Emergency Application — Ohio, et al., Applicants v. Environmental Protection Agency, et al.
Supreme Court briefJul 29, 2024
Ask Donna
What actually matters in this document.
Text
Appendix A
39798
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ADDRESSES: The EPA has established a
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Part 60
[EPA–HQ–OAR–2023–0072; FRL–8536–01–
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: Final rule.
ddrumheller on DSK120RN23PROD with RULES3
SUMMARY: The Environmental Protection
Agency (EPA) is finalizing multiple
actions under section 111 of the Clean
Air Act (CAA) addressing greenhouse
gas (GHG) emissions from fossil fuelfired electric generating units (EGUs).
First, the EPA is finalizing the repeal of
the Affordable Clean Energy (ACE) Rule.
Second, the EPA is finalizing 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. Third, the EPA is
finalizing revisions to the New Source
Performance Standards (NSPS) for GHG
emissions from new and reconstructed
fossil fuel-fired stationary combustion
turbine EGUs. Fourth, the EPA is
finalizing revisions to the NSPS 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. The EPA
is not finalizing emission guidelines for
GHG emissions from existing fossil fuelfired stationary combustion turbines at
this time; instead, the EPA intends to
take further action on the proposed
emission guidelines at a later date.
DATES: This final rule is effective on July
8, 2024. The incorporation by reference
of certain publications listed in the rules
is approved by the Director of the
Federal Register as of July 8, 2024. The
incorporation by reference of certain
other materials listed in the rule was
approved by the Director of the Federal
Register as of October 23, 2015.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
docket for these actions under Docket ID
No. EPA–HQ–OAR–2023–0072. All
documents in the docket are listed on
the https://www.regulations.gov
website. Although listed, 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 form.
Publicly available docket materials are
available electronically through https://
www.regulations.gov.
FOR FURTHER INFORMATION CONTACT: Lisa
Thompson (she/her), Sector Policies and
Programs Division (D243–02), Office of
Air Quality Planning and Standards,
U.S. Environmental Protection Agency,
109 T.W. Alexander Drive, P.O. Box
12055, Research Triangle Park, North
Carolina 27711; telephone number:
(919) 541–5158; and email address:
thompson.lisa@epa.gov.
SUPPLEMENTARY INFORMATION:
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
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
CO2 carbon dioxide
DER distributed energy resources
DOE Department of Energy
EEA energy emergency alert
EGU electric generating unit
EIA Energy Information Administration
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
FEED front-end engineering and design
FGD flue gas desulfurization
FR Federal Register
GHG greenhouse gas
GW gigawatt
GWh gigawatt-hour
HAP hazardous air pollutant
HRSG heat recovery steam generator
IIJA Infrastructure Investment and Jobs Act
PO 00000
Frm 00002
Fmt 4701
Sfmt 4700
IRC Internal Revenue Code
kg kilogram
kWh kilowatt-hour
LCOE levelized cost of electricity
LNG liquefied natural gas
MATS Mercury and Air Toxics Standards
MMBtu/h million British thermal units per
hour
MMT CO2e million metric tons of carbon
dioxide equivalent
MW megawatt
MWh megawatt-hour
NAAQS National Ambient Air Quality
Standards
NESHAP National Emission Standards for
Hazardous Air Pollutants
NGCC natural gas combined cycle
NOX nitrogen oxides
NSPS new source performance standards
NSR New Source Review
PM particulate matter
PM2.5 fine particulate matter
RIA regulatory impact analysis
TSD technical support document
U.S. United States
Organization of this document. The
information in this preamble is
organized as follows:
I. Executive Summary
A. Climate Change and Fossil Fuel-Fired
EGUs
B. Recent Developments in Emissions
Controls and the Electric Power Sector
C. Summary of the Principal Provisions of
These Regulatory Actions
D. Grid Reliability Considerations
E. Environmental Justice Considerations
F. Energy Workers and Communities
G. Key Changes From Proposal
II. General Information
A. Action Applicability
B. Where To Get a Copy of This Document
and Other Related Information
III. Climate Change Impacts
IV. Recent Developments in Emissions
Controls and the Electric Power Sector
A. Background
B. GHG Emissions From Fossil Fuel-Fired
EGUs
C. Recent Developments in Emissions
Control
D. The Electric Power Sector: Trends and
Current Structure
E. The Legislative, Market, and State Law
Context
F. Future 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
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-1
ddrumheller on DSK120RN23PROD with RULES3
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
VI. 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. Withdrawal of Proposed NSR Revisions
VII. Regulatory Approach for Existing Fossil
Fuel-Fired Steam Generating Units
A. Overview
B. Applicability Requirements and Fossil
Fuel-Type Definitions for Subcategories
of Steam Generating Units
C. Rationale for the BSER for Coal-Fired
Steam Generating Units
D. Rationale for the BSER for Natural GasFired and Oil-Fired Steam Generating
Units
E. Additional Comments Received on the
Emission Guidelines for Existing Steam
Generating Units and Responses
F. Regulatory Requirement To Review
Emission Guidelines for Coal-Fired Units
VIII. Requirements for New and
Reconstructed Stationary Combustion
Turbine EGUs and Rationale for
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. Standards of Performance
H. Reconstructed Stationary Combustion
Turbines
I. Modified Stationary Combustion
Turbines
J. Startup, Shutdown, and Malfunction
K. Testing and Monitoring Requirements
L. Recordkeeping and Reporting
Requirements
M. Compliance Dates
N. Compliance Date Extension
IX. Requirements for New, Modified, and
Reconstructed Fossil Fuel-Fired Steam
Generating Units
A. 2018 NSPS Proposal Withdrawal
B. Additional Amendments
C. Eight-Year Review of NSPS for Fossil
Fuel-Fired Steam Generating Units
D. Projects Under Development
X. State Plans for Emission Guidelines for
Existing Fossil Fuel-Fired EGUs
A. Overview
B. Requirement for State Plans To Maintain
Stringency of the EPA’s BSER
Determination
C. Establishing Standards of Performance
D. Compliance Flexibilities
E. State Plan Components and Submission
XI. Implications for Other CAA Programs
A. New Source Review Program
B. Title V Program
XII. Summary of Cost, Environmental, and
Economic Impacts
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
A. Air Quality Impacts
B. Compliance Cost Impacts
C. Economic and Energy Impacts
D. Benefits
E. Net Benefits
F. Environmental Justice Analytical
Considerations and Stakeholder
Outreach and Engagement
G. Grid Reliability Considerations and
Reliability-Related Mechanisms
XIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 14094: Modernizing 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 and Executive Order 14096:
Revitalizing Our Nation’s Commitment
to Environmental Justice for All
K. Congressional Review Act (CRA)
XIV. Statutory Authority
I. 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.2 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 2021.3 At the same time, a
range of cost-effective technologies and
approaches to reduce GHG emissions
from these sources is available to the
power sector—including carbon capture
and sequestration/storage (CCS), cofiring with less GHG-intensive fuels,
1 74 FR 66496 (December 15, 2009).
2 The 5th National Climate Assessment (NCA5)
states that the effects of human-caused climate
change are already far-reaching and worsening
across every region of the United States and that
climate change affects all aspects of the energy
system-supply, delivery, and demand-through the
increased frequency, intensity, and duration of
extreme events and through changing climate
trends.
3 https://www.epa.gov/ghgemissions/sourcesgreenhouse-gas-emissions.
PO 00000
Frm 00003
Fmt 4701
Sfmt 4700
39799
and more efficient generation. Congress
has also acted to provide funding and
other incentives to encourage the
deployment of various technologies,
including CCS, to achieve reductions in
GHG emissions from the power sector.
In this notice, the EPA is finalizing
several actions under section 111 of the
Clean Air Act (CAA) to reduce the
significant quantity of GHG emissions
from fossil fuel-fired EGUs by
establishing emission guidelines and
new source performance standards
(NSPS) that are based on available and
cost-effective technologies that directly
reduce GHG emissions from these
sources. Consistent with the statutory
command of CAA section 111, the final
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 first finalizing
the repeal of the Affordable Clean
Energy (ACE) Rule. Second, the EPA is
finalizing 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. Third, the EPA is
finalizing revisions to the NSPS for GHG
emissions from new and reconstructed
fossil fuel-fired stationary combustion
turbine EGUs. Fourth, the EPA is
finalizing revisions to the NSPS 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. The EPA
is not finalizing emission guidelines for
GHG emissions from existing fossil fuelfired combustion turbines at this time
and plans to expeditiously issue an
additional proposal that more
comprehensively addresses GHG
emissions from this portion of the fleet.
The EPA acknowledges that the share of
GHG emissions from existing fossil fuelfired combustion turbines has been
growing and is projected to continue to
do so, particularly as emissions from
other portions of the fleet decline, and
that it is vital to regulate the GHG
emissions from these sources consistent
with CAA section 111.
These final actions ensure that the
new and existing fossil fuel-fired EGUs
that are subject to these rules 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
standards and emission guidelines will
significantly decrease GHG emissions
from fossil fuel-fired EGUs and the
associated harms to human health and
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-2
ddrumheller on DSK120RN23PROD with RULES3
39800
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
welfare. Further, the EPA has designed
these standards and emission guidelines
in a way that is compatible with the
nation’s overall need for a reliable
supply of affordable electricity.
reducing GHG emissions from these
affected sources can also help reduce
power sector pollution that might
otherwise result from the electrification
of other sectors of the economy.
A. Climate Change and Fossil Fuel-Fired
EGUs
These final actions reduce the
emissions of GHGs from new and
existing fossil fuel-fired EGUs. 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 threaten human
health and welfare.
Fossil fuel-fired EGUs that are
uncontrolled for GHGs are one of the
biggest domestic sources of GHG
emissions. At the same time, there are
technologies available (including
technologies that can be applied to
fossil fuel-fired power plants) to
significantly reduce emissions of GHGs
from the power sector. Low- and zeroGHG electricity are also key enabling
technologies to significantly reduce
GHG emissions in almost every other
sector of the economy.
In 2021, the power sector was the
largest stationary source of GHGs in the
United States, emitting 25 percent of
overall domestic emissions.4 In 2021,
existing fossil fuel-fired steam
generating units accounted for 65
percent of the GHG emissions from the
sector, but only accounted for 23
percent of the total electricity
generation.
Because of its outsized contributions
to overall emissions, reducing emissions
from the power sector is essential to
addressing the challenge of climate
change—and sources in the power
sector also have many available options
for reducing their climate-destabilizing
emissions. Particularly relevant to these
actions are several key technologies
(CCS and co-firing of lower-GHG fuels)
that allow fossil fuel-fired steam
generating EGUs and stationary
combustion turbines 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,
B. Recent Developments in Emissions
Controls and the Electric Power Sector
Several recent developments
concerning emissions controls are
relevant for the EPA’s determination of
the BSER for existing coal-fired steam
generating EGUs and new natural gasfired stationary combustion turbines.
These include lower costs and
continued improvements in CCS
technology, alongside Federal tax
incentives that allow companies to
largely offset the cost of CCS. Wellestablished trends in the sector further
inform where using such technologies is
cost effective and feasible, and form part
of the basis for the EPA’s determination
of the BSER.
In recent years, the cost of CCS has
declined in part because of process
improvements learned from earlier
deployments and other advances in the
technology. In addition, the Inflation
Reduction Act (IRA), enacted in 2022,
extended and significantly increased the
tax credit for carbon dioxide (CO2)
sequestration under Internal Revenue
Code (IRC) section 45Q. The provision
of tax credits in the IRA, combined with
the funding included in the
Infrastructure Investment and Jobs Act
(IIJA), enacted in 2021, incentivize and
facilitate the deployment of CCS and
other GHG emission control
technologies. As explained later in this
preamble, these developments support
the EPA’s conclusion that CCS is the
BSER for certain subcategories of new
and existing EGUs because it is an
adequately demonstrated and available
control technology that significantly
reduces emissions of dangerous
pollution and because the costs of its
installation and operation are
reasonable. Some companies have
already made plans to install CCS on
their units independent of the EPA’s
regulations.
Well documented trends in the power
sector also influence the EPA’s
determination of the BSER. In
particular, CCS entails significant
capital expenditures and is only costreasonable for units that will operate
enough to defray those capital costs. At
the same time, many utilities and power
generating companies have recently
announced plans to accelerate changing
the mix of their generating assets. The
IIJA and IRA, state legislation,
technology advancements, market
forces, consumer demand, and the
advanced age of much of the existing
4 https://www.epa.gov/ghgemissions/sourcesgreenhouse-gas-emissions.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
PO 00000
Frm 00004
Fmt 4701
Sfmt 4700
fossil fuel-fired generating fleet are
collectively leading to, in most cases,
decreased use of the fossil fuel-fired
units that are the subjects of these final
actions. From 2010 through 2022, fossil
fuel-fired generation declined from
approximately 72 percent of total net
generation to approximately 60 percent,
with generation from coal-fired sources
dropping from 49 percent to 20 percent
of net generation during this period.5
These trends are expected to continue
and are relevant to determining where
capital-intensive technologies, like CCS,
may be feasibly and cost-reasonably
deployed to reduce emissions.
Congress has taken other recent
actions to drive the reduction of GHG
emissions from the power sector. As
noted earlier, Congress enacted IRC
section 45Q in section 115 of the Energy
Improvement and Extension Act of 2008
to provide a tax credit for the
sequestration of CO2. Congress
significantly amended IRC section 45Q
in the Bipartisan Budget Act of 2018,
and more recently in the IRA, to make
this tax incentive more generous and
effective in spurring long-term
deployment of CCS. In addition, the IIJA
provided more than $65 billion for
infrastructure investments and upgrades
for transmission capacity, pipelines, and
low-carbon fuels.6 Further, 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 could provide additional low-cost
options for power companies to reduce
overall GHG emissions.7 As discussed
in greater detail in section IV.E.1 of this
preamble, the IRA, the IIJA, and CHIPS
contain numerous other provisions
encouraging companies to reduce their
GHGs.
C. Summary of the Principal Provisions
of These Regulatory Actions
These final actions include the repeal
of the ACE Rule, BSER determinations
and emission guidelines for existing
fossil fuel-fired steam generating units,
and BSER determinations and
accompanying standards of performance
for GHG emissions from new and
reconstructed fossil fuel-fired stationary
combustion turbines and modified fossil
fuel-fired steam generating units.
5 U.S. Energy Information Administration (EIA).
Electric Power Annual. 2010 and 2022. https://
www.eia.gov/electricity/annual/html/epa_03_01_
a.html.
6 https://www.congress.gov/bill/117th-congress/
house-bill/3684.
7 https://www.congress.gov/bill/117th-congress/
house-bill/4346.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-3
ddrumheller on DSK120RN23PROD with RULES3
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
The EPA is taking these actions
consistent with its authority under CAA
section 111. Under CAA section 111,
once the EPA has identified a source
category that contributes significantly to
dangerous air pollution, 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, nonair quality health and environmental
impacts, and energy requirements.8 The
EPA may determine that different sets of
sources have different characteristics
relevant for determining the BSER and
may subcategorize sources accordingly.
Once it identifies the BSER, the EPA
must determine the ‘‘degree of emission
limitation’’ achievable by application of
the BSER. For new sources, the EPA
establishes 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
in 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 CAA
section 111 for more than 60 source
categories, which has established a
robust set of regulatory precedents that
has informed the development of these
final actions. 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 CAA section
111. As the Supreme Court has
recognized, the EPA has typically (and
does so in these actions) determined the
BSER to be ‘‘measures that improve the
pollution performance of individual
sources,’’ such as add-on controls and
clean fuels. West Virginia v. EPA, 597
U.S. 697, 734 (2022). For present
purposes, several of a BSER’s key
features include that it must reduce
emissions, be based on ‘‘adequately
demonstrated’’ technology, and have a
reasonable cost of control. The case law
interpreting section 111 has also
recognized that the BSER can be
forward-looking in nature and take into
account anticipated improvements in
control technologies. For example, the
EPA may determine a control to be
‘‘adequately demonstrated’’ even if it is
new and not yet in widespread
8 CAA section 111(a)(1).
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
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. Further, the
most relevant costs under CAA section
111 are the costs to the regulated
facility. The actions that the EPA is
finalizing are consistent with the
requirements of CAA section 111 and its
regulatory history and caselaw, which is
discussed in further detail in section V
of this preamble.
1. Repeal of ACE Rule
The EPA is finalizing its proposed
repeal of the existing ACE Rule
emission guidelines. First, as a policy
matter, the EPA concludes that the suite
of heat rate improvements (HRI) that
was identified in the ACE Rule as the
BSER is not an appropriate BSER for
existing coal-fired EGUs. Second, the
ACE Rule rejected CCS and natural gas
co-firing as the BSER for reasons that no
longer apply. Third, the EPA concludes
that the ACE Rule conflicted with CAA
section 111 and the EPA’s implementing
regulations because it did not provide
sufficient specificity as to the BSER the
EPA had identified or the ‘‘degree of
emission limitation achievable though
application of the [BSER].’’
Also, the EPA is withdrawing the
proposed revisions to the New Source
Review (NSR) regulations that were
included the ACE Rule proposal (83 FR
44773–83; August 31, 2018).
2. Emission Guidelines for Existing
Fossil Fuel-Fired Steam Generating
Units
The EPA is finalizing CCS with 90
percent capture as BSER for existing
coal-fired steam generating units. These
units have a presumptive standard 9 of
an 88.4 percent reduction in annual
emission rate, with a compliance
deadline of January 1, 2032. As
explained in detail below, CCS is an
adequately demonstrated technology
that achieves significant emissions
reduction and is cost-reasonable, taking
into account the declining costs of the
technology and a substantial tax credit
available to sources. In recognition of
the significant capital expenditures
involved in deploying CCS technology
and the fact that 45 percent of regulated
units already have announced
retirement dates, the EPA is finalizing a
separate subcategory for existing coal9 Presumptive standards of performance are
discussed in detail in section X 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.
PO 00000
Frm 00005
Fmt 4701
Sfmt 4700
39801
fired steam generating units that
demonstrate that they plan to
permanently cease operation before
January 1, 2039. The BSER for this
subcategory is co-firing with natural gas,
at a level of 40 percent of the unit’s
annual heat input. These units have a
presumptive standard of 16 percent
reduction in annual emission rate
corresponding to this BSER, with a
compliance deadline of January 1, 2030.
The EPA is finalizing an applicability
exemption for existing coal-fired steam
EGUs demonstrating that they plan to
permanently cease operation prior to
January 1, 2032, based on the Agency’s
determination that units retiring before
this date generally do not have costreasonable options for improving their
GHG emissions performance. Sources
that demonstrate they will permanently
cease operation before this applicability
deadline will not be subject to these
emission guidelines. Further, the EPA is
not finalizing the proposed imminentterm or near-term subcategories.
The EPA is finalizing the proposed
structure of the subcategory definitions
for natural gas- and oil-fired steam
generating units. The EPA is also
finalizing routine methods of operation
and maintenance as the BSER for
intermediate load and base load natural
gas- and oil-fired steam generating units.
Furthermore, the EPA is finalizing
presumptive standards for natural gasand oil-fired steam generating units that
are slightly higher than at proposal: base
load sources (those with annual
capacity factors greater than 45 percent)
have a presumptive standard of 1,400 lb
CO2/MWh-gross, and intermediate load
sources (those with annual capacity
factors greater than 8 percent and less
than or equal to 45 percent) have a
presumptive standard of 1,600 lb CO2/
MWh-gross. For low load (those with
annual capacity factors less than 8
percent), the EPA is finalizing a uniform
fuels BSER and a presumptive inputbased standard of 170 lb CO2/MMBtu
for oil-fired sources and a presumptive
standard of 130 lb CO2/MMBtu for
natural gas-fired sources.
3. Standards of Performance for New
and Reconstructed Fossil Fuel-Fired
Combustion Turbines
The EPA is finalizing emission
standards for three subcategories of
combustion turbines—base load,
intermediate load, and low load. The
BSER for base load combustion turbines
includes two components to be
implemented initially in two phases.
The first component of the BSER for
base load combustion turbines is highly
efficient generation (based on the
emission rates that the best performing
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-4
39802
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
units are achieving) and the second
component for base load combustion
turbines is utilization of CCS with 90
percent capture. Recognizing the lead
time that is necessary for new base load
combustion turbines to plan for and
install the second component of the
BSER (i.e., 90 percent CCS), including
the time that is needed to deploy the
associated infrastructure (CO2 pipelines,
storage sites, etc.), the EPA is finalizing
a second phase compliance deadline of
January 1, 2032, for this second
component of the standard.
The EPA has identified highly
efficient simple cycle generation as the
BSER for intermediate load combustion
turbines. For low load combustion
turbines, the EPA is finalizing its
proposed determination that the BSER
is the use of lower-emitting fuels.
4. New, Modified, and Reconstructed
Fossil Fuel-Fired Steam Generating
Units
The EPA is finalizing revisions of the
standards of performance for coal-fired
steam generating units that undertake a
large modification (i.e., a modification
that increases its hourly emission rate
by more than 10 percent) to mirror the
emission guidelines for existing coalfired steam generators. This reflects the
EPA’s determination that such modified
sources are capable of meeting the same
presumptive standards that the EPA is
finalizing for existing steam EGUs.
Further, this revised standard for
modified coal-fired steam EGUs will
avoid creating an unjustified disparity
between emission control obligations for
modified and existing coal-fired steam
EGUs.
The EPA did not propose, and we are
not finalizing, any review or revision of
the 2015 standard for large
modifications of oil- or gas-fired steam
generating units because we are not
aware of any existing oil- or gas-fired
steam generating EGUs that have
undertaken such modifications or have
plans to do so, and, unlike an existing
coal-fired steam generating EGUs,
existing oil- or gas-fired steam units
have no incentive to undertake such a
modification to avoid the requirements
we are including in this final rule for
existing oil- or gas-fired steam
generating units.
As discussed in the proposal
preamble, the EPA is not revising the
NSPS for newly constructed or
reconstructed fossil fuel-fired steam
electric generating units (EGU) at this
time because the EPA anticipates that
few, if any, such units will be
constructed or reconstructed in the
foreseeable future. However, the EPA
has recently become aware that a new
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
coal-fired power plant is under
consideration in Alaska. Accordingly,
the EPA is not, at this time, finalizing
its proposal not to review the 2015
NSPS, and, instead, will continue to
consider whether to review the 2015
NSPS. As developments warrant, the
EPA will determine either to conduct a
review, and propose revised standards
of performance, or not conduct a review.
Also, in this final action, the EPA is
withdrawing the 2018 proposed
amendments 10 to the NSPS for GHG
emissions from coal-fired EGUs.
5. Severability
This final action is composed of four
independent rules: the repeal of the
ACE rule; GHG emission guidelines for
existing fossil fuel-fired steam
generating units; NSPS for GHG
emissions from new and reconstructed
fossil fuel-fired combustion turbines;
and revisions to the standards of
performance for new, modified, and
reconstructed fossil fuel-fired steam
generating units. The EPA could have
finalized each of these rules in separate
Federal Register notices as separate
final actions. The Agency decided to
include these four independent rules in
a single Federal Register notice for
administrative ease because they all
relate to climate pollution from the
fossil fuel-fired electric generating units
source category. Accordingly, despite
grouping these rules into one single
Federal Register notice, the EPA
intends that each of these rules
described in sections I.C.1 through I.C.4
is severable from the other.
In addition, each rule is severable as
a practical matter. For example, the EPA
would repeal the ACE Rule separate and
apart from finalizing new standards for
these sources as explained herein.
Moreover, the BSER and associated
emission guidelines for existing fossil
fuel-fired steam generating units are
independent of and would have been
the same regardless of whether the EPA
finalized the other parts of this rule. In
determining the BSER for existing fossil
fuel-fired steam generating units, the
EPA considered only the technologies
available to reduce GHG emissions at
those sources and did not take into
consideration the technologies or
standards of performance for new fossil
fuel-fired combustion turbines. The
same is true for the Agency’s evaluation
and determination of the BSER and
associated standards of performance for
new fossil fuel-fired combustion
turbines. The EPA identified the BSER
and established the standards of
performance by examining the controls
10 See 83 FR 65424, December 20, 2018.
PO 00000
Frm 00006
Fmt 4701
Sfmt 4700
that were available for these units. That
analysis can stand alone and apart from
the EPA’s separate analysis for existing
fossil fuel-fired steam generating units.
Though the record evidence (including,
for example, modeling results) often
addresses the availability, performance,
and expected implementation of the
technologies at both existing fossil fuelfired steam generating units and new
fossil fuel-fired combustion turbines in
the same record documents, the
evidence for each evaluation stands on
its own, and is independently sufficient
to support each of the final BSERs.
In addition, within section I.C.1, the
final action to repeal the ACE Rule is
severable from the withdrawal of the
NSR revisions that were proposed in
parallel with the ACE Rule proposal.
Within the group of actions for existing
fossil fuel-fired steam generating units
in section I.C.2, the requirements for
each subcategory of existing sources are
severable from the requirements for
each other subcategory of existing
sources. For example, if a court were to
invalidate the BSER and associated
emission standard for units in the
medium-term subcategory, the BSER
and associated emission standard for
units in the long-term subcategory could
function sensibly because the
effectiveness of the BSER for each
subcategory is not dependent on the
effectiveness of the BSER for other
subcategories. Within the group of
actions for new and reconstructed fossil
fuel-fired combustion turbines in
section I.C.3, the following actions are
severable: the requirements for each
subcategory of new and reconstructed
turbines are severable from the
requirements for each other subcategory;
and within the subcategory for base load
turbines, the requirements for each of
the two components are severable from
the requirements for the other
component. Each of these standards can
function sensibly without the others.
For example, the BSER for low load,
intermediate load, and base load
subcategories is based on the
technologies the EPA determined met
the statutory standards for those
subcategories and are independent from
each other. And in the base load
subcategory units may practically be
constructed using the most efficient
technology without then installing CCS
and likewise may install CCS on a
turbine system that was not constructed
with the most efficient technology.
Within the group of actions for new,
modified, and reconstructed fossil fuelfired steam generating units in section
I.C.4, the revisions of the standards of
performance for coal-fired steam
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-5
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
generators that undertake a large
modification are severable from the
withdrawal of the 2018 proposal to
revise the NSPS for emissions of GHG
from EGUs. Each of the actions in these
final rules that the EPA has identified as
severable is functionally independent—
i.e., may operate in practice
independently of the other actions.
In addition, while the EPA is
finalizing this rule at the same time as
other final rules regulating different
types of pollution from EGUs—
specifically the Supplemental Effluent
Limitations Guidelines and Standards
for the Steam Electric Power Generating
Point Source Category (FR 2024–09815,
EPA–HQ–OW–2009–0819; FRL–8794–
02–OW); National Emission Standards
for Hazardous Air Pollutants: Coal and
Oil-Fired Electric Utility Steam
Generating Units Review of the Residual
Risk and Technology Review (FR 2024–
09148, EPA–HQ–OAR–2018–0794;
FRL–6716.3–02–OAR); Hazardous and
Solid Waste Management System:
Disposal of Coal Combustion Residuals
From Electric Utilities; Legacy CCR
Surface Impoundments (FR 2024–
09157, EPA–HQ–OLEM–2020–0107;
FRL–7814–04–OLEM)—and has
considered the interactions between and
cumulative effects of these rules, each
rule is based on different statutory
authority, a different record, and is
completely independent of the other
rules.
ddrumheller on DSK120RN23PROD with RULES3
D. Grid Reliability Considerations
The EPA is finalizing multiple
adjustments to the proposed rules that
ensure the requirements in these final
actions can be implemented without
compromising the ability of power
companies, grid operators, and state and
Federal energy regulators to maintain
resource adequacy and grid reliability.
In response to the May 2023 proposed
rule, the EPA received extensive
comments from balancing authorities,
independent system operators and
regional transmission organizations,
state regulators, power companies, and
other stakeholders on the need for the
final rule to accommodate resource
adequacy and grid reliability needs. The
EPA also engaged with the balancing
authorities that submitted comments to
the docket, the staff and Commissioners
of the Federal Energy Regulatory
Commission (FERC), the Department of
Energy (DOE), the North American
Electric Reliability Corporation (NERC),
and other expert entities during the
course of this rulemaking. Finally, at the
invitation of FERC, the EPA participated
in FERC’s Annual Reliability Technical
Conference on November 9, 2023.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
These final actions respond to this
input and feedback in multiple ways,
including through changes to the
universe of affected sources, longer
compliance timeframes for CCS
implementation, and other compliance
flexibilities, as well as articulation of
the appropriate use of RULOF to
address reliability issues during state
plan development and in subsequent
state plan revisions. In addition to these
adjustments, the EPA is finalizing
several programmatic mechanisms
specifically designed to address
reliability concerns raised by
commenters. For existing fossil fuelfired EGUs, a short-term reliability
emergency mechanism is available for
states to provide more flexibility by
using an alternative emission limitation
during acute operational emergencies
when the grid might be temporarily
under heavy strain. A similar short-term
reliability emergency mechanism is also
available to new sources. In addition,
the EPA is creating an option for states
to provide for a compliance date
extension for existing sources of up to
1 year under certain circumstances for
sources that are installing control
technologies to comply with their
standards of performance. Lastly, states
may also provide, by inclusion in their
state plans, a reliability assurance
mechanism of up to 1 year that under
limited circumstances would allow
existing units that had planned to cease
operating by a certain date to
temporarily remain available to support
reliability. Any extensions exceeding 1
year must be addressed through a state
plan revision. In order to utilize this
reliability pathway, there must be an
adequate demonstration of need and
certification by a reliability authority,
and approval by the appropriate EPA
Regional Administrator. The EPA plans
to seek the advice of FERC for extension
requests exceeding 6 months. Similarly,
for new fossil fuel-fired combustion
turbines, the EPA is creating a
mechanism whereby baseload units may
request a 1-year extension of their CCS
compliance deadline under certain
circumstances.
The EPA has evaluated the resource
adequacy implications of these actions
in the final technical support document
(TSD), Resource Adequacy Analysis,
and conducted capacity expansion
modeling of the final rules in a manner
that takes into account resource
adequacy needs. The EPA finds that
resource adequacy can be maintained
with the final rules. The EPA modeled
a scenario that complies with the final
rules and that meets resource adequacy
needs. The EPA also performed a variety
PO 00000
Frm 00007
Fmt 4701
Sfmt 4700
39803
of other sensitivity analyses looking at
higher electricity demand (load growth)
and impact of the EPA’s additional
regulatory actions affecting the power
sector. These sensitivity analyses
indicate that, in the context of higher
demand and other pending power sector
rules, the industry has available
pathways to comply with this rule that
respect NERC reliability considerations
and constraints.
In addition, the EPA notes that
significant planning and regulatory
mechanisms exist to ensure that
sufficient generation resources are
available to maintain reliability. The
EPA’s consideration of reliability in this
rulemaking has also been informed by
consultation with the DOE under the
auspices of the March 9, 2023,
memorandum of understanding
(MOU) 11 signed by the EPA
Administrator and the Secretary of
Energy, as well as by consultation with
FERC expert staff. In these final actions,
the EPA has included various
flexibilities that allow power companies
and grid operators to plan for achieving
feasible and necessary reductions of
GHGs from affected sources consistent
with the EPA’s statutory charge while
ensuring that the rule will not interfere
with systems operators’ ability to ensure
grid reliability.
A thorough description of how
adjustments in the final rules address
reliability issues, the EPA’s outreach to
balancing authorities, EPA’s
supplemental notice, as well as the
introduction of mechanisms to address
short- and long-term reliability needs is
presented in section XII.F of this
preamble.
E. Environmental Justice Considerations
Consistent with Executive Order
(E.O.) 14096, and the EPA’s
commitment to upholding
environmental justice (EJ) across its
policies and programs, the EPA
carefully considered the impacts of
these actions on communities with
environmental justice concerns. As part
of the regulatory development process
for these rulemakings, and consistent
with directives set forth in multiple
Executive Orders, the EPA conducted
extensive outreach with interested
parties including Tribal nations and
communities with environmental justice
concerns. These opportunities gave the
EPA a chance to hear directly from the
public, including from communities
potentially impacted by these final
11 Joint Memorandum of Understanding on
Interagency Communication and Consultation on
Electric Reliability (March 9, 2023). https://
www.epa.gov/power-sector/electric-reliability-mou.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-6
39804
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
actions. The EPA took this feedback into
account in its development of these
final actions.12 The EPA’s analysis of
environmental justice in these final
actions is briefly summarized here and
discussed in further detail in sections
XII.E and XIII.J of the preamble and
section 6 of the regulatory impact
analysis (RIA).
Several environmental justice
organizations and community
representatives raised significant
concerns about the potential health,
environmental, and safety impacts of
CCS. The EPA takes these concerns
seriously, agrees that any impacts to
historically disadvantaged and
overburdened communities are
important to consider, and has carefully
considered these concerns as it finalized
its determinations of the BSERs for
these rules. The Agency acknowledges
that while these final actions will result
in large reductions of both GHGs and
other emissions that will have
significant positive benefits, there is the
potential for localized increases in
emissions, particularly if units installing
CCS operate for more hours during the
year and/or for more years than they
would have otherwise. However, as
discussed in section VII.C.1.a.iii(B), a
robust regulatory framework exists to
reduce the risks of localized emissions
increases in a manner that is protective
of public health, safety, and the
environment. The Council on
Environmental Quality’s (CEQ) February
2022 Carbon Capture, Utilization, and
Sequestration Guidance and the EPA’s
evaluation of BSER recognize that
multiple Federal agencies have
responsibility for regulating and
permitting CCS projects, along with
state and tribal governments. As the
CEQ has noted, Federal agencies have
‘‘taken actions in the past decade to
develop a robust carbon capture,
utilization, and sequestration/storage
(CCUS) regulatory framework to protect
the environment and public health
across multiple statutes.’’ 13 14
12 Specifically, the EPA has relied on, and is
incorporating as a basis for this rulemaking,
analyses regarding possible adverse environmental
effects from CCS, including those highlighted by
commenters. Consideration of these effects is
permissible under CAA section 111(a)(1). Although
the EPA also conducted analyses of
disproportionate impacts pursuant to E.O. 14096,
see section XII.E, the EPA did not consider or rely
on these analyses as a basis for these rules.
13 87 FR 8808, 8809 (February 16, 2022).
14 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 EPA’s Greenhouse
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
Furthermore, the EPA plans to review
and update as needed its guidance on
NSR permitting, specifically with
respect to BACT determinations for
GHG emissions and consideration of copollutant increases from sources
installing CCS. For the reasons
explained in section VII.C, the EPA is
finalizing the determination 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. At the same time, the
EPA recognizes the critical importance
of ensuring that the regulatory
framework performs as intended to
protect communities.
These actions are focused on
establishing NSPS and emission
guidelines for GHGs that states will
implement to significantly reduce GHGs
and move us a step closer to avoiding
the worst impacts of climate change,
which is already having a
disproportionate impact on
communities with environmental justice
concerns. The EPA analyzed several
illustrative scenarios representing
potential compliance outcomes and
evaluated the potential impacts that
these actions may have on emissions of
GHG and other health-harming air
pollutants from fossil fuel-fired EGUs,
as well as how these changes in
emissions might affect air quality and
public health, particularly for
communities with EJ concerns.
The EPA’s national-level analysis of
emission reduction and public health
impacts, which is documented in
section 6 of the RIA and summarized in
greater detail in section XII.A and XII.D
of this preamble, finds that these actions
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), resulting in
public health benefits. The EPA also
evaluated how the air quality impacts
associated with these final actions are
distributed, with particular focus on
communities with EJ concerns. As
discussed in the RIA, our analysis
indicates that baseline ozone and PM2.5
concentration will decline substantially
relative to today’s levels. Relative to
these low baseline levels, ozone and
PM2.5 concentrations will decrease
further in virtually all areas of the
country, although some areas of the
Gas Reporting Program (GHGRP); and safety
regulations for CO2 pipelines administered by the
Pipeline and Hazardous Materials and Safety
Administration (PHMSA).
PO 00000
Frm 00008
Fmt 4701
Sfmt 4700
country may experience slower or faster
rates of decline in ozone and PM2.5
pollution over time due to the changes
in generation and utilization resulting
from these rules. Additionally, our
comparison of future air quality
conditions with and without these rules
suggests that while these actions are
anticipated to lead to modest but
widespread reductions in ambient levels
of PM2.5 and ozone for a large majority
of the nation’s population, there is
potential for some geographic areas and
demographic groups to experience small
increases in ozone concentrations
relative to the baseline levels which are
projected to be substantially lower than
today’s levels.
It is important to recognize that while
these projections of emissions changes
and resulting air quality changes under
various illustrative compliance
scenarios are based upon the best
information available to the EPA at this
time, with regard to existing sources,
each state will ultimately be responsible
for determining the future operation of
fossil fuel-fired steam generating units
located within its jurisdiction. The EPA
expects that, in making these
determinations, states will consider a
number of factors and weigh input from
the wide range of potentially affected
stakeholders. The meaningful
engagement requirements discussed in
section X.E.1.b.i of this preamble will
ensure that all interested stakeholders—
including community members
adversely impacted by pollution, energy
workers affected by construction and/or
other changes in operation at fossil-fuelfired power plants, consumers and other
interested parties—will have an
opportunity to have their concerns
heard as states make decisions
balancing a multitude of factors
including appropriate standards of
performance, compliance strategies, and
compliance flexibilities for existing
EGUs, as well as public health and
environmental considerations. The EPA
believes that these provisions, together
with the protections referenced above,
can reduce the risks of localized
emissions increases in a manner that is
protective of public health, safety, and
the environment.
F. Energy Workers and Communities
These final actions include
requirements for meaningful
engagement in development of state
plans, including with energy workers
and communities. These communities,
including energy workers employed at
affected EGUs, workers who may
construct and install pollution control
technology, workers employed by fuel
extraction and delivery, organizations
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-7
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
representing these workers, and
communities living near affected EGUs,
are impacted by power sector trends on
an ongoing basis and by these final
actions, and the EPA expects that states
will include these stakeholders as part
of their constructive engagement under
the requirements in this rule.
The EPA consulted with the Federal
Interagency Working Group on Coal and
Power Plant Communities and
Economic Revitalization (Energy
Communities IWG) in development of
these rules and the meaningful
engagement requirements. The EPA
notes that the Energy Communities IWG
has provided resources to help energy
communities access the expanded
federal resources made available by the
Bipartisan Infrastructure Law, CHIPS
and Science Act, and Inflation
Reduction Act, many of which are
relevant to the development of state
plans.
G. Key Changes From Proposal
The key changes from proposal in
these final actions are: (1) the reduction
in number of subcategories for existing
coal-fired steam generating units, (2) the
extension of the compliance date for
existing coal-fired steam generating
units to meet a standard of performance
based on implementation of CCS, (3) the
removal of low-GHG hydrogen co-firing
as a BSER pathway, and (4) the addition
of two reliability-related instruments. In
addition, (5), the EPA is not finalizing
proposed requirements for existing
fossil fuel-fired stationary combustion
turbines at this time.
The reduction in number of
subcategories for existing coal-fired
steam generating units: The EPA
proposed four subcategories for existing
coal-fired steam generating units, which
would have distinguished these units by
operating horizon and by load level.
These included subcategories for
existing coal-fired EGUs planning to
cease operations in the imminent-term
(i.e., prior to January 1, 2032) and those
planning to cease operations in the nearterm (i.e., prior to January 1, 2035).
While commenters were generally
supportive of the proposed
subcategorization approach, some
requested that the cease-operation-by
date for the imminent-term subcategory
be extended and the utilization limit for
the near-term subcategory be relaxed.
The EPA is not finalizing the imminentterm and near-term subcategories of
coal-fired steam generating units.
Rather, the EPA is finalizing an
applicability exemption for coal-fired
steam generating units demonstrating
that they plan to permanently cease
operation before January 1, 2032. See
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
section VII.B of this preamble for further
discussion.
The extension of the compliance date
for existing coal-fired steam generating
units to meet a standard of performance
based on implementation of CCS. The
EPA proposed a compliance date for
implementation of CCS for long-term
coal-fired steam generating units of
January 1, 2030. The EPA received
comments asserting that this deadline
did not provide adequate lead time. In
consideration of those comments, and
the record as a whole, the EPA is
finalizing a CCS compliance date of
January 1, 2032 for these sources.
The removal of low-GHG hydrogen cofiring as a BSER pathway and only use
of low-GHG hydrogen as a compliance
option: The EPA is not finalizing its
proposed BSER pathway of low-GHG
hydrogen co-firing for new and
reconstructed base load and
intermediate load combustion turbines
in accordance with CAA section
111(a)(1). The EPA is also not finalizing
its proposed requirement that only lowGHG hydrogen may be co-fired in a
combustion turbine for the purpose of
compliance with the standards of
performance. These decisions are based
on uncertainties identified for specific
criteria used to evaluate low-GHG
hydrogen co-firing as a potential BSER,
and after further analysis in response to
public comments, the EPA has
determined that these uncertainties
prevent the EPA from concluding that
low-GHG hydrogen co-firing is a
component of the ‘‘best’’ system of
emission reduction at this time. Under
CAA section 111, the EPA establishes
standards of performance but does not
mandate use of any particular
technology to meet those standards.
Therefore, certain sources may elect to
co-fire hydrogen for compliance with
the final standards of performance, even
absent the technology being a BSER
pathway.15 See section VIII.F.5 of this
preamble for further discussion.
15 The EPA is not placing qualifications on the
type of hydrogen a source may elect to co-fire at this
time (see section VIII.F.6.a of this preamble for
further discussion). The Agency continues to
recognize that even though the combustion of
hydrogen is zero-GHG emitting, its production can
entail a range of GHG emissions, from low to high,
depending on the production method. Thus, even
though the EPA is not finalizing the low-GHG
hydrogen co-firing as a BSER, as proposed, it
maintains that the overall GHG profile of a
particular method of hydrogen production should
be a primary consideration for any source that
decides to co-fire hydrogen to ensure that overall
GHG reductions and important climate benefits are
achieved. The EPA also notes the anticipated final
rule from the U.S. Department of the Treasury
pertaining to clean hydrogen production tax and
energy credits, which in its proposed form contains
certain eligibility parameters, as well as programs
PO 00000
Frm 00009
Fmt 4701
Sfmt 4700
39805
The addition of two reliability-related
instruments: Commenters expressed
concerns that these rules, in
combination with other factors, may
affect the reliability of the bulk power
system. In response to these comments
the EPA engaged extensively with
balancing authorities, power companies,
reliability experts, and regulatory
authorities responsible for reliability to
inform its decisions in these final rules.
As described later in this preamble, the
EPA has made adjustments in these
final rules that will support power
companies, grid operators, and states in
maintaining the reliability of the electric
grid during the implementation of these
final rules. In addition, the EPA has
undertaken an analysis of the reliability
and resource adequacy implications of
these final rules that supports the
Agency’s conclusion that these final
rules can be implemented without
adverse consequences for grid
reliability. Further, the EPA is finalizing
two reliability-related instruments as an
additional layer of safeguards for
reliability. These instruments include a
reliability mechanism for short-term
emergency issues, and a reliability
assurance mechanism, or compliance
flexibility, for units that have chosen
compliance pathways with enforceable
retirement dates, provided there is a
documented and verified reliability
concern. In addition, the EPA is
finalizing compliance extensions for
unanticipated delays with control
technology implementation.
Specifically, as described in greater
detail in section XII.F of this preamble,
the EPA is finalizing the following
features and changes from the proposal
that will provide even greater certainty
that these final rules are sensitive to
reliability-related issues and
constructed in a manner that does not
interfere with grid operators’
responsibility to deliver reliable power:
(1) longer compliance timelines for
existing coal-fired steam generating
units;
(2) a mechanism to extend
compliance timelines by up to 1 year in
the case of unforeseen circumstances,
outside of an owner/operator’s control,
that delay the ability to apply controls
(e.g., supply chain challenges or
permitting delays);
(3) transparent unit-specific
compliance information for EGUs that
will allow grid operators to plan for
system changes with greater certainty
and precision;
(4) a short-term reliability mechanism
to allow affected EGUs to operate at
administered by the U.S. Department of Energy,
such as the recent H2Hubs selections.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-8
ddrumheller on DSK120RN23PROD with RULES3
39806
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
baseline emission rates during
documented reliability emergencies;
and
(5) a reliability assurance mechanism
to allow states to delay cease operation
dates by up to 1 year in cases where the
planned cease operation date is forecast
to disrupt system reliability.
Not finalizing proposed requirements
for existing fossil fuel-fired stationary
combustion turbines at this time: The
EPA proposed emission guidelines for
large (i.e., greater than 300 MW),
frequently operated (i.e., with an annual
capacity factor of greater than 50
percent), existing fossil fuel-fired
stationary combustion turbines. The
EPA received a wide range of comments
on the proposed guidelines. Multiple
commenters suggested that the proposed
provisions would largely result in
shifting of generation away from the
most efficient natural gas-fired turbines
to less efficient natural gas-fired
turbines. Commenters stated that, as
emissions from coal-fired steam
generating units decreased, existing
natural gas-fired EGUs were poised to
become the largest source of GHG
emissions in the power sector.
Commenters noted that these units play
an important role in grid reliability,
particularly as aging coal-fired EGUs
retire. Commenters further noted that
the existing fossil fuel-fired stationary
combustion turbines that were not
covered by the proposal (i.e., the smaller
and less frequently operating units) are
often less efficient, less well controlled
for other pollutants such as NOX, and
are more likely to be located near
population centers and communities
with environmental justice concerns.
The EPA agrees with commenters
who observed that GHG emissions from
existing natural gas-fired stationary
combustion turbines are a growing
portion of the emissions from the power
sector. This is consistent with EPA
modeling that shows that by 2030 these
units will represent the largest portion
of GHG emissions from the power
sector. The EPA agrees that it is vital to
promulgate emission guidelines to
address GHG emissions from these
sources, and that the EPA has a
responsibility to do so under section
111(d) of the Clean Air Act. The EPA
also agrees with commenters who noted
that focusing only on the largest and
most frequently operating units, without
also addressing emissions from other
units, as the May 2023 proposed rule
provided, may not be the most effective
way to address emissions from this
sector. The EPA’s modeling shows that
over time as the power sector comes
closer to reaching the phase-out
threshold of the clean electricity
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
incentives in the Inflation Reduction
Act (IRA) (i.e., a 75 percent reduction in
emissions from the power sector from
2022 levels), the average capacity factor
for existing natural gas-fired stationary
combustion turbines decreases.
Therefore, the EPA’s proposal to focus
only on the largest units with the
highest capacity factors may not be the
most effective policy design for
reducing GHG emissions from these
sources.
Recognizing the importance of
reducing emissions from all fossil fuelfired EGUs, the EPA is not finalizing the
proposed emission guidelines for
certain existing fossil fuel-fired
stationary combustion turbines at this
time. Instead, the EPA intends to issue
a new, more comprehensive proposal to
regulate GHGs from existing sources.
The new proposal will focus on
achieving greater emission reductions
from existing stationary combustion
turbines—which will soon be the largest
stationary sources of GHG emissions—
while taking into account other factors
including the local non-GHG impacts of
gas turbine generation and the need for
reliable, affordable electricity.
II. General Information
A. Action Applicability
The source category that is the subject
of these actions is composed of fossil
fuel-fired electric utility generating
units. 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 final actions are likely to affect.
Final amendments to 40 CFR part 60,
subpart TTTT, are directly applicable to
affected facilities that began
construction after January 8, 2014, but
before May 23, 2023, and affected
facilities that began reconstruction or
modification after June 18, 2014, but
before May 23, 2023. The NSPS codified
in 40 CFR part 60, subpart TTTTa, is
directly applicable to affected facilities
that begin construction, reconstruction,
or modification on or after May 23,
2023. Federal, state, local, and tribal
government entities that own and/or
operate EGUs subject to 40 CFR part 60,
subpart TTTT or TTTTa, are affected by
these amendments and standards.
The emission guidelines codified in
40 CFR part 60, subpart UUUUb, are for
states to follow in developing,
submitting, and implementing state
plans to establish performance
standards to reduce emissions of GHGs
from designated facilities that are
PO 00000
Frm 00010
Fmt 4701
Sfmt 4700
existing sources. 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. Under the Tribal
Authority Rule (TAR), eligible tribes
may seek approval 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 the emission guidelines
codified in 40 CFR part 60, subpart
UUUUb. The TAR authorizes tribes to
develop and implement their own air
quality programs, or portions thereof,
under the CAA. However, it does not
require tribes to develop a CAA
program. Tribes may implement
programs that are most relevant to their
air quality needs. 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.16 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 these final
rulemakings is available on the internet
at https://www.epa.gov/stationarysources-air-pollution/greenhouse-gasstandards-and-guidelines-fossil-fuelfired-power. Following signature by the
EPA Administrator, the EPA will post a
copy of these final rulemakings at this
same website. Following publication in
the Federal Register, the EPA will post
the Federal Register version of the final
rules and key technical documents at
this same website.
C. Judicial Review and Administrative
Review
Under CAA section 307(b)(1), judicial
review of these final actions is available
only by filing a petition for review in
16 See the EPA’s website, https://www.epa.gov/
tribal/tribes-approved-treatment-state-tas, for
information on those tribes that have treatment as
a state for specific environmental regulatory
programs, administrative functions, and grant
programs.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-9
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
the United States Court of Appeals for
the District of Columbia Circuit by July
8, 2024. These final actions are
‘‘standard[s] of performance or
requirement[s] under section 111,’’ and,
in addition, are ‘‘nationally applicable
regulations promulgated, or final action
taken, by the Administrator under [the
CAA],’’ CAA section 307(b)(1). Under
CAA section 307(b)(2), the requirements
established by this final rule may not be
challenged separately in any civil or
criminal proceedings brought by the
EPA to enforce the requirements.
Section 307(d)(7)(B) of the CAA
further provides that ‘‘[o]nly an
objection to a rule or procedure which
was raised with reasonable specificity
during the period for public comment
(including any public hearing) may be
raised during judicial review.’’ This
section also provides a mechanism for
the EPA to convene a proceeding for
reconsideration, ‘‘[i]f the person raising
an objection can demonstrate to the EPA
that it was impracticable to raise such
objection within [the period for public
comment] or if the grounds for such
objection arose after the period for
public comment, (but within the time
specified for judicial review) and if such
objection is of central relevance to the
outcome of the rule.’’ Any person
seeking to make such a demonstration to
us should submit a Petition for
Reconsideration to the Office of the
Administrator, U.S. Environmental
Protection Agency, Room 3000, WJC
West Building, 1200 Pennsylvania Ave.
NW, Washington, DC 20460, with a
copy to both the person(s) listed in the
preceding FOR FURTHER INFORMATION
CONTACT section, and the Associate
General Counsel for the Air and
Radiation Law Office, Office of General
Counsel (Mail Code 2344A), U.S.
Environmental Protection Agency, 1200
Pennsylvania Ave. NW, Washington, DC
20460.
III. Climate Change Impacts
Elevated concentrations of GHGs have
been warming the planet, leading to
changes in the Earth’s climate that are
occurring at a pace and in a way that
threatens human health, society, and the
natural environment. While the EPA is
not making any new scientific or factual
findings with regard to the welldocumented impact of GHG emissions
on public health and welfare in support
of these rules, the EPA is providing in
this section a brief scientific background
on climate change to offer additional
context for these rulemakings and to
help the public understand the
environmental impacts of GHGs.
Extensive information on climate
change is available in the scientific
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
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 Greenhouse Gases Under
Section 202(a) of the CAA’’ (74 FR
66496, December 15, 2009) (‘‘2009
Endangerment Finding’’). In the 2009
Endangerment Finding, the
Administrator found under section
202(a) of the CAA that elevated
atmospheric concentrations of six key
well-mixed GHGs—CO2, methane (CH4),
nitrous oxide (N2O), 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). The 2009 Endangerment
Finding, 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 Finding further
explained that compared with 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 Finding also
documented, together with the
extensive scientific and technical
evidence in the supporting record, that
PO 00000
Frm 00011
Fmt 4701
Sfmt 4700
39807
climate change touches nearly every
aspect of public welfare 17 in the U.S.,
including the following: changes in
water supply and quality due to changes
in 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; 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 issued a
similar finding for GHG emissions from
aircraft under section 231(a)(2)(A) of the
CAA.18 In the 2016 Endangerment
Finding, the Administrator found that
the body of scientific evidence amassed
in the record for the 2009 Endangerment
Finding 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 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
Finding, the climate has continued to
change, with new observational records
being set for several climate indicators
such as global average surface
temperatures, GHG concentrations, and
sea level rise. Additionally, major
scientific assessments continue to be
released that further advance our
understanding of the climate system and
the impacts that GHGs have on public
health and welfare for both current and
future generations. These updated
observations and projections document
the rapid rate of current and future
17 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).
18 Finding That Greenhouse Gas Emissions From
Aircraft Cause or Contribute to Air Pollution That
May Reasonably Be Anticipated To Endanger Public
Health and Welfare. 81 FR 54422, August 15, 2016
(‘‘2016 Endangerment Finding’’).
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-10
39808
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
climate change both globally and in the
U.S.19 20 21 22 23 24 25 26 27 28 29 30 31
19 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.
20 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.
21 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.
22 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. Pörtner, D. Roberts, J. Skea, P.R. Shukla,
A. Pirani, W. Moufouma-Okia, C. Péan, 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.)].
23 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. Pörtner, 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.)].
24 IPCC, 2019: IPCC Special Report on the Ocean
and Cryosphere in a Changing Climate [H.-O.
Pörtner, D.C. Roberts, V. Masson-Delmotte, P. Zhai,
M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegriı́a, M. Nicolai, A. Okem, J. Petzold, B. Rama,
N.M. Weyer (eds.)].
25 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.
26 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.
27 National Academies of Sciences, Engineering,
and Medicine. 2019. Climate Change and
Ecosystems. Washington, DC: The National
Academies Press. https://doi.org/10.17226/25504.
28 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.
29 U.S. Environmental Protection Agency. 2021.
Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. EPA 430–
R–21–003.
30 Jay, A.K., A.R. Crimmins, C.W. Avery, T.A.
Dahl, R.S. Dodder, B.D. Hamlington, A. Lustig, K.
Marvel, P.A. Méndez-Lazaro, M.S. Osler, A.
Terando, E.S. Weeks, and A. Zycherman, 2023: Ch.
1. Overview: Understanding risks, impacts, and
responses. In: Fifth National Climate Assessment.
Crimmins, A.R., C.W. Avery, D.R. Easterling, K.E.
Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S.
Global Change Research Program, Washington, DC,
USA. https://doi.org/10.7930/NCA5.2023.CH1.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
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
because of both historical 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,
atmospheric concentrations of one of
these GHGs, CO2, measured at Mauna
Loa in Hawaii and at other sites around
the world reached 419 parts per million
(ppm) in 2022 (nearly 50 percent higher
than preindustrial levels) 32 and have
continued to rise at a rapid rate. Global
average temperature has increased by
about 1.1 °C (2.0 °F) in the 2011–2020
decade relative to 1850–1900.33 The
years 2015–2021 were the warmest 7
years in the 1880–2021 record,
contributing to the warmest decade on
record with a decadal temperature of
0.82 °C (1.48 °F) above the 20th
century.34 35 The Intergovernmental
Panel on Climate Change (IPCC)
determined (with medium confidence)
that this past decade was warmer than
any multi-century period in at least the
past 100,000 years.36 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
31 IPCC, 2023: Summary for Policymakers. In:
Climate Change 2023: Synthesis Report.
Contribution of Working Groups I, II and III to the
Sixth Assessment Report of the Intergovernmental
Panel on Climate Change [Core Writing Team, H.
Lee and J. Romero (eds.)].
32 https://gml.noaa.gov/webdata/ccgg/trends/co2/
co2_annmean_mlo.txt.
33 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. Péan, S. Berger, N. Caud,
Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K.
Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock,
T. Waterfield, O. Yelekçi, R. Yu, and B. Zhou
(eds.)]. Cambridge University Press, Cambridge,
United Kingdom and New York, NY, USA, pp. 3–
32, doi:10.1017/9781009157896.001.
34 NOAA National Centers for Environmental
Information, State of the Climate 2021 retrieved on
August 3, 2023, from https://www.ncei.noaa.gov/
bams-state-of-climate.
35 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/
2022BAMSStateoftheClimate1.
36 IPCC, 2021.
PO 00000
Frm 00012
Fmt 4701
Sfmt 4700
of the 1901 to 2018 period.37 The rate
of sea level rise over the 20th century
was higher than in any other century in
at least the last 2,800 years.38 Higher
CO2 concentrations have led to
acidification of the surface ocean in
recent decades to an extent unusual in
the past 65 million years, with negative
impacts on marine organisms that use
calcium carbonate to build shells or
skeletons.39 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.40 Humaninduced climate change has led to
heatwaves and heavy precipitation
becoming more frequent and more
intense, along with increases in
agricultural and ecological droughts 41
in many regions.42
The assessment literature
demonstrates that modest additional
amounts of warming may lead to a
climate different from anything humans
have ever experienced. The 2022 CO2
concentration of 419 ppm is already
higher than at any time in the last 2
million years.43 If concentrations exceed
450 ppm, they would likely be higher
than any time in the past 23 million
years: 44 at the current rate of increase of
more than 2 ppm per year, this would
occur in about 15 years. While GHGs are
not the only factor that controls climate,
it is illustrative that 3 million years ago
(the last time CO2 concentrations were
above 400 ppm) Greenland was not yet
completely covered by ice and still
supported forests, while 23 million
years ago (the last time concentrations
were above 450 ppm) the West Antarctic
ice sheet was not yet developed,
indicating the possibility that high GHG
concentrations could lead to a world
that looks very different from today and
from the conditions in which human
civilization has developed. If the
Greenland and Antarctic ice sheets were
37 IPCC, 2021.
38 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.
39 IPCC, 2018.
40 IPCC, 2021.
41 These are drought measures based on soil
moisture.
42 IPCC, 2021.
43 Annual Mauna Loa CO concentration data
2
from https://gml.noaa.gov/webdata/ccgg/trends/
co2/co2_annmean_mlo.txt, accessed September 9,
2023.
44 IPCC, 2013.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-11
ddrumheller on DSK120RN23PROD with RULES3
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
to melt substantially, sea levels would
rise dramatically.
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.45 Coral reefs will be at
risk for almost complete (99 percent)
losses with 1 °C (1.8 °F) of additional
warming from today (2 °C or 3.6 °F since
preindustrial). At this temperature,
between 8 and 18 percent of animal,
plant, and insect species could lose over
half of the geographic area with suitable
climate for their survival, and 7 to 10
percent of rangeland livestock would be
projected to be lost.46 The IPCC
similarly found that climate change has
caused substantial damages and
increasingly irreversible losses in
terrestrial, freshwater, and coastal and
open ocean marine ecosystems.
Every additional increment of
temperature comes with consequences.
For example, the half degree of warming
from 1.5 to 2 °C (0.9 °F of warming from
2.7 °F to 3.6 °F) above preindustrial
temperatures is projected on a global
scale to expose 420 million more people
to frequent extreme heatwaves at least
every five years, and 62 million more
people to frequent exceptional
heatwaves at least every five years
(where heatwaves are defined based on
a heat wave magnitude index which
takes into account duration and
intensity—using this index, the 2003
French heat wave that led to almost
15,000 deaths would be classified as an
‘‘extreme heatwave’’ and the 2010
Russian heatwave which led to
thousands of deaths and extensive
wildfires would be classified as
‘‘exceptional’’). It would increase the
frequency of sea-ice-free Arctic
summers from once in 100 years to once
in a decade. It could lead to 4 inches of
additional sea level rise by the end of
the century, exposing an additional 10
million people to risks of inundation as
well as increasing the probability of
triggering instabilities in either the
Greenland or Antarctic ice sheets.
Between half a million and a million
additional square miles of permafrost
would thaw over several centuries.
Risks to food security would increase
from medium to high for several lowerincome regions in the Sahel, southern
Africa, the Mediterranean, central
Europe, and the Amazon. In addition to
food security issues, this temperature
increase would have implications for
human health in terms of increasing
ozone concentrations, heatwaves, and
45 USGCRP, 2018.
46 IPCC, 2018.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
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).47
Moreover, every additional increment in
warming leads to larger changes in
extremes, including the potential for
events unprecedented in the
observational record. Every additional
degree will intensify extreme
precipitation events by about 7 percent.
The peak winds of the most intense
tropical cyclones (hurricanes) are
projected to increase with warming. In
addition to a higher intensity, the IPCC
found that precipitation and frequency
of rapid intensification of these storms
has already increased, the movement
speed has decreased, and elevated sea
levels have increased coastal flooding,
all of which make these tropical
cyclones more damaging.48
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.49 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 2004.50
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, requiring the installation of
costly pump stations, flooding streets,
and increasing storm surge damages.
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
47 IPCC, 2018.
48 IPCC, 2021.
49 USGCRP, 2018.
50 NIFC (National Interagency Fire Center). 2021.
Total wildland fires and acres (1983–2020).
Accessed August 2021. https://www.nifc.gov/
fireInfo/fireInfo_stats_totalFires.html.
PO 00000
Frm 00013
Fmt 4701
Sfmt 4700
39809
security, both through direct impacts on
military infrastructure and 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.51 The NCA5
further reinforces the science showing
that climate change will have many
impacts on the U.S., as described above
in the preamble. Particularly relevant
for these rules, the NCA5 states that
climate change affects all aspects of the
energy system-supply, delivery, and
demand-through the increased
frequency, intensity, and duration of
extreme events and through changing
climate trends.’’ 52
EPA modeling efforts can further
illustrate how these impacts from
climate change may be experienced
across the U.S. EPA’s Framework for
Evaluating Damages and Impacts
(FrEDI) 53 uses information from over 30
peer-reviewed climate change impact
studies to project the physical and
economic impacts of climate change to
the U.S. resulting from future
temperature changes. These impacts are
projected for specific regions within the
U.S. and for more than 20 impact
categories, which span a large number
of sectors of the U.S. economy.54 Using
51 USGCRP, 2018.
52 Jay, A.K., A.R. Crimmins, C.W. Avery, T.A.
Dahl, R.S. Dodder, B.D. Hamlington, A. Lustig, K.
Marvel, P.A. Méndez-Lazaro, M.S. Osler, A.
Terando, E.S. Weeks, and A. Zycherman, 2023: Ch.
1. Overview: Understanding risks, impacts, and
responses. In: Fifth National Climate Assessment.
Crimmins, A.R., C.W. Avery, D.R. Easterling, K.E.
Kunkel, B.C. Stewart, and T.K. Maycock, Eds. U.S.
Global Change Research Program, Washington, DC,
USA. https://doi.org/10.7930/NCA5.2023.CH1.
53 (1) Hartin, C., et al. (2023). Advancing the
estimation of future climate impacts within the
United States. Earth Syst. Dynam., 14, 1015–1037,
https://doi.org/10.5194/esd-14-1015-2023. (2)
Supplementary Material for the Regulatory Impact
Analysis for the Final Rulemaking, Standards of
Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing
Sources: Oil and Natural Gas Sector Climate
Review, ‘‘Report on the Social Cost of Greenhouse
Gases: Estimates Incorporating Recent Scientific
Advances,’’ Docket ID No. EPA–HQ–OAR–2021–
0317, November 2023, (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.
54 EPA (2021). Technical Documentation on the
Framework for Evaluating Damages and Impacts
(FrEDI). U.S. Environmental Protection Agency,
EPA 430–R–21–004, https://www.epa.gov/cira/
fredi. Documentation has been subject to both a
public review comment period and an independent
E:\FR\FM\09MYR3.SGM
Continued
09MYR3
App. A-12
39810
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
this framework, the EPA estimates that
global emission projections, with no
additional mitigation, will result in
significant climate-related damages to
the U.S.55 These damages to the U.S.
would mainly be from increases in lives
lost due to increases in temperatures, as
well as impacts to human health from
increases in climate-driven changes in
air quality, dust and wildfire smoke
exposure, and incidence of suicide.
Additional major climate-related
damages would occur to U.S.
infrastructure such as roads and rail, as
well as transportation impacts and
coastal flooding from sea level rise,
increases in property damage from
tropical cyclones, and reductions in
labor hours worked in outdoor settings
and buildings without air conditioning.
These impacts are also projected to vary
from region to region with the
Southeast, for example, projected to see
some of the largest damages from sea
level rise, the West Coast projected to
experience damages from wildfire
smoke more than other parts of the
country, and the Northern Plains states
projected to see a higher proportion of
damages to rail and road infrastructure.
While information on the distribution of
climate impacts helps to better
understand the ways in which climate
change may impact the U.S., recent
analyses are still only a partial
assessment of climate impacts relevant
to U.S. interests and in addition do 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 occurring abroad have
spillover effects in different regions of
the U.S.
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 56) and cause ocean
acidification. Nitrous oxide depletes the
levels of protective stratospheric
expert peer review, following EPA peer-review
guidelines.
55 Compared to a world with no additional
warming after the model baseline (1986–2005).
56 Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse,
J.F. Garofalo, A.S. Khan, I. Loladze, A.A. Pérez de
León, 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://health2016.globalchange.gov/low/
ClimateHealth2016_07_Food_small.pdf.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
ozone.57 Methane reacts to form
tropospheric ozone.
Section XII.E of this preamble
discusses the impacts of GHG emissions
on individuals living in socially and
economically vulnerable communities.
While the EPA did not conduct
modeling to specifically quantify
changes in climate impacts resulting
from these rules in terms of avoided
temperature change or sea-level rise, the
Agency did quantify climate benefits by
monetizing the emission reductions
through the application of the social
cost of greenhouse gases (SC–GHGs), as
described in section XII.D of this
preamble.
These scientific assessments, the 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
In this section, we discuss
background information about the
electric power sector and controls
available to limit GHG pollution from
the fossil fuel-fired power plants
regulated by these final rules, and then
discuss several recent developments
that are relevant for determining the
BSER for these sources. After giving
some general background, we first
discuss CCS and explain that its costs
have fallen significantly. Lower costs
are central for the EPA’s determination
that CCS is the BSER for certain existing
coal-fired steam generating units and
certain new natural gas-fired
combustion turbines. Second, we
discuss natural gas co-firing for coalfired steam generating units and explain
recent reductions in cost for this
approach as well as its widespread
availability and current and potential
deployment within this subcategory.
Third, we discuss highly efficient
generation as a BSER technology for
new and reconstructed simple cycle and
combined cycle combustion turbine
EGUs. The emission reductions
achieved by highly efficient turbines are
well demonstrated in the power sector,
and along with operational and
maintenance best practices, represent a
cost-effective technology that reduces
fuel consumption. Finally, we discuss
key developments in the electric power
sector that influence which units can
57 WMO (World Meteorological Organization),
Scientific Assessment of Ozone Depletion: 2018,
Global Ozone Research and Monitoring Project—
Report No. 58, 588 pp., Geneva, Switzerland, 2018.
PO 00000
Frm 00014
Fmt 4701
Sfmt 4700
feasibly and cost-effectively deploy
these technologies.
A. Background
1. Electric Power Sector
Electricity in the U.S. is generated by
a range of technologies, and different
EGUs play different roles in providing
reliable and affordable electricity. For
example, certain EGUs generate base
load power, which is the portion of
electricity loads that are continually
present and typically operate
throughout all hours of the year.
Intermediate EGUs often provide
complementary generation to balance
variable supply and demand resources.
Low load ‘‘peaking units’’ provide
capacity during hours of the highest
daily, weekly, or seasonal net demand,
and while these resources have low
levels of utilization on an annual basis,
they play important roles in providing
generation to meet short-term demand
and often must be available to quickly
increase or decrease their output.
Furthermore, many of these 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 58 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 are 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.
58 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 (1 kWh = 1,000 watt-hours),
megawatt-hours (1 MWh = 1,000 kWh), gigawatthours (1 GWh = 1 million kWh), or terawatt-hours
(1 TWh = 1 billion kWh).
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-13
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
Generated electricity must be
transmitted over networks 59 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; 60 in others, individual
utilities 61 coordinate the operations of
their generation and transmission to
balance the system across their
respective service territories.
2. Types of EGUs
ddrumheller on DSK120RN23PROD with RULES3
There are many types of EGUs
including fossil fuel-fired power plants
(i.e., those using coal, oil, and natural
gas), nuclear power plants, renewable
generating sources (such as wind and
solar) and others. This rule focuses on
the fossil fuel-fired portion of the
generating fleet that is responsible for
the vast majority of GHG emissions from
the power sector. The definition of fossil
fuel-fired electric utility steam
generating units includes utility boilers
as well as 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 refueled as natural gas-fired
utility boilers. 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.
59 The three network interconnections are the
Western Interconnection, comprising the western
parts of the U.S. and Canada, the Eastern
Interconnection, comprising the eastern parts of the
U.S. and Canada except parts of Eastern Canada in
the Quebec Interconnection, and the Texas
Interconnection, encompassing 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/Publishing
Images/NERC%20Interconnections.pdf.
60 For example, PJM Interconnection, LLC, New
York Independent System Operator (NYISO),
Midwest Independent System Operator (MISO),
California Independent System Operator (CAISO),
etc.
61 For example, Los Angeles Department of Power
and Water, Florida Power and Light, etc.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
Stationary combustion turbine EGUs
(most commonly natural gas-fired) use
one of two configurations: combined
cycle or simple cycle 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 load power. An EGU’s
capacity factor indicates a power plant’s
electricity output as a percentage of its
total generation capacity. Simple cycle
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.62
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 40 percent of the overall
62 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.
PO 00000
Frm 00015
Fmt 4701
Sfmt 4700
39811
net electricity supply in 2022. Many
projections show this share growing
over time. For example, the EPA’s
Power Sector Platform 2023 using IPM
(i.e., the EPA’s baseline projections of
the power sector) projects zero-emitting
sources reaching 76 percent of
electricity generation by 2040. This shift
is driven by multiple factors. These
factors include changes in the relative
economics of generating technologies,
the efforts by states to reduce GHG
emissions, utility and other corporate
commitments, and customer preference.
The shift is further promoted by
provisions of Federal legislation, most
notably the Clean Electricity Investment
and Production tax credits included in
IRC sections 48E and 45Y of the IRA,
which do not begin to phase out until
the later of 2032 or when power sector
GHG emissions are 75 percent less than
2022 levels. (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
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.’’ 63 The
Energy Strategy Coalition similarly said
in public comments that ‘‘[a]s major
electrical utilities and power producers,
our top priority is providing clean,
affordable, and reliable energy to our
customers’’ and are ‘‘seeking to
advance’’ technologies ‘‘such as a
carbon capture and storage, which can
significantly reduce carbon dioxide
63 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. Public comments
submitted to the EPA’s pre-proposal rulemaking,
Document ID No. EPA–HQ–OAR–2022–0723–0024.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-14
39812
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
emissions from fossil fuel-fired
EGUs.’’ 64
B. GHG Emissions From Fossil FuelFired EGUs
ddrumheller on DSK120RN23PROD with RULES3
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.65
The amount of CO2 produced when a
fossil fuel is burned in an EGU is a
function of the carbon content of the
fuel relative to the size and efficiency of
the EGU. Different fuels emit different
amounts of CO2 in relation to the energy
they produce when combusted. 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.66 67 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).68 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
64 Energy Strategy Coalition Comments on EPA’s
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, Document ID No.
EPA–HQ–OAR–2023–0072–0672, August 14, 2023.
65 U.S. Environmental Protection Agency (EPA).
Overview of greenhouse gas emissions. July 2021.
https://www.epa.gov/ghgemissions/overviewgreenhouse-gases#carbon-dioxide.
66 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.
67 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.
68 Energy Information Administration (EIA).
Carbon Dioxide Emissions Coefficients. https://
www.eia.gov/environment/emissions/co2_vol_
mass.php.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
and Sinks 69 (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 70 of GHGs,
including CO2 emissions since 1990.
According to the latest inventory of all
sectors, in 2021, total U.S. GHG
emissions were 6,340 million metric
tons of CO2 equivalent (MMT CO2e).71
The transportation sector (28.5 percent),
which includes approximately 300
million vehicles, was the largest
contributor to total U.S. GHG emissions
with 1,804 MMT CO2e followed by the
power sector (25.0 percent) with 1,584
MMT CO2e. In fact, GHG emissions from
the power sector were higher than the
GHG emissions from all other industrial
sectors combined (1,487 MMT CO2e).
Specifically, the power sector’s
emissions were far more than petroleum
and natural gas systems 72 at 301 MMT
CO2e; chemicals (71 MMT CO2e);
minerals (64 MMT CO2e); coal mining
(53 MMT CO2e); and metals (48 MMT
CO2e). The agriculture (636 MMT CO2e),
commercial (439 MMT CO2e), and
residential (366 MMT CO2e) sectors
combined to emit 1,441 MMT CO2e.
Fossil fuel-fired EGUs are by far the
largest stationary source emitters of
GHGs in the nation. For example,
according to the EPA’s Greenhouse Gas
Reporting Program (GHGRP), of the top
100 large facilities that reported facilitylevel GHGs in 2022, 85 were fossil fuelfired power plants while 10 were
refineries and/or chemical plants, four
were metals facilities, and one was a
petroleum and natural gas systems
facility.73 Of the 85 fossil fuel-fired
power plants, 81 were primarily coal69 U.S. Environmental Protection Agency (EPA).
Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990–2021. https://www.epa.gov/
ghgemissions/inventory-us-greenhouse-gasemissions-and-sinks-1990-2021.
70 Sinks are a physical unit or process that stores
GHGs, such as forests or underground or deep-sea
reservoirs of carbon dioxide.
71 U.S. Environmental Protection Agency (EPA).
Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990–2021. https://www.epa.gov/
ghgemissions/inventory-us-greenhouse-gasemissions-and-sinks.
72 Petroleum and natural gas systems include:
offshore and onshore petroleum and natural gas
production; onshore petroleum and natural gas
gathering and boosting; natural gas processing;
natural gas transmission/compression; onshore
natural gas transmission pipelines; natural gas local
distribution companies; underground natural gas
storage; liquified natural gas storage; liquified
natural gas import/export equipment; and other
petroleum and natural gas systems.
73 U.S. Environmental Protection Agency (EPA).
Greenhouse Gas Reporting Program. Facility Level
Information on Greenhouse Gases Tool (FLIGHT).
https://ghgdata.epa.gov/ghgp/main.do#.
PO 00000
Frm 00016
Fmt 4701
Sfmt 4700
fired, including the top 41 emitters of
CO2. In addition, of the 81 coal-fired
plants, 43 have no retirement planned
prior to 2039. The top 10 of these plants
combined to emit more than 135 MMT
of CO2e, with the top emitter (James H.
Miller power plant in Alabama)
reporting approximately 22 MMT of
CO2e with each of its four EGUs
emitting between 5 MMT and 6 MMT
CO2e that year. The combined capacity
of these 10 plants is more than 23
gigawatts (GW), and all except for the
Monroe (Michigan) plant operated at
annual capacity factors of 50 percent or
higher.74 For comparison, the largest
GHG emitter in the U.S. that is not a
fossil fuel-fired power plant is the
ExxonMobil refinery and chemical plant
in Baytown, Texas, which reported 12.6
MMT CO2e (No. 6 overall in the nation)
to the GHGRP in 2022. The largest
metals facility in terms of GHG
emissions was the U.S. Steel facility in
Gary, Indiana, with 10.4 MMT CO2e
(No. 16 overall in the nation).
Overall, 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).75 The reduction in CO2 emissions
can be attributed to the power sector’s
ongoing trend away from carbonintensive 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.76 This total
dropped to 1,351 MMT in 2015 and
reached 974 MMT in 2019, the first time
since 1978 that CO2 emissions from
coal-fired EGUs were below 1,000 MMT.
In 2020, emissions of CO2 from coalfired EGUs measured 788 MMT as the
result of pandemic-related closures and
reduced utilization before rebounding in
2021 to 909 MMT. 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.
74 U.S. Energy Information Administration (EIA).
Preliminary Monthly Electric Generator Inventory,
Form EIA–860M, November 2023. https://
www.eia.gov/electricity/data/eia860m/.
75 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.
76 U.S. Energy Information Administration (EIA).
Monthly Energy Review, table 11.6. September
2022. https://www.eia.gov/totalenergy/data/
monthly/pdf/sec11.pdf.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-15
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
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).77 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 is not
guaranteed to continue, therefore
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.
ddrumheller on DSK120RN23PROD with RULES3
C. Recent Developments in Emissions
Control
This section of the preamble describes
recent developments in GHG emissions
control in general. Details of those
controls in the context of BSER
determination are provided in section
VII.C.1.a for CCS on coal-fired steam
generating units, section VII.C.2.a for
natural gas co-firing on coal-fired steam
generating units, section VIII.F.2.b for
efficient generation on natural gas-fired
combustion turbines, and section
VIII.F.4.c.iv for CCS on natural gas-fired
combustion turbines. Further details of
the control technologies are available in
the final TSDs, GHG Mitigation
Measures for Steam Generating Units
and GHG Mitigation Measures—CCS for
Combustion Turbines, available in the
docket for these actions.
1. CCS
One of the key GHG reduction
technologies upon which the BSER
determinations are founded in these
final rules is CCS—a technology that
can capture and permanently store CO2
from fossil fuel-fired EGUs. CCS has
77 80 FR 63662 (October 23, 2015).
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
three major components: CO2 capture,
transportation, and sequestration/
storage. Solvent-based CO2 capture was
patented nearly 100 years ago in the
1930s 78 and has been used in a variety
of industrial applications for decades.
Thousands of miles of CO2 pipelines
have been constructed and securely
operated in the U.S. for decades.79 And
tens of millions of tons of CO2 have
been permanently stored deep
underground either for geologic
sequestration or in association with
enhanced oil recovery (EOR).80 The
American Petroleum Institute (API)
explains that ‘‘CCS is a proven
technology’’ and that ‘‘[t]he methods
that apply to [the] carbon sequestration
process are not novel. The U.S. has
more than 40 years of CO2 gas injection
and storage experience. During the last
40 years the U.S. gas and oil industry’s
(EOR) enhanced oil recovery operations)
have injected more than 1 billion tonnes
of CO2.’’ 81 82
In 2009, Mike Morris, then-CEO of
American Electric Power (AEP), was
interviewed by Reuters and the article
noted that Morris’s ‘‘companies’ work in
West Virginia on [CCS] gave [Morris]
more insight than skeptics who doubt
the technology.’’ In that interview,
Morris explained, ‘‘I’m convinced it will
be primetime ready by 2015 and
deployable.’’ 83 In 2011, Alstom Power,
the company that developed the 30 MW
pilot project upon which Morris had
78 Bottoms, R.R. Process for Separating Acidic
Gases (1930) United States patent application.
United States Patent US1783901A; Allen, A.S. and
Arthur, M. Method of Separating Carbon Dioxide
from a Gas Mixture (1933) United States Patent
Application. United States Patent US1934472A.
79 U.S. Department of Transportation, Pipeline
and Hazardous Material Safety Administration,
‘‘Hazardous Annual Liquid Data.’’ 2022. https://
www.phmsa.dot.gov/data-and-statistics/pipeline/
gas-distribution-gas-gathering-gas-transmissionhazardous-liquids.
80 GHGRP US EPA. https://www.epa.gov/
ghgreporting/supply-underground-injection-andgeologic-sequestration-carbon-dioxide.
81 American Petroleum Institute (API). (2024).
Carbon Capture and Storage: A Low-Carbon
Solution to Economy-Wide Greenhouse Gas
Emissions Reductions. https://www.api.org/newspolicy-and-issues/carbon-capture-storage.
82 Major energy company presidents have made
similar statements. For example, in 2021, Shell Oil
Company president Gretchen H. Watkins testified to
Congress that ‘‘Carbon capture and storage is a
proven technology,’’ and in 2022, Joe Blommaert,
the president of ExxonMobil Low Carbon Solutions,
stated that ‘‘Carbon capture and storage is a readily
available technology that can play a critical role in
helping society reduce greenhouse gas emissions.’’
See https://www.congress.gov/117/meeting/house/
114185/witnesses/HHRG-117-GO00-WstateWatkinsG-20211028.pdf and https://
corporate.exxonmobil.com/news/news-releases/
2022/0225_exxonmobil-to-expand-carbon-captureand-storage-at-labarge-wyoming-facility.
83 Woodall, B. (June 25, 2009). AEP sees carbon
capture from coal ready by 2015. Reuters. https://
www.reuters.com/article/idUSTRE55O6TS/.
PO 00000
Frm 00017
Fmt 4701
Sfmt 4700
39813
based his conclusions, reiterated the
claim that CCS would be commercially
available in 2015. A press release from
Alstom Power stated that, based on the
results of Alstom’s ‘‘13 pilot and
demonstration projects and validated by
independent experts . . . we can now
be confident that CCS works and is cost
effective . . . and will be available at a
commercial scale in 2015 and will allow
[plants] to capture 90% of the emitted
CO2.’’ The press release went on to note
that ‘‘the same conclusion applies for a
gas plant using CCS.’’ 84
In 2011, however, AEP determined
that the economic and regulatory
environment at the time did not support
further development of the technology.
After canceling a large-scale commercial
project, Morris explained, ‘‘as a
regulated utility, it is impossible to gain
regulatory approval to cover our share of
the costs for validating and deploying
the technology without federal
requirements to reduce greenhouse gas
emissions already in place.’’ 85
Thirteen years later, the situation is
fundamentally different. Since 2011, the
technological advances from full-scale
deployments (e.g., the Petra Nova and
Boundary Dam projects discussed later
in this preamble) combined with
supportive policies in multiple states
and the financial incentives included in
the IRA, mean that CCS can be deployed
at scale today. In addition to
applications at fossil fuel-fired EGUs,
installation of CCS is poised to
dramatically increase across a range of
industries in the coming years,
including ethanol production, natural
gas processing, and steam methane
reformers.86 Many of the CCS projects
across these industries, including
capture systems, pipelines, and
sequestration, are already in operation
or are in advanced stages of
deployment. There are currently at least
15 operating CCS projects in the U.S.,
and another 121 that are under
84 Alstom Power. (June 14, 2011). Alstom Power
study demonstrates carbon capture and storage
(CCS) is efficient and cost competitive. https://
www.alstom.com/press-releases-news/2011/6/pressreleases-3-26.
85 Indiana Michigan Power. (July 14, 2011). AEP
Places Carbon Capture Commercialization on Hold,
Citing Uncertain Status of Climate Policy, Weak
Economy. Press release. https://
www.indianamichiganpower.com/company/news/
view?releaseID=1206.
86 U.S. Department of Energy (DOE). (2023).
Pathways to Commercial Liftoff: Carbon
Management. https://liftoff.energy.gov/wp-content/
uploads/2024/02/20230424-Liftoff-CarbonManagement-vPUB_update4.pdf.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-16
39814
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
ddrumheller on DSK120RN23PROD with RULES3
construction or in advanced stages of
development.87
Process improvements learned from
earlier deployments of CCS, the
availability of better solvents, and other
advances have decreased the costs of
CCS in recent years. As a result, 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 2010.88
The IRA makes additional and
significant reductions in the cost of
implementing CCS by extending and
increasing the tax credit for CO2
sequestration under IRC section 45Q.
With this combination of polices, and
the advances related to CO2 capture,
multiple projects consistent with the
emission reduction requirements of a 90
percent capture amine based BSER are
in advanced stages of development.
These projects use a wider range of
technologies, and some of them are
being developed as first-of-a-kind
projects and offer significant advantages
over the amine-based CCS technology
that the EPA is finalizing as BSER.
For instance, in North Dakota,
Governor Doug Burgum announced a
goal of becoming carbon neutral by 2030
while retaining the core position of its
fossil fuel industries, and to do so by
significant CCS implementation. Gov.
Burgum explained, ‘‘This may seem like
a moonshot goal, but it’s actually not.
It’s actually completely doable, even
with the technologies that we have
today.’’ 89 Companies in the state are
backing up this claim with projects in
multiple industries in various stages of
operation and development. In the
power sector, two of the biggest projects
under development are Project Tundra
and Coal Creek. Project Tundra is a
carbon capture project on Minnkota
Power’s 705 MW Milton R Young Power
Plant in Oliver County, North Dakota.
Mitsubishi Heavy Industries will be
providing an advanced version of its
carbon capture equipment that builds
upon the lessons learned from the Petra
Nova project.90 Rainbow Energy is
87 Congressional Budget Office (CBO). (December
13, 2023). Carbon Capture and Storage in the United
States. https://www.cbo.gov/publication/59345.
88 Global CCS Institute. (March 2021). Technology
Readiness and Costs of CCS. https://
www.globalccsinstitute.com/wp-content/uploads/
2021/03/Technology-Readiness-and-Costs-for-CCS2021-1.pdf.
89 Willis, A. (May 12, 2021). Gov. Doug Burgum
calls for North Dakota to be carbon neutral by 2030.
The Dickinson Press. https://
www.thedickinsonpress.com/business/gov-dougburgum-calls-for-north-dakota-to-be-carbonneutral-by-2030.
90 Tanaka, H. et al. Advanced KM CDR Process
using New Solvent. 14th International Conference
on Greenhouse Gas Control Technologies, GHGT–
14. https://www.cfaenm.org/wp-content/uploads/
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
developing the project at the Coal Creek
Station, located in McLean, North
Dakota. Notably, Rainbow Energy
purchased the 1,150 MW Coal Creek
Station with a business model of
installing CCS based on the IRC section
45Q tax credit of $50/ton that existed at
the time (the IRA has since increased
the amount to $85/ton).91 Rainbow
Energy explains, ‘‘CCUS technology has
been proven and is an economical
option for a facility like Coal Creek
Station. We see CCUS as the best way
to manage emissions at our facility.’’ 92
While North Dakota has encouraged
CCS on coal-fired power plants without
specific mandates, Wyoming is taking a
different approach. Senate Bill 42,
enacted in 2024, requires utilities to
generate a specified percentage of their
electricity using coal-fired power plants
with CCS. SB 42 updates HB 200,
enacted in 2020, which required the
CCS to be installed by 2030, which SB
42 extends to 2033. To comply with
those requirements, PacificCorp has
stated in its 2023 IRP that it intends to
install CCS on two coal-fired units by
2028.93 Rocky Mountain Power has also
announced that it will explore a new
carbon capture technology at either its
David Johnston plant or its Wyodak
plant.94 Another CCS project is also
under development at the Dry Fork
Power Plant in Wyoming. Currently, a
pilot project that will capture 150 tons
of CO2 per day is under construction
and is scheduled to be completed in late
2024. Work has also begun on a fullscale front end engineering design
(FEED) study.
Like North Dakota, West Virginia does
not have a carbon capture mandate, but
there are several carbon capture projects
under development in the state. One is
a new, 2,000 MW natural gas combined
cycle plant being developed by
Competitive Power Ventures that will
capture 90–95 percent of the CO2 using
GE turbine and carbon capture
2019/03/GHGT14_manuscript_20180913Cleanversion.pdf.
91 Minot Daily News. (April 8, 2024). Hoeven: ND
to lead country with carbon capture project at Coal
Creek Station. https://minotdailynews.com/news/
local-news/2021/07/hoeven-nd-to-lead-countrywith-carbon-capture-project-at-coal-creek-station/.
92 Rainbow Energy Center. (ND). Carbon Capture.
https://rainbowenergycenter.com/what-we-do/
carbon-capture/.
93 PacifiCorp. (April 1, 2024). 2023 Integrated
Resource Plan Update. https://www.pacificorp.com/
content/dam/pcorp/documents/en/pacificorp/
energy/integrated-resource-plan/2023_IRP_
Update.pdf.
94 Rocky Mountain Power. (April 1, 2024). Rocky
Mountain Power and 8 Rivers to collaborate on
proposed Wyoming carbon capture project. Press
release. https://www.rockymountainpower.net/
about/newsroom/news-releases/rmp-proposedwyoming-carbon-capture-project.html.
PO 00000
Frm 00018
Fmt 4701
Sfmt 4700
technology.95 A second is an Omnis
Fuel Technologies project to convert the
coal-fired Pleasants Power Station to
run on hydrogen.96 Omnis intends to
use a pyrolysis-based process to convert
coal into hydrogen and graphite.
Because the graphite is a usable, solid
form of carbon, no CO2 sequestration
will be required. Therefore, unlike more
traditional amine-based approaches,
instead of the captured CO2 being a cost,
the graphite product will provide a
revenue stream.97 Omnis states that the
Pleasants Power Project broke ground in
August 2023 and will be online by 2025.
It should be noted that Wyoming,
West Virginia, and North Dakota
represented the first-, second-, and
seventh-largest coal producers,
respectively, in the U.S. in 2022.98
In addition to the coal-based CCS
projects mentioned above, multiple
other projects are in advanced stages of
development and/or have completed
FEED studies. For instance, Linde/BASF
is installing a 10 MW pilot project on
the Dallman Power Plant in Illinois.
Based on results from small scale pilot
studies, techno economic analysis
indicates that the Linde/BASF process
can provide a significant reduction in
capital costs compared to the NETL base
case for a supercritical pulverized coal
plant with carbon capture.’’ 99 Multiple
other FEED studies are either completed
or under development, putting those
projects on a path to being able to be
built and to commence operation well
before January 1, 2032.
In addition to the Competitive Power
Partners project, there are multiple postcombustion CCS retrofit projects in
various stages of development. In
particular, NET Power is in advanced
stages of development on a 300 MW
project in west Texas using the AllamFetvedt cycle, which is being designed
to achieve greater than 97 percent CO2
capture. In addition to working on this
first project, NET Power has indicated
that it has an additional project under
development and is working with
95 Competitive Power Ventures (CPV). Shay Clean
Energy Center. https://www.cpv.com/our-projects/
cpv-shay-energy-center/.
96 The Associated Press (AP). (August 30, 2023).
New owner restarts West Virginia coal-fired power
plant and intends to convert it to hydrogen use.
https://apnews.com/article/west-virginia-powerplant-coal-hydrogen-7b46798c8e3b093
a8591f25f66340e8f.
97 omnigenglobal.com.
98 U.S. Energy Information Administration (EIA).
(October 2023). Annual Coal Report 2022. https://
www.eia.gov/coal/annual/pdf/acr.pdf.
99 National Energy Technology Laboratory
(NETL). Large Pilot Carbon Capture Project
Supported by NETL Breaks Ground in Illinois.
https://netl.doe.gov/node/12284.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-17
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
suppliers to support additional future
projects.100
In developing these final rules, the
EPA reviewed the current state and cost
of CCS technology for use with both
steam generating units and stationary
combustion turbines. This review is
reflected in the respective BSER
discussions later in this preamble and is
further detailed in the accompanying
RIA and final TSDs, GHG Mitigation
Measures for Steam Generating Units
and GHG Mitigation Measures—Carbon
Capture and Storage for Combustion
Turbines. These documents are
included in the rulemaking docket.
ddrumheller on DSK120RN23PROD with RULES3
2. 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.’’
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 involves the installation of new
gas burners and related boiler
modifications and may involve the
construction of a natural gas supply
pipeline if one does not already exist. In
recent years, the cost of natural gas cofiring has declined because the expected
difference between coal and gas prices
has decreased and analysis supports
lower capital costs for modifying
existing boilers to co-fire with natural
gas, as discussed in section VII.C.2.a of
this preamble.
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 use of natural gas as a
primary fuel or for startup.101 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.102 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
100 Net Power. (March 11, 2024). Q4 2023
Business Update and Results. https://
d1io3yog0oux5.cloudfront.net/_
cde4aad258e20f5aec49abd8654499f8/netpower/db/
3583/33195/pdf/Q4_2023+Earnings+Presentation_
3.11.24.pdf.
101 U.S. Energy Information Administration (EIA).
Form 923. https://www.eia.gov/electricity/data/
eia923/.
102 U.S. Environmental Protection Agency (EPA).
‘‘Power Sector Emissions Data.’’ Washington, DC:
Office of Atmospheric Protection, Clean Air
Markets Division. https://campd.epa.gov.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
pipelines to those units, and it 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, many coal-fired
steam generating EGUs have also opted
to switch entirely to providing
generation from the firing of natural gas.
Since 2011, more than 80 coal-fired
utility boilers have been converted to
natural gas-fired utility boilers.103
In developing these final actions, 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 final TSD, GHG
Mitigation Measures for Steam
Generating Units. Both documents are
included in the rulemaking docket.
3. Efficient Generation
Highly efficient generation is the
BSER technology upon which the first
phase standards of performance are
based for certain new and reconstructed
stationary combustion turbine EGUs.
This technology is available for both
simple cycle and combined cycle
combustion turbines and has been
demonstrated—along with best
operating and maintenance practices—
to reduce emissions. Generally, as the
thermal efficiency of a combustion
turbine increases, less fuel is burned per
gross MWh of electricity produced and
there is a corresponding decrease in CO2
and other air emissions.
For simple cycle turbines,
manufacturers continue to improve the
efficiency by increasing firing
temperature, increasing pressure ratios,
using intercooling on the air
compressor, and adopting other
measures. Best operating practices for
simple cycle 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, a highly efficient combustion
turbine engine is matched with a highefficiency HRSG. 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
103 U.S. Energy Information Administration (EIA).
(5 August 2020). Today in Energy. More than 100
coal-fired plants have been replaced or converted to
natural gas since 2011. https://www.eia.gov/
todayinenergy/detail.php?id=44636.
PO 00000
Frm 00019
Fmt 4701
Sfmt 4700
39815
infiltration, and cleaning and
maintaining heat transfer surfaces.
As discussed in section VIII.F.2.b of
this preamble, efficient generation
technologies have been in use at
facilities in the power sector for decades
and the levels of efficiency that the EPA
is finalizing in this rule have been
achieved by many recently constructed
turbines. The efficiency improvements
are incremental in nature and do not
change how the combustion turbine is
operated or maintained and present
little incremental capital or compliance
costs compared to other types of
technologies that may be considered for
new and reconstructed sources. In
addition, more efficient designs have
lower fuel costs, which offset at least a
portion of the increase in capital costs.
For additional discussion of this BSER
technology, see the final TSD, Efficient
Generation in Combustion Turbines in
the docket for this rulemaking.
Efficiency improvements are also
available for fossil fuel-fired steam
generating units, and as discussed
further in section VII.D.4.a, the more
efficiently an EGU operates the less fuel
it consumes, thereby emitting lower
amounts of CO2 and other air pollutants
per MWh generated. Efficiency
improvements for steam generating
EGUs 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. These reductions are
small relative to the reductions that are
achievable from natural gas co-firing
and from CCS. Also, as efficiency
increases, some facilities could increase
their utilization and therefore increase
their CO2 emissions (as well as
emissions of other air pollutants). This
phenomenon is known as the ‘‘rebound
effect.’’ Because of this potential for
perverse GHG emission outcomes
resulting from deployment of efficiency
measures at certain steam generating
units, coupled with the relatively minor
overall GHG emission reductions that
would be expected, the EPA is not
finalizing efficiency improvements as
the BSER for any subcategory of existing
coal-fired steam generating units.
Specific details of efficiency measures
are described in the final TSD, GHG
Mitigation Measures for Steam
Generating Units, and an updated 2023
Sargent and Lundy HRI report (Heat
Rate Improvement Method Costs and
Limitations Memo), available in the
docket.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-18
39816
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
D. The Electric Power Sector: Trends
and Current Structure
ddrumheller on DSK120RN23PROD with RULES3
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—especially coal-fired
power plants—with more efficient and
lower-cost alternatives.
These developments have significant
implications for the types of controls
that the EPA determined to qualify as
the BSER for different types of fossil
fuel-fired EGUs. For example, power
plant owners and operators retired an
average annual coal-fired EGU capacity
of 10 GW from 2015 to 2023, and coalfired EGUs comprised 58 percent of all
retired capacity in 2023.104 While use of
CCS promises significant emissions
reduction from fossil fuel-fired sources,
it requires substantial up-front capital
expenditure. Therefore, it is not a
feasible or cost-reasonable emission
reduction technology for units that
intend to cease operation before they
would be able to amortize its costs.
Industry stakeholders requested that the
EPA structure these rules to avoid
imposing costly control obligations on
coal-fired power plants that have
announced plans to voluntarily cease
operations, and the EPA has determined
the BSER in accordance with its
understanding of which coal-fired units
will be able to feasibly and costeffectively deploy the BSER
technologies. In addition, the EPA
recognizes that utilities and power plant
operators are building new natural gasfired 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 finalizing as the BSER for
these turbines.
104 U.S. Energy Information Administration (EIA).
(7 February 2023). Today in Energy. Coal and
natural gas plants will account for 98 percent of
U.S. capacity retirements in 2023. https://
www.eia.gov/todayinenergy/detail.php?id=55439.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
2. Broad Trends Within the Power
Sector
For more than a decade, the power
sector has been experiencing 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; 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, as discussed in
section IV.D.3.b of this preamble and in
the final TSD, Power Sector Trends, the
existing fleet of coal-fired EGUs
continues to age and become more
costly to maintain and operate. At the
same time, natural gas prices have held
relatively low due to increased supply,
and renewable costs have fallen rapidly
with technological improvement and
growing scale. Natural gas surpassed
coal in monthly net electricity
generation for the first time in April
2015, and since that time natural gas has
maintained its position as the primary
fuel for base load electricity generation,
for peaking applications, and for
balancing renewable generation.105 In
2023, generation from natural gas was
more than 2.5 times as much as
generation from coal.106 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,
CCS and associated infrastructure,
advanced geothermal systems, and
advanced distributed energy resources
(DER) as well as more traditional wind,
solar, and battery energy storage
105 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.
106 U.S. Energy Information Administration (EIA).
Electric Power Monthly, March 2024. https://
www.eia.gov/electricity/monthly/current_month/
march2024.pdf.
PO 00000
Frm 00020
Fmt 4701
Sfmt 4700
resources. The IRA provides numerous
tax and other incentives to directly spur
deployment of clean energy
technologies. Particularly relevant to
these final actions, the incentives in the
IRA,107 108 which are discussed in detail
later in this section of the preamble,
support the expansion of technologies,
such as CCS, that reduce GHG emissions
from fossil-fired EGUs.
The ongoing transition of the power
sector is illustrated by a comparison of
data between 2007 and 2022. In 2007,
the year of peak coal generation,
approximately 72 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 2022, fossil fuel net
generation was approximately 60
percent, less than the share in 2007
despite electricity demand remaining
relatively flat over this same period.
Moreover, the share of generation
supplied by coal-fired EGUs fell from 49
percent in 2007 to 19 percent in 2022
while the share supplied by natural gasfired EGUs rose from 22 to 39 percent
during the same period. In absolute
terms, coal-fired generation declined by
59 percent while natural gas-fired
generation increased by 88 percent. This
reflects both the increase in natural gas
capacity as well as an increase in the
utilization of new and existing natural
gas-fired EGUs. The combination of
wind and solar generation also grew
from 1 percent of the electric power
sector mix in 2007 to 15 percent in
2022.109
Additional analysis of the utility
power sector, including projections of
future power sector behavior and the
impacts of these final rules, is discussed
in more detail in section XII of this
preamble, in the accompanying RIA,
and in the final TSD, Power Sector
Trends. The latter two documents are
available in the rulemaking docket.
Consistent with analyses done by other
energy modelers, the information
107 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.
108 U.S. Department of Energy (DOE). August
2023. Investing in American Energy. Significant
Impacts of the Inflation Reduction Act and
Bipartisan Infrastructure Law on the U.S. Energy
Economy and Emissions Reductions. https://
www.energy.gov/sites/default/files/2023-08/
DOE%20OP%20Economy%20Wide%20Report_
0.pdf.
109 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/.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-19
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
provided in the RIA and TSD
demonstrates that the sector trend of
moving away from coal-fired generation
is likely to continue, the share from
natural gas-fired generation is projected
to decline eventually, and the share of
generation from non-emitting
technologies is likely to continue
increasing. For instance, according to
the Energy Information Administration
(EIA), the net change in solar capacity
has been larger than the net change in
capacity for any other source of
electricity for every year since 2020. In
2024, EIA projects that the actual
increase in generation from solar will
exceed every other source of generating
capacity. This is in part because of the
large amounts of new solar coming
online in 2024 but is also due to the
large amount of energy storage coming
online, which will help reduce
renewable curtailments.110 EIA also
projects that in 2024, the U.S. will see
its largest year for installation of both
solar and battery storage. Specifically,
EIA projects that 36.4 GW of solar will
be added, nearly doubling last year’s
record of 18.4 GW. Similarly, EIA
projects 14.3 GW of new energy storage.
This would more than double last year’s
record installation of 6.4 GW and nearly
double the existing total capacity of 15.5
GW. This compares to only 2.5 GW of
new natural gas turbine capacity.111 The
only year since 2013 when renewable
generation did not make up the majority
of new generation capacity in the U.S.
was 2018.112
3. Coal-Fired Generation: Historical
Trends and Current Structure
ddrumheller on DSK120RN23PROD with RULES3
a. Historical 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.113
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
110 U.S. Energy Information Administration (EIA).
Short Term Energy Outlook, December 2023.
111 U.S. Energy Information Administration (EIA).
(February 15, 2024). Today in Energy. Solar and
Battery Storage to make up 81% of new U.S.
Electric-generating capacity in 2024. https://
www.eia.gov/todayinenergy/detail.php?id=61424.
112 U.S. Energy Information Administration (EIA).
Today in Energy. Natural gas and renewables make
up most of 2018 electric capacity additions. https://
www.eia.gov/todayinenergy/detail.php?id=36092.
113 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.
VerDate Sep<11>2014
20:13 May 08, 2024
Jkt 262001
during that 20-year period.114 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 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.115
With no new coal-fired steam generating
units larger than 25 MW commencing
construction in the past decade—and
with the EPA unaware of any plans
being approved to construct a new coalfired 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 2007, the power sector’s total
installed net summer capacity 116 has
increased by 167 GW (17 percent) while
coal-fired steam generating unit capacity
has declined by 123 GW.117 This
reduction in coal-fired steam generating
unit capacity was offset by a net
increase in total installed wind capacity
of 125 GW, net natural gas capacity of
110 GW, and a net increase in utilityscale solar capacity of 71 GW during the
same period. Additionally, significant
amounts (40 GW) of DER solar were also
added. At least half of these changes
were in the most recent 7 years of this
period. From 2015 to 2022, coal
capacity was reduced by 90 GW and this
reduction in capacity was offset by a net
increase of 69 GW of wind capacity, 63
GW of natural gas capacity, and 59 GW
114 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/.
115 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.
116 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).
117 U.S. Energy Information Administration (EIA).
Electric Power Annuals 2010 (Tables 1.1.A and
1.1.B) and 2022 (Tables 4.2.A and 4.2.B).
PO 00000
Frm 00021
Fmt 4701
Sfmt 4700
39817
of utility-scale solar capacity.
Additionally, a net summer capacity of
30 GW of DER solar were added from
2015 to 2022.
b. Current Structure of Coal-Fired
Generation
Although much of the fleet of coalfired 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.118 Moreover, average
annual capacity factors for coal-fired
steam generating units have declined
from 74 to 50 percent since 2007.119
These declining capacity factors
indicate that a larger share of units are
operating in non-base load fashion
largely because they are no longer costcompetitive in many hours of the year.
Older power plants also tend to
become uneconomic over time as they
become more costly to maintain and
operate,120 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 2022 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.121 To further
illustrate this trend, the existing coalfired steam generating units older than
40 years represent 71 percent (129
GW) 122 of the total remaining capacity.
In fact, more than half (100 GW) of the
coal-fired steam generating units still
operating have already announced
retirement dates prior to 2039 or
conversion to gas-fired units by the
118 U.S. Environmental Protection Agency.
National Electric Energy Data System (NEEDS) v7.
December 2023. https://www.epa.gov/power-sectormodeling/national-electric-energy-data-systemneeds.
119 U.S. Energy Information Administration (EIA).
Electric Power Annual 2021, table 1.2.
120 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.
121 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.
122 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/.
E:\FR\FM\09MYR3.SGM
09MYR3
App. A-20
39818
Federal Register / Vol. 89, No. 91 / Thursday, May 9, 2024 / Rules and Regulations
same year.123 As discussed later 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
1,172 million short tons (MMst)
followed by sharp declines in 2015 and
2020.124 In 2015, less than 900 MMst
were produced, and in 2020, the total
dropped to 535 MMst, the lowest output
since 1965. Following the pandemic, in
2022, annual coal production had
increased to 594 MMst. For additional
analysis of the coal-fired steam
generation fleet, see the final TSD,
Power Sector Trends included in the
docket for this rulemaking.
Notwithstanding these trends, in
2022, coal-fired energy sources were
still responsible for 50 percent of CO2
This text is long and has been trimmed here. Open the source document for the complete record.
This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.