine
EGUs in the CCS subcategory, and no later than January 1, 2032 for
combustion turbine EGUs in the hydrogen co-fired subcategory.\654\ For
the remaining increments, the EPA is not proposing date-specific
deadlines for achieving increments of progress. Instead, the EPA
proposes that states must assign calendar day deadlines for each of the
remaining increments for each affected EGU in their State plan
submissions. The first increment of progress listed at 40 CFR
60.21a(h)(1), submittal of a final control plan to the air pollution
control agency, must be assigned the earliest calendar date deadline
among the increments. The EPA believes that allowing states to schedule
sources' increments of progress would provide them with flexibility to
tailor compliance timelines to individual facilities, allow
simultaneous work toward separate increments, and still ensure full
performance by the compliance date. The EPA solicits comment on this
approach as well as whether the EPA should instead finalize date-
specific deadlines or more general timeframes for achieving increments
of progress rather than leaving the timing for most increments to State
discretion. The EPA also seeks comment on the specific deadlines or
timeframes that the EPA could assign to each increment under a more
prescriptive approach.
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\654\ The EPA is proposing that the second phase of the standard
of performance for existing hydrogen co-fired combustion turbines,
which corresponds to co-firing 96 percent by volume low-GHG
hydrogen, would start on January 1, 2038. However, the EPA is not
proposing an increment of progress associated with this second phase
because the Agency anticipates the relevant planning, design, and
construction steps will have occurred ahead of the January 1, 2032
compliance date.
---------------------------------------------------------------------------
The EPA is not proposing increments of progress for either the
imminent- or near-term subcategories for coal-fired steam generating
units, or for oil- or natural gas-fired steam generating units. The
proposed BSERs for these affected EGUs are routine operation and
maintenance, which does not require the installation of significant new
emission controls or operational changes. Because there is no need for
the types of increments of progress specified in 40 CFR 60.21a(h) to
ensure that affected EGUs in the imminent and near-term coal-fired and
oil- and natural gas-fired subcategories can achieve full compliance by
the compliance date, the EPA is proposing that the requirement
[[Page 33389]]
for increments of progress in 40 CFR 60.24a(d) does not apply to these
units.
For coal-fired steam generating units falling within the medium-
term subcategory and combustion turbine EGUs within the hydrogen co-
fired subcategory (i.e., units with proposed BSERs of co-firing clean
fuels), the EPA proposes the following increments of progress as
enforceable elements required to be included in a State plan: (1)
Submission of a final control plan for the affected EGU to the
appropriate air pollution control agency. The final control plan must
be consistent with the subcategory declaration in the State plan and
must include supporting analysis for the affected EGU's control
strategy, including the design basis for modifications at the facility,
the anticipated timeline to achieve full compliance, and the benchmarks
the facility anticipates along the way. (2) Awarding of contracts for
boiler or turbine modifications, or issuance of orders for the purchase
of component parts to accomplish such modifications. Affected EGUs can
demonstrate compliance with this increment by submitting sufficient
evidence that the appropriate contracts have been awarded. (3)
Initiation of onsite construction or installation of any boiler or
turbine modifications necessary to enable natural gas co-firing at a
level of 40 percent on an annual average basis or hydrogen co-firing at
30 percent on an annual average basis, as appropriate for the
applicable subcategory. (4) Completion of onsite construction of any
boiler or turbine modifications necessary to enable natural gas co-
firing at a level of 40 percent on an annual average basis or hydrogen
co-firing at 30 percent on an annual average basis, as appropriate for
the applicable subcategory. (5) Final compliance with the standard of
performance by January 1, 2030 for coal-fired steam generating units
and by January 1, 2032 for combustion turbine EGUs.
In addition to the five increments of progress derived from the CAA
section 111(d) implementing regulations, the EPA is proposing an
additional increment of progress for affected EGUs with proposed BSERs
based on co-firing clean fuels (natural gas co-firing for medium-term
coal-fired steam generating EGUs and hydrogen co-firing for hydrogen
co-fired combustion turbine EGUs) to ensure timely completion of any
pipeline infrastructure needed to transport natural gas or hydrogen to
designated facilities within each subcategory. Affected EGUs would be
required to demonstrate that all permitting actions related to pipeline
construction have commenced by a date specified in the State plan.
Evidence in support of the demonstration must include pipeline planning
and design documentation that informed the permitting application
process, a complete list of pipeline-related permitting applications,
including the nature of the permit sought and the authority to which
each permit application was submitted, an attestation that the list of
pipeline-related permit applications is complete with respect to the
authorizations required to operate the facility at full compliance with
the standard of performance, and a timeline to complete all pipeline
permitting activities.
Affected EGUs within the hydrogen co-fired combustion turbine
subcategory must meet an additional increment of progress to
demonstrate they have secured access to hydrogen supplies sufficient to
meet their anticipated 2032 fuel needs. This increment can be met by a
capacity contract for hydrogen at volumes in 2032 consistent with the
information provided in the final control plan and the pipeline
specification included in the pipeline construction increment of
progress.
For coal-fired EGUs falling within the long-term subcategory and
for combustion turbine EGUs falling within the CCS subcategory (i.e.,
units with proposed BSERs of CCS), the EPA proposes the following
increments of progress as required, enforceable elements to be included
in a State plan submission: (1) Submission of a final control plan for
the affected EGU to the appropriate air pollution control agency. The
final control plan must be consistent with the subcategory declaration
in the State plan and must include supporting analysis for the affected
EGU's control strategy, including a feasibility and/or FEED study. (2)
Awarding of contracts for emission control systems or for process
modifications, or issuance of orders for the purchase of component
parts to accomplish emission control or process modification. Affected
EGUs can demonstrate compliance with this increment by submitting
sufficient evidence that the appropriate contracts have been awarded.
(3) Initiation of onsite construction or installation of emission
control equipment or process change required to achieve 90 percent
CO2 capture on an annual basis. (4) Completion of onsite
construction or installation of emission control equipment or process
change required to achieve 90 percent CO2 capture on an
annual basis. (5) Final compliance with the standard of performance by
January 1, 2030 for coal-fired steam generating units and by January 1,
2035 for combustion turbine EGUs.
In addition to the five increments of progress derived from the CAA
section 111(d) implementing regulations, the EPA is proposing two
additional increments for affected EGUs that adopt CCS to meet the
standard of performance for the long-term coal-fired steam generating
unit and CCS combustion turbine subcategories. The first mirrors the
proposed approach for the co-firing subcategories to ensure timely
completion of pipeline infrastructure and the second is designed to
ensure timely selection of an appropriate sequestration site. As the
first additional increment, the EPA proposes that affected EGUs using
CCS to comply with their standards of performance would be required to
demonstrate that all permitting actions related to pipeline
construction have commenced by a date specified in the State plan.
Evidence in support of the demonstration must include pipeline planning
and design documentation that informed the permitting process, a
complete list of pipeline-related permitting applications, including
the nature of the permit sought and the authority to which each permit
application was submitted, an attestation that the list of pipeline-
related permits is complete with respect to the authorizations required
to operate the facility at full compliance with the standard of
performance, and a timeline to complete all pipeline permitting
activities.
The second proposed additional increment of progress for affected
EGUs using CCS to comply with their standards of performance is
formulated to ensure timely completion of site selection for geologic
sequestration of captured CO2 from the facility. Affected
EGUs within this subcategory must submit a report identifying the
geographic location where CO2 will be injected underground,
how the CO2 will be transported from the capture location to
the storage location, and the regulatory requirements associated with
the sequestration activities, as well as an anticipated timeline for
completing related permitting activities.
The EPA requests comment on the substance of each of the six
proposed increments of progress for coal-fired steam generating units
falling within the medium-term subcategory, the seven increments of
progress for units within the hydrogen co-fired combustion turbine
subcategory, and the seven increments of progress proposed for both
subcategories that anticipate CCS adoption. The EPA seeks comment on
whether the increments contain an
[[Page 33390]]
appropriate level of specificity to establish clear, verifiable
criteria to ensure that states and affected EGUs are taking the steps
necessary to reach full compliance. If commenters believe they do not,
the EPA requests comment on the appropriate level of specificity for
each increment. Additionally, as discussed in section XII.F.1.b.ii of
this preamble, the EPA is proposing a requirement that each State plan
provide for the establishment of Carbon Pollution Standards for EGUs
websites by the owners or operators of affected EGUs. The EPA is
further proposing that State plans must require affected EGUs with
increments of progress to post those increments, the schedule required
in the State plan for achieving them, and any documentation necessary
to demonstrate that they have been achieved to this website in a timely
manner.
b. Milestones for Affected EGUs That Have Elected To Commit To Cease
Operations
The EPA is proposing that State plans must include legally
enforceable milestones for affected EGUs within the imminent-term,
near-term, and medium-term coal-fired steam generating unit
subcategories. As described in section X of this preamble, the
applicability criteria for each of the subcategories of coal-fired
steam generating units include an affected EGU's intended operating
horizon; where owners or operators of affected EGUs have elected to
commit to permanently cease operations by a date certain before January
1, 2040, and, where a State further elects to include such commitments
as an enforceable element in a State plan, such EGUs will fall into one
of these three subcategories. Accordingly, affected EGUs in the
imminent-term, near-term, and medium-term subcategories have BSERs that
are specifically tailored to and dependent on their shorter operating
horizons. The EPA is aware that there are many processes an affected
EGU must complete in order to permanently cease operation. Therefore,
to ensure that affected EGUs can complete the steps necessary to
qualify for a subcategory with a less stringent standard of performance
and to provide the public assurance that those steps will be concluded
in a timely manner, the EPA is proposing additional State plan
requirements, referred to as ``milestones,'' for EGUs in the imminent-
term, near-term, and medium-term subcategories.
The proposed milestone reporting requirements count backward from
an affected EGU's date to permanently cease operations to ensure timely
progress toward that date. Five years before any date used to determine
the applicable subcategory under these emission guidelines or 60 days
after State plan submission, whichever is later, designated facilities
must submit an Initial Milestone Report to the applicable State
administering authority that includes the following: (1) A summary of
the process steps required for the affected EGU to permanently cease
operation by the date included in the State plan, including the
approximate timing and duration of each step. (2) A list of key
milestones, metrics that will be used to assess whether each milestone
has been met, and calendar day deadlines for each milestone. These
milestones must include at least the following: notice to the official
reliability authority of the retirement date; submittal of an official
suspension filing (or equivalent filing) made to the affected EGU's
reliability authority; and submittal of an official retirement filing
with the unit's reliability authority. (3) An analysis of how the
process steps, milestones, and associated timelines included in the
Milestone Report compare to the timelines of similar units within the
State that have permanently ceased operations within the 10 years prior
to the date of promulgation of these emission guidelines. (4)
Supporting regulatory documents, including correspondence and official
filings with the relevant regional transmission organization, balancing
authority, public utility commission, or other applicable authority, as
well as any filings with the SEC or notices to investors in which the
plans for the EGU are mentioned and any integrated resource plan.
For each of the remaining years prior to the date to permanently
cease operations that is used to determine the applicable subcategory,
affected EGUs must submit an annual Milestone Status Report that
addresses the following: (1) Progress toward meeting all milestones and
related metrics identified in the Milestone Report; and (2) supporting
regulatory documents, including correspondence and official filings
with the relevant regional transmission organization, balancing
authority, public utility commission, or other applicable authority to
demonstrate compliance with or progress toward all milestones.
The EPA is also proposing that affected EGUs with reporting
milestones associated with commitments to permanently cease operations
would be required to submit a Final Milestone Status Report no later
than 6 months following its federally enforceable date. This report
would document any actions that the unit has taken subsequent to
ceasing operation to ensure that such cessation is permanent, including
any regulatory filings with applicable authorities or decommissioning
plans. The EPA requests input on whether 6 months after the federally
enforceable date is an appropriate period of time to capture any
actions affected EGUs taken following cessation of operations.
The EPA is proposing that affected EGUs with reporting milestones
for commitments to permanently cease operations would be required to
post their Initial Milestone Report, annual Milestone Status Reports,
and Final Milestone Status Report, including the schedule for achieving
milestones and any documentation necessary to demonstrate that
milestones have been achieved, on the Carbon Pollution Standards for
EGUs website, as described in section XII.F.1.b, within 30 business
days of being filed.
The EPA recognizes that applicable regulatory authorities,
retirement processes, and retirement approval criteria will vary across
states and affected EGUs. The proposed milestone requirements are
intended to establish a general framework flexible enough to account
for significant differences across jurisdictions while assuring timely
planning toward the dates by which affected EGUs permanently cease
operations. The EPA requests comment on this proposed approach,
specifically whether any jurisdictions present unique State
circumstances that should be considered when defining milestones and
the required reporting elements.
4. Testing and Monitoring Requirements
The EPA is proposing to require states to include in their plans a
requirement that affected EGUs monitor and report hourly CO2
mass emissions emitted to the atmosphere, total heat input, and total
gross electricity output, including electricity generation and, where
applicable, useful thermal output converted to gross MWh, in accordance
with the 40 CFR part 75 monitoring and reporting requirements. Under
this proposal, affected EGUs would be required to use a 40 CFR part 75
certified monitoring methodology and report the hourly data on a
quarterly basis, with each quarterly report due to the Administrator 30
days after the last day in the calendar quarter. The monitoring
requirements of 40 CFR part 75 require most fossil fuel-fired boilers
to use a CO2 CEMS, including a CO2 concentration
monitor and stack gas flow monitor, although some oil- and
[[Page 33391]]
natural gas-fired boilers may have options to use alternative
measurement methodologies (e.g., fuel flow meters). A CO2
CEMS is the most technically reliable method of emission measurement
for EGUs that burn solid fuels, as it provides a measurement method
that is performance based rather than equipment specific and is
verified based on NIST traceable standards. A CEMS provides a
continuous measurement stream that can account for variability in the
fuels and the combustion process. Reference methods have been developed
to ensure that all CEMS meet the same performance criteria, which helps
to ensure consistent, accurate data. Natural gas-fired combustion
turbines have options under appendices D and G of 40 CFR part 75 to use
fuel flowmeters in lieu of a CO2 CEMS. The flue flowmeter
data, paired with fuel quality data, is used to determine
CO2 mass emissions and heat input.
The majority of EGUs will generally have no changes to their
monitoring and reporting requirements and will continue to monitor and
submit emissions reports under 40 CFR part 75 as they have under
existing programs, such as the Acid Rain Program (ARP) and the Regional
Greenhouse Gas Initiative (RGGI)--a cooperative of several states
formed to reduce CO2 emissions from EGUs. The majority of
coal- and oil-fired EGUs not subject to the ARP or RGGI are subject to
the MATS program and, therefore, will have installed stack gas flow
monitors and/or CO2 concentration monitors necessary to
comply with the MATS. Similarly, the majority of natural gas-fired
combustion turbines that may be affected by this rule already use fuel
flowmeters to monitor and report CO2 mass emissions and heat
input under appendices D and G of 40 CFR part 75. Relying on the same
monitors that are certified and quality-assured in accordance with 40
CFR part 75 ensures cost efficient, consistent, and accurate data that
may be used for different purposes for multiple regulatory programs.
The EPA requests comment on monitoring and reporting requirements
for captured CO2 mass emissions and net electricity output,
and on allowable testing methods for stack gas flow rate.
The CCS process is also subject to monitoring and reporting
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires
reporting of facility-level GHG data and other relevant information
from large sources and suppliers in the U.S. The ``suppliers of carbon
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires
those affected facilities with production process units that capture a
CO2 stream for purposes of supplying CO2 for
commercial applications or that capture and maintain custody of a
CO2 stream in order to sequester or otherwise inject it
underground to report the mass of CO2 captured and supplied.
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of
CO2 sequestered under the ``geologic sequestration of carbon
dioxide'' source category of the GHGRP (GHGRP subpart RR). In 2022, to
complement GHGRP subpart RR, the EPA proposed the ``geologic
sequestration of carbon dioxide with enhanced oil recovery (EOR) using
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide
an alternative method of reporting geologic sequestration in
association with EOR.655 656 657
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\655\ 87 FR 36920 (June 21, 2022).
\656\ International Standards Organization (ISO) standard
designated as CSA Group (CSA/American National Standards Institute
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil
Recovery (CO2--EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
\657\ As described in 87 FR 36920 (June 21, 2022), both subpart
RR and proposed subpart VV (CSA/ANSI ISO 27916:2019) require an
assessment and monitoring of potential leakage pathways;
quantification of inputs, losses, and storage through a mass balance
approach; and documentation of steps and approaches used to
establish these quantities. Primary differences relate to the terms
in their respective mass balance equations, how each defines
leakage, and when facilities may discontinue reporting.
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The EPA is proposing that any affected unit that employs CCS
technology that captures enough CO2 to meet the proposed
standard and injects the captured CO2 underground must
report under GHGRP subpart RR or proposed GHGRP subpart VV. If the
emitting EGU sends the captured CO2 offsite, it must assure
that the CO2 is managed at a facility subject to the GHGRP
requirements, and the facility injecting the CO2 underground
must report under GHGRP subpart RR or proposed GHGRP subpart VV. This
proposal does not change any of the requirements to obtain or comply
with a UIC permit for facilities that are subject to the EPA's UIC
program under the Safe Drinking Water Act.
The EPA also notes that compliance with the standard is determined
exclusively by the tons of CO2 captured by the emitting EGU.
The tons of CO2 sequestered by the geologic sequestration
site are not part of that calculation, though the EPA anticipates that
the quantity of CO2 sequestered will be substantially similar to the
quantity captured. However, to verify that the CO2 captured
at the emitting EGU is sent to a geologic sequestration site, we are
leveraging regulatory requirements under the GHGRP. The BSER is
determined to be adequately demonstrated based solely on geologic
sequestration that is not associated with EOR. However, EGUs also have
the compliance option to send CO2 to EOR facilities that
report under GHGRP subpart RR or proposed GHGRP subpart VV. We also
emphasize that this proposal does not involve regulation of downstream
recipients of captured CO2. That is, the regulatory standard
applies exclusively to the emitting EGU, not to any downstream user or
recipient of the captured CO2. The requirement that the
emitting EGU assure that captured CO2 is managed at an
entity subject to the GHGRP requirements is thus exclusively an element
of enforcement of the EGU standard. This will avoid duplicative
monitoring, reporting, and verification requirements between this
proposal and the GHGRP, while also ensuring that the facility injecting
and sequestering the CO2 (which may not necessarily be the
EGU) maintains responsibility for these requirements. Similarly, the
existing regulatory requirements applicable to geologic sequestration
are not part of the proposed rule.
The EPA requests comment on the following questions related to
additional monitoring and reporting of hourly captured CO2
under 40 CFR part 75: (a) should EGUs with carbon capture technologies
be required to monitor and report the hourly captured CO2
mass emissions under 40 CFR part 75, (b) if EGUs with carbon capture
technologies are not required to monitor and report the hourly captured
CO2 mass emissions, the calculation procedures for total
heat input and NOX rate in appendix F to 40 CFR part 75 may
no longer provide accurate results; therefore, what changes might be
necessary to accurately determine total heat input and NOX
rate, (c) to ensure accurate and complete accounting of CO2
mass emissions emitted to the atmosphere and captured for use or
sequestration, at what locations should CO2 concentration
and stack gas flow be monitored, and should other values also be
monitored at those locations, (d) are there quality assurance
activities outside of those required under 40 CFR part 75 for
CO2 concentration monitors and stack gas flow monitors that
should be required of the monitors to accurately and reliably measure
captured CO2 mass emissions, and (e) what monitoring plan,
quality assurance, and emissions
[[Page 33392]]
data should be reported to the EPA to support evaluation and ensure
consistent and accurate data as it relates to CO2 emissions
capture.
The 40 CFR part 75 monitoring and reporting provisions require
hourly reporting of total gross electricity output, including useful
thermal output, but do not require the reporting of net electricity
output. The EPA requests comment on the following questions related to
reporting of net electricity output: (a) should EGUs be required to
measure and report total net electricity output, including useful
thermal output, under 40 CFR part 75, (b) what guidance should the EPA
provide on how to measure and apportion net electricity output, (c)
should EGUs measure and report net electricity output at the unit or
facility level, and (d) what monitoring plan, quality assurance, and
output data should be reported to the EPA to support evaluation and
ensure consistent and accurate data as it relates to total net
electricity output.
To calculate CO2 mass emissions at a fossil fuel-fired
boiler, the EGU typically measures CO2 concentration and
flue gas flow rate as the exhaust gases from combustion pass through
the stack (or duct). Under 40 CFR part 75, EGUs must complete regular
performance tests on the flue gas flow monitor based on EPA Reference
Method 2 or its allowable alternatives that are provided in 40 CFR part
60, appendices A-1 and A-2. In general, the allowable alternative
measurement methods reduce or eliminate the potential overestimation of
stack gas flow rate that results from the use of EPA Reference Method 2
when the specific flow conditions (e.g., angular flow) are present in
the stack. However, EGUs with stack gas flow monitors are not required
to use the allowable alternative measurement methods and EGUs may
change methods at any time. The EPA requests comment on the following
questions related to the use of EPA Reference Method 2 and its
allowable alternatives for stack gas flow monitors under 40 CFR part
75: (a) should or under what conditions should EGUs be required to
conduct a flow study and choose the appropriate EPA reference method
for each stack gas flow monitor based on the results of the study, (b)
once an EGU selects the use of an EPA reference method for a stack gas
flow monitor, regardless of the basis for that selection, should the
EGU be required to continue using the same EPA reference method until a
flow study or other engineering justification is made to change the EPA
reference method, and (c) what additional monitoring plan, quality
assurance, and emissions data should be reported to the EPA to support
evaluation and ensure consistent and accurate data as it relates stack
gas flow rate and performance of the stack gas flow monitor.
E. Compliance Flexibilities
In developing these proposed emission guidelines, the EPA has heard
from stakeholders seeking flexibility in complying with standards of
performance under these emission guidelines. In particular,
stakeholders have requested that the EPA allow states to include
flexibilities such as averaging and market-based mechanisms in their
State plans, as has been permitted under prior EPA rules. The EPA is
proposing to allow states to incorporate averaging and emission trading
into their State plans, provided that states ensure that use of these
compliance flexibilities will result in a level of emission performance
by the affected EGUs that is equivalent to each source individually
achieving its standard of performance. As discussed below, the EPA also
recognizes that the structure of the proposed subcategories and
associated degrees of emission limitation, as well as the unique
characteristics of the existing sources in the relevant source
categories, will likely require that certain limitations or conditions
be placed on the incorporation of averaging and trading in order to
ensure that such standards are at least as stringent as the EPA's BSER.
This section discusses considerations related to such compliance
flexibilities in the context of this particular rule and set of
regulated sources--existing steam generating units and existing
combustion turbine EGUs--and solicits comment on whether certain types
of averaging and trading maintain the stringency of the EPA's BSER.
1. Overview
In the proposed subpart Ba revisions, ``Adoption and Submittal of
State Plans for Designated Facilities: Implementing Regulations Under
Clean Air Act Section 111(d)'' (87 FR 79176; December 23, 2022), the
EPA explained that under its proposed interpretation of CAA section
111, each State is permitted to adopt measures that allow its sources
to meet their emission limits in the aggregate when the EPA determines,
in any particular emission guideline, that it is appropriate to do so
given, inter alia, the pollutant, sources, and standards of performance
at issue. Thus, the EPA has proposed to return to its longstanding
position that CAA section 111(d) authorizes the EPA to approve State
plans that achieve the requisite emission limitation through aggregate
reductions from their sources, including through trading or averaging,
where appropriate for a particular emission guideline and consistent
with the intended environmental outcomes of the BSER.\658\ See 87 FR
79208 (December 23, 2022).
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\658\ The EPA has authorized trading or averaging as compliance
methods in several emission guidelines. See, e.g., 40 CFR
60.33b(d)(2) (emission guidelines for municipal waste combustors
permit state plans to establish trading programs for NOX
emissions); 70 FR 28606, 28617 (May 18, 2005) (Clean Air Mercury
Rule authorized trading) (vacated on other grounds); 40 CFR
60.24(b)(1) (subpart B CAA section 111 implementing regulations
promulgated in 2005 allow States' standards of performance to be
based on an ``allowance system''); 80 FR 64662, 64840 (October 23,
2015) (CPP authorizing trading or averaging as a compliance
strategy). In the recent supplemental proposal to promulgate
emission guidelines for the oil and natural gas industry, the EPA
has also proposed to allow States to permit sources to demonstrate
compliance in the aggregate. 87 FR 74702, 74812 (December 6, 2022).
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Consistent with the return to this longstanding position, the EPA
is proposing to allow states to incorporate trading and averaging in
their State plans under these emission guidelines. States would not be
required to allow for such compliance mechanisms in their State plans
but could provide for trading and averaging for existing steam
generating units and/or existing combustion turbines at their
discretion.\659\ As discussed in section XII.C of this preamble, State
plans must demonstrate that they achieve a level of emission
performance by affected EGUs that is consistent with the application of
the BSER. The EPA is therefore proposing that, in order to find that a
State plan that includes trading or averaging is ``satisfactory,'' it
must demonstrate that it maintains the level of emission performance
for the source category that would be achieved if each affected EGU was
individually achieving its presumptive standard of performance, after
allowing for any application of RULOF. In the case of averaging,
discussed in section XII.E.3 of this preamble, an equivalence
demonstration would be relatively straightforward. For emission trading
programs, ensuring equivalent emission
[[Page 33393]]
performance in the aggregate may be more difficult.
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\659\ The EPA notes that these flexibilities, trading and
averaging, would be used to comply with standards of performance,
rather than to establish standards of performance in the first
instance. In contrast to the RULOF mechanism, which, as described in
section XI.D.2 of this preamble, States may use to establish
different standards of performance than those described by the EPA's
BSER, trading or averaging may be used to demonstrate compliance
with already established standards of performance. That is, States
incorporating trading or averaging would not need to undergo a RULOF
demonstration for sources participating in trading or averaging
programs.
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Section XII.E.2 of this preamble discusses considerations related
to the appropriateness of trading and averaging for affected EGUs in
certain circumstances, e.g., affected EGUs with proposed BSERs based on
routine methods of operation and maintenance. Section XII.E.2 of this
preamble also discusses program design examples as well as potential
design elements and takes comment on whether these or other designs or
design elements could ensure that use of emission trading or averaging
does not undermine the stringency of the EPA's BSER. However, the
Agency is not proposing a presumptively approvable averaging or trading
approach at this time.
The EPA also notes that States that incorporate trading or
averaging into their State plans would need to conduct meaningful
engagement on this aspect of their plans with pertinent stakeholders,
just as they would need to do for any other part of a plan. As
discussed in greater detail in section XII.F.1.b of this preamble,
meaningful engagement provides an opportunity for communities most
affected by and vulnerable to the impacts of a plan to provide input,
including input on any impacts resulting from the use of trading or
averaging for compliance.
2. Emission Trading
The EPA is proposing to allow State plans to include emission
trading programs as a compliance flexibility for affected existing EGUs
under these emission guidelines and is taking comment on whether
certain types of trading programs could satisfy the requirement to
maintain equivalence with source-specific application of standards of
performance. This section discusses considerations related to affected
EGUs under these emission guidelines and how a State could potentially
incorporate a rate-based trading program or a mass-based trading
program in a way that preserves the stringency of the BSER.
a. Considerations for Emission Trading in State Plans
Emission trading has been used to achieve required emission
reductions in the power sector for nearly 3 decades. In Title IV of the
Clean Air Act Amendments of 1990, Congress specified the design
elements for the Acid Rain Program, a 48-State allowance trading
program to reduce SO2 emissions and the resulting acid
precipitation. Building on the success of that first allowance trading
program as a tool for addressing multi-State air pollution issues, the
EPA has promulgated and implemented multiple allowance trading programs
since 1998 for SO2 or NOX emissions to address
the requirements of the CAA's good neighbor provision with respect to
successively more stringent NAAQS for fine particulate matter and
ozone. The EPA currently administers eight power sector emission
trading programs that differ in pollutants, geographic regions, covered
time periods, and levels of stringency.\660\ Annual progress reports
demonstrate that EPA trading programs have been successful in
mitigating the problems they were designed to address, exhibiting
significant emission reductions and extraordinarily high levels of
compliance.\661\ In addition, several states have implemented regional
or intrastate CO2 emissions trading programs to address GHG
emissions from the power sector (the RGGI and California trading
programs, respectively).
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\660\ The six current CSAPR trading programs are the CSAPR
NOX Annual Trading Program, CSAPR NOX Ozone
Season Group 1 Trading Program, CSAPR SO2 Group 1 Trading
Program, CSAPR SO2 Group 2 Trading Program, CSAPR
NOX Ozone Season Group 2 Trading Program, and CSAPR
NOX Ozone Season Group 3 Trading Program. The regulations
for the six CSAPR programs are set forth at subparts AAAAA, BBBBB,
CCCCC, DDDDD, EEEEE, and GGGGG, respectively, of 40 CFR part 97. The
regulations for the Texas SO2 Trading Program are set
forth at subpart FFFFF of 40 CFR part 97. The Acid Rain Program
SO2 trading program is set forth in Title IV of the Clean
Air Act Amendments of 1990.
\661\ Environmental Protection Agency (2021). Power Sector
Programs--Progress Report. EPA. https://www3.epa.gov/airmarkets/progress/reports/.
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In general, emission trading programs provide flexibility for EGUs
to secure emission reductions at a lower cost relative to more
prescriptive forms of regulation. Emission trading can allow the owners
and operators of EGUs to prioritize emission reduction actions where
they are the quickest or cheapest to achieve while still meeting
electricity demand and broader environmental and economic performance
goals. These benefits are heightened where there is a diverse set of
emission sources (e.g., variation in technology, fuel type, age, and
operating parameters) included in an emission trading program. This
diversity of sources is typically accompanied by differences in
marginal emission abatement costs and operating parameters, resulting
in heterogeneity in economic emission reduction opportunities that can
be optimized through the compliance flexibility provided through
emission trading. In addition, the EPA has observed, with the support
of multiple independent analyses, that there is significant evidence
that implementation of trading programs prompted greater innovation and
deployment of clean technologies that reduce emissions and control
costs.\662\
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\662\ LaCount, M.D., Haeuber, R.A., Macy, T.R., & Murray, B.A.
(2021). Reducing Power Sector Emissions under the 1990 Clean Air Act
Amendments: A Retrospective on 30 Years of Program Development and
Implementation. Atmospheric Environment (Oxford, England: 1994),
245, 1-10. https://doi.org/10.1016/j.atmosenv.2020.118012.
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Emission trading may also provide important benefits. Having
flexibility to prioritize the most cost effective emission reductions
among affected EGUs may reduce the cost of compliance as well as
provide flexibility for fleet management, while achieving the requisite
level of emission performance. In particular, emission trading may
provide some short-term operational flexibility.
At the same time, there may be challenges for implementing an
emission trading program, especially in the context of the emission
guidelines that the EPA is proposing here. The EPA notes that while the
proposed emission guidelines include both steam generating units and
combustion turbines, the fleet of affected steam generating units is
expected to shrink under BAU projections (see section IV.F of this
preamble), and the number of existing combustion turbines subject to
these emission guidelines is limited (see section XI.C of this
preamble) given the subcategory applicability thresholds. As a result,
there is unlikely to be as much diversity in cost and emission
performance among affected emission sources (resulting in less
diversity in emission reduction opportunities and marginal abatement
costs) as seen in prior emission trading programs for the electric
power sector.
The utility of trading under these emission guidelines may also be
obviated somewhat by the subcategories that the EPA has proposed to
establish for existing coal-fired steam generating units and existing
gas combustion turbines. The specific subcategories proposed under
these emission guidelines for steam generating units are designed to
provide for much of the same operational flexibility as would be
provided through trading; as a result, the EPA believes that it would
not be appropriate to allow affected EGUs in certain subcategories--
imminent-term and near-term coal-fired steam generating units and
natural gas- and oil-fired steam generating units--to comply with their
standards of performance through trading. Similarly, the EPA believes
it would not be
[[Page 33394]]
appropriate to allow affected EGUs with less-stringent, source-specific
standards based on RULOF to comply with those standards of performance
through trading. As discussed in section X.D.3 of this preamble, the
proposed BSER determinations for the imminent- and near-term coal-fired
steam generating unit subcategories are designed to take into account
factors such as operating horizon and load level (expressed as annual
capacity factor) and, as a result, are based on routine methods of
operation and maintenance. Natural gas- and oil-fired steam generating
units also have proposed BSER determinations based on routine methods
of operation and maintenance. An emission trading program that includes
affected EGUs that have BSERs and resulting standards of performance
based on limited expected emission reduction potential--or, in the case
of affected EGUs for which states have invoked RULOF, less stringent
standards of performance--may introduce the risk of undermining the
intended stringency of the BSER for other facilities.
The EPA also believes that emission trading may be inappropriate
for some subcategories of affected EGUs based on other, subcategory-
specific reasons. Affected EGUs that receive the IRC section 45Q tax
credit for permanent sequestration of CO2 may have an
overriding incentive to maximize both the application of the CCS
technology and total electric generation, leading to source behavior
that may be non-responsive to the economic incentives of a trading
program. This consideration may be relevant for affected EGUs in the
long-term coal-fired steam generating unit subcategory and the CCS
combustion turbine subcategory that comply with their standards of
performance using CCS. Additionally, the utilization applicability
criterion for existing combustion turbines creates a barrier to
emission trading under these emission guidelines. Specifically,
existing combustion turbines that are greater than 300 MW qualify as
affected EGUs and thus have applicable standards of performance only
when they operate at an annual capacity factor of greater than 50
percent. When they operate at an annual capacity factor of 50 percent
or less, they are not subject to standards of performance. The EPA
believes that the fact that units may fall in or out of a trading
program from year to year very likely precludes their inclusion in any
such program as a practical matter.
The EPA requests comment on these challenges and on whether, in
light of these and other considerations, emission trading should be
permitted for certain subcategories and not permitted for others, and
on whether emission trading should be limited to within certain
subcategories, and why. In the following sections, the EPA discusses
potential rate-based and mass-based emission trading program approaches
that could potentially be included in a State plan and solicits comment
on applied implementation issues in the context of these proposed
emission guidelines and the considerations discussed in this subsection
XII.E.2.a of the preamble.
b. Rate-Based Emission Trading
A rate-based trading program allows affected EGUs to trade
compliance instruments that are generated based on their emission
performance. This section describes one method of how states could
establish a rate-based trading program as part of a State plan. The EPA
requests comment on whether this or another method of rate-based
trading could demonstrate equivalent stringency as would be achieved if
each affected EGU was achieving its standard of performance.
In this example, affected EGUs that perform at a lower emission
rate (lb CO2/MWh) than their standard of performance would
be issued compliance instruments that are denominated in one ton of
CO2. A tradable instrument denominated in another unit of
measure, such as a MWh, is not fungible in the context of a rate-based
emission trading program. A compliance instrument denominated in MWh
that is awarded to one affected EGU may not represent an equivalent
amount of emissions credit when used by another affected EGU to
demonstrate compliance, as the CO2 emission rates (lb
CO2/MWh) of the two affected EGUs are likely to differ. This
may pose a challenge for states trying to demonstrate equivalence with
the intended stringency of the BSER.
These compliance instruments could be transferred among affected
EGUs, making them ``tradable.'' Compliance would be demonstrated for an
affected EGU based on a combination of its reported CO2
emission performance (in lb CO2/MWh) and, if necessary, the
surrender of an appropriate number of tradable compliance instruments,
such that the demonstrated lb CO2/MWh emission performance
is equivalent to the rate-based standard of performance for the
affected EGU.
Specifically, each affected EGU would have a particular standard of
performance, based on the degree of emission limitation achievable
through application of the BSER, with which it would have to
demonstrate compliance. Under a rate-based trading program, affected
EGUs performing at a CO2 emission rate below their standard
of performance would be awarded compliance instruments at the end of
each control period denominated in tons of CO2. The number
of compliance instruments awarded would be equal to the difference
between their standard of performance CO2 emission rate and
their actual reported CO2 emission rate multiplied by their
generation in MWh. Affected EGUs performing worse than their standard
of performance would be required to obtain and surrender an appropriate
number of compliance instruments when demonstrating compliance, such
that their demonstrated CO2 emission rate is equivalent to
their rate-based standard of performance. Transfer and use of these
compliance instruments would be accounted for with a rate adjustment as
each affected EGU performs its compliance demonstration.
In general, rate-based emission trading can by design assure
achievement of the requisite level of emission performance for affected
sources, because reduced utilization and retirements are automatically
accounted for in the award of the compliance instrument. By default,
only operating affected EGUs could receive or participate in the
trading of compliance instruments.
The EPA is seeking comment on whether rate-based emission trading
might be appropriate under these emission guidelines, taking into
consideration the discussion of the appropriateness of trading for
certain subcategories in section XII.E.2.a of this preamble. In
particular, the EPA requests comment on whether and how a rate-based
emission trading program could be designed to ensure equivalent
stringency as would be achieved if each participating affected EGU was
achieving its source-specific standard of performance, given the
structure of the proposed subcategories and their proposed BSERs. The
EPA also requests comment on any other methods of rate-based trading
that would preserve the stringency of the BSER.
c. Mass-Based Emission Trading
A mass-based trading program establishes a budget of allowable mass
emissions for a group of affected EGUs, with tradable instruments
(typically referred to as ``allowances'') issued to affected EGUs in
the amount equivalent to the emission budget. Each allowance would
represent a tradable permit to emit one ton of CO2, with
affected EGUs required to surrender allowances in a number equal to
their reported CO2
[[Page 33395]]
emissions during each compliance period. This section describes one
method of how states could establish a mass-based trading program as
part of a State plan. The EPA requests comment on whether this or
another method of mass-based trading could ensure equivalent stringency
as would be achieved if each participating affected EGU was achieving
its source-specific standard of performance.
As previously discussed, mass-based emission trading has been used
in the power sector at the Federal, regional, and State levels for
nearly 3 decades. Owners and operators of EGUs, utilities, and State
agencies thus have extensive familiarity with mass-based emission
trading, which could make the design and implementation of a mass-based
trading program as part of a State plan relatively straightforward.
However, this familiarity comes with an awareness on the part of states
and the EPA of the need to tailor the design of a mass-based emission
trading program to the situation in which it is applied. Past
experience shows that emission budgets have often been overestimated
when set many years in advance of the start of a program, as economic
and technological conditions have changed significantly between the
time the program was adopted and when compliance obligations begin.
Projecting affected EGU fleet composition and utilization beyond the
relative near term has become increasingly challenging, driven by
factors including changes in relative fuel prices and continued rapid
improvement in the cost and performance of wind and solar generation,
along with new incentives for technology deployment provided by the
IIJA and the IRA. Critically, if affected EGUs reduce utilization or
exit the source category, the remaining affected EGUs face a reduced or
eliminated obligation to improve their emission performance. In this
case, the emission budget would be established at a level such that the
sources would not be collectively meeting the required level of
emission performance commensurate with each source achieving its rate-
based standard of performance.
One program design states might employ to ensure that affected EGUs
participating in a mass-based trading program continue to meet the
level of emission performance prescribed by category-wide, source-
specific implementation of the rate-based standards of performance
includes regularly adjusting emission budgets to account for sources
that cease operations or change their utilization. One budget
adjustment method that the EPA has developed is dynamic budgeting, as
applied in the Good Neighbor Plan,\663\ in which budgets are updated
annually based on recent historical generation. States could apply a
similar dynamic budgeting process to mass-based trading implemented
under these emission guidelines. In this context, states could
establish an emission budget based on the unit-specific standards of
performance of the participating affected EGUs, as described in section
XII.D of this preamble, multiplied by each affected EGU's recent
historical generation. The emission budget would be updated regularly
to account for units that reduce utilization or cease operation. This
is one way that states could assure achievement of the requisite level
of emission performance for affected EGUs through mass-based trading,
though the EPA acknowledges that existing State or regional mass-based
trading programs may have developed other regular emission budget
adjustment methods that could potentially provide similar assurance and
might provide a model that could be applied for trading under these
emission guidelines.
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\663\ The final Good Neighbor Plan was signed by the
Administrator on March 15, 2023. At this time, the final action has
not yet been published in the Federal Register.
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The EPA also acknowledges that other methods could be used to
establish an emission budget that, in conjunction with the
aforementioned dynamic budget approach, could achieve at least the
requisite level of emission performance consistent with application of
the BSER. States could use a single rate at the level of the
subcategory or source category that is, for example, as stringent as
the most controlled unit in the group (based on unit-specific standards
of performance as defined in section XII.D.1) to establish the emission
budget.
The EPA is seeking comment on whether mass-based emission trading
might be appropriate under these emission guidelines, taking into
consideration the discussion of the appropriateness of trading for
certain subcategories in section XII.E.2.a of this preamble. In
particular, the EPA requests comment on whether and how a mass-based
emission trading program could be designed to ensure equivalent
stringency as each participating affected EGU achieving its source-
specific standard of performance, given the structure of the proposed
subcategories and their proposed BSERs. The EPA is also seeking comment
on whether the method of mass-based emission trading using dynamic
budgeting, as discussed in this section, might be appropriate under
these emission guidelines. The EPA is also seeking comment on other
approaches or features that could ensure that emission budgets reflect
the stringency that would be achieved through unit-specific application
of rate-based standards of performance.
d. General Emission Trading Program Implementation Elements
The EPA notes that states would need to establish procedures and
systems necessary to implement and enforce an emission trading program,
whether it is rate-based or mass-based, if they elect to incorporate
emission trading into their State plans. This would include, but is not
limited to, establishing compliance timeframes and the mechanics for
demonstrating compliance under the program (e.g., surrender of
compliance instruments as necessary based on monitoring and reporting
of CO2 emissions and generation); establishing requirements
for continuous monitoring and reporting of CO2 emissions and
generation; and developing a tracking system for tradable compliance
instruments. Additionally, for states implementing a mass-based
emission trading program, State plans would need to specify how
allowances would be distributed to participating affected EGUs.
The EPA acknowledges that the proposed dates as of which standards
of performance would apply for sources covered by these emission
guidelines differ by subcategory: January 1, 2030, for all steam
generating units; January 1, 2032, for the hydrogen co-fired combustion
turbine subcategory; and January 1, 2035, for the CCS combustion
turbine subcategory. If trading is permitted for two or more of these
sets of sources, this difference could potentially pose an
implementation challenge where a trading program includes these
sources. To address this issue, a program could, for example, begin in
2030 for steam generating units and bring in combustion turbine EGUs
later, or states could delay implementation of a trading program to
coincide with the later combustion turbine date. The Agency requests
comment on potential ways to address this implementation issue in the
context of a State plan, and whether this issue impacts the utility or
feasibility of trading across subcategories.
The EPA is also requesting comment on whether and to what extent
there would be a desire to capitalize on the EPA's existing reporting
and compliance tracking infrastructure to support State implementation
of an
[[Page 33396]]
emission trading program included in a State plan.
e. Banking of Compliance Instruments
The EPA requests comment on whether State plans should be allowed
to provide for banking of tradable compliance instruments (hereafter
referred to as ``allowance banking,'' although it is relevant for both
mass-based and rate-based trading programs). Allowance banking has
potential implications for a trading program's ability to maintain the
requisite stringency of the standards of performance. The EPA
recognizes that allowance banking--that is, permitting allowances that
remain unused in one control period to be carried over for use in
future control periods--may provide incentives for early emission
reductions, promote operational flexibility and planning, and
facilitate market liquidity. However, the EPA has observed that
unrestricted allowance banking from one control period to the next
(absent provisions that adjust future control period budgets to account
for banked allowances) may result in a long-term allowance surplus that
has the potential to undermine a trading program's ability to ensure
that, at any point in time, the affected sources are achieving the
required level of emission performance. In addition to requesting
comment on whether the EPA should permit allowance banking, the EPA
requests comment on the treatment of banked allowances, specifically
whether all or only some portion of an allowance bank could be carried
over for use in future control periods or if additional program design
elements would be necessary to accommodate allowance banking.
f. Interstate Emission Trading
The EPA is requesting comment on whether, and under what
circumstances or conditions, to allow interstate emission trading under
these emission guidelines. Given the interconnectedness of the power
sector and given that many utilities operate in multiple states,
interstate emission trading may increase compliance flexibility. For
interstate emission trading programs to function successfully, all
participating states would need to, at a minimum, use the same form of
trading and have identical trading program requirements. There are many
requirements for program reciprocity and approvability that would need
to be established in the emission guidelines, in addition to providing
mechanisms for submission and EPA review of State plans that include
interstate trading mechanisms. Given the increased level of program
complexity that would be necessary to accommodate interstate trading
and the operational flexibilities already provided by the structure of
the proposed subcategories and their proposed BSERs, the EPA requests
comment on whether there is utility in providing for it under these
emission guidelines. In addition, the EPA requests comment on the
information, guidance, and requirements the EPA would need to provide
for states to implement successful interstate emission trading
programs.
3. Rate-Based Averaging
The EPA is proposing to allow State plans to include rate-based
averaging as a compliance flexibility for affected EGUs under these
emission guidelines. This section discusses how states could
potentially incorporate a rate-based averaging program in a way that
preserves the stringency of the EPA's BSER as well as some
considerations related to incorporating averaging in State plans. The
EPA is seeking comment on one potential method, described in this
section, as well as other methods that could maintain the required
level of emission performance equivalent to each source individually
achieving its standard of performance.
Averaging allows multiple affected EGUs to jointly meet a rate-
based standard of performance. Affected EGUs participating in averaging
could, for example, demonstrate compliance through an effective
CO2 emission rate that is based on a gross generation-based
weighted average of the required standards of performance of the
affected EGUs that participate in averaging. The scope of such
averaging could apply at the facility level or the owner or operator
level. This method for calculating a composite rate could demonstrate
equivalence with source-specific standards of performance.
Averaging can provide potential benefits. First, it offers some
flexibility for sources to target cost effective reductions at any
affected EGU. For example, owners or operators of affected EGUs might
target installation of emission control approaches at units that
operate more. Second, averaging at the facility level provides greater
ease of compliance accounting for affected EGUs with a complex stack
configuration (such as a common- or multi-stack configuration). In such
instances, unit-level compliance involves apportioning reported
emissions to individual affected EGUs that share a stack based on
electricity generation or other parameters.
However, the EPA notes that the subcategory approach in these
emission guidelines already provides significant operational
flexibility for affected EGUs, potentially making the provision of
further flexibility through averaging redundant or inappropriate,
especially at the owner or operator level.
The EPA is seeking comment on the utility of rate-based averaging
as a compliance flexibility, as well as on the illustrative method for
developing a composite standard of performance for the purposes of
rate-based averaging. The EPA is also seeking comment on any other
considerations related to rate-based averaging, including whether the
scope of averaging should be limited to a certain level of aggregation
(e.g., to facility-level rate-based averaging) or to certain
subcategories.
4. Relationship to Existing State Programs
The EPA recognizes that many states have adopted binding policies
and programs (with both a supply-side and demand-side focus) under
their own authorities that have significantly reduced CO2
emissions from EGUs, that these policies will continue to achieve
future emission reductions, and that states may continue to adopt new
power sector policies addressing GHG emissions. States have exercised
their power sector authorities for a variety of purposes, including
economic development, energy supply and resilience goals, conventional
and GHG pollution reduction, and generating allowance proceeds for
investments in communities disproportionately impacted by environmental
harms. The scope and approach of EPA's proposed emission guidelines
differs significantly from the range of policies and programs employed
by states to reduce power sector CO2 emissions, and this
proposal operates more narrowly to improve the CO2 emission
performance of a subset of EGUs within the broader electric power
sector. The Agency recognizes the importance of State programs and
their potential to reduce power sector CO2 emissions through
a range of strategies broader than those proposed here pursuant to CAA
section 111(d). The EPA seeks comment on whether there are any elements
of the proposed emission guidelines that might interfere with the
implementation of State requirements that limit CO2
emissions from EGUs that may be subject to the proposed emission
guidelines.
F. State Plan Components and Submission
This section describes the proposed requirements for the contents
of State plans, the proposed timing of State plan submissions, and the
EPA's review of
[[Page 33397]]
and action on State plan submissions. This section also discusses
issues related to the applicability of a Federal plan and timing for
the promulgation of a Federal plan.
As explained earlier in this preamble, the requirements of 40 CFR
part 60, subpart Ba, govern State plan submissions under these emission
guidelines. Where the EPA is proposing to add to, supersede, or
otherwise vary the requirements of subpart Ba for the purposes of State
plan submissions under these particular emission guidelines,\664\ those
proposals are addressed explicitly in section XII.F.1.b on specific
State plan requirements and throughout this preamble. Unless expressly
amended or superseded in these proposed emission guidelines, the
provisions of subpart Ba would apply.
---------------------------------------------------------------------------
\664\ 40 CFR 60.20a(a)(1).
---------------------------------------------------------------------------
1. Components of a State Plan Submission
The EPA is proposing that a State plan must include a number of
discrete components. These proposed plan components include those that
apply for all State plans pursuant to 40 CFR part 60, subpart Ba. The
EPA is also proposing additional plan components that are specific to
State plans submitted pursuant to these emission guidelines. For
example, the EPA is proposing plan components that are necessary to
implement and enforce the specific types of standards of performance
for affected EGUs that would be adopted by a State and incorporated
into its State plan.
a. General Components
The CAA section 111 implementing regulations at 40 CFR part 60
subpart Ba provide separate lists of administrative and technical
criteria that must be met in order for a State plan submission to be
deemed complete. The EPA's proposed revisions to subpart Ba would add
one item to the list of administrative criteria related to meaningful
engagement (element 9 in the list below).\665\ If that criterion is
finalized as proposed, the complete list of applicable administrative
completeness criteria for State plan submissions would be: (1) A formal
letter of submittal from the Governor or the Governor's designee
requesting EPA approval of the plan or revision thereof; (2) Evidence
that the State has adopted the plan in the State code or body of
regulations; or issued the permit, order, or consent agreement
(hereafter ``document'') in final form. That evidence must include the
date of adoption or final issuance as well as the effective date of the
plan, if different from the adoption/issuance date; (3) Evidence that
the State has the necessary legal authority under State law to adopt
and implement the plan; (4) A copy of the official State regulation(s)
or document(s) submitted for approval and incorporated by reference
into the plan, signed, stamped, and dated by the appropriate State
official indicating that they are fully adopted and enforceable by the
State. The effective date of the regulation or document must, whenever
possible, be indicated in the document itself. The State's electronic
copy must be an exact duplicate of the hard copy. For revisions to the
approved plan, the submission must indicate the changes made to the
approved plan by redline/strikethrough; (5) Evidence that the State
followed all applicable procedural requirements of the State's
regulations, laws, and constitution in conducting and completing the
adoption/issuance of the plan; (6) Evidence that public notice was
given of the plan or plan revisions with procedures consistent with the
requirements of 40 CFR 60.23, including the date of publication of such
notice; (7) Certification that public hearing(s) were held in
accordance with the information provided in the public notice and the
State's laws and constitution, if applicable and consistent with the
public hearing requirements in 40 CFR 60.23; (8) Compilation of public
comments and the State's response thereto; and (9) Evidence of
meaningful engagement, including a list of pertinent stakeholders, a
summary of the engagement conducted, and a summary of stakeholder input
received.
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\665\ 87 FR 79176, 79204 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions at 40 CFR 60.27a(g)(2)).
---------------------------------------------------------------------------
Pursuant to subpart Ba, the technical criteria required for all
plans must include each of the following: \666\ (1) Description of the
plan approach and geographic scope; (2) Identification of each
designated facility (i.e., affected EGU); identification of standards
of performance for each affected EGU; and monitoring, recordkeeping,
and reporting requirements that will determine compliance by each
designated facility; (3) Identification of compliance schedules and/or
increments of progress; (4) Demonstration that the State plan
submission is projected to achieve emission performance under the
applicable emission guidelines; (5) Documentation of State
recordkeeping and reporting requirements to determine the performance
of the plan as a whole; and (6) Demonstration that each standard is
quantifiable, permanent, verifiable, enforceable, and non-duplicative.
---------------------------------------------------------------------------
\666\ 40 CFR 60.27a(g)(3)).
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b. Specific State Plan Requirements
To ensure that State plans submitted pursuant to these emission
guidelines are consistent with the requirements of subpart Ba, the EPA
is proposing regulatory requirements that would apply to all affected
EGUs subject to a standard of performance under a State plan pursuant
to these proposed emission guidelines, as well as requirements that
apply to affected EGUs within specific subcategories. Standards of
performance for affected EGUs included in a State plan must be
quantifiable, verifiable, permanent, enforceable, and non-duplicative.
Additionally, per CAA section 302(l), standards of performance must be
continuous in nature. Additional proposed State plan requirements
include:
Identification of affected EGUs and the subcategory to
which each affected EGU is assigned;
Identification of standards of performance for each
affected EGU in lb CO2/MWh-gross basis, including provisions
for implementation and enforcement of such standards;
Identification of enforceable increments of progress and
milestones, as required for affected EGUs within the applicable
subcategory, included as enforceable elements of a State plan;
If relevant, identification of applicable enforceable
requirements that are prerequisites for inclusion of an affected EGU in
a specific subcategory, such as enforceable commitments to cease
operations by a specified date or to limit annual capacity factor,
where a State and the owner or operator of an affected EGU have chosen
to rely on such commitments in order for the affected EGU to be
included in a specific subcategory, included as enforceable elements of
a State plan; and
Identification of applicable monitoring, reporting, and
recordkeeping requirements for affected EGUs.
The proposed emission guidelines include requirements pertaining to
the methodologies states must use for establishing a presumptively
approvable standard of performance for an affected EGU within a
respective subcategory. These proposed methodologies are specified for
each of the subcategories of affected EGUs in section XII.D.1 of this
preamble.
[[Page 33398]]
The EPA notes that standards of performance for affected EGUs in a
State plan must be representative of the level of emission performance
that results from the application of the BSER in these emission
guidelines. As discussed in section XII.C of this preamble, in order
for the EPA to find a State plan ``satisfactory,'' that plan must
achieve the level of emission performance that would result if each
affected source was achieving its presumptive standard of performance,
after accounting for any application of RULOF. That is, while states
have the discretion to establish the applicable standards of
performance for affected sources in their State plans, the structure
and purpose of CAA section 111 require that those plans achieve an
equivalent level of emission performance as applying the EPA's
presumptive standards of performance to those sources (again, after
accounting for any application of RULOF).
The proposed emission guidelines also include requirements that
apply to states when they invoke RULOF in applying a less stringent
standard of performance for an affected EGU than the presumptively
approvable standard of performance. Such requirements include a
demonstration by the State of why an affected EGU for which the State
invokes RULOF cannot reasonably apply the BSER. The State would also be
required to demonstrate where and how it considered the potential
pollution impacts and benefits of control to communities most affected
by and vulnerable to emissions from the designated facility. The EPA
expects that states would identify these communities, gather
information about the potential pollution impacts and benefits of
control, and document how they have considered that information in
setting source-specific standards of performance for RULOF sources
through their meaningful engagement processes.
In addition to consideration of impacts on and benefits to affected
communities in the context of invoking RULOF for particular sources,
the proposed revisions to the CAA section 111 subpart Ba implementing
regulations include requirements for public engagement on overall State
plan development. These requirements are intended to ensure robust and
meaningful public involvement in the plan development process and to
ensure that those who are most affected by and vulnerable to the
impacts of a plan will share in the benefits of the plan and are
protected from being adversely impacted. The proposed requirements are
in addition to the existing public notice requirements under subpart Ba
and, if finalized, would apply to State plan development in the context
of these emission guidelines.
The fundamental purpose of CAA section 111 is to reduce emissions
from categories of stationary sources that cause, or significantly
contribute to, air pollution which may reasonably be anticipated to
endanger public health or welfare. Therefore, a key consideration in
the State's development of a State plan is the potential impact of the
proposed plan requirements on public health and welfare. Meaningful
engagement is a corollary to the longstanding requirement for public
participation, including through public hearings, in the course of
State plan development under CAA section 111.\667\ A robust and
meaningful engagement process is critical to ensuring that the entire
public has an opportunity to participate in the State plan development
process and that states understand and consider the full range of
impacts of a proposed plan.
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\667\ 40 CFR 60.23(c)-(g); 40 CFR 60.23a(c)-(h).
---------------------------------------------------------------------------
In the subpart Ba revisions of December 2022, the EPA proposed to
define meaningful engagement as:
[T]timely engagement with pertinent stakeholder representation
in the plan development or plan revision process. Such engagement
must not be disproportionate in favor of certain stakeholders. It
must include the development of public participation strategies to
overcome linguistic, cultural, institutional, geographic, and other
barriers to participation to assure pertinent stakeholder
representation, recognizing that diverse constituencies may be
present within any particular stakeholder community. It must include
early outreach, sharing information, and soliciting input on the
State plan.\668\
---------------------------------------------------------------------------
\668\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.21a(k)).
The EPA proposed to define that pertinent stakeholders ``include
but are not limited to, industry, small businesses, and communities
most affected by and/or vulnerable to the impacts of the plan or plan
revision.'' \669\ The preamble to the proposed revisions to subpart Ba
notes that ``increased vulnerability of communities may be
attributable, among other reasons, to both an accumulation of negative
and lack of positive environmental, health, economic, or social
conditions within these populations or communities.'' \670\
---------------------------------------------------------------------------
\669\ 87 FR 79176, 79191 (December 23, 2022), Docket ID No. EPA-
HQ-OAR-2021-0527-0002 (proposed revisions at 40 CFR 60.21a(l)).
\670\ 87 FR 79176, 79191 (December 23, 2022).
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In the context of these emission guidelines, the air pollutant of
concern is greenhouse gases and the air pollution is elevated
concentrations of these gases in the atmosphere, which result in
warming temperatures and other changes to the climate system that are
leading to serious and life-threatening environmental and human health
impacts. Thus, one set of impacts on communities that states should
consider in identifying pertinent stakeholders is climate change
impacts, including increased incidence of drought and flooding, damage
to crops and disruption of associated food, fiber, and fuel production
systems, increased incidence of pests, increased incidence of heat-
induced illness, and impacts on water availability and water quality.
These and other such climate change-related impacts can have a
disproportionate impact on communities and populations depending on,
inter alia, accumulation of negative and lack of positive
environmental, health, economic, or social conditions. The Agency
therefore expects states' pertinent stakeholders to include not only
owners and operators of affected EGUs but also communities within the
State that are most affected by and/or vulnerable to the impacts of
climate change, including those exposed to more extreme drought,
flooding, and other severe weather impacts, including extreme heat and
cold (states should refer to section III of this preamble, on climate
impacts, to assist them in identifying their pertinent stakeholders).
Additionally, communities near affected EGUs may also be affected
by a State plan or plan revision due to impacts associated with
implementation of that plan. For example, communities located near
affected EGUs may be impacted by construction and operation of
infrastructure required under a State plan. Activities related to the
construction and operation of new natural gas, CCS, and hydrogen
pipelines may impact individuals and communities both locally and at
larger distances from affected EGUs but near any associated pipelines.
Thus, communities near affected EGUs and communities near pipelines
constructed pursuant to State plan requirements should be considered
pertinent stakeholders and included in meaningful engagement.
The EPA also acknowledges that employment at affected EGUs
(including employment in operation and maintenance as well as in
construction for installation of pollution control technology) is
impacted by power sector trends on an ongoing basis, and states may
choose to take energy communities into consideration as part of
meaningful engagement. A variety of Federal
[[Page 33399]]
programs are available to support these communities.\671\
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\671\ An April 2023 report of the Federal Interagency Working
Group on Coal and Power Plant Communities and Economic
Revitalization (Energy Communities IWG) summarizes how the
Bipartisan Infrastructure Law, CHIPS and Science Act, and Inflation
Reduction Act have greatly increased the amount of Federal funding
relevant to meeting the needs of energy communities, as well as how
the Energy Communities IWG has launched an online Clearinghouse of
broadly available Federal funding opportunities relevant for meeting
the needs and interests of energy communities, with information on
how energy communities can access Federal dollars and obtain
technical assistance to make sure these new funds can connect to
local projects in their communities. Interagency Working Group on
Coal and Power Plant Communities and Economic Revitalization.
``Revitalizing Energy Communities: Two-Year Report to the
President'' (April 2023). https://energycommunities.gov/wp-content/uploads/2023/04/IWG-Two-Year-Report-to-the-President.pdf.
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In some cases, an affected EGU may be located near State or Tribal
borders and impact communities in neighboring states or Tribal lands.
In such cases, the EPA believes it could be reasonable for a State to
identify pertinent stakeholders in the neighboring State or Tribal land
and to work with the relevant air pollution control authority to
conduct meaningful engagement that addresses cross-border impacts. The
EPA solicits comment on how meaningful engagement should apply to
pertinent stakeholders outside a State's borders.
It is important for states to recognize and engage the communities
most affected by and/or vulnerable to the impacts of a State plan,
particularly as these communities may not have had a voice when the
affected EGUs were originally constructed. Consistent with the long-
standing requirements for public engagement in State plan development,
states should design meaningful engagement to ensure that all pertinent
stakeholders are able to provide input on how affected EGUs in their
State comply with their State plan requirements pursuant to these
emission guidelines. Because these emission guidelines address air
pollution that becomes well mixed and is long-lived in the atmosphere,
the EPA expects states will consider communities and populations within
the State that are both most impacted by particular affected EGUs and
associated pipelines and that will be most affected by the overall
stringency of State plans. (Note that the EPA addresses consideration
of impacts of particular sources in the context of RULOF in section
XII.D.2.c of this preamble.)
During the Agency's pre-proposal outreach, some environmental
justice organizations and community representatives raised strongly
held concerns about the potential health, environmental, and safety
impacts of CCS. The EPA believes that any deployment of CCS can and
should take place in a manner that is protective of public health,
safety, and the environment, and that includes early and meaningful
engagement with affected communities and the public. As stated in the
Council on Environmental Quality's (CEQ) February 2022 Carbon Capture,
Utilization, and Sequestration Guidance, ``the successful widespread
deployment of responsible CCUS will require strong and effective
permitting, efficient regulatory regimes, meaningful public engagement
early in the review and deployment process, and measures to safeguard
public health and the environment.'' \672\
---------------------------------------------------------------------------
\672\ Carbon Capture, Utilization, and Sequestration Guidance,
87 FR 8808, 8809 (February 16, 2022), https://www.govinfo.gov/content/pkg/FR-2022-02-16/pdf/2022-03205.pdf.
_____________________________________-
As discussed in section V.C.3 of this preamble, the EPA is required
to consider nonair quality health and environmental impacts, along with
other considerations, in determining the BSER for both new and existing
affected EGUs. In developing this proposed rulemaking, the EPA heard
and carefully considered concerns expressed by affected communities
regarding the possible impacts of CCS and hydrogen infrastructure in
the context of selecting the proposed BSER. After weighing any adverse
nonair quality health and environmental impacts of CCS and hydrogen co-
firing along with the other BSER considerations, including the
significant amount of emission reductions that can be achieved, and the
reasonableness of the control costs, the EPA decided to propose that
CCS and hydrogen co-firing meet the qualifications for the BSER for
certain subcategories of sources. See, for example, section X.D.1.a.iii
of this preamble.
The EPA recognizes, however, that facility- and community-specific
circumstances, including the existence of cumulative impacts affecting
a community's resilience or where infrastructure buildout would
necessarily occur in an already vulnerable community, may also exist.
The meaningful engagement process is designed to identify and enable
consideration of these and other facility- and community-specific
circumstances. This includes consideration of facility- and community-
specific concerns with emissions control systems, including CCS and
hydrogen co-firing. States should design meaningful engagement to
elicit input from pertinent stakeholders on facility- and community-
specific issues related to implementation of emissions control systems
generally, as well as on any considerations for particular systems.
If the revisions to subpart Ba are finalized as proposed, states
would need to demonstrate in their State plans how they provided
meaningful engagement with the pertinent stakeholders. This includes
providing a list of the pertinent stakeholders, a summary of engagement
conducted, and a summary of the stakeholder input provided, including
information about the potential pollution impacts and benefits of
control. As previously noted, the State must allow for balanced
participation, including communities most vulnerable to the impacts of
the plan. States must consider the best way to reach affected
communities, which may include but should not be limited to
notification through the internet. Other channels may include notice
through newspapers, libraries, schools, hospitals, travel centers,
community centers, places of worship, gas stations, convenience stores,
casinos, smoke shops, Tribal Assistance for Needy Families offices,
Indian Health Services, clinics, and/or other community health and
social services as appropriate. The State should also consider any
geographic, linguistic, or other barriers to participation in
meaningful engagement for members of the public. If a State plan
submission does not meet the required elements for notice and
opportunity for public participation, including requirements for
meaningful engagement, this may be grounds for the EPA to find the
submission incomplete or to disapprove the plan. As discussed in
section XII.F.2 of this preamble, the EPA is proposing to provide 24
months from the date of publication of final emission guidelines for
State plan submission, which should allow states adequate time to
conduct meaningful engagement.
The EPA is requesting comment on what assistance states and
pertinent stakeholders may need in conducting meaningful engagement
with affected communities to ensure that there are adequate
opportunities for public input on decisions to implement emissions
control technology (including but not limited to CCS or low-GHG
hydrogen). The EPA is also requesting comment on any tools or
methodologies that states may find helpful for identifying communities
that are most affected by and vulnerable to emissions from affected
EGUs under these emission guidelines. The EPA is also requesting
comment on whether it would be useful for the Agency to promulgate
minimum approvability requirements for
[[Page 33400]]
meaningful engagement that are specific to these emission guidelines
and, if so, what those requirements should be.
i. Specific State Plan Requirements for Existing Combustion Turbines
Co-Firing Low-GHG Hydrogen
As discussed in section XI.C of this preamble, the EPA is proposing
that the BSER for affected combustion turbine EGUs in the hydrogen co-
fired subcategory is co-fired 30 percent low-GHG hydrogen by volume
starting January 1, 2032, and 96 percent low-GHG hydrogen by volume
starting January 1, 2038. Therefore, as discussed in section
XII.D.1.c.ii of this preamble, the EPA is proposing a rate-based
presumptive standard of performance for the hydrogen co-fired
subcategory based on co-firing low-GHG hydrogen at these levels.
However, CAA section 111 does not require that sources meet their
applicable standards of performance by implementing the BSER.
Therefore, affected combustion turbine EGUs in the hydrogen co-fired
subcategory do not necessarily have to meet their standards of
performance by co-firing hydrogen. However, should they choose to
comply in this manner, the hydrogen that they co-fire to meet their
standards of performance must be low-GHG hydrogen. Thus, the EPA is
proposing that State plans require that affected EGUs in the hydrogen
co-fired subcategory that meet their standards of performance by co-
firing hydrogen demonstrate that they are co-firing low-GHG hydrogen.
The EPA discusses its rationale for requiring low-GHG hydrogen to be
used for compliance and its proposed definition of low-GHG hydrogen in
sections VII.F.3.c.vi and VII.F.3.c.vii(F) of this preamble.
Section VII.K.3 of this preamble discusses the EPA's proposal to
closely follow Department of Treasury protocols, which are currently
under development, in determining how affected EGUs demonstrate
compliance with the requirement to use low-GHG hydrogen. In the context
of the proposed CAA section 111(b) rule for new combustion turbines,
the EPA is taking comment on what forms of acceptable mechanisms and
documentary evidence should be required for EGUs to demonstrate
compliance with the obligation to co-fire low-GHG hydrogen, including
proof of production pathway, overall emissions calculations or modeling
results and input, purchasing agreements, contracts, and attribute
certificates. The EPA is also taking comment, in the context of the CAA
section 111(b) rule, on whether EGUs should be required to make fully
transparent their sources of low-GHG hydrogen and the corresponding
quantities procured, as well as on whether the EPA should require EGUs
to demonstrate that their hydrogen is exclusively from facilities that
produce only low-GHG hydrogen, as a means of reducing burden and
opportunities for double counting. The EPA proposed to mirror the
requirements it finalizes for verification of low-GHG hydrogen for new
combustion turbine EGUs, as discussed in section VII.K.3 of this
preamble, in the State plan requirements for affected existing
combustion turbine EGUs in the hydrogen co-fired subcategory under
these emission guidelines. The EPA therefore requests comment on the
proposed approaches for verifying that low-GHG hydrogen is used for
complying with an applicable standard of performance discussed in
section VII.K.3 of this preamble. Additionally, the EPA requests
comment on any unique considerations regarding the implementation of
such verification requirements through State plans, including whether
any additional or different requirements may be necessary to ensure
that affected existing combustion turbine EGUs in the hydrogen co-
firing subcategory that co-fire hydrogen to meet their standards of
performance co-fire with low-GHG hydrogen.
ii. Specific State Plan Requirements for Transparency and Compliance
Assurance
The EPA is proposing or requesting comment on several requirements
designed to help states ensure compliance by affected EGUs with
standards of performance, as well as to assist the public in tracking
increments of progress toward the final compliance date.
First, the EPA is requesting comment on whether to require that an
affected EGU's enforceable commitment to permanently cease operations,
when a State relies on that commitment for subcategory applicability
(e.g., a State elects to rely on an affected coal-fired steam-
generating unit's commitment to permanently cease operations by
December 31, 2034, to meet the applicability requirements for the near-
term subcategory), must be in the form of an emission limit of 0 lb
CO2/MWh that applies on the relevant date.\673\ Such an
emission limit would be included in a State regulation, permit, order,
or other acceptable legal instrument and submitted to the EPA as part
of a State plan. If approved, the affected EGU would have a federally
enforceable emission limit of 0 lb CO2/MWh that would become
effective as of the date that the EGU permanently ceases operations.
The EPA is requesting comment on whether such an emission limit would
have any advantages or disadvantages for compliance and enforceability
relative to the alternative, which is an enforceable commitment in a
State plan to cease operation by a date certain.
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\673\ As explained in section X of this preamble, an affected
EGU's federally enforceable commitment to cease operations is not
part of that EGU's standard of performance but is rather a
prerequisite condition for subcategory applicability.
---------------------------------------------------------------------------
Second, the EPA is proposing that State plans that cover affected
coal-fired steam generating units within any subcategory that is based
on the date by which a source elects to permanently cease operations
(i.e., imminent-term, near-term, medium-term) must include, in
conjunction with an enforceable date, the requirement that each source
comply with applicable State and Federal requirements for permanently
ceasing operation of the EGU, including removal from its respective
State's air emissions inventory and amending or revoking all applicable
permits to reflect the permanent shutdown status of the EGU.
Third, the EPA is proposing that each State plan must require
owners and operators of affected EGUs to establish publicly accessible
websites, referred to here as a ``Carbon Pollution Standards for EGUs
website,'' to which all reporting and recordkeeping information for
each affected EGU subject to the State plan would be posted. Although
this information will also be required to be submitted directly to the
EPA and the relevant State regulatory authority, the EPA is interested
in ensuring that the information is made accessible in a timely manner
to all pertinent stakeholders. The EPA anticipates that the owners or
operators of a portion of the affected EGUs may already be posting
comparable reporting and recordkeeping information to publicly
available websites under the EPA's April 2015 Coal Combustion Residuals
Rule,\674\ such that the burden of this website requirement for these
units could be minimal.
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\674\ See https://www.epa.gov/coalash/list-publicly-accessible-internet-sites-hosting-compliance-data-and-information-required for
a list of websites for facilities posting Coal Combustion Rule
compliance information.
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In particular, the EPA is proposing that the owners or operators of
affected EGUs would be required to post to their websites their
subcategory designations and compliance schedules, including for
increments of progress and milestones, leading up to full
[[Page 33401]]
compliance with the applicable standards of performance. Owners or
operators would also be required to post to their websites any
information or documentation needed to demonstrate that an increment of
progress or milestone has been achieved. Similarly, the EPA is
proposing that emissions data and other information needed to
demonstrate compliance with a standard of performance would also be
required to be posted to the Carbon Pollution Standards for EGUs
website for an affected EGU in a timely manner. The EPA is proposing
that all information required to be made publicly available on the
Carbon Pollution Standards for EGUs website be posted within 30
business days of the information becoming available to or reported by
the owner or operator of an affected EGU. Information would have to
remain on the website for a minimum of 10 years. The EPA solicits
comment on these timeframes for posting and information retention, as
well as on any concerns related to confidential business information.
The EPA proposes that owners or operators of affected EGUs that are
also subject to similar website reporting requirements for the Coal
Combustion Residuals Rule may use an already established website to
house the reporting and recordkeeping information necessary to satisfy
its Carbon Pollution Standards for EGUs website requirements. The EPA
solicits comment on other ways to reduce redundancy and burden while
satisfying the objective of making it easier for pertinent stakeholders
to access affected EGUs' reporting and recordkeeping information.
To make it easier for the public to find the relevant Carbon
Pollution Standards for EGUs websites, the EPA is also proposing that a
State must establish a website that displays the links to the websites
for all affected EGUs in its State plan.
Fourth, to promote transparency and to assist the EPA and the
public in assessing increments of progress under a State plan, the EPA
is proposing that State plans must include a requirement that the owner
or operator of each affected EGU must report any deviation from any
federally enforceable State plan increment of progress or milestone
within 30 business days after the owner or operator of the affected EGU
knew or should have known of the event. In the report, the owner or
operator of the affected EGU would be required to explain the cause or
causes of the deviation and describe all measures taken or to be taken
by the owner or operator of the EGU to cure the reported deviation and
to prevent such deviations in the future, including the timeframes in
which the owner or operator intends to cure the deviation. The owner or
operator of the EGU must submit the report to the State regulatory
agency and post the report to the affected EGU's Carbon Pollution
Standards for EGUs website.
Fifth, to aid all affected parties and stakeholders in implementing
these emission guidelines, the EPA is explaining its intended approach
to exercising its enforcement authorities to ensure compliance while
addressing genuine risks to electric system reliability. In these
emission guidelines, the EPA has included subcategories for coal-fired
steam generating units that take into account the operating horizons of
these units and has provided relatively long planning and compliance
timeframes. The EPA's proposed emission guidelines for existing
combustion turbines likewise provide extensive lead time to meet the
proposed degrees of emission limitation and apply only to a portion of
the fleet that exceeds certain capacity and utilization thresholds. The
Agency therefore does not anticipate that either the need for certain
coal-fired steam generating units and existing combustion turbines to
install controls, or affected EGUs' preexisting decisions to
permanently cease operations, will result in resource constraints that
would adversely affect electric reliability.
Nonetheless, the EPA believes it is appropriate to provide
accommodations for potential isolated instances in which unanticipated
factors beyond an owner or operator's control, and ability to predict
and plan for, could have an adverse, localized impact on electric
reliability. In such instances, affected EGUs could find themselves in
the position of either operating in noncompliance with approved,
federally enforceable State plan requirements or halting operations and
thereby potentially impacting electric reliability.
CAA section 113 authorizes the EPA to bring enforcement actions
against sources in violation of CAA requirements, seeking injunctive
relief, civil penalties and, in certain circumstances, other
appropriate relief. The EPA also has the discretion to agree to
negotiated resolutions, including administrative compliance orders
(``ACOs'') for achieving compliance with CAA requirements, that include
expeditious compliance schedules with enforceable compliance
milestones. The EPA does not generally speak to the intended scope of
its enforcement efforts, particularly in advance of a violation
actually occurring. However, the EPA is explaining its intended
approach to ACOs here to provide confidence both with respect to
electric reliability and that emission reductions under these emission
guidelines will occur as required under CAA section 111(d).
The EPA would evaluate each request for an ACO for an affected EGU
that is required to run in violation of a State plan requirement for
reliability purposes on a case-by-case basis. However, as a general
matter, the EPA anticipates that to qualify for an ACO, the owner/
operator would need to demonstrate, as a minimum, that the following
conditions have been satisfied: \675\
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\675\ This is a nonexclusive list of conditions. The EPA may
choose to consider additional factors when deciding whether to enter
an ACO in any given situation.
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The owner/operator of the affected EGU requesting an ACO
has requested, in writing and in a timely manner, an enforceable
compliance schedule in an ACO.
The owner/operator of the affected EGU requesting an ACO
has provided the EPA written analysis and documentation of reliability
risk if the unit were not in operation, which demonstrates that
operation of the unit in noncompliance is critical to maintaining
electric reliability and that failure to operate the unit would result
in violation of the established reliability criteria for the relevant
control area/balancing authority, or cause reserves to fall below the
required system reserve margin.
The owner/operator of the affected EGU requesting an ACO
has provided the EPA with written concurrence with the reliability
analysis from the relevant electric planning authority for the area in
which the affected EGU is located.
The owner/operator of the affected EGU requesting an ACO
has demonstrated that the need to continue operating for reliability
purposes is due to factors beyond the control of the owner/operator and
that the owner/operator of the affected EGU has not contributed to the
purported need for an ACO.
The owner/operator of the affected EGU requesting an ACO
demonstrates that it has met all applicable increments of progress and
milestones in the State plan.
It can be demonstrated that there is insufficient time to
address the reliability risk and potential noncompliance through a
State plan revision.
If deemed appropriate to do so, the EPA would issue an ACO that
includes
[[Page 33402]]
a compliance schedule and milestones to achieve compliance as
expeditiously as practicable. The ACO would also include any
operational limits, including limits on utilization reflecting the
extent to which the unit is needed for grid reliability, and/or work
practices necessary to minimize or mitigate any emissions to the
maximum extent practicable during any operation of the affected EGU
before it has achieved full compliance. The EPA reiterates that it
would not be appropriate to request an ACO to address reliability risk
and anticipated noncompliance in circumstances in which a State plan
revision is possible.
The EPA requests comment on whether to promulgate requirements in
the final emission guidelines pertaining to the demonstrations,
analysis, and information the owner or operator of an affected EGU
would have to submit to the EPA in order to be considered for an ACO.
2. Timing of State Plan Submissions
The EPA's proposed subpart Ba revisions would require states to
submit State plans within 15 months after publication of the final
emission guidelines.\676\ For the purpose of these particular emission
guidelines, the EPA is proposing to supersede that timeline and is
proposing a State plan submission deadline that is 24 months from the
date of publication of the final emission guidelines. Crucially, these
proposed emission guidelines apply to a relatively large and complex
source category--existing fossil fuel-fired steam generating units and
existing fossil fuel-fired combustion turbines. Making the decisions
necessary for State plan development will require significant analysis,
consultation, and coordination between states, utilities, ISOs or RTOs,
and the owners or operators of individual affected EGUs. The power
sector is subject to many layers of regulatory and other requirements
under many authorities, and the decisions states make under these
emission guidelines will necessarily have to accommodate many
overlapping considerations and processes. States' plan development may
be additionally complicated by the fact that, unlike some other source
sectors to which the general CAA section 111 implementing regulations
apply, decision-making regarding control strategies and operations for
affected EGUs may not be solely within the purview of the owners or
operators of those sources; at the very least, affected EGUs often must
obtain permission before making significant or permanent changes. The
EPA does not believe it is reasonable to expect states and affected
EGUs to undertake the coordination and planning necessary to ensure
that their plans for implementing these emission guidelines are
consistent with the broader needs and trajectory of the power sector in
the space of 15 months.
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\676\ 87 FR 79182 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.23a(a)).
---------------------------------------------------------------------------
Additionally, prior to an owner or operator providing a suggestion
for a subcategory and standard of performance for an affected EGU to a
State, that owner or operator will likely need to analyze options for
complying with the applicable BSER for the subcategory. The EPA
anticipates that some owners or operators of affected coal-fired steam
generating units and affected combustion turbines will do feasibility
and FEED studies for CCS prior to committing to it as a control
strategy in a State plan. As discussed in section XII.B of this
preamble and in the GHG Mitigation Measures for Steam Generating Units
TSD, FEED studies take approximately 12 months to complete,\677\ after
which additional time is necessary to allow the conclusions from that
study to be integrated into a State's planning process for certain
affected EGUs. For other coal-fired steam generating units, there may
also be planning, design, and permitting exercises that will be
necessary for utilities to undertake prior to committing to a
subcategory based on natural gas co-firing. While any boiler
modifications required for affected EGUs that intend to co-fire natural
gas are relatively straightforward, the owners or operators of EGUs in
the medium-term subcategory may also be required to construct new
pipelines to enable co-firing of 40 percent natural gas. Pipeline
projects also require an initial planning and design process to
determine feasibility and, in some cases, could involve FERC approval.
Similar considerations apply for affected combustion turbine EGUs in
the hydrogen co-fired subcategory with regard to any turbine upgrades
that may be necessary to co-fire higher percentages of hydrogen and/or
to the construction of any pipeline laterals that are necessary to
supply the EGU with low-GHG hydrogen. Based on the approximately 12-
month period that states and the owners or operators of affected EGUs
will likely take to assess control strategies for these units, the EPA
does not believe it is reasonable to require State plans to be
submitted 15 months after promulgation of these emission guidelines.
---------------------------------------------------------------------------
\677\ GHG Mitigation Measures for Steam Generating Units TSD,
chapter 4.7.1.
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In the proposed subpart Ba timelines for State plan submission, the
EPA justified the generally applicable timelines in the context of
public health and welfare impacts by proposing timelines that are as
quick as is reasonably feasible for a generic set of emission
guidelines under CAA section 111(d). The EPA is proposing 24 months for
State plan timelines for these emission guidelines because 24 months is
the quickest time that the EPA believes to be reasonably feasible for a
State to submit a State plan based on the work and evaluation needed to
establish which compliance strategy (such as CCS or co-firing) will be
appropriate at a given EGU. Additionally, the EPA does not believe
providing a longer timeline for the submission of State plans in this
particular instance would ultimately impact how quickly the affected
EGUs can comply with their standards of performance. As explained in
section XII.B of this preamble and in the GHG Mitigation Measures for
Steam Generating Units TSD, the EPA anticipates that CCS projects will
take roughly 5 years to complete, assuming some steps are undertaken
concurrently. If the EPA were to promulgate these emission guidelines
in June 2024 and require State plan submissions in September 2025, the
EPA anticipates that the soonest compliance could commence is in the
third quarter of 2029. However, in this case, it is likely that at
least some owners/operators of affected EGUs would have to commit to
subcategories or control technologies before completing feasibility and
FEED studies, which could result in the need for plan revisions and
delayed emission reductions. In contrast, providing 24 months for State
plan submission would mean that although plans would be due June 2026,
owners or operators of affected EGUs would have had time to complete
their feasibility and FEED studies and some initial planning steps
before then. The EPA anticipates that owners or operators would need
approximately another 3.5 years to reach full compliance, meaning that
emission reductions would commence in the first quarter of 2030. The
EPA does not believe that a difference of three months will adversely
impact public health or welfare, especially when it is considered that
providing more time for State plan development in this instance is more
likely to ultimately result in certainty and timely emission
reductions. The EPA solicits comment on the 24-month State planning
period. The EPA specifically requests comments
[[Page 33403]]
from owners and operators of affected EGUs regarding the steps, and
amount of time needed for each step, that they would have to undertake
to determine the applicable subcategories and to plan and implement the
associated control strategies for each of their affected EGUs.
Additionally, the EPA requests comment on the 24-month planning period
from states, including on any unique characteristics of the fossil
fuel-fired EGU source category that they believe merit planning
timeframes longer than 15 months. Through outreach, many states have
expressed a need for longer planning periods and the EPA solicits
comment on whether this 24-month planning period accommodates that
need. The EPA also requests comment from potentially impacted
communities and other pertinent stakeholders on any considerations
related to providing a longer State plan submission timeframe under
these emission guidelines.
The EPA is additionally requesting comment on a potential
bifurcated approach to State plan submissions for affected steam
generating units and affected combustion turbine EGUs. In contrast to
the proposed compliance deadline for steam generating units, the EPA is
proposing compliance deadlines for combustion turbine EGUs in the CCS
subcategory and combustion turbine EGUs in the hydrogen co-fired
subcategory of January 1, 2035, and January 1, 2032 (with a second
phase commencing on January 1, 2038), respectively. Despite the longer
period between the anticipated promulgation of these emission
guidelines and the proposed compliance deadlines for affected
combustion turbine EGUs, the EPA is proposing that State plan
submissions containing standards of performance and other applicable
requirements for these units would be due 24 months after promulgation.
Based on many of the same considerations regarding power sector
planning and coordination discussed above, the EPA believes that
states; owners and operators of affected EGUs; RTOs, ISOs, or other
balancing authorities; and the public may benefit from considering the
control strategies for all affected EGUs under these emission
guidelines on the same timeline. Additionally, the EPA is cognizant of
the need to achieve emission reductions and thus the public health and
welfare benefits as soon as reasonably practicable.
However, the EPA also acknowledges that the compliance timeframes
for combustion turbine EGUs are likely to be longer than those for
steam generating units under these emission guidelines due to, inter
alia, the need to phase installation of CCS across the power sector and
the continued ramp-up in production and transmission capacity for low-
GHG hydrogen. The EPA is therefore requesting comment on an approach in
which states would submit two different plans on different timelines: a
State plan addressing affected steam-generating units due 24 months
after promulgation of these emission guidelines and a second State plan
addressing affected combustion turbine EGUs due 36 months after
promulgation of these emission guidelines. The EPA solicits comment on
this staggered approach and on whether 36 months, or a longer or
shorter period, could be an appropriate State plan submission deadline
for combustion turbine EGUs, and why. The EPA requests that commenters
explain if and how a longer State plan submission timeline for affected
combustion turbine EGUs would be consistent with achieving the emission
reductions under these emission guidelines as quickly as reasonably
practicable, as well as on the potential interactions between the State
plan submission time frame and the proposed compliance deadlines for
combustion turbine EGUs. The EPA also solicits comment from potentially
impacted communities and other pertinent stakeholders on any
considerations related to providing a longer State plan submission
timeframe for combustion turbine EGUs under these emission guidelines.
3. State Plan Revisions
The EPA expects that the State plan submission deadline proposed
under these emission guidelines would give states, utilities and
independent power producers, and stakeholders sufficient time to
determine in which subcategory each of the affected EGUs falls and to
formulate and submit a State plan accordingly. However, the EPA also
acknowledges that, despite states' best efforts to accurately reflect
the plans of owners or operators with regard to affected EGUs at the
time of State plan submission, such plans may subsequently change. In
general, states have the authority and discretion to submit revised
State plans to the EPA for approval.\678\ State plan revisions are
generally subject to the same requirements as initial State plan
submissions under these emission guidelines and the subpart Ba
implementation regulations, including meaningful engagement, and the
EPA reviews State plan revisions against the applicable requirements of
these emission guidelines in the same manner in which it reviews
initial State plan submissions pursuant to 40 CFR 60.27a.
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\678\ 40 CFR 60.23a(a)(2), 60.28a.
---------------------------------------------------------------------------
Approved State plan requirements remain federally enforceable
unless and until the EPA approves a plan revision that supersedes such
requirements. States and affected EGUs should plan accordingly to avoid
noncompliance.
The EPA is proposing a State plan submission date that is 24 months
after the publication of final emission guidelines and is proposing
that the first compliance date for a portion of affected EGUs would be
on January 1, 2030. A State may choose to submit a plan revision prior
to compliance with its existing State plan requirements; however, the
EPA reiterates that any already approved federally enforceable
requirements, including milestones, increments of progress, and
standards of performance, will remain in place unless and until the EPA
approves the plan revision. The EPA requests comment on whether it
would be helpful to states to impose a cut-off date for the submission
of plan revisions ahead of the January 1, 2030, compliance date for
coal-fired steam generating affected EGUs or ahead of the separate
compliance dates for achieving the CCS-based or hydrogen co-firing-
based standards for existing combustion turbines. Such a cut-off date,
e.g., January 1, 2028, would in effect establish a temporary moratorium
on plan submissions in order to provide a sufficient window for the EPA
to act on them and effectuate any changes to existing State plan
requirements ahead of the final compliance date. State plan revisions
would again be permitted after the final compliance date. As an
alternative to a cut-off date for State plan revisions ahead of the
compliance date, the EPA requests comment on the dual-path standards of
performance approach discussed in section XII.F.4 of this preamble.
Under the proposed emission guidelines for existing coal-fired
steam generating units, states would place their affected coal-fired
steam generating units into one of four subcategories based on the time
horizons over which those EGUs elect to operate. These subcategories
are static--affected EGUs would not be able move between subcategories
absent a plan revision.\679\ However, the EPA
[[Page 33404]]
acknowledges that there may be instances in which a change in
subcategory will be necessary. For affected coal-fired steam generating
EGUs that are switching into the imminent-term, near-term, or medium-
term subcategories, the EPA proposes to require that the State include
in its State plan revision documentation of the affected EGU's
submission to the relevant RTO or balancing authority of the new date
it intends to permanently cease operations, any responses from and
studies conducted by the RTO or balancing authority addressing
reliability and any other considerations related to ceasing operations,
any filings with the SEC or notices to investors in which the plans for
the EGU are mentioned, any integrated resource plan, and any other
relevant information in support of the new date. This documentation
must be published on the Carbon Pollution Standards for EGUs website.
These proposed requirements are modeled on the proposed milestones for
sources electing to commit to permanently cease operations and are
intended to help states, stakeholders, and the EPA ensure that the
affected EGU's change in circumstances is sufficiently certain to
warrant a State plan revision. Because of the long lead times for
planning and implementation of control systems for affected EGUs,
revising a State plan after the submission deadline has the potential
to significantly disrupt states' and affected EGUs' compliance
strategies. The EPA therefore believes it is reasonable to require
affected EGUs and states to provide evidence that a source's
circumstances have in fact changed, in order for the EPA to approve a
plan revision. Affected EGUs switching into the imminent-term, near-
term, or medium-term subcategories would also be required to comply
with the proposed enforceable milestones applicable to those
subcategories.
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\679\ If the EPA finalizes an option for States to include dual
paths for an affected coal-fired EGU or EGUs in their state plans,
those affected EGUs would be able to choose between two
subcategories prior to the final compliance date without the state's
needing to revise its plan.
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Some changes between subcategories of affected coal-fired steam
generating EGUs, including from the long-term into the medium-term
subcategory and from the imminent-term or near-term into the medium-
term or long-term subcategory, would entail new standards of
performance reflecting a different add-on control strategy than
initially anticipated. In order to avoid undermining the stringency of
these proposed emission guidelines, the EPA expects affected EGUs
changing subcategories before the January 1, 2030, compliance deadline
to make every reasonable effort to meet that compliance deadline.
However, the EPA acknowledges that, in some circumstances, it may not
be possible to complete the necessary planning and construction within
a shortened timeframe. Additionally, unforeseen circumstances could
require some affected EGUs to change subcategories after the final
compliance deadline has passed (e.g., to ensure reliability).
In these circumstances, the EPA is proposing that states may use
the RULOF mechanism described in section XII.D.2 of this preamble to
adjust the compliance deadlines for affected EGUs that cannot comply
with their applicable standards of performance by the January 1, 2030,
deadline. The EPA expects that states may be able to demonstrate that
the change in subcategory constitutes an ``other circumstance[ ]
specific to the facility . . . that [is] fundamentally different from
the information considered in the determination of the best system of
emission reduction in the emission guidelines.'' \680\ In order to
invoke RULOF to change a compliance deadline for an affected EGU that
has switched subcategories, the EPA proposes that the State must first
demonstrate that the affected EGU cannot meet the applicable
presumptive standard of performance by the compliance deadline in these
emission guidelines. As part of this demonstration the State would be
required to provide evidence supporting the affected EGU's need to
switch subcategories. The State would also be required to demonstrate
that the need to invoke RULOF and to provide a different compliance
deadline or less stringent standard of performance was not caused by
self-created impossibility.
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\680\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions to RULOF provisions at 40 CFR
60.24a(e)(3)).
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Like subcategorization for affected coal-fired steam-generating
units, states would place their affected combustion turbine EGUs into
one of the two subcategories in their State plans, along with the
corresponding standard of performance. These subcategory designations
are static--affected EGUs would not be able to move between
subcategories absent a plan revision. The EPA expects that situations
necessitating a change in subcategory for combustion turbine EGUs will
be far less likely than for coal-fired steam-generating units. However,
should the need arise for an affected combustion turbine EGU to change
subcategories in a State plan, the same considerations discussed above
for coal-fired steam generating units would apply. If a combustion
turbine EGU changes subcategories in a manner that entails a new
standard of performance that is based on a different control technology
than initially anticipated, the EPA expects the owner or operator of
that EGU to make every reasonable effort to meet the original
compliance deadline for the newly applicable subcategory. For
situations in which this is impossible, the EPA is proposing that
states could use the RULOF mechanism as described above to provide a
revised compliance deadline. As part of its RULOF demonstration, a
State would be required to provide evidence supporting the affected
combustion turbine's need to switch subcategories, as well as a
demonstration that the need to invoke RULOF and to provide a different
compliance deadline was not caused by the owner or operator's self-
created impossibility.
Documentation related to these demonstrations must also be posted
to the Carbon Pollution Standards for EGUs website. For example, it
would not be reasonable for a State that has been notified that an RTO
requires an affected EGU to switch subcategories to wait to revise its
SIP until the remaining useful life of that EGU is so short as to
preclude otherwise reasonable systems of emission reduction. To this
end, the EPA is proposing to consider when a State knew or should have
known that an affected EGU would need to switch subcategories when
evaluating the approvability of State plans that include RULOF
demonstrations. The EPA is additionally proposing to consider whether
an affected EGU has been complying with its applicable milestones and
increments of progress when evaluating RULOF demonstrations. The EPA
encourages states to consult with their EPA Regional Offices as early
as possible if they believe it may become necessary for an affected EGU
to switch subcategories. The EPA requests comment on whether to set a
deadline for states to provide plan revisions within a certain
timeframe of knowing that an affected EGU needs to switch subcategories
and on what timeframe would be appropriate.
The EPA is proposing that states invoking RULOF because an affected
EGU cannot comply with its newly applicable presumptive standard of
performance by the final compliance deadline first evaluate whether the
affected EGU is able to comply with that standard by a different,
later-in-time deadline. If a State can demonstrate that an affected EGU
cannot reasonably comply with the applicable presumptive standard of
performance under any reasonable compliance deadline, it may
[[Page 33405]]
then evaluate different systems of emission reduction according to the
proposed RULOF mechanism described in section XII.D.2 of this preamble.
4. Dual-Path Standards of Performance for Affected EGUs
Under the structure of these emission guidelines as proposed,
states would assign affected coal-fired steam generating units to
subcategories in their State plans and an affected EGU would not be
able to change its applicable subcategory without a State plan
revision. This is because, due to the nature of the BSERs for coal-
fired steam generating units, an affected EGU that switches between
subcategories may not be able to meet compliance obligations for a new
and different subcategory without considerable lag time and thus the
switch would result in noncompliance and a loss of emission reductions.
Similarly, states would be required to assign their affected combustion
turbine EGUs to either the CCS or hydrogen co-fired subcategory in
their State plans, at which point a unit could not switch between
subcategories without a plan revision. Therefore, as a general matter,
states must assign each affected EGU to a subcategory and have in place
all the legal instruments necessary to implement the requirements for
that subcategory by the time of State plan submission.
However, the EPA acknowledges that there may be circumstances in
which the owner or operator of a coal-fired steam generating unit has
not yet finalized its future operating plans and wishes to retain the
option to choose between two different subcategories ahead of the
proposed January 1, 2030, compliance date. Similarly, the owner or
operator of a combustion turbine EGU may wish to retain the ability to
choose between the CCS and hydrogen co-fired subcategories,
particularly because the relatively long period between State plan
submission and compliance means that a unit's circumstances could
change materially in that time. The EPA is therefore soliciting comment
on the following dual-path approach that may result in an additional
flexibility for owners or operators of affected coal-fired steam
generating units and affected combustion turbine EGUs that want
additional time to commit to a particular subcategory without the need
for a State plan revision.
The EPA is soliciting comment on an approach that allows coal-fired
steam generating units and combustion turbine EGUs to have two
different standards of performance submitted to the EPA in a State plan
based on potential inclusion in two different subcategories. A State
plan would be required to have all the associated components for each
subcategory. For example, for an affected coal-fired steam generating
unit that wants the option to be part of either the long-term or
imminent-term subcategory, the State plan would include an enforceable
standard of performance based on implementation of CCS and associated
requirements, including increments of progress; as well as an
enforceable requirement to permanently cease operations before January
1, 2033, and a standard of performance based on routine operation and
maintenance. The affected EGU would be required to meet all compliance
obligations for both subcategories, including increments of progress
and/or milestones for commitments to cease operations, leading up to
the compliance date of January 1, 2030. The State and the owner or
operator of the affected EGU would be required to choose a subcategory
for the affected EGU ahead of that date. Specifically, the EPA is
proposing that the State must notify the EPA of its final applicable
subcategory and standard of performance at least 6 months prior to the
compliance date. For affected coal-fired steam generating units, the
State would be required to notify the EPA of the applicable standard by
July 1, 2029. For affected combustion turbine EGUs, the State would be
required to notify the EPA of the applicable standard by the earliest
compliance date, or July 1, 2031. If the State has not notified the EPA
by the required date (July 1, 2029, or July 1, 2031) of the final
applicable subcategory for the affected EGU, the EPA is proposing that
a coal-fired steam generating unit would automatically be subject to
the requirements of the subcategory that corresponds to the longer
remaining life of the EGU, while a combustion turbine EGU would
automatically be subject to the requirements of the CCS subcategory.
Additionally, if the affected EGU misses an enforceable increment of
progress, milestone (as described in section XII.D.3 of this preamble),
or any other requirement for one of the two subcategories, the EGU will
automatically be subject to the requirements of the other subcategory.
If the EGU misses submissions for increments of progress and/or
milestones for both subcategories, the EGU will automatically be
subject to the requirements of the subcategory that corresponds to the
longer remaining life of the EGU (for coal-fired steam generating
units) or the CCS subcategory (for combustion turbine EGUs) and will
additionally be found to be out of compliance for the increment of
progress or milestone that it has missed.
The EPA is soliciting comment on this approach to provide
flexibility to states and affected coal-fired steam generating units
and affected combustion turbine EGUs. In some instances, owners or
operators of affected EGUs may wish to have additional time to evaluate
future operating plans; this proposed dual-path approach should provide
owners or operators additional time to commit to a subcategory.
However, with this additional time comes additional burden on owners
and operators to demonstrate compliance with each of the requirements
associated with two different subcategories that would be included in a
State plan. As an example, a coal-fired steam generating unit intends
to cease operations between 2038 and 2041. The State plan is submitted
and contains two different enforceable dates to permanently cease
operations, e.g., December 31, 2038, with a standard of performance
based on natural gas co-firing and December 31, 2041, with a standard
of performance based on CCS, as well as an enforceable commitment by
the State to choose one path or the other by July 1, 2029. The affected
EGU would then be required to comply with the increments of progress
for both the long-term (CCS) and medium-term (co-firing) subcategories,
until the point at which the State decides which of the two paths in
its plan it will require for the unit.
The EPA solicits comment on whether this proposed dual-path
flexibility would have utility and on whether it could be implemented
in a manner that ensures that states and affected coal-fired steam
generating units and affected combustion turbine EGUs would be able to
comply with applicable requirements in a timely manner. Additionally,
the EPA solicits comment on whether notification deadlines of July 1,
2029, for coal-fired steam generating units, and July 1, 2031, for
combustion turbine EGUs are the appropriate dates for a final decision
between two potential standards of performance and why.
5. EPA Action on State Plans
Pursuant to proposed subpart Ba, the EPA would use a 60-day
timeline for the Administrator's determination of completeness of a
State plan submission \681\ and a 12-month timeline
[[Page 33406]]
for action on State plans.\682\ The EPA is not proposing to supersede
these timelines; therefore, review of and action on State plan
submissions will be governed by the requirements of revised subpart Ba.
First, the EPA would review the components of the State plan to
determine whether the plan meets the completeness criteria of 40 CFR
60.27a(g). The EPA must determine whether a State plan submission has
met the completeness criteria within 60 days of its receipt of that
submission. If the EPA has failed to make a completeness determination
for a State plan submission within 60 days of receipt, the submission
shall be deemed, by operation of law, complete as of that date.
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\681\ The timeframes and requirements for state plan submissions
described in this section also apply to state plan revisions. See
generally 40 CFR 60.27a.
\682\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a).
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Proposed subpart Ba would require the EPA to take action on a State
plan submission within 12 months of that submission's being deemed
complete. The EPA will review the components of State plan submissions
against the applicable requirements of subpart Ba and these emission
guidelines, consistent with the underlying requirement that State plans
must be ``satisfactory'' per CAA section 111(d). If the EPA finalizes
the revisions to subpart Ba as proposed, the Administrator would have
the option to fully approve, fully disapprove, partially approve,
partially disapprove, and conditionally approve a State plan
submission.\683\ Any components of a State plan submission that the EPA
approves become federally enforceable.
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\683\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(b)).
---------------------------------------------------------------------------
The EPA requests comment on the use of the timeframes provided in
subpart Ba, as the EPA has proposed to revise it, for EPA actions on
State plan submissions and for the promulgation of Federal plans for
these particular emission guidelines.
6. Federal Plan Applicability and Promulgation Timing
The provisions of subpart Ba, including any revisions the EPA
finalizes pursuant to its December 2022 proposal, will apply to the
EPA's promulgation of any Federal plans under these emission
guidelines. The EPA's obligation to promulgate a Federal plan is
triggered in three situations: where a State does not submit a plan by
the plan submission deadline; where the EPA determines that a State
plan submission does not meet the completeness criteria and the time
period for State plan submission has elapsed; and where the EPA fully
or partially disapproves a State's plan.\684\ Where a State has failed
to submit a plan by the submission deadline, the proposed revisions to
subpart Ba would give the EPA 12 months from the State plan submission
due date to promulgate a Federal plan; otherwise, the 12-month period
starts from the date the State plan submission is deemed incomplete,
whether in whole or in part, or from the date of the EPA's disapproval.
The EPA may approve a State plan submission that corrects the relevant
deficiency within the 12-month period, before it promulgates a Federal
plan, in which case its obligation to promulgate a Federal plan is
relieved.\685\ As provided by 40 CFR 60.27a(e), a Federal plan will
prescribe standards of performance for affected EGUs of the same
stringency as required by these emission guidelines and will require
compliance with such standards as expeditiously as practicable but no
later than the final compliance date under these guidelines. However,
upon application by the owner or operator of an affected EGU, the EPA
in its discretion may provide for a less stringent standard of
performance or longer compliance schedule than provided by these
emission guidelines, in which case the EPA would follow the same
process and criteria in the regulations that apply to states' provision
of RULOF standards.\686\ Under the proposed revisions to subpart Ba,
the EPA would also be required to conduct meaningful engagement with
pertinent stakeholders prior to promulgating a Federal plan.\687\
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\684\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(c)).
\685\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(d)).
\686\ 40 CFR 60.27a(e)(2).
\687\ 87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-
2021-0527-0002 (proposed revisions at 40 CFR 60.27a(f)).
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As described in section XII.F.2 of this preamble, the EPA is
proposing to allow states 24 months for a State plan submission after
the promulgation of the final emission guidelines. Therefore, the EPA
would be obligated to promulgate a Federal plan within 36 months of the
final emission guidelines for all states that fail to submit plans.
Note that this will be the earliest obligation for the EPA to
promulgate Federal plans for states and that different triggers (e.g.,
a disapproved State plan) will result in later obligations to
promulgate Federal plans contingent on when the obligation is
triggered.
Under the Tribal Authority Rule (TAR) adopted by the EPA, Tribes
may seek authority to implement a plan under CAA section 111(d) in a
manner similar to that of a State. See 40 CFR part 49, subpart A.
Tribes may, but are not required to, seek approval for treatment in a
manner similar to that of a State for purposes of developing a Tribal
Implementation Plan (TIP) implementing the emission guidelines. If a
Tribe obtains approval and submits a TIP, the EPA will generally use
similar criteria and follow similar procedures as those described for
State plans when evaluating the TIP submission and will approve the TIP
if appropriate. The EPA is committed to working with eligible Tribes to
help them seek authorization and develop plans if they choose. Tribes
that choose to develop plans will generally have the same flexibilities
available to states in this process. If a Tribe does not seek and
obtain the authority from the EPA to establish a TIP, the EPA has the
authority to establish a Federal CAA section 111(d) plan for areas of
Indian country where designated facilities are located. A Federal plan
would apply to all designated facilities located in the areas of Indian
country covered by the Federal plan unless and until the EPA approves
an applicable TIP applicable to those facilities.
XIII. Implications for Other EPA Programs
A. Implications for New Source Review (NSR) Program
CAA section 110(a)(2)(C) requires that a SIP include a New Source
Review (NSR) program that provides for the ``regulation of the
modification and construction of any stationary source . . . as
necessary to assure that [the NAAQS] are achieved.'' Within the NSR
program, the ``major NSR'' preconstruction permitting program applies
to new construction and modifications of existing sources that emit
``regulated NSR pollutants'' at or above certain established
thresholds. New sources and modifications that emit regulated NSR
pollutants under the established thresholds may be subject to ``minor
NSR'' program requirements or may be excluded from NSR requirements
altogether. The NSR program for a State or local permitting authority
with an approved SIP is implemented through 40 CFR 51.160 to 51.166,
while the NSR program applying in areas for which the EPA or a
delegated State, local or Tribal agency is the permitting authority is
implemented through 40 CFR part 49 and 40 CFR 52.21.
NSR applicability is pollutant-specific and, for the major NSR
program, the
[[Page 33407]]
permitting requirements that apply to a source depend on the air
quality designation at the location of the source for each of its
emitted pollutants at the time the permit is issued. Major NSR permits
for sources located in an area that is designated as attainment or
unclassifiable for the NAAQS for its pollutants are referred to as
Prevention of Significant Deterioration (PSD) permits. In addition, PSD
permits can include requirements for specific pollutants for which
there are no NAAQS.\688\ Sources subject to PSD must, among other
requirements, comply with emission limitations that reflect the Best
Available Control Technology (BACT) for ``each pollutant subject to
regulation'' as specified by CAA sections 165(a)(4) and 169(3). Major
NSR permits for sources located in nonattainment areas and that emit at
or above the specified major NSR threshold for the pollutant for which
the area is designated as nonattainment are referred to as
Nonattainment NSR (NNSR) permits. Sources subject to NNSR must, among
other requirements, meet the Lowest Achievable Emissions Rate (LAER)
pursuant to CAA sections 171(3) and 173(a)(2) for any pollutant subject
to NNSR. For sources subject to minor NSR, the CAA and EPA rules do not
set forth prescriptive control technology requirements for minor NSR
programs so these permits can be less stringent than major NSR permits.
Due to the pollutant-specific applicability of the NSR program, it is
conceivable that a source seeking to newly construct or modify may have
to obtain multiple types of NSR permits (i.e., NNSR, PSD, or minor NSR)
depending on the air quality designation at the location of the source
and the types and amounts of pollutants it emits.
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\688\ For the PSD program, ``regulated NSR pollutant'' includes
any pollutant for which a NAAQS has been promulgated (``criteria
pollutants'') and any other air pollutant that meets the
requirements of 40 CFR 52.21(b)(50). Some of these non-criteria
pollutants include fluorides, sulfuric acid mist, hydrogen sulfide,
total reduced sulfur, and reduced sulfur compounds.
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A new stationary source is subject to major NSR requirements if its
potential to emit (PTE) a regulated NSR pollutant exceeds statutory
emission thresholds, upon which the NSR regulations define it as a
``major stationary source.'' \689\ For PSD permitting, once a new
stationary source is determined to be subject to major NSR for one
regulated NSR pollutant (with the exception of GHG),\690\ the source
can be subject to major NSR requirements for any other regulated NSR
pollutant if the PTE of that pollutant is at least the ``significant''
emissions rate (``SER''), as defined in 40 CFR 52.21(b)(23). In the
case of GHG,\691\ the EPA has not promulgated a GHG SER but applies a
BACT applicability threshold of 75,000 TPY CO2e.\692\
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\689\ For PSD, the statute uses the term ``major emitting
facility'' and defines it as a stationary source that emits, or has
a PTE, at least 100 tons per year (TPY) if the source is in one of
28 listed source categories, or at least 250 TPY if the source is
not a listed source category. CAA section 169(1). For NNSR, the
emissions threshold for a major stationary source is 100 TPY, and
lower thresholds apply for certain pollutants based on the severity
of the nonattainment classification.
\690\ As a result of the Supreme Court's decision in UARG v.
EPA, the D.C. Circuit issued an amended judgment in Coalition for
Responsible Regulation, Inc. v. EPA, Nos. 09-1322, 10-073, 10-1092
and 10-1167 (D.C. Cir. April 10, 2015), which, among other things,
vacated the PSD and title V regulations under review in that case to
the extent that they require a stationary source to obtain a PSD or
title V permit solely because the construction of the source, or a
modification at the source, emits or has the potential to emit GHGs
at or above the applicable major NSR thresholds.
\691\ Consistent with the 2009 Endangerment Findings, the PSD
program treats GHG as a single air pollutant defined as the
aggregate group of six gases: CO2, N2O,
CH4, HFCs, PFCs, and SF6. 40 CFR
52.21(b)(49)(i).
\692\ See Janet G. McCabe and Cynthia Giles, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Air Regulatory Group v. Environmental Protection Agency
(July 24, 2014), https://www.epa.gov/sites/default/files/2015-12/documents/20140724memo.pdf.
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For an existing source, it can be subject to major NSR requirements
if it is a major stationary source and its emissions increase resulting
from a modification (i.e., physical change or change in the method of
operation) are equal to or greater than the SER for a regulated NSR
pollutant, upon which the NSR regulations define it as a ``major
modification.'' \693\ As with new sources, the one exception to this
applicability approach is GHG, which currently applies a BACT
applicability threshold in lieu of a SER and can only be subject to
major NSR if another pollutant is also subject to major NSR for the
modification. Generally, an existing major stationary source triggering
major NSR requirements for a regulated NSR pollutant would have both a
significant emissions increase from the modification and a significant
net emissions increase at the stationary source, and the calculation of
the significant emissions increase differs depending on whether the
modification is to an existing emissions unit, or the addition of a new
emissions unit, or if it involves multiple types of emission
units.\694\ An existing major stationary source would trigger PSD
permitting requirements for GHGs if it undertakes a modification and:
(1) The modification is otherwise subject to PSD for a pollutant other
than GHG; and (2) the modification results in a GHG emissions increase
and a GHG net emissions increase that is equal to or greater than
75,000 TPY CO2e and greater than zero on a mass basis.
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\693\ Per 40 CFR 52.21(b)(1)(i)(c), a minor source that
undergoes a physical change that would itself be considered major,
is subject to major source requirements.
\694\ 40 CFR 52.21(a)(2)(iv); 40 CFR 52.21(b)(2)(i); 40 CFR
52.21(b)(3).
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Since GHG is not a criteria pollutant, it is regulated under the
CAA's PSD program, but not under the NNSR or minor NSR programs. For
new sources and modifications that are subject to PSD, the permitting
authority must establish emission limitations based on BACT for each
pollutant that is subject to PSD at the major stationary source or at
each emissions unit involved in the major modification. BACT is
assessed on a case-by-case basis, and the permitting authority, in its
analysis of BACT for each pollutant, evaluates the emission reductions
that each available emissions-reducing technology or technique would
achieve, as well as the energy, environmental, economic, and other
costs associated with each technology or technique. The CAA also
specifies that BACT cannot be less stringent than any applicable
standard of performance under the NSPS.\695\ Permitting authorities may
determine BACT by applying the EPA's five-step ``top down''
approach.\696\ The ultimate determination of BACT is made by the
permitting authority after a public notice and comment period of at
least 30-days on the draft permit and supporting information.\697\
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\695\ 42 U.S.C. 7479(3) (``In no event shall application of
`best available control technology' result in emissions of any
pollutants which will exceed the emissions allowed by any applicable
standard established pursuant to [CAA Section 111 or 112].'').
\696\ U.S. EPA, NSR Workshop Manual (Draft October 1990),
https://www.epa.gov/sites/default/files/2015-07/documents/1990wman.pdf; U.S. EPA, PSD and Title V Permitting Guidance for
Greenhouse Gases (March 2011), https://www.epa.gov/sites/default/files/2015-07/documents/ghgguid.pdf.
\697\ 40 CFR 124.10.
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1. NSR Implications of a CAA Section 111(b) Standard
As noted above, BACT cannot be set at a level that is less
stringent than the standard of performance established by an applicable
NSPS, and the EPA refers to this minimum control level as the ``BACT
floor.'' While a proposed NSPS does not establish the BACT floor for
affected facilities seeking a PSD permit, once an NSPS is promulgated,
it then serves as the BACT floor for any new major stationary source or
major modification that meets the
[[Page 33408]]
applicability of the NSPS and commences construction after the date of
the proposed NSPS in the Federal Register.\698\ In the context of
combustion turbines that would be subject to this NSPS at 40 CFR part
60, subpart TTTTa, for any new major stationary source or major
modification that commences construction or reconstruction of a
stationary combustion turbine EGU after the date of publication of this
proposed NSPS, the PSD permit should reflect a BACT determination that
is at least as stringent as the promulgated NSPS for each of the
source's affected EGUs.
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\698\ U.S. EPA, PSD and Title V Permitting Guidance for
Greenhouse Gases (March 2011), p. 25.
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However, the fact that a minimum control requirement is established
by an applicable NSPS does not mean that a permitting authority cannot
select a more stringent control level for the PSD permit or consider
technologies for BACT beyond those that were considered in developing
the NSPS. As explained above, BACT is a case-by-case review that
considers a number of factors, and the review should reflect advances
in control technology, reductions in the costs or other impacts of
using particular control strategies, or other relevant information that
may have become available after development of an applicable NSPS.
2. NSR Implications of a CAA Section 111(d) Standard
With respect to the proposed action for emission guidelines, should
it be promulgated, states will be called upon to develop a plan that
establish standards of performance for each affected EGU that meets the
requirements in the emission guidelines. In doing so, a State agency
may develop a plan that results in an affected source undertaking a
physical or operational change. Under the NSR program, undertaking a
physical or operational change may require the source to obtain a
preconstruction permit for the proposed change, with the type of NSR
permit (i.e., NNSR, PSD, or minor NSR) depending on the amount of the
emissions increase resulting from the change and the air quality
designation at the location of the source for its emitted pollutants.
More specifically, any time an existing source adds equipment or
otherwise makes physical or operational changes to its facility,
regardless of whether it has done so to comply with a national or State
level requirement, the source may be required to obtain a NSR permit
prior to making the changes unless the permitting authority determines
that the action is exempt from permitting.\699\
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\699\ The EPA sought to exempt environmentally beneficially
pollution control projects from NSR requirements in a 2002 rule that
codified longstanding EPA policy, but this rule was struck down in
court. New York v. EPA, 413 F.3d 3, 40-42 (D.C. Cir. 2005) (New York
I).
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Thus, there may be circumstances in which an affected source that
is implementing a BSER requirement from a State plan is required to
obtain a major NSR permit for one or more of its pollutants. One
scenario in which this may occur is if an affected source experiences
greater unit availability and reliability as a result of implementing
its BSER requirement (e.g., an efficiency based BSER) that, in turn,
lowers the operating costs of its EGU. Since EGUs that operate at lower
costs are generally preferred in the dispatch by the system operator
over units with higher operational costs, the BSER implementation could
result in improving the source's relative economics that would, in
turn, increase its utilization of its EGU(s). With an increase in
utilization resulting from the source implementing the BSER, the annual
emissions from the EGU could increase, and if the emissions increase
equals or exceeds the relevant SER for one or more of its pollutants,
the source may be required to obtain a major NSR permit for the
modification.
However, while it may be possible for an affected source to trigger
major NSR requirements from actions it takes to implement a BSER
requirement, we expect this situation to not occur often. As previously
discussed in this preamble, states will have considerable flexibility
in adopting varied compliance measures as they develop their plans to
meet the standards of performance of the emission guidelines. One of
these flexibilities is the ability for states to establish the
standards of performance in their plans in such a way so that their
affected sources, in complying with those standards, in fact would not
have emission increases that trigger major NSR requirements. To achieve
this, the State would need to conduct an analysis consistent with the
NSR regulatory requirements that supports its determination that as
long as affected sources comply with the standards of performance,
their emissions would not increase in a way that trigger major NSR
requirements. For example, a State could, as part of its State plan,
develop enforceable conditions for a source expected to trigger major
NSR that would effectively limit the unit's ability to increase its
emissions in amounts that would trigger major NSR (effectively
establishing a synthetic minor limitation).\700\
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\700\ Certain stationary sources that emit or have the potential
to emit a pollutant at a level that is equal to or greater than
specified thresholds are subject to major source requirements. See,
e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A synthetic
minor limitation is a legally and practicably enforceable
restriction that has the effect of limiting emissions below the
relevant level and that a source voluntarily obtains to avoid major
stationary source requirements, such as the PSD or title V
permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4),
70.2 (definition of ``potential to emit'').
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B. Implications for Title V Program
Title V is implemented through 40 CFR parts 70 and 71. Part 70
defines the minimum requirements for State, local and Tribal (state)
agencies to develop, implement and enforce a title V operating permit
program; these programs are developed by the State and the State
submits a program to the EPA for a review of consistency with part 70.
There are about 117 approved part 70 programs in effect, with about
14,000 part 70 permits currently in effect. (See Appendix A of 40 CFR
part 70 for the approval status of each State program.) Part 71 is a
Federal permit program run by the EPA, primarily where there is no part
70 program in effect (e.g., in Indian country, the Federal Outer
Continental Shelf, and for offshore Liquified Natural Gas
terminals).\701\ There are about 100 part 71 permits currently in
effect (most are in Indian country).
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\701\ In some circumstances, the EPA may delegate authority for
part 71 permitting to another permitting agency, such as a Tribal
agency or a state. The EPA has entered into delegation agreements
for certain part 71 permitting activities with at least one Tribal
agency. There are currently no States that do not have an approved
part 70 program; thus, there is no need for the EPA to delegate part
71 delegated authority to any state at this time.
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The title V regulations require each permit to include emission
limitations and standards, including operational requirements and
limitations that assure compliance with all applicable requirements.
Requirements resulting from these rules that are imposed on EGUs or
other potentially affected entities that have title V operating permits
are applicable requirements under the title V regulations and would
need to be incorporated into the source's title V permit in accordance
with the schedule established in the title V regulations. For example,
if the permit has a remaining life of three years or more, a permit
reopening to incorporate the newly applicable requirement shall be
completed no later than 18 months after promulgation of the applicable
requirement. If the permit has a remaining life of less than three
[[Page 33409]]
years, the newly applicable requirement must be incorporated at permit
renewal.
If a State needs to include provisions related to the State plan in
a source's title V permit before submitting the plan to the EPA, these
limits should be labeled as ``state-only'' or ``not federally
enforceable'' until the EPA has approved the State plan. The EPA
solicits comment on whether, and under what circumstances, states might
use this mechanism.
XIV. Impacts of Proposed Actions
In accordance with E.O. 12866 and 13563, the guidelines of OMB
Circular A-4 and the EPA's Guidelines for Preparing Economic Analyses,
the EPA prepared an RIA for these proposed actions. This RIA presents
the expected economic consequences of the EPA's proposed rules,
including analysis of the benefits and costs associated with the
projected emission reductions for three illustrative scenarios. The
first scenario represents the proposed CAA 111(b) combustion turbine
phase 1 and phase 2 standards and 111(d) steam generating turbine
proposals in combination. The second and third scenarios represent
different stringencies of the combined policies. All three illustrative
scenarios are compared against a single baseline. For detailed
descriptions of the three illustrative scenarios and the baseline, see
section 1 of the RIA, which is titled ``Regulatory Impact Analysis for
the Proposed New Source Performance Standards for Greenhouse Gas
Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired
Electric Generating Units; Emission Guidelines for Greenhouse Gas
Emissions from Existing Fossil Fuel-Fired Electric Generating Units;
and Repeal of the Affordable Clean Energy Rule.''
The three scenarios detailed in the RIA, including the proposal
scenario, are illustrative in nature and do not represent the plans
that states may ultimately pursue. As there are considerable
flexibilities afforded to states in developing their State plans, the
EPA does not have sufficient information to assess specific compliance
measures on a unit-by-unit basis. Nonetheless, the EPA believes that
such illustrative analysis can provide important insights.
In the RIA, the EPA evaluates the potential impacts of the three
illustrative scenarios using the present value (PV) of costs, benefits,
and net benefits, calculated for the years 2024 to 2042 from the
perspective of 2024, using both a three percent and seven percent
discount rate. In addition, the EPA presents the assessment of costs,
benefits, and net benefits for specific snapshot years, consistent with
the Agency's historic practice. These specific snapshot years are 2028,
2030, 2035, and 2040. In addition to the core benefit-cost analysis,
the RIA also includes analyses of anticipated economic and energy
impacts, environmental justice impacts, and employment impacts.
The analysis presented in this preamble section summarizes key
results of the illustrative policy scenario. For detailed benefit-cost
results for the three illustrative scenarios and results of the variety
of impact analysis just mentioned, please see the RIA, which is
available in the docket for this action. The EPA also seeks comment on
all aspects of the analysis, including modeling assumptions.
A. Air Quality Impacts
For the analysis of the proposed standards for new combustion
turbines and for existing steam generating EGUs, which do not include
the impact of the proposed standards for existing combustion turbines
and the third phase of the proposed standards for new combustion
turbines, total cumulative power sector CO2 emissions
between 2028 and 2042 are projected to be 617 million metric tons lower
under the illustrative proposal scenario than under the baseline. Table
7 shows projected aggregate annual electricity sector emission changes
for the illustrative proposal scenario, relative to the baseline.
Table 7--Projected Electricity Sector Emission Impacts for the Illustrative Proposal Scenario, Relative to the
Baseline
----------------------------------------------------------------------------------------------------------------
Ozone Season Direct PM2.5
CO2 (million Annual NOX NOX (thousand Annual SO2 (thousand
metric tons) (thousand short tons) (thousand short tons)
short tons) short tons)
----------------------------------------------------------------------------------------------------------------
2028............................ -10 -7 -3 -12 -1
2030............................ -89 -64 -22 -107 -6
2035............................ -37 -21 -7 -41 -1
2040............................ -24 -13 -4 -30 -1
----------------------------------------------------------------------------------------------------------------
Note: Ozone season is the May through September period in this analysis.
The emissions changes in these tables do not account for changes in
HAP that are likely to occur as a result of this action.
For the analysis of the proposed standards for existing combustion
turbines and for the third phase of the proposed standards for new
natural gas-fired EGUs, total cumulative power sector CO2
emissions between 2028 and 2042 are estimated to be between 215-409
million metric tons lower than under the illustrative proposal
scenario.
Table 8--Estimated Electricity Sector Emission Impacts From Existing Gas
Standard and Third Phase of Low-GHG Hydrogen Co-Firing Standard for New
Base Load Combustion Turbines
------------------------------------------------------------------------
CO2 (million metric
tons)
---------------------
Low High
------------------------------------------------------------------------
2028.............................................. 0 0
2030.............................................. 0 0
2035.............................................. -20 -37
2040.............................................. -20 -39
------------------------------------------------------------------------
B. Compliance Cost Impacts
The power industry's compliance costs are represented in this
analysis as the change in electric power generation costs between the
baseline and illustrative scenarios, including the cost of monitoring,
reporting, and recordkeeping. In simple terms, these costs are an
estimate of the increased power industry expenditures required to
comply with the proposed actions.
The compliance assumptions--and, therefore, the projected
compliance costs--set forth in this analysis are illustrative in nature
and do not represent the plans that states may
[[Page 33410]]
ultimately pursue. The illustrative proposal scenario is designed to
reflect, to the extent possible, the scope and nature of the proposed
guidelines. However, there is uncertainty with regards to the precise
measures that states will adopt to meet the requirements because there
are flexibilities afforded to the states in developing their State
plans.
The impact of the IRA is to accelerate the ongoing shift towards
lower emitting technology. In particular, tax credits for low-emitting
technology results in growing generation share for renewable resources
and the deployment of 11 GW of CCS retrofits on existing coal fired
EGUs, and 10 GW of CCS retrofits on existing combined cycle EGUs by
2035. New combined cycle builds are 22 GW by 2030, and existing coal
capacity continues to decline, falling to 69 GW by 2030 and 35 GW by
2040. As a result, the compliance cost of the proposed rules is lower
than it would be absent the IRA.
We estimate the present value (PV) of the projected compliance
costs for the analysis of the proposed standards for new combustion
turbines and for existing steam-generating EGUs, which do not include
the impact of the proposed standards for existing combustion turbines
EGUs and the third phase of the proposed standards for new combustion
turbines over the 2024 to 2042 period, as well as estimate the
equivalent annual value (EAV) of the flow of the compliance costs over
this period. The EAV represents a flow of constant annual values that,
had they occurred annually, would yield a sum equivalent to the PV. All
dollars are in 2019 dollars. Consistent with Executive Order 12866
guidance, we estimate the PV and EAV using 3 and 7 percent discount
rates. The PV of the compliance costs, discounted at the 3-percent
rate, is estimated to be about $14 billion, with an EAV of about $0.95
billion. At the 7-percent discount rate, the PV of the compliance costs
is estimated to be about $10 billion, with an EAV of about $0.98
billion.
The EPA has developed a separate estimate of the projected
compliance costs for the proposed standards for existing combustion
turbines and third phase of the proposed standards for new natural gas-
fired EGUs over the 2024 to 2042 period. The PV of these compliance
costs, discounted at the 3-percent rate, is estimated to be between
about $5.7 to 10 billion, with an EAV of between about $0.4 to 0.7
billion. At the 7 percent discount rate, the PV of these compliance
costs is estimated to be between about $3.5 to 6.2 billion, with an EAV
of about $0.34 to 0.6 billion.
Sections 3 and 8 of the RIA present detailed discussions of the
compliance cost projections for the proposed requirements, as well as
projections of compliance costs for less and more stringent regulatory
options. For a detailed description of these compliance cost
projections, please see sections 3 and 8 of the RIA. The EPA solicits
comment on its cost estimation generally.
C. Economic and Energy Impacts
These proposed actions have economic and energy market
implications. The energy impact estimates presented here reflect the
EPA's illustrative analysis of the proposed rules. States are afforded
flexibility to implement the proposed rules, and thus the impacts could
be different to the extent states make different choices than those
assumed in the illustrative analysis. Table 9 presents a variety of
energy market impact estimates for 2028, 2030, 2035, and 2040 for the
illustrative proposal scenario, relative to the baseline. These results
pertain to the analysis of the proposed standards for new combustion
turbines and for existing steam generation EGUs, and do not include the
impact of the proposed standards for existing combustion turbines and
the third phase of the proposed standards for new combustion turbines.
Table 9--Summary of Certain Energy Market Impacts for the Illustrative
Proposal Scenario, Relative to the Baseline
[Percent change]
------------------------------------------------------------------------
2028 (%) 2030 (%) 2035 (%) 2040 (%)
------------------------------------------------------------------------
Retail electricity prices... -1 2 0 0
Average price of coal -1 0 2 2
delivered to power sector..
Coal production for power -2 -40 -23 -15
sector use.................
Price of natural gas 0 9 -2 -3
delivered to power sector..
Price of average Henry Hub 0 10 -2 -2
(spot).....................
Natural gas use for 0 8 -1 -2
electricity generation.....
------------------------------------------------------------------------
These and other energy market impacts are discussed more
extensively in section 3 of the RIA.
More broadly, changes in production in a directly regulated sector
may have effects on other markets when output from that sector--for
this rule electricity--is used as an input in the production of other
goods. It may also affect upstream industries that supply goods and
services to the sector, along with labor and capital markets, as these
suppliers alter production processes in response to changes in factor
prices. In addition, households may change their demand for particular
goods and services due to changes in the price of electricity and other
final goods prices. Economy-wide models--and, more specifically,
computable general equilibrium (CGE) models--are analytical tools that
can be used to evaluate the broad impacts of a regulatory action. A
CGE-based approach to cost estimation concurrently considers the effect
of a regulation across all sectors in the economy.
In 2015, the EPA established a Science Advisory Board (SAB) panel
to consider the technical merits and challenges of using economy-wide
models to evaluate costs, benefits, and economic impacts in regulatory
analysis. In its final report, the SAB recommended that the EPA begin
to integrate CGE modeling into applicable regulatory analysis to offer
a more comprehensive assessment of the effects of air regulations.\702\
In response to the SAB's recommendations, the EPA developed a new CGE
model called SAGE designed for use in regulatory analysis. A second SAB
panel
[[Page 33411]]
performed a peer review of SAGE, and the review concluded in 2020.\703\
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\702\ U.S. EPA. 2017. SAB Advice on the Use of Economy-Wide
Models in Evaluating the Social Costs, Benefits, and Economic
Impacts of Air Regulations. EPA-SAB-17-012.
\703\ U.S. EPA. 2020. Technical Review of EPA's Computable
General Equilibrium Model, SAGE. EPA-SAB-20-010.
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The EPA used SAGE to evaluate potential economy-wide impacts of
these proposed rules, and the results are contained in an appendix of
the RIA. As presented in the RIA, annualized social costs estimated in
SAGE are approximately 35 percent larger than the partial equilibrium
private compliance costs (less taxes and transfers) derived from IPM.
This is consistent with general expectations based on the empirical
literature.\704\ However, the social cost estimate reflects the
combined effect of the proposed rules' requirements and interactions
with IRA subsidies for specific technologies that are expected to see
increased use in response to the proposed rules. We are not able to
identify their relative roles at this time. The EPA solicits comment on
the SAGE analysis presented in the RIA appendix.
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\704\ See, for example, Marten, A.L., Garbaccio, R., and
Wolverton, A. 2019. Exploring the General Equilibrium Costs of
Sector-Specific Environmental Regulations. Journal of the
Association of Environmental and Resource Economists, 6(6), 1065-
1104.
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Environmental regulation may affect groups of workers differently,
as changes in abatement and other compliance activities cause labor and
other resources to shift. An employment impact analysis describes the
characteristics of groups of workers potentially affected by a
regulation, as well as labor market conditions in affected occupations,
industries, and geographic areas. Employment impacts of these proposed
actions are discussed more extensively in section 5 of the RIA.
D. Benefits
Pursuant to E.O. 12866, the RIA for these actions analyzes the
benefits associated with the projected emission reductions under the
proposals to inform the EPA and the public about these projected
impacts.\705\ These proposed rules are projected to reduce emissions of
CO2, SO2, NOX, and PM2.5
nationwide which we estimate will provide climate benefits and public
health benefits. The potential climate, health, welfare, and water
quality impacts of these emission reductions are discussed in detail in
the RIA. In the RIA, the EPA presents the projected monetized climate
benefits due to reductions in CO2 emissions and the
monetized health benefits attributable to changes in SO2,
NOX, and PM2.5 emissions, based on the emissions
estimates in illustrative scenarios described previously. We monetize
benefits of the proposed standards and evaluate other costs in part to
enable a comparison of costs and benefits pursuant to E.O. 12866, but
we recognize there are substantial uncertainties and limitations in
monetizing benefits, including benefits that have not been quantified
or monetized.
---------------------------------------------------------------------------
\705\ These results pertain to the analysis of the proposed
standards for new combustion turbine EGUs and for existing steam-
generating EGUs, and do not include the impact of the proposed
standards for existing combustion turbine EGUs and the third phase
of the proposed standards for new natural gas-fired EGUs.
---------------------------------------------------------------------------
We estimate the climate benefits from these proposed rules using
estimates of the social cost of greenhouse gases (SC-GHG), specifically
the SC-CO2. The SC-CO2 is the monetary value of
the net harm to society associated with a marginal increase in
CO2 emissions in a given year, or the benefit of avoiding
that increase. In principle, SC-CO2 includes the value of
all climate change impacts (both negative and positive), including (but
not limited to) changes in net agricultural productivity, human health
effects, property damage from increased flood risk natural disasters,
disruption of energy systems, risk of conflict, environmental
migration, and the value of ecosystem services. The SC-CO2,
therefore, reflects the societal value of reducing emissions of the gas
in question by one metric ton and is the theoretically appropriate
value to use in conducting benefit-cost analyses of policies that
affect CO2 emissions. In practice, data and modeling
limitations naturally restrain the ability of SC-CO2
estimates to include all the important physical, ecological, and
economic impacts of climate change, such that the estimates are a
partial accounting of climate change impacts and will therefore, tend
to be underestimates of the marginal benefits of abatement. The EPA and
other Federal agencies began regularly incorporating SC-GHG estimates
in their benefit-cost analyses conducted under E.O. 12866 since 2008,
following a Ninth Circuit Court of Appeals remand of a rule for failing
to monetize the benefits of reducing CO2 emissions in a
rulemaking process.
We estimate the global social benefits of CO2 emission
reductions expected from the proposed rule using the SC-GHG estimates
presented in the February 2021 TSD: Social Cost of Carbon, Methane, and
Nitrous Oxide Interim Estimates under E.O. 13990. These SC-GHG
estimates are interim values developed under E.O. 13990 for use in
benefit-cost analyses until updated estimates of the impacts of climate
change can be developed based on the best available climate science and
economics. We have evaluated the SC-GHG estimates in the TSD and have
determined that these estimates are appropriate for use in estimating
the global social benefits of CO2 emission reductions
expected from this proposed rule. After considering the TSD, and the
issues and studies discussed therein, the EPA finds that these
estimates, while likely an underestimate, are the best currently
available SC-GHG estimates. These SC-GHG estimates were developed over
many years using a transparent process, peer-reviewed methodologies,
the best science available at the time of that process, and with input
from the public. As discussed in section 4 of the RIA, these interim
SC-CO2 estimates have a number of limitations, including
that the models used to produce them do not include all of the
important physical, ecological, and economic impacts of climate change
recognized in the climate-change literature and that several modeling
input assumptions are outdated. As discussed in the February 2021 TSD,
the Interagency Working Group on the Social Cost of Greenhouse Gases
(IWG) finds that, taken together, the limitations suggest that these
SC-CO2 estimates likely underestimate the damages from
CO2 emissions. The IWG is currently working on a
comprehensive update of the SC-GHG estimates (under E.O. 13990) taking
into consideration recommendations from the National Academies of
Sciences, Engineering and Medicine, recent scientific literature,
public comments received on the February 2021 TSD and other input from
experts and diverse stakeholder groups. The EPA is participating in the
IWG's work. In addition, while that process continues, the EPA is
continuously reviewing developments in the scientific literature on the
SC-GHG, including more robust methodologies for estimating damages from
emissions, and looking for opportunities to further improve SC-GHG
estimation going forward. Most recently, the EPA has developed a draft
updated SC-GHG methodology within a sensitivity analysis in the
regulatory impact analysis of the EPA's November 2022 supplemental
proposal for oil and gas standards that is currently undergoing
external peer review and a public comment process. If EPA's updated SC-
GHG methodology is finalized before these rules are finalized, the EPA
intends to present monetized climate benefits using the updated SC-GHG
estimates in the final RIA. See section 4 of the RIA for more
discussion of this effort.
[[Page 33412]]
In addition to CO2, these proposed rules are expected to
reduce emissions of NOX and SO2 and direct
PM2.5 nationally throughout the year. Because NOX
and SO2 are also precursors to secondary formation of
ambient PM2.5, reducing these emissions would reduce human
exposure to ambient PM2.5 throughout the year and would
reduce the incidence of PM2.5-attributable health effects.
These proposed rules are also expected to reduce ozone season
NOX emissions nationally. In the presence of sunlight,
NOX and volatile organic compounds (VOCs) can undergo a
chemical reaction in the atmosphere to form ozone. Reducing
NOX emissions in most locations reduces human exposure to
ozone and the incidence of ozone-related health effects, though the
degree to which ozone is reduced will depend in part on local
concentration levels of VOCs. The RIA estimates the health benefits of
changes in PM2.5 and ozone concentrations. The health effect
endpoints, effect estimates, benefit unit-values, and how they were
selected, are described in the Estimating PM2.5- and Ozone-
Attributable Health Benefits TSD, which is referenced in the RIA for
these actions. Our approach for updating the endpoints and to identify
suitable epidemiologic studies, baseline incidence rates, population
demographics, and valuation estimates is summarized in section 4 of the
RIA.
The following PV and EAV estimates reflect projected benefits over
the 2024 to 2042 period, discounted to 2024 in 2019 dollars, for the
analysis of the proposed standards for new natural gas-fired EGUs and
for existing coal-fired EGUs, which do not include the impact of the
proposed standards for existing natural gas-fired EGUs and the third
phase of the proposed standards for new natural gas-fired EGUs. We
monetize benefits of the proposed standards and evaluate other costs in
part to enable a comparison of costs and benefits pursuant to E.O.
12866, but we recognize there are substantial uncertainties and
limitations in monetizing benefits, including benefits that have not
been quantified. The projected PV of monetized climate benefits is
about $30 billion, with an EAV of about $2.1 billion using the SC-
CO2 discounted at 3 percent. The projected PV of monetized
health benefits is about $68 billion, with an EAV of about $4.8 billion
discounted at 3 percent. Combining the projected monetized climate and
health benefits yields a total PV estimate of about $98 billion and EAV
estimate of $6.9 billion.
At a 7 percent discount rate, these proposed rules are expected to
generate projected PV of monetized health benefits of about $44
billion, with an EAV of about $4.3 billion discounted at 7 percent. The
EPA notes that while OMB Circular A-4, as published in 2003, recommends
using 3 percent and 7 percent discount rates as ``default'' values,
Circular A-4 also recognizes that ``special ethical considerations
arise when comparing benefits and costs across generations,'' and
Circular A-4 acknowledges that analyses may appropriately ``discount
future costs and consumption benefits . . . at a lower rate than for
intragenerational analysis.'' Therefore, climate benefits remain
discounted at 3 percent in this benefits analysis. Thus, these proposed
rules would generate a PV of total monetized benefits of $74 billion,
with an EAV of $6.4 billion discounted at a 7 percent rate.
The projected PV of monetized climate benefits for the analysis of
the impact of the proposed standards for existing combustion turbines
and the third phase of the proposed standards for new natural gas-fired
EGUs is between about $10 to 20 billion, with an EAV of between about
$0.7 to 1.4 billion using the SC-CO2 discounted at 3
percent.
The results presented in this section provide an incomplete
overview of the effects of the proposals. The monetized climate
benefits estimates do not include important benefits that we are unable
to fully monetize due to data and modeling limitations. In addition,
important health, welfare, and water quality benefits anticipated under
these proposed rules are not quantified. We anticipate that taking non-
monetized effects into account would show the proposals to be more
beneficial than the tables in this section reflect. Discussion of the
non-monetized health, climate, welfare, and water quality benefits is
found in section 4 of the RIA.
E. Environmental Justice Analytical Considerations and Stakeholder
Outreach and Engagement
Consistent with the EPA's commitment to integrating environmental
justice (EJ) in the Agency's actions, and following the directives set
forth in multiple Executive Orders, the Agency has analyzed the impacts
of these proposed rules on communities with potential environmental
justice concerns and engaged with stakeholders representing these
communities to seek input and feedback. The EPA evaluates, to the
extent practicable, whether proposed GHG reductions are accompanied by
changes in other health-harming pollutants that may place further
burdens on these communities.\706\
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\706\ These results pertain to the analysis of the proposed
standards for new combustion turbine EGUs and for existing steam-
generating EGUs, and do not include the impact of the proposed
standards for existing combustion turbine EGUs and the third phase
of the proposed standards for new natural gas-fired EGUs.
---------------------------------------------------------------------------
Executive Order 12898 is discussed in section XV.J of this preamble
and analytical results are available in section 6 of the RIA.
1. Introduction
Executive Order 12898 directs the EPA to identify the populations
of concern who are most likely to experience unequal burdens from
environmental harms; specifically, minority populations, low-income
populations, and indigenous peoples. Additionally, Executive Order
13985 is intended to advance racial equity and support underserved
communities through Federal government actions. The EPA defines
environmental justice as the fair treatment and meaningful involvement
of all people regardless of race, color, national origin, or income,
with respect to the development, implementation, and enforcement of
environmental laws, regulations, and policies. The EPA further defines
the term fair treatment to mean that ``no group of people should bear a
disproportionate burden of environmental harms and risks, including
those resulting from the negative environmental consequences of
industrial, governmental, and commercial operations or programs and
policies''.\707\ In recognizing that minority and low-income
populations often bear an unequal burden of environmental harms and
risks, the EPA continues to consider ways of protecting them from
adverse public health and environmental effects of air pollution.
---------------------------------------------------------------------------
\707\ Plan EJ 2014. Washington, DC: U.S. EPA, Office of
Environmental Justice. https://www.epa.gov/environmentaljustice/plan-ej-2014.
---------------------------------------------------------------------------
2. Analytical Considerations
EJ concerns for each rulemaking are unique and should be considered
on a case-by-case basis, and the EPA's EJ Technical Guidance states
that ``[t]he analysis of potential EJ concerns for regulatory actions
should address three questions:
1. Are there potential EJ concerns associated with environmental
stressors affected by the regulatory action for population groups of
concern in the baseline?
2. Are there potential EJ concerns associated with environmental
stressors affected by the regulatory action for population groups of
concern for the
[[Page 33413]]
regulatory option(s) under consideration?
3. For the regulatory option(s) under consideration, are potential
EJ concerns created or mitigated compared to the baseline?''
To address these questions, the EPA developed an analytical
approach that considers the purpose and specifics of the rulemaking, as
well as the nature of known and potential exposures and impacts. For
the rules, the EPA quantitatively evaluates the proximity of existing
affected facilities to potentially vulnerable and/or overburdened
populations for consideration of local pollutants impacted by these
rules but not modeled here (RIA section 6.4), as well as the
distribution of ozone and PM2.5 concentrations in the
baseline and changes due to the proposed rulemakings across different
demographic groups on the basis of race, ethnicity, poverty status,
employment status, health insurance status, age, sex, educational
attainment, and degree of linguistic isolation (RIA section 6.5). The
EPA also qualitatively discusses potential EJ climate impacts (RIA
section 6.3). Each of these analyses was performed to answer separate
questions and is associated with unique limitations and uncertainties.
Baseline demographic proximity analyses provide information as to
whether there may be potential EJ concerns associated with
environmental stressors emitted from sources affected by the regulatory
actions for certain population groups of concern. The baseline
demographic proximity analyses examined the demographics of populations
living within 5 km and 10 km of the following three sets of sources:
(1) all 140 coal plants with units potentially subject to the proposed
rules, (2) three coal plants retiring by January 1, 2032 with units
potentially subject to the proposed rules, and (3) 19 coal plants
retiring between January 1, 2032 to January 1, 2040 with units
potentially subject to the proposed rules. The proximity analysis of
the full population of potentially affected units greater than 25 MW
indicated that the demographic percentages of the population within 10
km and 50 km of the facilities are relatively similar to the national
averages. The proximity analysis of the 19 units that will retire from
1/1/32 to 1/1/40 (a subset of the total 140 units) found that the
percent of the population within 10 km that is African American is
higher than the national average. The proximity analysis for the 3
units that will retire by 1/1/32 (a subset of the total 140 units)
found that for both the 10 km and 50 km populations the percent of the
population that is Native American for one facility is significantly
above the national average, the percent of the population that is
Hispanic/Latino for another facility is significantly above the
national average, and all three facilities were well above the national
average for both the percent below the poverty level and the percent
below two times the poverty level.
Because the pollution impacts that are the focus of these rules may
occur downwind from affected facilities, ozone and PM2.5
exposure analyses that evaluate demographic variables are better able
to evaluate any potentially disproportionate pollution impacts of these
rulemakings. The baseline PM2.5 and ozone exposure analyses
respond to question 1 from EPA's EJ Technical Guidance document more
directly than the proximity analyses, as they evaluate a form of the
environmental stressor primarily affected by the regulatory actions
(RIA section 6.5). Baseline ozone and PM2.5 exposure
analyses show that certain populations, such as Hispanics, Asians,
those linguistically isolated, and those less educated may experience
disproportionately higher ozone and PM2.5 exposures as
compared to the national average. Black populations may also experience
disproportionately higher PM2.5 concentrations than the
reference group, and American Indian populations and children may also
experience disproportionately higher ozone concentrations than the
reference group. Therefore, there likely are potential EJ concerns
associated with environmental stressors affected by the regulatory
actions for population groups of concern in the baseline (question 1).
Finally, the EPA evaluates how post-policy regulatory alternatives
of these proposed rulemakings are expected to differentially impact
demographic populations, informing questions 2 and 3 from EPA's EJ
Technical Guidance with regard to ozone and PM2.5 exposure
changes. We infer that baseline disparities in the ozone and
PM2.5 concentration burdens are likely to remain after
implementation of the regulatory action or alternatives under
consideration. This is due to the small magnitude of the concentration
changes associated with these rulemakings across population demographic
groups, relative to the magnitude of the baseline disparities (question
2). This EJ assessment also suggests that these actions are unlikely to
mitigate or exacerbate PM2.5 exposures disparities across
populations of EJ concern analyzed. Regarding ozone exposures, while
most policy options and future years analyzed will not likely mitigate
or exacerbate ozone exposure disparities for the population groups
evaluated, ozone exposure disparities may be exacerbated for some
population groups analyzed in 2030 under all regulatory options.
However, the extent to which disparities may be exacerbated is likely
modest, due to the small magnitude of the ozone concentration changes
(question 3). Importantly, the actions described in these proposals are
expected to lower PM2.5 and ozone in many areas, and thus
mitigate some pre-existing health risks of air pollution across all
populations evaluated.
3. Outreach and Engagement
In outreach with potentially vulnerable communities, residents have
voiced two primary concerns. First, there is the concern that their
communities have experienced historically disproportionate burdens from
the environmental impacts of energy production, and second, that as the
sector evolves to use new technologies such as CCS and hydrogen, they
may continue to face disproportionate burdens.
With regard to CCS, the EPA is proposing that CCS is a component of
the BSER for new base load stationary combustion turbine EGUs, existing
coal-fired steam generating units that intend to operate after 2040,
and large and frequently operated existing stationary combustion
turbine EGUs. The EPA recognizes and has given careful consideration to
the various concerns that potentially vulnerable communities have
raised with regard to the use of CCS in determining that CCS is BSER
for these sources. In the following section, the EPA discusses various
measures undertaken in this rulemaking and elsewhere to address
community concerns on this matter.
One concern the EPA has heard from stakeholders is that adding CCS
to EGUs can extend the life of an existing coal-fired steam generating
unit, subjecting local residents who have already been negatively
impacted by the operation of the coal-fired steam generating unit to
additional harmful pollution. There are several important factors the
EPA considered in evaluating the emission impact of an upgraded EGU
when determining BSER for these units that intend to operate in the
long term. First, CCS is the most effective add-on pollution control
available for mitigation of GHG emissions from affected sources.
Second, most CCS technologies work much more effectively when the EGU
is emitting the lowest levels of SO2 possible; therefore it
is likely that as part of a CCS installation, companies will improve
their EGUs' SO2 control. Third, a CCS
[[Page 33414]]
retrofit may trigger requirements under the major NSR program because
of the potential for an emissions increase of one or more pollutants
due to the additional energy production by the EGU to power the
CO2 capture system. If the source is undergoing major NSR
permitting, the permitting authority would provide an opportunity for
the public to comment on the draft permit, which is another avenue for
affected residents to submit input regarding additional controls that
may be needed to meet best available control technology requirements
for non-GHG pollutants such as NOX.\708\
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\708\ The EPA discusses the interactions between CCS and non-GHG
pollutants for existing coal-fired steam generating units in section
X.D.1.a.iii(B) of this preamble.
---------------------------------------------------------------------------
Communities have also expressed concerns about CO2
pipeline safety and geologic sequestration. As discussed in section
VII.F.3.b.iii of the preamble, supercritical CO2 pipeline
safety is regulated by PHMSA. These regulations protect against
environmental release during transport and PHMSA has announced steps to
further strengthen its safety oversight of supercritical CO2
pipelines, including initiating a new rulemaking to update standards
for supercritical CO2 pipelines and solicited research
proposals to strengthen CO2 pipeline safety.\709\ Geologic
sequestration of CO2 is regulated by the EPA through the UIC
Program under the Safe Drinking Water Act, and through the GHGRP under
the Clean Air Act. UIC Class VI regulations include strong protections
for communities to prevent contamination of underground sources of
drinking water. These regulatory protections include a variety of
measures, including proper site characterization and strict
construction, operating, and monitoring requirements to ensure well and
formation integrity, proper plugging of wells, and long-term project
management and post-injection site care to ensure leakage
prevention.\710\ GHGRP requirements complement and build on UIC
regulations through air-side monitoring and reporting requirements that
provide the EPA and communities with a transparent means of evaluating
the effectiveness of geologic sequestration. These programs work in
combination to provide security and transparency.
---------------------------------------------------------------------------
\709\ PHMSA, ``PHMSA Announces New Safety Measures to Protect
Americans From Carbon Dioxide Pipeline Failures After Satartia, MS
Leak.'' 2022. https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
\710\ See generally Administrator Michael S. Regan, Underground
Injection Control Class VI Letter to Governors (December 9, 2022),
https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
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The final concern the EPA has heard from stakeholders is about a
lack of opportunity for impacted communities to voice opinions about
projects like this that affect them. Recognizing the important stake
that local residents have in decisions regarding EGUs in their
communities, the EPA expects that states will address facility-specific
concerns about how to responsibly deploy CCS and any other potential
control strategies in the course of meaningful engagement under the
proposed emission guidelines for existing steam generating units and
existing combustion turbines, as discussed in section XII.F.1.b of the
preamble. State plans should specifically ensure that community members
have an opportunity to share their input if they reside near a fossil
fuel-fired steam generating unit that plans to install CCS to meet the
requirements of these proposed rules regarding how to responsibly
deploy this technology.
With regard to the decision to construct a new combustion turbine,
most of the safeguards outlined above for CCS retrofits apply. While
meaningful engagement applies under emission guidelines to existing
sources, there exists an opportunity for community engagement for new
sources as part of the major NSR permitting process, in the event that
the source triggers major NSR requirements. While new combustion
turbines that co-fire with hydrogen may trigger major NSR, there are
cases in which they are less likely to trigger major NSR, such as: (1)
If the new combustion turbine is proposed at an existing facility and
the facility is able to reduce its emissions more than the emissions
increase from the combustion turbine (e.g., if the combustion turbine
replaces an existing coal-fired EGU and the facility has emission
reduction credits from the shutdown unit), or (2) if the emissions from
the new combustion turbine are low enough to not trigger major NSR.
The EPA further notes that hydrogen production presents a unique
set of potential issues for vulnerable communities. During the February
27th National Tribal Energy Roundtable Webinar, one of the primary
concerns articulated was the potential for fossil-derived hydrogen to
essentially extend the life of petrochemical industries already
creating localized pollution loading. Since hydrogen is non-toxic, and
it does not produce carbon dioxide when burned, the inclusion of
hydrogen in combustion turbine operations will lower overall health
risks compared with hydrocarbons. Perceived community risks with
hydrogen related to storage and transportation include its
combustibility and propensity to leak due to extremely low molecular
weight. Despite concerns about hydrogen, its low molecular weight
ensures that it dissipates and disperses quickly when released
outdoors, reducing unintended combustion risks compared with other
fuels.\711\ Adequate ventilation and leak detection are available to
ensure safety and are important elements in the design of hydrogen
systems. Concerns around hydrogen leaks can be mitigated with hydrogen
monitoring systems combined with adequate ventilation and leak
detection equipment, including special flame detectors.\712\ Further,
building and operational codes and standards developed specifically for
hydrogen's properties can minimize risks around hydrogen usage in a
community.\713\
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\711\ Department of Energy, Safe Use of Hydrogen https://www.energy.gov/eere/fuelcells/safe-use-hydrogen.
\712\ Ibid.
\713\ Department of Energy, Safety Codes and Standards https://www.energy.gov/eere/fuelcells/safety-codes-and-standards-basics.
---------------------------------------------------------------------------
New combustion turbine models designed to combust hydrogen, and
those potentially being retrofit to combust hydrogen, may be co-located
with electrolyzers that produce the hydrogen the facility will use. In
such instances, water scarcity could be exacerbated in some areas by
the freshwater demands of electrolytic hydrogen production, which could
pose a particular challenge for vulnerable communities. As such,
electrolyzer siting will need to take water availability into account.
Examples for sustainable siting for electrolyzers are emerging in
Europe, which has begun to employ Sustainable Value Methodology
designed to be sensitive to water access and availability and includes,
``decision-making support, combining economic, environmental and social
criteria''.\714\ We also expect advances in electrolytic technology
over time to reduce water demand, including the potential to enabling
sea-water usage in electrolyzers.\715\
---------------------------------------------------------------------------
\714\ Journal of Cleaner Production, Volume 315, 15 September
2021, 128124, ``Water Availability and Water Usage Solutions for
Electrolysis in Hydrogen Production'' Simoes, Sophia et al., https://www.sciencedirect.com/science/article/pii/S0959652621023428.
\715\ Sun, F., Qin, J., Wang, Z. et al. Energy-saving hydrogen
production by chlorine-free hybrid seawater splitting coupling
hydrazine degradation. Nat Commun 12, 4182 (2021). https://doi.org/10.1038/s41467-021-24529-3.
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[[Page 33415]]
F. Grid Reliability Considerations
The requirements for sources and states set forth in these proposed
actions were developed cognizant of concerns about an electric grid
under transition, and related reliability considerations. As previously
stated, a variety of important influences have led to notable changes
in the generation mix and expectations of how the power sector will
evolve. These trends have generally put existing high-emitting
generators under greater economic pressure and will continue to do so
even absent any EPA action pursuant to CAA section 111, and that is
manifest in various economic projections and modeling of the electric
power system. Recent legislation, including the IIJA, the IRA, and
State policies have amplified these trends, with continued change
expected for the existing fleet of EGUs. Moreover, many regions of the
country have experienced a significant increase in the frequency and
severity of extreme weather events--events that are notably projected
to worsen if GHG emissions are not adequately controlled. These events
have impacted energy infrastructure and both the demand for and supply
of electricity. A wide range of stakeholders including power
generators, grid operators and State and Federal regulators are
actively engaged in ensuring the reliability of the electric power
system is maintained and enhanced in the face of these changes.
As explained in this preamble, these proposed actions take account
of the rapidly evolving power sector and extensive input received from
power companies and other stakeholders on the future of these regulated
sources, while ensuring that new natural gas-fired combustion turbines
and existing steam EGUs achieve significant and cost-effective
reductions in GHG emissions through the application of adequately
demonstrated control technologies. Preserving the ability of power
companies and grid operators to maintain system reliability has been a
paramount consideration in the development of these proposed actions.
Accordingly, these proposed rules include significant design elements
that are intended to allow the power sector continued resource and
operational flexibility, and to facilitate long-term planning during
this dynamic period. Among other things, these elements include
subcategories of new natural gas-fired combustion turbines that allow
for the stringency of standards of performance to vary by capacity
factor; subcategories for existing steam EGUs that are based on
operating horizons and fuel reflecting the request of industry
stakeholders; compliance deadlines for both new and existing EGUs that
provide ample lead time to plan; and proposed State plan flexibilities.
In addition, this preamble discusses EPA's intention to exercise its
enforcement discretion where needed to address any potential instances
in which individual EGUs may need to temporarily operate for
reliability reasons, and to set forth clear and transparent
expectations for administrative compliance orders to ensure that
compliance with these proposed rules can be achieved without impairing
the ability of power companies and grid operators to maintain
reliability. As such, these proposed rules provide the flexibility
needed to avoid reliability concerns while still securing the pollution
reductions consistent with section 111 of the CAA.
To support these proposed actions, the EPA has conducted an
analysis of resource adequacy based upon power sector modeling and
projections of the standards on existing steam generating units, and
the first two phases of the standards on new combustion turbines, as
well as the results of the spreadsheet-based analysis of the standards
on existing combustion turbines and the third phase of the standards on
new combustion turbines, that can be found in the RIA. Any potential
impact of these proposed actions is dependent upon a myriad of
decisions and compliance choices source owners and operators may
pursue. It is important to recognize that the proposed rules provide
multiple flexibilities that preserve the ability of responsible
authorities to maintain electric reliability. While not explicitly
modeled using IPM, the proposed emission guidelines for existing
natural gas-fired EGUs are estimated to have very little incremental
impact on resource adequacy. The guidelines would affect a subset of
the total natural gas fleet, and units that install CCS are still able
to maintain capacity accreditation values (after accounting for
capacity de-rates). Moreover, units that operate below 50 percent
capacity factor annually (and are not subject to the CCS requirement)
would still be able to operate at higher levels during times of greater
demand, thereby maintaining their capacity accreditation values.
The results presented in the Resource Adequacy Analysis TSD, which
is available in the docket, show that the projected impacts of the
proposed rules on power system operations, under conditions preserving
resource adequacy, are modest and manageable. For the specific
scenarios analyzed in the RIA, the implementation of the proposed rules
can be achieved while maintaining resource adequacy even as shifts in
existing and new capacity occur. Retirements are offset by additions,
along with reserve transfers where/when needed, which demonstrates that
ample compliance pathways exist for sources while preserving resource
adequacy.
The EPA routinely consults with the DOE and FERC on electric
reliability and intends to continue to do so as it develops and
implements a final rule. This ongoing engagement will be strengthened
with routine and comprehensive communication between the agencies under
the DOE-EPA Joint Memorandum of Understanding on Interagency
Communication and Consultation on Electric Reliability signed on March
8, 2023.\716\ The memorandum will provide greater interagency
engagement on electric reliability issues at a time of significant
dynamism in the power sector, allowing the EPA and the DOE to use their
considerable expertise in various aspects of grid reliability to
support the ability of Federal and State regulators, grid operators,
regional reliability entities, and power companies to continue to
deliver a high standard of reliable electric service. As the power
sector continues to change and as the agencies carry out their
respective authorities, the agencies intend to continue to engage and
collectively monitor, share information, and consult on policy and
program decisions to assure the continued reliability of the bulk power
system.
---------------------------------------------------------------------------
\716\ Joint Memorandum of Understanding on Interagency
Communication and Consultation on Electric Reliability (March 8,
2023). https://www.epa.gov/power-sector/electric-reliability-mou.
---------------------------------------------------------------------------
In addition, the EPA observes that power companies, grid operators,
and State public utility commissions have well-established procedures
in place to preserve electric reliability in response to changes in the
generating portfolio, and expects that those procedures will continue
to be effective in addressing compliance decisions that power companies
may make over the extended time period for implementation of these
proposed rules. In response to any regulatory requirement, affected
sources will have to take some type of action to reduce emissions,
which will generally have costs. Some EGU owners may conclude that, all
else being equal, retiring a particular EGU is likely to be the more
economic option from the perspective of the unit's customers and/or
owners because there are better opportunities for using the capital
than investing it in new emissions controls at
[[Page 33416]]
the unit. Such a retirement decision will require the unit's owner to
follow the processes put in place by the relevant RTO, balancing
authority, or State regulator to protect electric system reliability.
These processes typically include analysis of the potential impacts of
the proposed EGU retirement on electrical system reliability,
identification of options for mitigating any identified adverse
impacts, and, in some cases, temporary provision of additional revenues
to support the EGU's continued operation until longer-term mitigation
measures can be put in place. In some rare instances where the
reliability of the system is jeopardized due to extreme weather events
or other unforeseen emergencies, authorities can request a temporary
reprieve from environmental requirements and constraints (through DOE)
in order to meet electric demand and maintain reliability. These
proposed actions do not interfere with these already available
provisions, but rather provides a long-term pathway for sources to
develop and implement a proper plan to reduce emissions while
maintaining adequate supplies of electricity.
XV. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
These actions were submitted to the Office of Management and Budget
(OMB) for review under Section 3(f)(1) of Executive Order 12866. Any
changes made in response to recommendations received as part of
Executive Order 12866 review have been documented in the docket. The
EPA prepared an analysis of the potential costs and benefits associated
with these actions. This analysis, ``Regulatory Impact Analysis for the
Proposed New Source Performance Standards for Greenhouse Gas Emissions
from New, Modified, and Reconstructed Fossil Fuel-Fired Electric
Generating Units; Emission Guidelines for Greenhouse Gas Emissions from
Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the
Affordable Clean Energy Rule,'' is available in the docket.
Table 10 presents the estimated present values (PV) and equivalent
annualized values (EAV) of the projected climate benefits, health
benefits, compliance costs, and net benefits of the proposed rule in
2019 dollars discounted to 2024. This analysis covers the impacts of
the proposed standards for new combustion turbines and for existing
steam generating EGUs, and does not include the impact of the proposed
standards for existing combustion turbines and the third phase of the
proposed standards for new combustion turbines. The estimated monetized
net benefits are the projected monetized benefits minus the projected
monetized costs of the proposed rules.
The projected climate benefits in table 8 are based on estimates of
the social cost of carbon (SC-CO2) at a 3 percent discount
rate and are discounted using a 3 percent discount rate to obtain the
PV and EAV estimates in the table. Under E.O. 12866, the EPA is
directed to consider the costs and benefits of its actions.
Accordingly, in addition to the projected climate benefits of the
proposals from anticipated reductions in CO2 emissions, the
projected monetized health benefits include those related to public
health associated with projected reductions in fine particulate matter
(PM2.5) and ozone concentrations. The projected health
benefits are associated with several point estimates and are presented
at real discount rates of 3 and 7 percent. The power industry's
compliance costs are represented in this analysis as the change in
electric power generation costs between the baseline and policy
scenarios. In simple terms, these costs are an estimate of the
increased power industry expenditures required to implement the
proposed requirements.
These results present an incomplete overview of the potential
effects of the proposals because important categories of benefits--
including benefits from reducing HAP emissions--were not monetized and
are therefore not reflected in the benefit-cost tables. The EPA
anticipates that taking non-monetized effects into account would show
the proposals to have a greater net benefit than this table reflects.
---------------------------------------------------------------------------
\717\ This analysis pertains to the proposed standards for new
combustion turbines and for existing steam generating EGUs and does
not include the impact of the proposed standards for existing
combustion turbines and the third phase of the proposed standards
for new combustion turbines.
Table 10--Projected Monetized Benefits, Compliance Costs, and Net
Benefits of the Proposed Rules, 2024 Through 2042 \717\
[Billions 2019$, discounted to 2024] \a\
------------------------------------------------------------------------
3% Discount 7% Discount
rate rate
------------------------------------------------------------------------
Present Value:
Climate Benefits \c\................ $30 $30
Health Benefits \d\................. 68 44
Compliance Costs.................... 14 10
Net Benefits \e\.................... 85 64
Equivalent Annualized Value \b\:
Climate Benefits \c\................ 2.1 2.1
Health Benefits \d\................. 4.8 4.3
Compliance Costs.................... 0.95 0.98
Net Benefits \e\.................... 5.9 5.4
------------------------------------------------------------------------
\a\ Values have been rounded to two significant figures. Rows may not
appear to sum correctly due to rounding.
\b\ The annualized present value of costs and benefits are calculated
over the 20-year period from 2024 to 2042.
\c\ Climate benefits are based on changes (reductions) in CO2 emissions.
Climate benefits in this table are based on estimates of the SC-CO2 at
a 3 percent discount rate and are discounted using a 3 percent
discount rate to obtain the PV and EAV estimates in the table. The EPA
does not have a single central SC-CO2 point estimate. We emphasize the
importance and value of considering the benefits calculated using all
four SC-CO2 estimates (model average at 2.5 percent, 3 percent, and 5
percent discount rates; 95th percentile at 3 percent discount rate).
As discussed in section 4 of the RIA, consideration of climate
benefits calculated using discount rates below 3 percent, including 2
percent and lower, is also warranted when discounting
intergenerational impacts.
[[Page 33417]]
\d\ The EPA notes that while OMB Circular A-4, as published in 2003,
recommends using 3 percent and 7 percent discount rates as ``default''
values, Circular A-4 also recognizes that ``special ethical
considerations arise when comparing benefits and costs across
generations,'' and Circular A-4 acknowledges that analyses may
appropriately ``discount future costs and consumption benefits . . .
at a lower rate than for intragenerational analysis.'' Therefore,
climate benefits remain discounted at 3 percent in this benefits
analysis.
\e\ The projected monetized health benefits include those related to
public health associated with reductions in PM2.5 and ozone
concentrations. The projected health benefits are associated with
several point estimates and are presented at real discount rates of 3
and 7 percent.
\f\ Several categories of benefits remain unmonetized and are thus not
reflected in the table. Non-monetized benefits include important
climate, health, welfare, and water quality benefits and are described
in RIA Table 4-6.
As shown in table 10, the proposed rules are projected to reduce
greenhouse gas emissions in the form of CO2, producing a
projected PV of monetized climate benefits of about $30 billion, with
an EAV of about $2.1 billion using the SC-CO2 discounted at
3 percent. The proposed rules are also projected to reduce
PM2.5 and ozone concentrations, producing a projected PV of
monetized health benefits of about $68 billion, with an EAV of about
$4.8 billion discounted at 3 percent.
The PV of the projected compliance costs are $14 billion, with an
EAV of about $0.95 billion discounted at 3 percent. Combining the
projected benefits with the projected compliance costs yields a net
benefit PV estimate of about $85 billion and EAV of about $5.9 billion
at a 3 percent discount rate.
At a 7 percent discount rate, the proposed rules are expected to
generate projected PV of monetized health benefits of about $44
billion, with an EAV of about $4.3 billion. Climate benefits remain
discounted at 3 percent in this net benefits analysis. Thus, the
proposed rules would generate a PV of monetized benefits of about $74
billion, with an EAV of about $6.4 billion discounted at a 7 percent
rate. The PV of the projected compliance costs are about $10 billion,
with an EAV of $0.98 billion discounted at 7 percent. Combining the
projected benefits with the projected compliance costs yields a net
benefit PV estimate of about $64 billion and an EAV of about $5.4
billion discounted at 7 percent.
The EPA has developed a separate analysis of the proposed standards
for existing combustion turbines and third phase of the proposed
standards for new natural gas-fired EGUs over the 2024 to 2042 period.
This analysis includes estimated compliance costs and climate benefits,
and is located in Section 8 of the RIA. The PV of the compliance costs,
discounted at the 3-percent rate, is estimated to be between about $5.7
to 10 billion, with an EAV of between about $0.40 to 0.70 billion. At
the 7 percent discount rate, the PV of the compliance costs is
estimated to be between about $ 3.5 to 6.2 billion, with an EAV of
about $ 0.34 to 0.60 billion. The PV of the climate benefits,
discounted at the 3-percent rate, is estimated to be between about $10
to 20 billion, with an EAV of between about $0.70 to 1.4 billion.
As discussed in section XIV of this preamble, the monetized
benefits estimates provide an incomplete overview of the beneficial
impacts of the proposals. In particular, the monetized climate benefits
are incomplete and an underestimate as explained in section 4.2 of the
RIA. In addition, important health, welfare, and water quality benefits
anticipated under these proposed rules are not quantified or monetized.
The EPA anticipates that taking non-monetized effects into account
would show the proposals to have greater benefits than the estimates in
the preamble and RIA reflect. Simultaneously, the estimates of
compliance costs used in the net benefits analysis may provide an
incomplete characterization of the true costs of the rule. The balance
of unquantified benefits and costs is ambiguous but is unlikely to
change the result that the benefits of the proposals exceed the costs
by billions of dollars annually.
We also note that the RIA follows the EPA's historic practice of
using a technology-rich partial equilibrium model of the electricity
and related fuel sectors to estimate the incremental costs of producing
electricity under the requirements of proposed and final major EPA
power sector rules. In Appendix B of the RIA for these actions, the EPA
has also included an economy-wide analysis that considers additional
facets of the economic response to the proposed rules, including the
full resource requirements of the expected compliance pathways, some of
which are paid for through subsidies in the partial equilibrium
analysis. The social cost estimates in the economy-wide analysis and
discussed in Appendix B of the RIA are still far below the projected
benefits of the proposed rules.
B. Paperwork Reduction Act (PRA)
1. 40 CFR Part 60, Subpart TTTT
This action does not impose any new information collection burden
under the PRA. OMB has previously approved the information collection
activities contained in the existing regulations and has assigned OMB
control number 2060-0685.
2. 40 CFR Part 60, Subpart TTTTa
The information collection activities in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the PRA. The Information Collection Request (ICR) document
that the EPA prepared has been assigned EPA ICR number 2771.01. You can
find a copy of the ICR in the docket for this rule, and it is briefly
summarized here.
Respondents/affected entities: Owners and operators of fossil-fuel
fired EGUs.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 2.
Frequency of response: Annual.
Total estimated burden: 110 hours (per year). Burden is defined at
5 CFR 1320.3(b).
Total estimated cost: $14,000 (per year), includes $0 annualized
capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to the EPA using the docket identified at
the beginning of this rule. The EPA will respond to any ICR-related
comments in the final rule. You may also send your ICR-related comments
to OMB's Office of Information and Regulatory Affairs using the
interface at www.reginfo.gov/public/do/PRAMain. Find this particular
information collection by selecting ``Currently under Review--Open for
Public Comments'' or by using the search function. OMB must receive
comments no later than July 24, 2023.
3. 40 CFR Part 60, Subpart UUUUb
The information collection activities in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the PRA. The Information Collection Request (ICR) document
that the EPA prepared has been assigned EPA ICR number 2770.01. You can
find a copy of the ICR in the docket for this rule, and it is briefly
summarized here.
[[Page 33418]]
This rule imposes specific requirements on State governments with
existing fossil fuel-fired steam generating units. The information
collection requirements are based on the recordkeeping and reporting
burden associated with developing, implementing, and enforcing a plan
to limit GHG emissions from existing EGUs. These recordkeeping and
reporting requirements are specifically authorized by CAA section 114
(42 U.S.C. 7414). All information submitted to the EPA pursuant to the
recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The annual burden for this collection of information for the states
(averaged over the first 3 years following promulgation) is estimated
to be 104,000 hours at a total annual labor cost of $13.1 million. The
annual burden for the Federal government associated with the State
collection of information (averaged over the first 3 years following
promulgation) is estimated to be 27,347 hours at a total annual labor
cost of $1.8 million. Burden is defined at 5 CFR 1320.3(b).
Respondents/affected entities: States with one or more designated
facilities covered under subpart UUUUb.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 50.
Frequency of response: Once.
Total estimated burden: 104,000 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $13,163,689, includes $36,750 annualized
capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the Agency's need for this information, the
accuracy of the provided burden estimates and any suggested methods for
minimizing respondent burden to the EPA using the docket identified at
the beginning of this rule. The EPA will respond to any ICR-related
comments in the final rule. You may also send your ICR-related comments
to OMB's Office of Information and Regulatory Affairs using the
interface at www.reginfo.gov/public/do/PRAMain. Find this particular
information collection by selecting ``Currently under Review--Open for
Public Comments'' or by using the search function. OMB must receive
comments no later than July 24, 2023.
4. 40 CFR Part 60, Subpart UUUUa
This proposed rule does not impose an information collection burden
under the PRA.
C. Regulatory Flexibility Act (RFA)
I certify that these actions will not have a significant economic
impact on a substantial number of small entities under the RFA. The
small entities subject to the requirements of the NSPS are private
companies, investor-owned utilities, cooperatives, municipalities, and
sub-divisions, that would seek to build and operate stationary
combustion turbines in the future. The Agency has determined that seven
small entities may be so impacted, and may experience an impact of 0
percent to 0.9 percent of revenues in 2035. Details of this analysis
are presented in section 5.3 of the RIA.
The EPA started the Small Business Advocacy Review (SBAR) panel
process prior to determining if the NSPS would have a significant
economic impact on a substantial number of small entities under the
RFA. The EPA conducted an initial outreach meeting with small entity
representatives on December 14, 2022. The EPA sought input from
representatives of small entities while developing the proposed NSPS
which enabled the EPA to hear directly from these representatives about
the regulation of GHG emissions from EGUs. The purpose of the meeting
was to provide general background on the NSPS rulemaking, answer
questions, and solicit input. Fifteen various small entities that
potentially would be affected by the NSPS attended the meeting. The
representatives included small entity municipalities, cooperatives, and
industry professional organizations. When the EPA determined the NSPS
would not have a significant economic impact on a substantial number of
small entities under the RFA, the EPA did not proceed with convening
the SBAR panel.
Emission guidelines will not impose any requirements on small
entities. Specifically, emission guidelines established under CAA
section 111(d) do not impose any requirements on regulated entities
and, thus, will not have a significant economic impact upon a
substantial number of small entities. After emission guidelines are
promulgated, states establish standards on existing sources, and it is
those State requirements that could potentially impact small entities.
The analysis in the accompanying RIA is consistent with the
analysis of the analogous situation arising when the EPA establishes
NAAQS, which do not impose any requirements on regulated entities. As
here, any impact of a NAAQS on small entities would only arise when
states take subsequent action to maintain and/or achieve the NAAQS
through their State implementation plans. See American Trucking Assoc.
v. EPA, 175 F.3d 1029, 1043-45 (D.C. Cir. 1999) (NAAQS do not have
significant impacts upon small entities because NAAQS themselves impose
no regulations upon small entities).
The EPA is aware that there is substantial interest in the proposed
rules among small entities and invites comments on all aspects of the
proposals and their impacts, including potential impacts on small
entities.
D. Unfunded Mandates Reform Act of 1995 (UMRA)
The proposed NSPS contain a Federal mandate under UMRA, 2 U.S.C.
1531-1538, that may result in expenditures of $100 million or more for
the private sector in any one year. The proposed NSPS do not contain an
unfunded mandate of $100 million or more as described in UMRA, 2 U.S.C.
1531-1538 for State, local, and Tribal governments, in the aggregate.
Accordingly, the EPA prepared, under section 202 of UMRA, a written
statement of the benefit-cost analysis, which is in section XIV of this
preamble and in the RIA.
The proposed repeal of the ACE Rule and emission guidelines do not
contain an unfunded mandate of $100 million or more as described in
UMRA, 2 U.S.C. 1531-1538, and do not significantly or uniquely affect
small governments. The proposed emission guidelines do not impose any
direct compliance requirements on regulated entities, apart from the
requirement for states to develop plans to implement the guidelines
under CAA section 111(d) for designated EGUs. The burden for states to
develop CAA section 111(d) plans in the 24-month period following
promulgation of the emission guidelines was estimated and is listed in
section XV.B, but this burden is estimated to be below $100 million in
any one year. As explained in section XII.F.6, the proposed emission
guidelines do not impose specific requirements on Tribal governments
that have designated EGUs located in their area of Indian country.
The proposed actions are not subject to the requirements of section
203 of UMRA because they contain no regulatory requirements that might
significantly or uniquely affect small governments.
In light of the interest in these rules among governmental
entities, the EPA
[[Page 33419]]
initiated consultation with governmental entities. The EPA invited the
following 10 national organizations representing State and local
elected officials to a virtual meeting on September 22, 2022: (1)
National Governors Association, (2) National Conference of State
Legislatures, (3) Council of State Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6) National Association of
Counties, (7) International City/County Management Association, (8)
National Association of Towns and Townships, (9) County Executives of
America, and (10) Environmental Council of States. These 10
organizations representing elected State and local officials have been
identified by the EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. Also, the
EPA invited air and utility professional groups who may have State and
local government members, including the Association of Air Pollution
Control Agencies, National Association of Clean Air Agencies, and
American Public Power Association, Large Public Power Council, National
Rural Electric Cooperative Association, and National Association of
Regulatory Utility Commissioners to participate in the meeting. The
purpose of the consultation was to provide general background on these
rulemakings, answer questions, and solicit input from State and local
governments. Subsequent to the September 22, 2022, meeting, the EPA
received letters from five organizations. These letters were submitted
to the pre-proposal non-rulemaking docket. See Docket ID No. EPA-HQ-
OAR-2022-0723-0013, EPA-HQ-OAR-2022-0723-0016, EPA-HQ-OAR-2022-0723-
0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-2022-0723-0021. For
summary of the UMRA consultation see the memorandum in the docket
titled, Federalism Pre-Proposal Consultation Summary.
E. Executive Order 13132: Federalism
The proposed NSPS and the proposed repeal of the ACE Rule do not
have federalism implications. These actions will not have substantial
direct effects on the states, on the relationship between the national
government and the states, or on the distribution of power and
responsibilities among the various levels of government.
The EPA has concluded that the proposed emission guidelines may
have federalism implications, because they may impose substantial
direct compliance costs on State or local governments, and the Federal
Government will not provide the funds necessary to pay these costs.
Any potential federalism implications arise from the provisions of
CAA section 111(d)(1), which direct the EPA to ``prescribe regulations
. . . under which each State shall submit to the [EPA] a [state] plan .
. .'' establishing standards of performance for sources in the State.
As discussed in the Supporting Statement found in the docket for this
rulemaking, the development of State plans will entail many hours of
staff time to develop and coordinate programs for compliance with the
proposed emission guidelines, as well as time to work with State
legislatures as appropriate, and develop a plan submittal.
Although the direct compliance costs may not be substantial, the
EPA nonetheless elected to consult with representatives of State and
local governments in the process of developing these actions to permit
them to have meaningful and timely input into their development. The
EPA's consultation regarded planned actions for the NSPS and emission
guidelines. The EPA invited the following 10 national organizations
representing State and local elected officials to a virtual meeting on
September 22, 2022: (1) National Governors Association, (2) National
Conference of State Legislatures, (3) Council of State Governments, (4)
National League of Cities, (5) U.S. Conference of Mayors, (6) National
Association of Counties, (7) International City/County Management
Association, (8) National Association of Towns and Townships, (9)
County Executives of America, and (10) Environmental Council of States.
These 10 organizations representing elected State and local officials
have been identified by the EPA as the ``Big 10'' organizations
appropriate to contact for purpose of consultation with elected
officials. Also, the EPA invited air and utility professional groups
who may have State and local government members, including the
Association of Air Pollution Control Agencies, National Association of
Clean Air Agencies, and American Public Power Association, Large Public
Power Council, National Rural Electric Cooperative Association, and
National Association of Regulatory Utility Commissioners to participate
in the meeting. The purpose of the consultation was to provide general
background on these rulemakings, answer questions, and solicit input
from State and local governments. Subsequent to the September 22, 2022,
meeting, the EPA received letters from five organizations. These
letters were submitted to the pre-proposal non-rulemaking docket. See
Docket ID No. EPA-HQ-OAR-2022-0723-0013, EPA-HQ-OAR-2022-0723-0016,
EPA-HQ-OAR-2022-0723-0017, EPA-HQ-OAR-2022-0723-0020, and EPA-HQ-OAR-
2022-0723-0021. For a summary of the Federalism consultation see the
memorandum in the docket titled Federalism Pre-Proposal Consultation
Summary. A detailed Federalism Summary Impact Statement (FSIS)
describing the most pressing issues raised in pre-proposal and post-
proposal comments will be forthcoming with the final emission
guidelines, as required by section 6(b) of Executive Order 13132. In
the spirit of E.O. 13132, and consistent with EPA policy to promote
communications between State and local governments, the EPA
specifically solicits comment on these proposed actions from State and
local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
These actions do not have Tribal implications, as specified in
Executive Order 13175. The proposed NSPS would impose requirements on
owners and operators of new or reconstructed stationary combustion
turbines and emission guidelines would not impose direct requirements
on Tribal governments. Tribes are not required to develop plans to
implement the emission guidelines developed under CAA section 111(d)
for designated EGUs. The EPA is aware of six fossil fuel-fired steam
generating units located in Indian country but is not aware of any
fossil fuel-fired steam generating units owned or operated by Tribal
entities. The EPA notes that the proposed emission guidelines do not
directly impose specific requirements on EGU sources, including those
located in Indian country, but before developing any standards for
sources on Tribal land, the EPA would consult with leaders from
affected Tribes. Thus, Executive Order 13175 does not apply to these
actions.
Because the EPA is aware of Tribal interest in these proposed rules
and consistent with the EPA Policy on Consultation and Coordination
with Indian Tribes, the EPA offered government-to-government
consultation with Tribes and conducted stakeholder engagement.
The EPA will hold additional meetings with Tribal environmental
staff to inform them of the content of these proposed rules as well as
offer government-to-government consultation with Tribes. The EPA
specifically
[[Page 33420]]
solicits additional comment on these proposed rules from Tribal
officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks Populations and Low-Income Populations
Executive Order 13045 (62 FR 19885, April 23, 1997) directs Federal
agencies to include an evaluation of the health and safety effects of
the planned regulation on children in Federal health and safety
standards and explain why the regulation is preferable to potentially
effective and reasonably feasible alternatives. This action is not
subject to Executive Order 13045 because the EPA does not believe the
environmental health risks or safety risks addressed by this action
present a disproportionate risk to children. The EPA evaluated the
health benefits of the CO2, ozone and PM2.5
emissions reductions and the results of this evaluation are contained
in the RIA and are available in the docket. The EPA believes that the
PM2.5-related, ozone-related, and CO2-related
benefits projected under these proposed rules will improve children's
health. Additionally, the PM2.5 and ozone EJ exposure
analyses in section 6 of the RIA suggests that nationally, children
(ages 0-17) will experience at least as great a reduction in
PM2.5 and ozone exposures as adults (ages 18-64) in 2028,
2030, 2035 and 2040 under all regulatory alternatives of these
rulemakings.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
These actions, which are significant regulatory actions under
Executive Order 12866, are likely to have a significant adverse effect
on the supply, distribution or use of energy. The EPA has prepared a
Statement of Energy Effects for these action as follows. This analysis
pertains to the proposed standards for new combustion turbines and for
existing steam generating EGUs, and does not include the impact of the
proposed standards for existing combustion turbines and the third phase
of the proposed standards for new combustion turbines. The EPA
estimates a 0.2 percent increase in retail electricity prices on
average, across the contiguous U.S. in 2035, and a 28 percent reduction
in coal-fired electricity generation in 2035 as a result of these
actions. The EPA projects that utility power sector delivered natural
gas prices will decrease 2.4 percent in 2035. For more information on
the estimated energy effects, please refer sections 5.1 and 8.3.3 of
the RIA, which is in the public docket.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
These proposed actions involve technical standards. Therefore, the
EPA conducted searches for the New Source Performance Standards for
Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil
Fuel-Fired Electric Generating Units; Emission Guidelines for
Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric
Generating Units; and Repeal of the Affordable Clean Energy Rule
through the Enhanced National Standards Systems Network (NSSN) Database
managed by the American National Standards Institute (ANSI). Searches
were conducted for EPA Method 19 of 40 CFR part 60, appendix A. No
applicable voluntary consensus standards were identified for EPA Method
19. For additional information, please see the March 23, 2023,
memorandum titled, Voluntary Consensus Standard Results for New Source
Performance Standards for Greenhouse Gas Emissions from New, Modified,
and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission
Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired
Electric Generating Units; and Repeal of the Affordable Clean Energy
Rule.
The EPA welcomes comments on this aspect of the proposed
rulemakings and, specifically, invites the public to identify
potentially applicable VCS and to explain why such standards should be
used in these regulations.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629; February 16, 1994) directs
Federal agencies, to the greatest extent practicable and permitted by
law, to make environmental justice part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations (people of color and/or Indigenous
peoples) and low-income populations.
For new sources constructed after the date of publication of this
proposed action under CAA section 111(b), the EPA believes that it is
not practicable to assess whether the human health or environmental
conditions that exist prior to this action result in disproportionate
and adverse effects on people of color, low-income populations and/or
Indigenous peoples, because the location and number of new sources is
unknown.
For existing sources of this proposed action under CAA section
111(d), the EPA believes that the human health or environmental
conditions that exist prior to this action result in or have the
potential to result in disproportionate and adverse human health or
environmental effects on people of color, low-income populations, and/
or Indigenous peoples. The EPA believes that this proposed action is
not likely to change disproportionate and adverse PM2.5
exposure impacts on people of color, low-income populations, Indigenous
peoples, and/or other potential populations of concern evaluated in the
future analytical years. The EPA also believes that this proposed
action is not likely to change disproportionate and adverse ozone
exposure impacts on people of color, low-income populations, Indigenous
peoples, and/or other potential populations of concern evaluated in
2028, 2035, and 2040. However, in the analytical year of 2030, this
action is likely to slightly increase existing national level
disproportionate and adverse ozone exposure impacts on Asian
populations, Hispanic populations, and those linguistically isolated.
The EPA believes that it is not practicable to assess whether the
GHG impacts associated with this action are likely to result in a
change in disproportionate and adverse effects on people of color, low-
income populations and/or Indigenous peoples. However, the EPA believes
that the projected total cumulative power sector reduction of 617
million metric tons of CO2 emissions between 2028 and 2042
will have a beneficial effect on populations at risk of climate change
effects/impacts. Research indicates that some communities of color,
specifically populations defined jointly by ethnic/racial
characteristics and geographic location, may be uniquely vulnerable to
climate change health impacts in the U.S. See sections VII, X, and XIV
of this preamble for further information regarding GHG controls and
emission reductions.
Michael S. Regan,
Administrator.
[FR Doc. 2023-10141 Filed 5-22-23; 8:45 am]
BILLING CODE 6560-50-P
