[Federal Register Volume 89, Number 91 (Thursday, May 9, 2024)]
[Rules and Regulations]
[Pages 39798-40064]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-09233]
[[Page 39797]]
Vol. 89
Thursday,
No. 91
May 9, 2024
Part III
Environmental Protection Agency
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40 CFR Part 60
New Source Performance Standards for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Fossil Fuel-Fired Electric Generating
Units; Emission Guidelines for Greenhouse Gas Emissions From Existing
Fossil Fuel-Fired Electric Generating Units; and Repeal of the
Affordable Clean Energy Rule; Final Rule
Federal Register / Vol. 89 , No. 91 / Thursday, May 9, 2024 / Rules
and Regulations
[[Page 39798]]
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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.
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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 fuel-fired
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 fuel-fired 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.
ADDRESSES: The EPA has established a 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:
[email protected].
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
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
[[Page 39799]]
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 Gas-Fired 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
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), co-firing with less GHG-intensive fuels,
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.
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\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/sources-greenhouse-gas-emissions.
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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 fuel-fired 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 fuel-fired 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
[[Page 39800]]
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.
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 zero-GHG 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.
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\4\ https://www.epa.gov/ghgemissions/sources-greenhouse-gas-emissions.
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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, 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.
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 gas-fired 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. Well-established
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 cost-reasonable 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 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.
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\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.
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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.
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\6\ https://www.congress.gov/bill/117th-congress/house-bill/3684.
\7\ https://www.congress.gov/bill/117th-congress/house-bill/4346.
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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.
[[Page 39801]]
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, non-air 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.
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\8\ CAA section 111(a)(1).
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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 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 coal-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.
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\9\ 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.
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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 cost-
reasonable 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 imminent-
term 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 gas- and 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 input-based 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
[[Page 39802]]
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 coal-
fired 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 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.
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\10\ See 83 FR 65424, December 20, 2018.
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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 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 fuel-fired 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 fuel-fired steam generating
units in section I.C.4, the revisions of the standards of performance
for coal-fired steam
[[Page 39803]]
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.
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.
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 fuel-fired 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 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.
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\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.
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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
[[Page 39804]]
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).
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\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.
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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\ 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 co-pollutant
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.
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\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 Gas Reporting Program (GHGRP); and safety
regulations for CO2 pipelines administered by the
Pipeline and Hazardous Materials and Safety Administration (PHMSA).
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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 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-fuel-fired
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
[[Page 39805]]
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 near-term (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 imminent-term 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 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 co-firing 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 low-GHG 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.
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\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
administered by the U.S. Department of Energy, such as the recent
H2Hubs selections.
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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
[[Page 39806]]
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 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
fuel-fired 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 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.
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\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.
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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/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-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
[[Page 39807]]
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 well-documented 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 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 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).
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\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).
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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).
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\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'').
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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
[[Page 39808]]
climate change both globally and in the
U.S.19 20 21 22 23 24 25 26 27 28 29 30 31
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\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 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner,
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)].
\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. P[ouml]rtner, 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. P[ouml]rtner, D.C. Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegri[iacute]a, 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. M[eacute]ndez-
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.
\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.)].
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The most recent information demonstrates that the climate is
continuing to change in response to the human-induced buildup of GHGs
in the atmosphere. These recent assessments show that atmospheric
concentrations of GHGs have risen to a level that has no precedent in
human history and that they continue to climb, primarily 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 [deg]C (2.0
[deg]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 [deg]C (1.48 [deg]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 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\ Human-induced climate change has led to heatwaves and
heavy precipitation becoming more frequent and more intense, along with
increases in agricultural and ecological droughts \41\ in many
regions.\42\
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\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. P[eacute]an, S. Berger, N. Caud, Y. Chen, L. Goldfarb,
M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K.
Maycock, T. Waterfield, O. Yelek[ccedil]i, R. Yu, and B. Zhou
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and
New York, 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.
\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.
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The assessment literature demonstrates that modest additional
amounts of warming may lead to a climate different from anything humans
have ever experienced. The 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
[[Page 39809]]
to melt substantially, sea levels would rise dramatically.
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\43\ Annual Mauna Loa CO2 concentration data from
https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt,
accessed September 9, 2023.
\44\ IPCC, 2013.
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The NCA4 found that it is very likely (greater than 90 percent
likelihood) that by mid-century, the Arctic Ocean will be almost
entirely free of sea ice by late summer for the first time in about 2
million years.\45\ Coral reefs will be at risk for almost complete (99
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from
today (2 [deg]C or 3.6 [deg]F since preindustrial). At this
temperature, between 8 and 18 percent of animal, plant, and insect
species could lose over half of the geographic area with suitable
climate for their survival, and 7 to 10 percent of rangeland livestock
would be projected to be lost.\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.
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\45\ USGCRP, 2018.
\46\ IPCC, 2018.
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Every additional increment of temperature comes with consequences.
For example, the half degree of warming from 1.5 to 2 [deg]C (0.9
[deg]F of warming from 2.7 [deg]F to 3.6 [deg]F) above preindustrial
temperatures is projected on a global scale to expose 420 million more
people to frequent extreme heatwaves 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 lower-income regions in the
Sahel, southern Africa, the Mediterranean, central Europe, and the
Amazon. In addition to food security issues, this temperature increase
would have implications for human health in terms of increasing ozone
concentrations, heatwaves, and vector-borne diseases (for example,
expanding the range of the mosquitoes which carry dengue fever,
chikungunya, yellow fever, and the Zika virus or the ticks which carry
Lyme, babesiosis, or Rocky Mountain Spotted Fever).\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\
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\47\ IPCC, 2018.
\48\ IPCC, 2021.
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The NCA4 also evaluated a number of impacts specific to the U.S.
Severe drought and outbreaks of insects like the mountain pine beetle
have killed hundreds of millions of trees in the western U.S. Wildfires
have burned more than 3.7 million acres in 14 of the 17 years between
2000 and 2016, and Federal wildfire suppression costs were about a
billion dollars annually.\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
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\
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\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.
\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. M[eacute]ndez-
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.
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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
[[Page 39810]]
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.
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\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 expert peer review, following EPA peer-
review guidelines.
\55\ Compared to a world with no additional warming after the
model baseline (1986-2005).
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Some GHGs also have impacts beyond those mediated through climate
change. For example, elevated concentrations of CO2
stimulate plant growth (which can be positive in the case of beneficial
species, but negative in terms of weeds and invasive species, and can
also lead to a reduction in plant micronutrients \56\) and cause ocean
acidification. Nitrous oxide depletes the levels of protective
stratospheric ozone.\57\ Methane reacts to form tropospheric ozone.
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\56\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F.
Garofalo, A.S. Khan, I. Loladze, A.A. P[eacute]rez de Le[oacute]n,
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.
\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.
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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 coal-fired 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 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.
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\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), gigawatt-hours (1 GWh =
1 million kWh), or terawatt-hours (1 TWh = 1 billion kWh).
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In general, the EGUs with the lowest operating costs are dispatched
first, and, as a result, an inefficient EGU with high fuel costs will
typically only operate if other lower-cost plants are unavailable or
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.
[[Page 39811]]
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.
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\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/PublishingImages/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.
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2. Types of EGUs
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.
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\
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\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.
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Other generating sources produce electricity by harnessing kinetic
energy from flowing water, wind, or tides, thermal energy from
geothermal wells, or solar energy primarily through photovoltaic solar
arrays. Spurred by a combination of declining costs, consumer
preferences, and government policies, the capacity of these renewable
technologies is growing, and when considered with existing nuclear
energy, accounted for 40 percent of the overall 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 net-zero goals . . . . EEI's
member companies see a clear path to continued emissions reductions
over the next decade using current technologies, including nuclear
power, natural gas-based generation, energy demand efficiency, energy
storage, and deployment of new renewable energy--especially wind and
solar--as older coal-based and less-efficient natural gas-based
generating units retire.'' \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
[[Page 39812]]
emissions from fossil fuel-fired EGUs.'' \64\
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\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.
\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.
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B. GHG Emissions From Fossil Fuel-Fired EGUs
The principal GHGs that accumulate in the Earth's atmosphere above
pre-industrial levels because of human activity are CO2,
CH4, N2O, HFCs, PFCs, and SF6. Of
these, CO2 is the most abundant, accounting for 80 percent
of all GHGs present in the atmosphere. This abundance of CO2
is largely due to the combustion of fossil fuels by the transportation,
electricity, and industrial sectors.\65\
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\65\ U.S. Environmental Protection Agency (EPA). Overview of
greenhouse gas emissions. July 2021. https://www.epa.gov/ghgemissions/overview-greenhouse-gases#carbon-dioxide.
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The amount of CO2 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.
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\66\ Natural gas is primarily CH4, which has a higher
hydrogen to carbon atomic ratio, relative to other fuels, and thus,
produces the least CO2 per unit of heat released. In
addition to a lower CO2 emission rate on a lb/MMBtu
basis, natural gas is generally converted to electricity more
efficiently than coal. According to EIA, the 2020 emissions rate for
coal and natural gas were 2.23 lb CO2/kWh and 0.91 lb
CO2/kWh, respectively. www.eia.gov/tools/faqs/faq.php?id=74&t=11.
\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.
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The EPA prepares the official U.S. Inventory of Greenhouse Gas
Emissions 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.
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\69\ 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-gas-emissions-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-gas-emissions-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.
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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 facility-level GHGs in 2022, 85 were fossil
fuel-fired 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 coal-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).
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\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#.
\74\ U.S. Energy Information Administration (EIA). Preliminary
Monthly Electric Generator Inventory, Form EIA-860M, November 2023.
https://www.eia.gov/electricity/data/eia860m/.
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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 carbon-intensive coal-
fired generation and toward more natural gas-fired and renewable
sources. In 2005, CO2 emissions from coal-fired EGUs alone
measured 1,983 MMT.\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 coal-fired 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.
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\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.
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[[Page 39813]]
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.
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\77\ 80 FR 63662 (October 23, 2015).
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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 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
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\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-transmission-hazardous-liquids.
\80\ GHGRP US EPA. https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-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/news-policy-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-Wstate-WatkinsG-20211028.pdf and https://corporate.exxonmobil.com/news/news-releases/2022/0225_exxonmobil-to-expand-carbon-capture-and-storage-at-labarge-wyoming-facility.
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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 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\
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\83\ Woodall, B. (June 25, 2009). AEP sees carbon capture from
coal ready by 2015. Reuters. https://www.reuters.com/article/idUSTRE55O6TS/.
\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/press-releases-3-26.
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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\
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\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.
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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
[[Page 39814]]
construction or in advanced stages of development.\87\
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\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-Carbon-Management-vPUB_update4.pdf.
\87\ Congressional Budget Office (CBO). (December 13, 2023).
Carbon Capture and Storage in the United States. https://www.cbo.gov/publication/59345.
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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.
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\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-CCS-2021-1.pdf.
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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 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\
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\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-doug-burgum-calls-for-north-dakota-to-be-carbon-neutral-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/2019/03/GHGT14_manuscript_20180913Clean-version.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-country-with-carbon-capture-project-at-coal-creek-station/.
\92\ Rainbow Energy Center. (ND). Carbon Capture. https://rainbowenergycenter.com/what-we-do/carbon-capture/.
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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 full-
scale front end engineering design (FEED) study.
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\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-proposed-wyoming-carbon-capture-project.html.
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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 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.
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\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-power-plant-coal-hydrogen-7b46798c8e3b093a8591f25f66340e8f.
\97\ omnigenglobal.com.
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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\
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\98\ U.S. Energy Information Administration (EIA). (October
2023). Annual Coal Report 2022. https://www.eia.gov/coal/annual/pdf/acr.pdf.
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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.
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\99\ National Energy Technology Laboratory (NETL). Large Pilot
Carbon Capture Project Supported by NETL Breaks Ground in Illinois.
https://netl.doe.gov/node/12284.
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In addition to the Competitive Power Partners project, there are
multiple post-combustion 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 Allam-Fetvedt
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
[[Page 39815]]
suppliers to support additional future projects.\100\
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\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.
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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.
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 co-
firing 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 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\
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\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.
\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.
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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 high-efficiency
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 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.
[[Page 39816]]
D. The Electric Power Sector: Trends and Current Structure
1. Overview
The electric power sector is experiencing a prolonged period of
transition and structural change. Since the generation of electricity
from coal-fired power plants peaked nearly two decades ago, the power
sector has changed at a rapid pace. Today, natural gas-fired power
plants provide the largest share of net generation, coal-fired power
plants provide a significantly smaller share than in the recent past,
renewable energy provides a steadily increasing share, and as new
technologies enter the marketplace, power producers continue to replace
aging assets--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 coal-fired 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 cost-effectively
deploy the BSER technologies. In addition, the EPA recognizes that
utilities and power plant operators are building new natural gas-fired
combustion turbines with plans to operate them at varying levels of
utilization, in coordination with other existing and expected new
energy sources. These patterns of operation are important for the type
of controls that the EPA is finalizing as the BSER for these turbines.
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\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.
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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 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.
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\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.
\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.
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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 gas-fired 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\
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\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/.
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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
[[Page 39817]]
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\
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\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.
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3. Coal-Fired Generation: Historical Trends and Current Structure
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 during that 20-year period.\114\
The peak annual capacity addition was 14 GW, which was added in 1980.
These coal-fired steam generating units operated as base load units for
decades. However, beginning in 2005, the U.S. power sector--and
especially the coal-fired fleet--began experiencing a period of
transition that continues today. Many of the older coal-fired steam
generating units built in the 1960s, 1970s, and 1980s have retired 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 coal-fired EGU--much of the fleet
that remains is aging, expensive to operate and maintain, and
increasingly uncompetitive relative to other sources of generation in
many parts of the country.
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\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.
\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.
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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 utility-scale 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 of utility-scale solar capacity. Additionally, a net summer
capacity of 30 GW of DER solar were added from 2015 to 2022.
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\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).
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b. Current Structure of Coal-Fired Generation
Although much of the fleet of coal-fired steam generating units has
historically operated as base load, there can be notable differences in
design and operation across various facilities. For example, coal-fired
steam generating units smaller than 100 MW comprise 18 percent of the
total number of coal-fired units, but only 2 percent of total coal-
fired capacity.\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 cost-competitive in many hours of the year.
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\118\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v7. December 2023. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
\119\ U.S. Energy Information Administration (EIA). Electric
Power Annual 2021, table 1.2.
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Older power plants also tend to become uneconomic over time as they
become more costly to maintain and operate,\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 coal-fired 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
[[Page 39818]]
same year.\123\ As discussed later in this section, projections
anticipate that this trend will continue.
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\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/.
\123\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v6. October 2022. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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The reduction in coal-fired generation by electric utilities is
also evident in data for annual U.S. coal production, which reflects
reductions in international demand as well. In 2008, annual coal
production peaked at nearly 1,172 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.
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\124\ U.S. Energy Information Administration (EIA). (October
2023). Annual Coal Report 2022. https://www.eia.gov/coal/annual/pdf/acr.pdf.
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Notwithstanding these trends, in 2022, coal-fired energy sources
were still responsible for 50 percent of CO2 emissions from
the electric power sector.\125\
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\125\ U.S. Energy Information Administration (EIA). U.S.
CO2 emissions from energy consumption by source and
sector, 2022. https://www.eia.gov/totalenergy/data/monthly/pdf/flow/CO2_emissions_2022.pdf.
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4. Natural Gas-Fired Generation: Historical Trends and Current
Structure
a. Historical Trends in Natural Gas-Fired Generation
There has been significant expansion of the natural gas-fired EGU
fleet since 2000, coinciding with efficiency improvements of combustion
turbine technologies, increased availability of natural gas, increased
demand for flexible generation to support the expanding capacity of
variable energy resources, and declining costs for all three elements.
According to data from EIA, annual capacity additions for natural gas-
fired EGUs peaked between 2000 and 2006, with more than 212 GW added to
the grid during this period (about 35 GW per year). Of this total,
approximately 147 GW (70 percent) were combined cycle capacity and 65
GW were simple cycle capacity.\126\ From 2007 to 2022, more than 132 GW
of capacity were constructed and approximately 77 percent of that total
were combined cycle EGUs. This figure represents an average of almost
8.8 GW of new combustion turbine generation capacity per year. In 2022,
the net summer capacity of combustion turbine EGUs totaled 419 GW, with
289 GW being combined cycle generation and 130 GW being simple cycle
generation.
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\126\ U.S. Energy Information Administration (EIA). Electric
Generators Inventory, Form EIA-860M, Inventory of Operating
Generators and Inventory of Retired Generators, July 2022. https://www.eia.gov/electricity/data/eia860m/.
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This trend away from electricity generation using coal-fired EGUs
to natural gas-fired turbine EGUs is also reflected in comparisons of
annual capacity factors, sizes, and ages of affected EGUs. For example,
the average annual capacity factors for natural gas-fired units
increased from 28 to 38 percent between 2010 and 2022. And compared
with the fleet of coal-fired steam generating units, the natural gas
fleet is generally smaller and newer. While 67 percent of the coal-
fired steam generating unit fleet capacity is over 500 MW per unit, 75
percent of the gas fleet is between 50 and 500 MW per unit. In terms of
the age of the generating units, nearly 50 percent of the natural gas
capacity has been in service less than 15 years.\127\
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\127\ National Electric Energy Data System (NEEDS) v.6.
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b. Current Structure of Natural Gas-Fired Generation
In the lower 48 states, most combustion turbine EGUs burn natural
gas, and some have the capability to fire distillate oil as backup for
periods when natural gas is not available, such as when residential
demand for natural gas is high during the winter. Areas of the country
without access to natural gas often use distillate oil or some other
locally available fuel. Combustion turbines have the capability to burn
either gaseous or liquid fossil fuels, including but not limited to
kerosene, naphtha, synthetic gas, biogases, liquified natural gas
(LNG), and hydrogen.
Over the past 20 years, advances in hydraulic fracturing (i.e.,
fracking) and horizontal drilling techniques have opened new regions of
the U.S. to gas exploration. As the production of natural gas has
increased, the annual average price has declined during the same
period, leading to more natural gas-fired combustion turbines.\128\
Natural gas net generation increased 181 percent in the past two
decades, from 601 thousand gigawatt-hours (GWh) in 2000 to 1,687
thousand GWh in 2022. For additional analysis of natural gas-fired
generation, see the final TSD, Power Sector Trends included in the
docket for this rulemaking.
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\128\ U.S. Energy Information Administration (EIA). Natural Gas
Annual, September 2021. https://www.eia.gov/energyexplained/natural-gas/prices.php.
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E. The Legislative, Market, and State Law Context
1. Recent Legislation Impacting the Power Sector
On November 15, 2021, President Biden signed the IIJA \129\ (also
known as the Bipartisan Infrastructure Law), which allocated more than
$65 billion in funding via grant programs, contracts, cooperative
agreements, credit allocations, and other mechanisms to develop and
upgrade infrastructure and expand access to clean energy technologies.
Specific objectives of the legislation are to improve the nation's
electricity transmission capacity, pipeline infrastructure, and
increase the availability of low-GHG fuels. Some of the IIJA programs
\130\ that will impact the utility power sector include more than $20
billion to build and upgrade the nation's electric grid, up to $6
billion in financial support for existing nuclear reactors that are at
risk of closing, and more than $700 million for upgrades to the
existing hydroelectric fleet. The IIJA established the Carbon Dioxide
Transportation Infrastructure Finance and Innovation Program to provide
flexible Federal loans and grants for building CO2 pipelines
designed with excess capacity, enabling integrated carbon capture and
geologic storage. The IIJA also allocated $21.5 billion to fund new
programs to support the development, demonstration, and deployment of
clean energy technologies, such as $8 billion for the development of
regional clean hydrogen hubs and $7 billion for the development of
carbon management technologies, including regional direct air capture
hubs, carbon capture large-scale pilot projects for development of
transformational technologies, and carbon capture commercial-scale
demonstration projects to improve efficiency and effectiveness. Other
clean energy technologies with IIJA and IRA funding include industrial
demonstrations, geologic sequestration, grid-scale energy storage, and
advanced nuclear reactors.
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\129\ https://www.congress.gov/bill/117th-congress/house-bill/3684/text.
\130\ https://www.whitehouse.gov/wp-content/uploads/2022/05/BUILDING-A-BETTER-AMERICA-V2.pdf.
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The IRA, which President Biden signed on August 16, 2022,\131\ has
the potential for even greater impacts on the electric power sector.
Energy Security and Climate Change programs in the
[[Page 39819]]
IRA covering grant funding and tax incentives provide significant
investments in low and non GHG-emitting generation. For example, one of
the conditions set by Congress for the expiration of the Clean
Electricity Production Tax Credits of the IRA, found in section 13701,
is a 75 percent reduction in GHG emissions from the power sector below
2022 levels. The IRA also contains the Low Emission Electricity Program
(LEEP) with funding provided to the EPA with the objective to reduce
GHG emissions from domestic electricity generation and use through
promotion of incentives, tools to facilitate action, and use of CAA
regulatory authority. In particular, CAA section 135, added by IRA
section 60107, requires the EPA to conduct an assessment of the GHG
emission reductions expected to occur from changes in domestic
electricity generation and use through fiscal year 2031 and, further,
provides the EPA $18 million ``to ensure that reductions in [GHG]
emissions are achieved through use of the existing authorities of [the
Clean Air Act], incorporating the assessment. . . .'' CAA section
135(a)(6).
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\131\ https://www.congress.gov/bill/117th-congress/house-bill/5376/text.
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The IRA's provisions also demonstrate an intent to support
development and deployment of low-GHG emitting technologies in the
power sector through a broad array of additional tax credits, loan
guarantees, and public investment programs. Particularly relevant for
these final actions, these provisions are aimed at reducing emissions
of GHGs from new and existing generating assets, with tax credits for
CCUS and clean hydrogen production, providing a pathway for the use of
coal and natural gas as part of a low-GHG electricity grid.
To assist states and utilities in their decarbonizing efforts, and
most germane to these final actions, the IRA increased the tax credit
incentives for capturing and storing CO2, including from
industrial sources, coal-fired steam generating units, and natural gas-
fired stationary combustion turbines. The increase in credit values,
found in section 13104 (which revises IRC section 45Q), is 70 percent,
equaling $85/metric ton for CO2 captured and securely stored
in geologic formations and $60/metric ton for CO2 captured
and utilized or securely stored incidentally in conjunction with
EOR.\132\ The CCUS incentives include 12 years of credits that can be
claimed at the higher credit value beginning in 2023 for qualifying
projects. These incentives will significantly cut costs and are
expected to accelerate the adoption of CCS in the utility power and
other industrial sectors. Specifically for the power sector, the IRA
requires that a qualifying carbon capture facility have a
CO2 capture design capacity of not less than 75 percent of
the baseline CO2 production of the unit and that
construction must begin before January 1, 2033. Tax credits under IRC
section 45Q can be combined with some other tax credits, in some
circumstances, and with state-level incentives, including California's
low carbon fuel standard, which is a market-based program with fuel-
specific carbon intensity benchmarks.\133\ The magnitude of this
incentive is driving investment and announcements, evidenced by the
increased number of permit applications for geologic
sequestration.\134\
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\132\ 26 U.S.C. 45Q. Note, qualified facilities must meet
prevailing wage and apprenticeship requirements to be eligible for
the full value of the tax credit.
\133\ Global CCS Institute. (2019). The LCFS and CCS Protocol:
An Overview for Policymakers and Project Developers. Policy report.
https://www.globalccsinstitute.com/wp-content/uploads/2019/05/LCFS-and-CCS-Protocol_digital_version-2.pdf.
\134\ EPA. (2024). Current Class VI Projects under Review at
EPA. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
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The new provisions in section 13204 (IRC section 45V) codify
production tax credits for `clean hydrogen' as defined in the
provision. The value of the credits earned by a project is tiered (four
different tiers) and depends on the estimated GHG emissions of the
hydrogen production process as defined in the statute. The credits
range from $3/kg H2 for less than 0.45 kilograms of
CO2-equivalent emitted per kilogram of low-GHG hydrogen
produced (kg CO2e/kg H2) down to $0.6/kg
H2 for 2.5 to 4.0 kg CO2e/kg H2
(assuming wage and apprenticeship requirements are met). Projects with
production related GHG emissions greater than 4.0 kg CO2e/kg
H2 are not eligible. Future costs for clean hydrogen
produced using renewable energy are anticipated to through 2030 due to
these tax incentives and concurrent scaling up of manufacturing and
deployment of clean hydrogen production facilities.
Both IRC section 45Q and IRC section 45V are eligible for
additional provisions that increase the value and usability of the
credits. Certain tax-exempt entities, such as electric co-operatives,
may elect direct payment for the full 12- or 10-year lifetime of the
credits to monetize the credits directly as cash refunds rather than
through tax equity transactions. Tax-paying entities may elect to have
direct payment of IRC section 45Q or 45V credits for 5 consecutive
years. Tax-paying entities may also elect to transfer credits to
unrelated taxpayers, enabling direct monetization of the credits again
without relying on tax equity transactions.
In addition to provisions such as 45Q that allow for the use of
fossil-generating assets in a low-GHG future, the IRA also includes
significant incentives to deploy clean energy generation. For instance,
the IRA provides an additional 10 percent in production tax credit
(PTC) and investment tax credit (ITC) bonuses for clean energy projects
located in energy communities with historic employment and tax bases
related to fossil fuels.\135\ The IRA's Energy Infrastructure
Reinvestment Program also provides $250 billion for the DOE to finance
loan guarantees that can be used to reduce both the cost of retiring
existing fossil assets and of replacement generation for those assets,
including updating operating energy infrastructure with emissions
control technologies.\136\ As a further example, the Empowering Rural
America (New ERA) Program provides rural electric cooperatives with
funds that can be used for a variety of purposes, including ``funding
for renewable and zero emissions energy systems that eliminate aging,
obsolete or expensive infrastructure'' or that allow rural cooperatives
to ``change [their] purchased-power mixes to support cleaner
portfolios, manage stranded assets and boost [the] transition to clean
energy.'' \137\ The $9.7 billion New ERA program represents the single
largest investment in rural energy systems since the Rural
Electrification Act of 1936.\138\
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\135\ U.S. Department of the Treasury. (April 4, 2023). Treasury
Releases Guidance to Drive Investment to Coal Communities. Press
release. https://home.treasury.gov/news/press-releases/jy1383.
\136\ Fong, C., Posner, D., Varadarajan, U. (February 16, 2024).
The Energy Infrastructure Reinvestment Program: Federal financing
for an equitable, clean economy. Case studies from Missouri and
Iowa. Rocky Mountain Institute (RMI). https://rmi.org/the-energy-infrastructure-reinvestment-program-federal-financing-for-an-equitable-clean-economy/.
\137\ U.S. Department of Agriculture (USDA). Empowering Rural
America New ERA Program. https://www.rd.usda.gov/programs-services/electric-programs/empowering-rural-america-new-era-program.
\138\ Rocky Mountain Institute (RMI). (October 4, 2023). USDA
$9.7B Rural Community Clean Energy Program Receives 150+ Letters of
Interest. Press release. https://rmi.org/press-release/usda-9-7b-rural-community-clean-energy-program-receives-150-letters-of-interest/.
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On September 12, 2023, the EPA released a report assessing the
impact of the IRA on the power sector. Modeling results showed that
economy-wide CO2 emissions are lower under the IRA. The
[[Page 39820]]
results from the EPA's analysis of an array of multi-sector and
electric sector modeling efforts show that a wide range of emissions
reductions are possible. The IRA spurs CO2 emissions
reductions from the electric power sector of 49 to 83 percent below
2005 levels in 2030. This finding reflects diversity in how the models
represent the IRA, the assumptions the models use, and fundamental
differences in model structures.\139\
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\139\ U.S. Environmental Protection Agency (EPA). (September
2023). Electricity Sector Emissions Impacts of the Inflation
Reduction Act. https://www.epa.gov/system/files/documents/2023-09/Electricity_Emissions_Impacts_Inflation_Reduction_Act_Report_EPA-FINAL.pdf.
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In determining the CAA section 111 emission limitations that are
included in these final actions, the EPA did not consider many of the
technologies that receive investment under recent Federal legislation.
The EPA's determination of the BSER focused on ``measures that improve
the pollution performance of individual sources,'' \140\ not generation
technologies that entities could employ as alternatives to fossil fuel-
fired EGUs. However, these overarching incentives and policies are
important context for this rulemaking and influence where control
technologies can be feasibly and cost-reasonably deployed, as well as
how owners and operators of EGUs may respond to the requirements of
these final actions.
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\140\ West Virginia v. EPA, 597 U.S. at 734.
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2. Commitments by Utilities To Reduce GHG Emissions
Integrated resource plans (IRPs) are filed by public utilities and
demonstrate how utilities plan to meet future forecasted energy demand
while ensuring reliable and cost-effective service. In developing these
rules, the EPA reviewed filed IRPs of companies that have publicly
committed to reducing their GHGs. These IRPs demonstrate a range of
strategies that public utilities are planning to adopt to reduce their
GHGs, independent of these final actions. These strategies include
retiring aging coal-fired steam generating EGUs and replacing them with
a combination of renewable resources, energy storage, other non-
emitting technologies, and natural gas-fired combustion turbines, and
reducing GHGs from their natural gas-fired assets through a combination
of CCS and reduced utilization. To affirm these findings, according to
EIA, as of 2022 there are no new coal-fired EGUs in development. This
section highlights recent actions and announced plans of many utilities
across the industry to reduce GHGs from their fleets. Indeed, 50 power
producers that are members of the Edison Electric Institute (EEI) have
announced CO2 reduction goals, two-thirds of which include
net-zero carbon emissions by 2050.\141\ The members of the Energy
Strategies Coalition, a group of companies that operate and manage
electricity generation facilities, as well as electricity and natural
gas transmission and distribution systems, likewise are focused on
investments to reduce carbon dioxide emissions from the electricity
sector.\142\ This trend is not unique. Smaller utilities, rural
electric cooperatives, and municipal entities are also contributing to
these changes.
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\141\ See Comments of Edison Electric Institute to EPA's Pre-
Proposal Docket on Greenhouse Gas Regulations for Fossil Fuel-fired
Power Plants, Document ID No. EPA-HQ-OAR-2022-0723-0024, November
18, 2022 (``Fifty EEI members have announced forward-looking carbon
reduction goals, two-third of which include a net-zero by 2050 or
earlier equivalent goal, and members are routinely increasing the
ambition or speed of their goals or altogether transforming them
into net-zero goals.'').
\142\ 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.
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Many electric utilities have publicly announced near- and long-term
emission reduction commitments independent of these final actions. The
Smart Electric Power Alliance demonstrates that the geographic
footprint of commitments for 100 percent renewable, net-zero, or other
carbon emission reductions by 2050 made by utilities, their parent
companies, or in response to a state clean energy requirement, covers
portions of 47 states and includes 80 percent of U.S. customer
accounts.\143\ According to this same source, 341 utilities in 26
states have similar commitments by 2040. Additional detail about
emission reduction commitments from major utilities is provided in
section 2.2 of the RIA and in the final TSD, Power Sector Trends.
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\143\ Smart Electric Power Alliance Utility Carbon Tracker.
https://sepapower.org/utility-transformation-challenge/utility-carbon-reduction-tracker/.
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3. State Actions To Reduce Power Sector GHG Emissions
States across the country have taken the lead in efforts to reduce
GHG emissions from the power sector. As of mid-2023, 25 states had made
commitments to reduce economy-wide GHG emissions consistent with the
goals of the Paris Agreement, including reducing GHG emissions by 50 to
52 percent by 2030.144 145 146 These actions include
legislation to decarbonize state power systems as well as commitments
that require utilities to expand renewable and clean energy production
through the adoption of renewable portfolio standards (RPS) and clean
energy standards (CES).
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\144\ Cao, L., Brindle., T., Schneer, K., and DeGolia, A.
(December 2023). Turning Climate Commitments into Results:
Evaluating Updated 2023 Projections vs. State Climate Targets.
Environmental Defense Fund (EDF). https://www.edf.org/sites/default/files/2023-11/EDF-State-Emissions-Gap-December-2023.pdf.
\145\ United Nations Framework Convention on Climate Change.
What is the Paris Agreement? https://unfccc.int/process-and-meetings/the-paris-agreement.
\146\ U.S. Department of State and U.S. Executive Office of the
President. November 2021. The Long-Term Strategy of the United
States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.
https://www.whitehouse.gov/wp-content/uploads/2021/10/us-long-term-strategy.pdf.
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Several states have enacted binding economy-wide emission reduction
targets that will require significant decarbonization from state power
sectors, including California, Colorado, Maine, Maryland,
Massachusetts, New Jersey, New York, Rhode Island, Vermont, and
Washington.\147\ These commitments are statutory emission reduction
targets accompanied by mandatory agency directives to develop
comprehensive implementing regulations to achieve the necessary
reductions. Some of these states, along with other neighboring states,
also participate in the Regional Greenhouse Gas Initiative (RGGI), a
carbon market limiting pollution from power plants throughout New
England.\148\ The pollution limit combined with carbon price and
allowance market has led member states to reduce power sector
CO2 emissions by nearly 50 percent since the start of the
program in 2009. This is 10 percent more than all non-RGGI states.\149\
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\147\ Cao, L., Brindle., T., Schneer, K., and DeGolia, A.,
December 2023. Turning Climate Commitments into Results: Evaluating
Updated 2023 Projections vs. State Climate Targets. Environmental
Defense Fund (EDF). https://www.edf.org/sites/default/files/2023-11/EDF-State-Emissions-Gap-December-2023.pdf.
\148\ A full list of states currently participating in RGGI
include Connecticut, Delaware, Maine, Maryland, Massachusetts, New
Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and
Vermont.
\149\ Note that these figures do not include Virginia and
Pennsylvania, which were not members of RGGI for the full duration
of 2009-2023. Acadia Center: Regional Greenhouse Gas Initiative;
Findings and Recommendations for the Third Program Review. https://acadiacenter.wpenginepowered.com/wp-content/uploads/2023/04/AC_RGGI_2023_Layout_R6.pdf.
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Other states dependent on coal-fired power generation or coal
production also have significant, albeit non-
[[Page 39821]]
binding, commitments that signal broad public support for policy with
emissions-based metrics and public affirmation that climate change is
fundamentally linked to fossil-intensive energy sources. These states
include Illinois, Michigan, Minnesota, New Mexico, North Carolina,
Pennsylvania, and Virginia. States like Wyoming, the top coal producing
state in the U.S., have promulgated sector-specific regulations
requiring their public service commissions to implement low-carbon
energy standards for public utilities.150 151 Specific
standards are further detailed in the sections that follow and in the
final TSD, Power Sector Trends.
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\150\ State of Wyoming. (Adopted March 24, 2020). House Bill 200
Reliable and dispatchable low-carbon energy standards. https://www.wyoleg.gov/Legislation/2020/HB0200.
\151\ State of Wyoming. (Adopted March 15, 2024). Senate Bill 42
Low-carbon reliable energy standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042.
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Technologies like CCS provide a means to achieve significant
emission reduction targets. For example, to achieve GHG emission
reduction goals legislatively enacted in 2016, California Senate Bill
100, passed in 2018, requires the state to procure 60 percent of all
electricity from renewable sources by 2030 and plan for 100 percent
from carbon-free sources by 2045.\152\ Achieving California's
established goal of carbon-free electricity by 2045 requires emissions
to be balanced by carbon sequestration, capture, or other technologies.
Therefore, California Senate Bill 905, passed in 2022, requires the
California Air Resources Board (CARB) to establish programs for
permitting CCS projects while preventing the use of captured
CO2 for EOR within the state.\153\ As mentioned previously,
as the top coal producing state, Wyoming has been exceptionally
persistent on the implementation of CCS by incentivizing the national
testing of CCS at Basin Electric's coal-fired Dry Fork Station \154\
and by requiring the consideration of CCS as an alternative to coal
plant retirement.\155\ At least five other states, including Montana
and North Dakota, also have tax incentives and regulations for
CCS.\156\ In the case of Montana, the acquisition of an equity interest
or lease of coal-fired EGUs is prohibited unless it captures and stores
at least 50 percent of its CO2 emissions.\157\ These state
policies have coincided with the planning and development of large CCS
projects.
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\152\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
\153\ Berkeley Law. California Climate Policy Dashboard. https://www.law.berkeley.edu/research/clee/research/climate/climate-policy-dashboard.
\154\ Basin Electric Power Cooperative. (May 2023). Press
Release: Carbon Capture Technology Developers Break Ground at
Wyoming Integrated Test Center Located at Basin Electric's Dry Fork
Station. https://www.basinelectric.com/News-Center/news-briefs/Carbon-capture-technology-developers-break-ground-at-Wyoming-Integrated-Test-Center-located-at-Basin-Electrics-Dry-Fork-Station.
\155\ State of Wyoming. (Adopted March 15, 2024). Senate Bill 42
Low-carbon reliable energy standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042.
\156\ Sabin Center for Climate Change Law. 2019. Legal Pathways
to Deep Decarbonization. Interactive Tracker for State Action on
Carbon Capture. https://cdrlaw.org/ccus-tracker/.
\157\ Sabin Center for Climate Change Law. 2019. Legal Pathways
to Deep Decarbonization. Model Laws. Montana prohibition on
acquiring coal plants without CCS. https://lpdd.org/resources/montana-prohibition-on-acquiring-coal-plants-without-ccs/.
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Other states have broad decarbonization laws that will drive
significant decrease in power sector GHG emissions. In New York, The
Climate Leadership and Community Protection Act, passed in 2019, sets
several climate targets. The most important goals include an 85 percent
reduction in GHG emissions by 2050, 100 percent zero-emission
electricity by 2040, and 70 percent renewable energy by 2030. Other
targets include 9,000 MW of offshore wind by 2035, 3,000 MW of energy
storage by 2030, and 6,000 MW of solar by 2025.\158\ Washington State's
Climate Commitment Act sets a target of reducing GHG emissions by 95
percent by 2050. The state is required to reduce emissions to 1990
levels by 2020, 45 percent below 1990 levels by 2030, 70 percent below
1990 levels by 2040, and 95 percent below 1990 levels by 2050. This
also includes achieving net-zero emissions by 2050.\159\ Illinois'
Climate and Equitable Jobs Act, enacted in September 2021, requires all
private coal-fired or oil-fired power plants to reach zero carbon
emissions by 2030, municipal coal-fired plants to reach zero carbon
emissions by 2045, and natural gas-fired plants to reach zero carbon
emissions by 2045.\160\ In October 2021, North Carolina passed House
Bill 951 that required the North Carolina Utilities Commission to
``take all reasonable steps to achieve a seventy percent (70 percent)
reduction in emissions of carbon dioxide (CO2) emitted in
the state from electric generating facilities owned or operated by
electric public utilities from 2005 levels by the year 2030 and carbon
neutrality by the year 2050.'' \161\
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\158\ New York State. Climate Act: Progress to our Goals.
https://climate.ny.gov/Our-Impact/Our-Progress.
\159\ Department of Ecology Washington State. Greenhouse Gases.
https://ecology.wa.gov/Air-Climate/Climate-change/Tracking-greenhouse-gases.
\160\ State of Illinois General Assembly. Public Act 102-0662:
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
\161\ General Assembly of North Carolina, House Bill 951 (2021).
https://www.ncleg.gov/Sessions/2021/Bills/House/PDF/H951v5.pdf.
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The ambition and scope of these state power sector polices will
impact the electric generation fleet for decades. Seven states with
100-percent power sector decarbonization polices include a total of 20
coal-fired EGUs with slightly less than 10 GW total capacity and
without announced retirement dates before 2039.\162\ Virginia, which
has three coal-steam units with no announced retirement dates and one
with a 2045 retirement date, enacted the Clean Economy Act in 2020 to
impose a 100 percent RPS requirement by 2050. The combined capacity of
all four of these units in Virginia totals nearly 1.5 GW. North
Carolina, which has one coal-fired unit without an announced retirement
date and one with a planned 2048 retirement, as previously mentioned,
enacted a state law in 2021 requiring the state's utilities commission
to achieve carbon neutrality by 2050. The combined capacity of both
units totals approximately 1.4 GW of capacity. Nebraska, where three
public utility boards serving a large portion of the state have adopted
net-zero electricity emission goals by 2040 or 2050, includes six coal-
fired units with a combined capacity of 2.9 GW. The remaining eight
units are in states with long-term decarbonization goals (Illinois,
Louisiana, Maryland, and Wisconsin). All four of these states have set
100 percent clean energy goals by 2050.
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\162\ These estimates are based on an analysis of the EPA's
NEEDS database, which contains information about EGUs across the
country. The analysis includes a basic screen for units within the
NEEDS database that are likely subject to the final 111(d) EGU rule,
namely coal-steam units with capacity greater than 25 MW, and then
removes units with an announced retirement dates prior to 2039,
units with announced plans to convert from coal- to gas-fired units,
and units likely to fall outside of the rule's applicability via the
cogeneration exemption.
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Twenty-nine states and the District of Columbia have enforceable
RPS \163\ that require a percentage of electricity that utilities sell
to come from eligible renewable sources like wind and solar rather than
from fossil fuel-based sources like coal and natural gas. Furthermore,
20 states have adopted a CES that includes some form of clean
[[Page 39822]]
energy requirement or goal with a 100 percent or net-zero target.\164\
A CES shifts generating fleets away from fossil fuel resources by
requiring a percentage of retail electricity to come from sources that
are defined as clean. Unlike an RPS, which defines eligible generation
in terms of the renewable attributes of its energy source, CES
eligibility is based on the GHG emission attributes of the generation
itself, typically with a zero or net-zero carbon emissions requirement.
Additional discussion of state actions and legislation to reduce GHG
emissions from the power sector is provided in the final TSD, Power
Sector Trends.
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\163\ DSIRE, Renewable Portfolio Standards and Clean Energy
Standards (2023). https://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2023/12/RPS-CES-Dec2023-1.pdf; LBNL, U.S. State
Renewables Portfolio & Clean Electricity Standards: 2023 Status
Update. https://emp.lbl.gov/publications/us-state-renewables-portfolio-clean.
\164\ This count is adapted from Lawrence Berkeley National
Laboratory's (LBNL) U.S. State Renewables Portfolio & Clean
Electricity Standards: 2023 Status Update, which identifies 15
states with 100 percent CES. The LBNL count includes Virginia, which
the EPA omits because it considers Virginia a 100 percent RPS.
Further, the LBNL count excludes Louisiana, Michigan, New Jersey,
and Wisconsin because their clean energy goals are set by executive
order. The EPA instead includes Louisiana, New Jersey, and Wisconsin
but characterizes them as goals rather than requirements. Michigan,
which enacted a CES by statute after the LBNL report's publication,
is also included in the EPA count. Finally, the EPA count includes
Maryland, whose December 2023 Climate Pollution Reduction Plan sets
a goal of 100 percent clean energy by 2035, and Delaware, which
enacted a statutory goal to reach net-zero GHG emissions by 2050.
See LBNL, U.S. State Renewables Portfolio & Clean Electricity
Standards: 2023 Status Update, https://emp.lbl.gov/publications/us-state-renewables-portfolio-clean; Maryland's Climate Pollution
Reduction Plan, https://mde.maryland.gov/programs/air/ClimateChange/Maryland%20Climate%20Reduction%20Plan/Maryland%27s%20Climate%20Pollution%20Reduction%20Plan%20-%20Final%20-%20Dec%2028%202023.pdf; and HB 99, An Act to Amend
Titles 7 and 29 of the Delaware Code Relating to Climate Change,
https://legis.delaware.gov/json/BillDetail/GenerateHtmlDocumentEngrossment?engrossmentId=25785&docTypeId=6.
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F. Future Projections of Power Sector Trends
Projections for the U.S. power sector--based on the landscape of
market forces in addition to the known actions of Congress, utilities,
and states--have indicated that the ongoing transition will continue
for specific fuel types and EGUs. The EPA's Power Sector Platform 2023
using IPM reference case (i.e., the EPA's projections of the power
sector, which includes representation of the IRA absent further
regulation), provides projections out to 2050 on future outcomes of the
electric power sector. For more information on the details of this
modeling, see the model documentation.\165\
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\165\ U.S. Environmental Protection Agency.Power Sector Platform
2023 using IPM. April 2024. https://www.epa.gov/power-sector-modeling.
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Since the passage of the IRA in August 2022, the EPA has engaged
with many external partners, including other governmental entities,
academia, non-governmental organizations (NGOs), and industry, to
understand the impacts that the IRA will have on power sector GHG
emissions. In addition to engaging in several workgroups, the EPA has
contributed to two separate journal articles that include multi-model
comparisons of IRA impacts across several state-of-the-art models of
the U.S. energy system and electricity sector 166 167 and
participated in public events exploring modeling assumptions for the
IRA.\168\ The EPA plans to continue collaborating with stakeholders,
conducting external engagements, and using information gathered to
refine modeling of the IRA.
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\166\ Bistline, et al. (2023). ``Emissions and Energy System
Impacts of the Inflation Reduction Act of 2022.'' https://www.science.org/stoken/author-tokens/ST-1277/full.
\167\ Bistline, et al. (2023). ``Power Sector Impacts of the
Inflation Reduction Act of 2022.''https://iopscience.iop.org/article/10.1088/1748-9326/ad0d3b.
\168\ Resource for the Future (2023). ``Future Generation:
Exploring the New Baseline for Electricity in the Presence of the
Inflation Reduction Act.'' https://www.rff.org/events/rff-live/future-generation-exploring-the-new-baseline-for-electricity-in-the-presence-of-the-inflation-reduction-act/.
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While much of the discussion below focuses on the EPA's Power
Sector Platform 2023 using IPM reference case, many other analyses show
similar trends,\169\ and these trends are consistent with utility IRPs
and public GHG reduction commitments, as well as state actions, both of
which were described in the previous sections.
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\169\ A wide variety of modeling teams have assessed baselines
with IRA. The baseline estimated here is generally in line with
these other estimates. Bistline, et al. (2023). ``Power Sector
Impacts of the Inflation Reduction Act of 2022.'' https://iopscience.iop.org/article/10.1088/1748-9326/ad0d3b.
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1. Future Projections for Coal-Fired Generation
As described in the EPA's baseline modeling, coal-fired steam
generating unit capacity is projected to fall from 181 GW in 2023 \170\
to 52 GW in 2035, of which 11 GW includes retrofit CCS. Generation from
coal-fired steam generating units is projected to also fall from 898
thousand GWh in 2021 \171\ to 236 thousand GWh by 2035. This change in
generation reflects the anticipated continued decline in projected
coal-fired steam generating unit capacity as well as a steady decline
in annual operation of those EGUs that remain online, with capacity
factors falling from approximately 48 percent in 2022 to 45 percent in
2035 at facilities that do not install CCS. By 2050, coal-fired steam
generating unit capacity is projected to diminish further, with only 28
GW, or less than 16 percent of 2023 capacity (and approximately 9
percent of the 2010 capacity), still in operation across the
continental U.S.
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\170\ U.S. Energy Information Administration (EIA), Preliminary
Monthly Electric Generator Inventory, December 2023. https://www.eia.gov/electricity/data/eia860m/
\171\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
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These projections are driven by the eroding economic opportunities
for coal-fired steam generating units to operate, the continued aging
of the fleet of coal-fired steam generating units, and the continued
availability and expansion of low-cost alternatives, like natural gas,
renewable technologies, and energy storage. The projected retirements
continue the trend of coal plant retirements in recent decades that is
described in section IV.D.3. of this preamble (and further in the Power
Sector Trends technical support document). The decline in coal
generation capacity has generally resulted from a more competitive
economic environment and increasing coal plant age. Most notably,
declines in natural gas prices associated with the rise of hydraulic
fracturing and horizontal drilling lowered the cost of natural gas-
fired generation.\172\ Lower gas generation costs reduced coal plant
capacity factors and revenues. Rapid declines in the costs of
renewables and battery storage have put further price pressure on coal
plants, given the zero marginal cost operation of solar and
wind.173 174 175 In addition, most operational coal plants
today were built before 2000, and many are reaching or have surpassed
their expected useful lives.\176\ Retiring coal plants tend to be
[[Page 39823]]
old.\177\ As plants age, their efficiency tends to decline and
operations and maintenance costs increase. Older coal plant operational
parameters are less aligned with current electric grid needs. Coal
plants historically were used as base load power sources and can be
slow (or expensive) to increase or decrease generation output
throughout a typical day. That has put greater economic pressure on
older coal plants, which are forced to either incur the costs of
adjusting their generation or operate during less profitable hours when
loads are lower or renewable generation is more plentiful.\178\ All of
these factors have contributed to retirements over the past 15 years,
and similar underlying factors are projected to continue the trend of
coal retirements in the coming years.
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\172\ International Energy Agency (IEA). Energy Policies of IEA
Countries: United States 2019 Review. https://iea.blob.core.windows.net/assets/7c65c270-ba15-466a-b50d-1c5cd19e359c/United_States_2019_Review.pdf.
\173\ U.S. Energy Information Administration (EIA). (April 13,
2023). U.S. Electric Capacity Mix shifts from Fossil Fuels to
Renewables in AEO2023. https://www.eia.gov/todayinenergy/detail.php?id=56160.
\174\ Solomon, M., et al. (January 2023). Coal Cost Crossover
3.0: Local Renewables Plus Storage Create New Opportunities for
Customer Savings and Community Reinvestment. Energy Innovation.
https://energyinnovation.org/wp-content/uploads/2023/01/Coal-Cost-Crossover-3.0.pdf.
\175\ Barbose, G., et al. (September 2023). Tracking the Sun:
Pricing and Design Trends for Distributed Photovoltaic Systems in
the United States, 2023 Edition. Lawrence Berkeley National
Laboratory. https://emp.lbl.gov/sites/default/files/5_tracking_the_sun_2023_report.pdf.
\176\ U.S. Energy Information Administration (EIA). (August
2022). Electric Generators Inventory, Form-860M, Inventory of
Operating Generators and Inventory of Retired Generators. https://www.eia.gov/electricity/data/eia860m/.
\177\ Mills, A., et al. (November 2017). Power Plant
Retirements: Trends and Possible Drivers. Lawrence Berkeley National
Laboratory. https://live-etabiblio.pantheonsite.io/sites/default/files/lbnl_retirements_data_synthesis_final.pdf.
\178\ National Association of Regulatory Utility Commissioners.
(January 2020). Recent Changes to U.S. Coal Plant Operations and
Current Compensation Practices. https://pubs.naruc.org/pub/7B762FE1-A71B-E947-04FB-D2154DE77D45.
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In 2020, there was a total of 1,439 million metric tons of
CO2 emissions from the power sector with coal-fired sources
contributing to more than half of those emissions. In the EPA's Power
Sector Platform 2023 using IPM reference case, power sector related
CO2 emission are projected to fall to 724 million metric
tons by 2035, of which 23 percent is projected to come from coal-fired
sources in 2035.
2. Future Projections for Natural Gas-Fired Generation
As described in the EPA's Power Sector Platform 2023 using IPM
reference case, natural gas-fired capacity is expected to continue to
build out during the next decade with 34 GW of new capacity projected
to come online by 2035 and 261 GW of new capacity by 2050. By 2035, the
new natural gas capacity is comprised of 14 GW of simple cycle turbines
and 20 GW of combined cycle turbines. By 2050, most of the incremental
new capacity is projected to come just from simple cycle turbines. This
also represents a higher rate of new simple cycle turbine builds
compared to the reference periods (i.e., 2000-2006 and 2007-2021)
discussed previously in this section.
It should be noted that despite this increase in capacity, both
overall generation and emissions from the natural gas-fired capacity
are projected to decline. Generation from natural gas units is
projected to fall from 1,579 thousand GWh in 2021 \179\ to 1,344
thousand GWh by 2035. Power sector related CO2 emissions
from natural gas-fired EGUs were 615 million metric tons in 2021.\180\
By 2035, emission levels are projected to reach 521 million metric
tons, 96 percent of which comes from NGCC sources.
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\179\ U.S. Energy Information Administration (EIA), Electric
Power Annual, table 3.1.A. November 2022. https://www.eia.gov/electricity/annual/.
\180\ U.S. Environmental Protection Agency, Inventory of U.S.
Greenhouse Gas Emission Sources and Sinks. February 2023. https://www.epa.gov/system/files/documents/2023-02/US-GHG-Inventory-2023-Main-Text.pdf.
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The decline in generation and emissions is driven by a projected
decline in NGCC capacity factors. In model projections, NGCC units have
a capacity factor early in the projection period of 59 percent, but by
2035, capacity factor projections fall to 48 percent as many of these
units switch from base load operation to more intermediate load
operation to support the integration of variable renewable energy
resources. Natural gas-fired simple cycle turbine capacity factors also
fall, although since they are used primarily as a peaking resource and
their capacity factors are already below 10 percent annually, their
impact on generation and emissions changes are less notable.
Some of the reasons for this anticipated continued growth in
natural gas-fired capacity, coupled with a decline in generation and
emissions, include the anticipated growth in peak load, retirement of
older fossil generators, and growth in renewable energy coupled with
the greater flexibility offered by combustion turbines. Simple cycle
turbines operate at lower efficiencies than NGCC units but offer fast
startup times to meet peaking load demands. In addition, combustion
turbines, along with energy storage technologies and demand response
strategies, support the expansion of renewable electricity by meeting
demand during peak periods and providing flexibility around the
variability of renewable generation and electricity demand. In the
longer term, as renewables and battery storage grow, they are
anticipated to outcompete the need for some natural gas-fired
generation and the overall utilization of natural gas-fired capacity is
expected to decline. For additional discussion and analysis of
projections of future coal- and natural gas-fired generation, see the
final TSD, Power Sector Trends in the docket for this rulemaking.
As explained in greater detail later in this preamble and in the
accompanying RIA, future generation projections for natural gas-fired
combustion turbines differ from those highlighted in recent historical
trends. The largest source of new generation is from renewable energy,
and projections show that total natural gas-fired combined cycle
capacity is likely to decline after 2030 in response to increased
generation from renewables, deployment of energy storage, and other
technologies. Approximately 95 percent of capacity additions in 2024
are expected to be from non-emitting generation resources including
solar, battery storage, wind, and nuclear.\181\ The IRA is likely to
influence this trend, which is also expected to impact the operation of
certain combustion turbines. For example, as the electric output from
additional variable renewable generating sources fluctuates daily and
seasonally, flexible low and intermediate load combustion turbines will
be needed to support these variable sources and provide reliability to
the grid. This requires the ability to start and stop quickly and
change load more frequently. Today's system includes 212 GW of
intermediate and low load combustion turbines. These operational
changes, alongside other tools like demand response, energy storage,
and expanded transmission, will maintain reliability of the grid.
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\181\ U.S. Energy Information Administration (EIA). Today in
Energy. Solar and battery storage to make up 81 percent of new U.S.
electric-generating capacity in 2024. February 2024. https://www.eia.gov/todayinenergy/detail.php?id=61424.
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V. Statutory Background and Regulatory History for CAA Section 111
A. Statutory Authority To Regulate GHGs From EGUs Under CAA Section 111
The EPA's authority for and obligation to issue these final rules
is CAA section 111, which establishes mechanisms for controlling
emissions of air pollutants from new and existing stationary sources.
CAA section 111(b)(1)(A) requires the EPA Administrator to promulgate a
list of categories of stationary sources that the Administrator, in his
or her judgment, finds ``causes, or contributes significantly to, air
pollution which may reasonably be anticipated to endanger public health
or welfare.'' The EPA has the authority to define the scope of the
source categories, determine the pollutants for which standards should
be developed, and distinguish among classes, types, and sizes within
categories in establishing the standards.
[[Page 39824]]
1. Regulation of Emissions From New Sources
Once the EPA lists a source category, the EPA must, under CAA
section 111(b)(1)(B), establish ``standards of performance'' for ``new
sources'' in the source category. These standards are referred to as
new source performance standards, or NSPS. The NSPS are national
requirements that apply directly to the sources subject to them.
Under CAA section 111(a)(1), a ``standard of performance'' is
defined, in the singular, as ``a standard for emissions of air
pollutants'' that is determined in a specified manner, as noted in this
section, below.
Under CAA section 111(a)(2), a ``new source'' is defined, in the
singular, as ``any stationary source, the construction or modification
of which is commenced after the publication of regulations (or, if
earlier, proposed regulations) prescribing a standard of performance
under this section, which will be applicable to such source.'' Under
CAA section 111(a)(3), a ``stationary source'' is defined as ``any
building, structure, facility, or installation which emits or may emit
any air pollutant.'' Under CAA section 111(a)(4), ``modification''
means any physical change in, or change in the method of operation of,
a stationary source which increases the amount of any air pollutant
emitted by such source or which results in the emission of any air
pollutant not previously emitted. While this provision treats modified
sources as new sources, EPA regulations also treat a source that
undergoes ``reconstruction'' as a new source. Under the provisions in
40 CFR 60.15, ``reconstruction'' means the replacement of components of
an existing facility such that: (1) The fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility; and (2) it is
technologically and economically feasible to meet the applicable
standards. Pursuant to CAA section 111(b)(1)(B), the standards of
performance or revisions thereof shall become effective upon
promulgation.
In setting or revising a performance standard, CAA section
111(a)(1) provides that performance standards are to reflect ``the
degree of emission limitation achievable through the application of the
best system of emission reduction which (taking into account the cost
of achieving such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.'' The term ``standard of
performance'' in CAA 111(a)(1) makes clear that the EPA is to determine
both the ``best system of emission reduction . . . adequately
demonstrated'' (BSER) for the regulated sources in the source category
and the ``degree of emission limitation achievable through the
application of the [BSER].'' West Virginia v. EPA, 597 U.S. 697, 709
(2022). To determine the BSER, the EPA first identifies the ``system[s]
of emission reduction'' that are ``adequately demonstrated,'' and then
determines the ``best'' of those systems, ``taking into account''
factors including ``cost,'' ``nonair quality health and environmental
impact,'' and ``energy requirements.'' The EPA then derives from that
system an ``achievable'' ``degree of emission limitation.'' The EPA
must then, under CAA section 111(b)(1)(B), promulgate ``standard[s] for
emissions''--the NSPS--that reflect that level of stringency.
2. Regulation of Emissions From Existing Sources
When the EPA establishes a standard for emissions of an air
pollutant from new sources within a category, it must also, under CAA
section 111(d), regulate emissions of that pollutant from existing
sources within the same category, unless the pollutant is regulated
under the National Ambient Air Quality Standards (NAAQS) program, under
CAA sections 108-110, or the National Emission Standards for Hazardous
Air Pollutants (NESHAP) program, under CAA section 112. See CAA section
111(d)(1)(A)(i) and (ii); West Virginia, 597 U.S. at 710.
CAA section 111(d) establishes a framework of ``cooperative
federalism for the regulation of existing sources.'' American Lung
Ass'n, 985 F.3d at 931. CAA sections 111(d)(1)(A)-(B) require ``[t]he
Administrator . . . to prescribe regulations'' that require ``[e]ach
state . . . to submit to [EPA] a plan . . . which establishes standards
of performance for any existing stationary source for'' the air
pollutant at issue, and which ``provides for the implementation and
enforcement of such standards of performance.'' CAA section 111(a)(6)
defines an ``existing source'' as ``any stationary source other than a
new source.''
To meet these requirements, the EPA promulgates ``emission
guidelines'' that identify the BSER and the degree of emission
limitation achievable through the application of the BSER. Each state
must then establish standards of performance for its sources that
reflect that level of stringency. However, the states need not compel
regulated sources to adopt the particular components of the BSER
itself. The EPA's emission guidelines must also permit a state, ``in
applying a standard of performance to any particular source,'' to
``take into consideration, among other factors, the remaining useful
life of the existing source to which such standard applies.'' 42 U.S.C.
7411(d)(1). Once a state receives the EPA's approval of its plan, the
provisions in the plan become federally enforceable against the source,
in the same manner as the provisions of an approved State
Implementation Plan (SIP) under the Act. CAA section 111(d)(2)(B). If a
state elects not to submit a plan or submits a plan that the EPA does
not find ``satisfactory,'' the EPA must promulgate a plan that
establishes Federal standards of performance for the state's existing
sources. CAA section 111(d)(2)(A).
3. EPA Review of Requirements
CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years, review and, if appropriate, revise'' new source performance
standards. However, the Administrator need not review any such standard
if the ``Administrator determines that such review is not appropriate
in light of readily available information on the efficacy'' of the
standard. Id. When conducting a review of an NSPS, the EPA has the
discretion and authority to add emission limits for pollutants or
emission sources not currently regulated for that source category. CAA
section 111 does not by its terms require the EPA to review emission
guidelines for existing sources, but the EPA retains the authority to
do so. See 81 FR 59277 (August 29, 2016) (explaining legal authority to
review emission guidelines for municipal solid waste landfills).
B. History of EPA Regulation of Greenhouse Gases From Electricity
Generating Units Under CAA Section 111 and Caselaw
The EPA has listed more than 60 stationary source categories under
CAA section 111(b)(1)(A). See 40 CFR part 60, subparts Cb-OOOO. In
1971, the EPA listed fossil fuel-fired EGUs (which includes natural
gas, petroleum, and coal) that use steam-generating boilers in a
category under CAA section 111(b)(1)(A). See 36 FR 5931 (March 31,
1971) (listing ``fossil fuel-fired steam generators of more than 250
million Btu per hour heat input''). In 1977, the EPA listed fossil
fuel-fired combustion turbines, which can be used in EGUs, in a
category under CAA section 111(b)(1)(A). See 42 FR 53657 (October 3,
1977) (listing ``stationary gas turbines'').
[[Page 39825]]
Beginning in 2007, several decisions by the U.S. Supreme Court and
the D.C. Circuit have made clear that under CAA section 111, the EPA
has authority to regulate GHG emissions from listed source categories.
The U.S. Supreme Court ruled in Massachusetts v. EPA that GHGs \182\
meet the definition of ``air pollutant'' in the CAA,\183\ and
subsequently premised its decision in AEP v. Connecticut \184\--that
the CAA displaced any Federal common law right to compel reductions in
CO2 emissions from fossil fuel-fired power plants--on its
view that CAA section 111 applies to GHG emissions. The D.C. Circuit
confirmed in American Lung Ass'n v. EPA, 985 F.3d 914, 977 (D.C. Cir.
2021), discussed in section V.B.5, that the EPA is authorized to
promulgate requirements under CAA section 111 for GHG from the fossil
fuel-fired EGU source category notwithstanding that the source category
is regulated under CAA section 112. As discussed in section V.B.6, the
U.S. Supreme Court did not accept certiorari on the question whether
the EPA could regulate GHGs from fossil-fuel fired EGUs under CAA
section 111(d) when other pollutants from fossil-fuel fired EGUs are
regulated under CAA section 112 in West Virginia v. EPA, 597 U.S. 697
(2022), and so the D.C. Circuit's holding on this issue remains good
law.
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\182\ The EPA's 2009 endangerment finding defines the air
pollution which may endanger public health and welfare as the well-
mixed aggregate group of the following gases: CO2,
methane (CH4), nitrous oxide (N2O), sulfur
hexafluoride (SF6), hydrofluorocarbons (HFCs), and
perfluorocarbons (PFCs).
\183\ 549 U.S. 497, 520 (2007).
\184\ 131 S. Ct. 2527, 2537-38 (2011).
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In 2015, the EPA promulgated two rules that addressed
CO2 emissions from fossil fuel-fired EGUs. The first
promulgated standards of performance for new fossil fuel-fired EGUs.
``Standards of Performance for Greenhouse Gas Emissions From New,
Modified, and Reconstructed Stationary Sources: Electric Utility
Generating Units; Final Rule,'' (80 FR 64510; October 23, 2015) (2015
NSPS). The second promulgated emission guidelines for existing sources.
``Carbon Pollution Emission Guidelines for Existing Stationary Sources:
Electric Utility Generating Units; Final Rule,'' (80 FR 64662; October
23, 2015) (Clean Power Plan, or CPP).
1. 2015 NSPS
In 2015, the EPA promulgated an NSPS to limit emissions of GHGs,
manifested as CO2, from newly constructed, modified, and
reconstructed fossil fuel-fired electric utility steam generating
units, i.e., utility boilers and IGCC EGUs, and newly constructed and
reconstructed stationary combustion turbine EGUs. These final standards
are codified in 40 CFR part 60, subpart TTTT. In promulgating the NSPS
for newly constructed fossil fuel-fired steam generating units, the EPA
determined the BSER to be a new, highly efficient, supercritical
pulverized coal (SCPC) EGU that implements post-combustion partial CCS
technology. The EPA concluded that CCS was adequately demonstrated
(including being technically feasible) and widely available and could
be implemented at reasonable cost. The EPA identified natural gas co-
firing and IGCC technology (either with natural gas co-firing or
implementing partial CCS) as alternative methods of compliance.
The 2015 NSPS included standards of performance for steam
generating units that undergo a ``reconstruction'' as well as units
that implement ``large modifications,'' (i.e., modifications resulting
in an increase in hourly CO2 emissions of more than 10
percent). The 2015 NSPS did not establish standards of performance for
steam generating units that undertake ``small modifications'' (i.e.,
modifications resulting in an increase in hourly CO2
emissions of less than or equal to 10 percent), due to the limited
information available to inform the analysis of a BSER and
corresponding standard of performance.
The 2015 NSPS also finalized standards of performance for newly
constructed and reconstructed stationary combustion turbine EGUs. For
newly constructed and reconstructed base load natural gas-fired
stationary combustion turbines, the EPA finalized a standard based on
efficient NGCC technology as the BSER. For newly constructed and
reconstructed non-base load natural gas-fired stationary combustion
turbines and for both base load and non-base load multi-fuel-fired
stationary combustion turbines, the EPA finalized a heat input-based
standard based on the use of lower-emitting fuels (referred to as clean
fuels in the 2015 NSPS). The EPA did not promulgate final standards of
performance for modified stationary combustion turbines due to lack of
information. The 2015 NSPS remains in effect today.
The EPA received six petitions for reconsideration of the 2015
NSPS. On May 6, 2016 (81 FR 27442), the EPA denied five of the
petitions on the basis that they did not satisfy the statutory
conditions for reconsideration under CAA section 307(d)(7)(B) and
deferred action on one petition that raised the issue of the treatment
of biomass. Apart from these petitions, the EPA proposed to revise the
2015 NSPS in 2018, as discussed in section V.B.2.
Multiple parties also filed petitions for judicial review of the
2015 NSPS in the D.C. Circuit. These cases have been briefed and, on
the EPA's motion, are being held in abeyance pending EPA action
concerning the 2018 proposal to revise the 2015 NSPS.
In the 2015 NSPS, the EPA noted that it was authorized to regulate
GHGs from the fossil fuel-fired EGU source categories because it had
listed those source categories under CAA section 111(b)(1)(A). The EPA
added that CAA section 111 did not require it to make a determination
that GHGs from EGUs contribute significantly to dangerous air pollution
(a pollutant-specific significant contribution finding), but in the
alternative, the EPA did make that finding. It explained that
``[greenhouse gas] air pollution may reasonably be anticipated to
endanger public health or welfare,'' 80 FR 64530 (October 23, 2015) and
emphasized that power plants are ``by far the largest emitters'' of
greenhouse gases among stationary sources in the U.S. Id. at 64522. In
American Lung Ass'n v. EPA, 985 F.3d 977 (D.C. Cir. 2021), the court
held that even if the EPA were required to determine that
CO2 from fossil fuel-fired EGUs contributes significantly to
dangerous air pollution--and the court emphasized that it was not
deciding that the EPA was required to make such a pollutant-specific
determination--the determination in the alternative that the EPA made
in the 2015 NSPS was not arbitrary and capricious and, accordingly, the
EPA had a sufficient basis to regulate greenhouse gases from EGUs under
CAA section 111(d) in the ACE Rule. This aspect of the decision remains
good law. The EPA is not reopening and did not solicit comment on any
of those determinations in the 2015 NSPS concerning its rational basis
to regulate GHG emissions from EGUs or its alternative finding that GHG
emissions from EGUs contribute significantly to dangerous air
pollution.
2. 2018 NSPS Proposal To Revise the 2015 NSPS
In 2018, the EPA proposed to revise the NSPS for new, modified, and
reconstructed fossil fuel-fired steam generating units and IGCC units,
in the Review of Standards of Performance for Greenhouse Gas Emissions
From New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units; Proposed Rule (83 FR 65424;
[[Page 39826]]
December 20, 2018) (2018 NSPS Proposal). The EPA proposed to revise the
NSPS for newly constructed units, based on a revised BSER of a highly
efficient SCPC, without partial CCS. The EPA also proposed to revise
the NSPS for modified and reconstructed units. As discussed in IX.A, in
the present action, the EPA is withdrawing this proposed rule.\185\
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\185\ In the 2018 NSPS Proposal, the EPA solicited comment on
whether it is required to make a determination that GHGs from a
source category contribute significantly to dangerous air pollution
as a predicate to promulgating a NSPS for GHG emissions from that
source category for the first time. 83 FR 65432 (December 20, 2018).
The EPA subsequently issued a final rule that provided that it would
not regulate GHGs under CAA section 111 from a source category
unless the GHGs from the category exceed 3 percent of total U.S. GHG
emissions, on grounds that GHGs emitted in a lesser amount do not
contribute significantly to dangerous air pollution. 86 FR 2652
(January 13, 2021). Shortly afterwards, the D.C. Circuit granted an
unopposed motion by the EPA for voluntary vacatur and remand of the
final rule. California v. EPA, No. 21-1035, doc. 1893155 (D.C. Cir.
April 5, 2021).
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3. Clean Power Plan
With the promulgation of the 2015 NSPS, the EPA also incurred a
statutory obligation under CAA section 111(d) to issue emission
guidelines for GHG emissions from existing fossil fuel-fired steam
generating EGUs and stationary combustion turbine EGUs, which the EPA
initially fulfilled with the promulgation of the CPP. See 80 FR 64662
(October 23, 2015). The EPA first determined that the BSER included
three types of measures: (1) improving heat rate (i.e., the amount of
fuel that must be burned to generate a unit of electricity) at coal-
fired steam plants; (2) substituting increased generation from lower-
emitting NGCC plants for generation from higher-emitting steam plants
(which are primarily coal-fired); and (3) substituting increased
generation from new renewable energy sources for generation from fossil
fuel-fired steam plants and combustion turbines. See 80 FR 64667
(October 23, 2015). The latter two measures are known as ``generation
shifting'' because they involve shifting electricity generation from
higher-emitting sources to lower-emitting ones. See 80 FR 64728-29
(October 23, 2015).
The EPA based this BSER determination on a technical record that
evaluated generation shifting, including its cost-effectiveness,
against the relevant statutory criteria for BSER and on a legal
interpretation that the term ``system'' in CAA section 111(a)(1) is
sufficiently broad to encompass shifting of generation from higher-
emitting to lower-emitting sources. See 80 FR 64720 (October 23, 2015).
The EPA then determined the ``degree of emission limitation achievable
through the application of the [BSER],'' CAA section 111(a)(1),
expressed as emission performance rates. See 80 FR 64667 (October 23,
2015). The EPA explained that a state would ``have to ensure, through
its plan, that the emission standards it establishes for its sources
individually, in the aggregate, or in combination with other measures
undertaken by the state, represent the equivalent of'' those
performance rates (80 FR 64667; October 23, 2015). Neither states nor
sources were required to apply the specific measures identified in the
BSER (80 FR 64667; October 23, 2015), and states could include trading
or averaging programs in their state plans for compliance. See 80 FR
64840 (October 23, 2015).
Numerous states and private parties petitioned for review of the
CPP before the D.C. Circuit. On February 9, 2016, the U.S. Supreme
Court stayed the rule pending review, West Virginia v. EPA, 577 U.S.
1126 (2016). The D.C. Circuit held the litigation in abeyance, and
ultimately dismissed it at the petitioners' request. American Lung
Ass'n, 985 F.3d at 937.
4. The CPP Repeal and ACE Rule
In 2019, the EPA repealed the CPP and replaced it with the ACE
Rule. In contrast to its interpretation of CAA section 111 in the CPP,
in the ACE Rule the EPA determined that the statutory ``text and
reasonable inferences from it'' make ``clear'' that a ``system'' of
emission reduction under CAA section 111(a)(1) ``is limited to measures
that can be applied to and at the level of the individual source,'' (84
FR 32529; July 8, 2019); that is, the system must be limited to control
measures that could be applied at and to each source to reduce
emissions at each source. See 84 FR 32523-24 (July 8, 2019).
Specifically, the ACE Rule argued that the requirements in CAA sections
111(d)(1), (a)(3), and (a)(6), that each state establish a standard of
performance ``for'' ``any existing source,'' defined, in general, as
any ``building . . . [or] facility,'' and the requirement in CAA
section 111(a)(1) that the degree of emission limitation must be
``achievable'' through the ``application'' of the BSER, by their terms,
impose this limitation. The EPA concluded that generation shifting is
not such a control measure. See 84 FR 32546 (July 8, 2019). Based on
its view that the CPP was a ``major rule,'' the EPA further determined
that, absent ``a clear statement from Congress,'' the term `` `system
of emission reduction' '' should not be read to encompass ``generation-
shifting measures.'' See 84 FR 32529 (July 8, 2019). The EPA
acknowledged, however, that ``[m]arket-based forces ha[d] already led
to significant generation shifting in the power sector,'' (84 FR 32532;
July 8, 2019), and that there was ``likely to be no difference between
a world where the CPP is implemented and one where it is not.'' See 84
FR 32561 (July 8, 2019); the Regulatory Impact Analysis for the Repeal
of the Clean Power Plan, and the Emission Guidelines for Greenhouse Gas
Emissions from Existing Electric Utility Generating Units, 2-1 to 2-
5.\186\
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\186\ https://www.epa.gov/sites/default/files/2019-06/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf.
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In addition, the EPA promulgated in the ACE Rule a new set of
emission guidelines for existing coal-fired steam-generating EGUs. See
84 FR 32532 (July 8, 2019). In light of ``the legal interpretation
adopted in the repeal of the CPP,'' (84 FR 32532; July 8, 2019)--which
``limit[ed] `standards of performance' to systems that can be applied
at and to a stationary source,'' (84 FR 32534; July 8, 2019)--the EPA
found the BSER to be heat rate improvements alone. See 84 FR 32535
(July 8, 2019). The EPA listed various technologies that could improve
heat rate (84 FR 32536; July 8, 2019), and identified the ``degree of
emission limitation achievable'' by ``providing ranges of expected
[emission] reductions associated with each of the technologies.'' See
84 FR 32537-38 (July 8, 2019).
5. D.C. Circuit Decision in American Lung Association v. EPA Concerning
the CPP Repeal and ACE Rule
Numerous states and private parties petitioned for review of the
CPP Repeal and ACE Rule. In 2021, the D.C. Circuit vacated the ACE
Rule, including the CPP Repeal. American Lung Ass'n v. EPA, 985 F.3d
914 (D.C. Cir. 2021). The court held, among other things, that CAA
section 111(d) does not limit the EPA, in determining the BSER, to
measures applied at and to an individual source. The court noted that
``the sole ground on which the EPA defends its abandonment of the [CPP]
in favor of the ACE Rule is that the text of [CAA section 111] is clear
and unambiguous in constraining the EPA to use only improvements at and
to existing sources in its [BSER].'' 985 F.3d at 944. The court found
``nothing in the text, structure, history, or purpose of [CAA section
111] that compels the reading the EPA adopted.'' 985 F.3d at 957. The
court likewise rejected the
[[Page 39827]]
view that the CPP's use of generation-shifting implicated a ``major
question'' requiring unambiguous authorization by Congress. 985 F.3d at
958-68.
The D.C. Circuit concluded that, because the EPA had relied on an
``erroneous legal premise,'' both the CPP Repeal Rule and the ACE Rule
should be vacated. 985 F.3d at 995. The court did not decide, however,
``whether the approach of the ACE Rule is a permissible reading of the
statute as a matter of agency discretion,'' 985 F.3d at 944, and
instead ``remanded to the EPA so that the Agency may `consider the
question afresh,' '' 985 F.3d at 995 (citations omitted).
The court also rejected the arguments that the EPA cannot regulate
CO2 emissions from coal-fired power plants under CAA section
111(d) at all because it had already regulated mercury emissions from
coal-fired power plants under CAA section 112. 985 F.3d at 988. In
addition, the court held that that the 2015 NSPS included a valid
determination that greenhouse gases from the EGU source category
contributed significantly to dangerous air pollution, which provided a
sufficient basis for a CAA section 111(d) rule regulating greenhouse
gases from existing fossil fuel-fired EGUs. Id. at 977.
Because the D.C. Circuit vacated the ACE Rule on the grounds noted
above, it did not address the other challenges to the ACE Rule,
including the arguments by Petitioners that the heat rate improvement
BSER was inadequate because of the limited number of reductions it
achieved and because the ACE Rule failed to include an appropriately
specific degree of emission limitation.
Upon a motion from the EPA, the D.C. Circuit agreed to stay its
mandate with respect to vacatur of the CPP Repeal, American Lung Assn
v. EPA, No. 19-1140, Order (February 22, 2021), so that the CPP
remained repealed. Therefore, following the D.C. Circuit's decision, no
EPA rule under CAA section 111 to reduce GHGs from existing fossil
fuel-fired EGUs remained in place.
6. U.S. Supreme Court Decision in West Virginia v. EPA Concerning the
CPP
The Supreme Court granted petitions for certiorari from the D.C.
Circuit's American Lung Association decision, limited to the question
of whether CAA section 111 authorized the EPA to determine that
``generation shifting'' was the best system of emission reduction for
fossil-fuel fired EGUs. The Supreme Court did not grant certiorari on
the question of whether the EPA was authorized to regulate GHG
emissions from fossil-fuel fired power plants under CAA section 111,
when fossil-fuel fired power plants are regulated for other pollutants
under CAA section 112. In 2022, the U.S. Supreme Court reversed the
D.C. Circuit's vacatur of the ACE Rule's embedded repeal of the CPP.
West Virginia v. EPA, 597 U.S. 697 (2022). The Supreme Court stated
that CAA section 111 authorizes the EPA to determine the BSER and the
degree of emission limitation that state plans must achieve. Id. at
2601-02. The Supreme Court concluded, however, that the CPP's BSER of
``generation-shifting'' raised a ``major question,'' and was not
clearly authorized by section 111. The Court characterized the
generation-shifting BSER as ``restructuring the Nation's overall mix of
electricity generation,'' and stated that the EPA's claim that CAA
section 111 authorized it to promulgate generation shifting as the BSER
was ``not only unprecedented; it also effected a fundamental revision
of the statute, changing it from one sort of scheme of regulation into
an entirely different kind.'' Id. at 2612 (internal quotation marks,
brackets, and citation omitted). The Court explained that the EPA, in
prior rules under CAA section 111, had set emissions limits based on
``measures that would reduce pollution by causing the regulated source
to operate more cleanly.'' Id. at 2610. The Court noted with approval
those ``more traditional air pollution control measures,'' and gave as
examples ``fuel-switching'' and ``add-on controls,'' which, the Court
observed, the EPA had considered in the CPP. Id. at 2611 (internal
quotations marks and citation omitted). In contrast, the Court
continued, generation shifting was ``unprecedented'' because ``[r]ather
than focus on improving the performance of individual sources, it would
improve the overall power system by lowering the carbon intensity of
power generation. And it would do that by forcing a shift throughout
the power grid from one type of energy source to another.'' Id. at
2611-12 (internal quotation marks, emphasis, and citation omitted).
The Court recognized that a rule based on traditional measures
``may end up causing an incidental loss of coal's market share,'' but
emphasized that the CPP was ``obvious[ly] differen[t]'' because, with
its generation-shifting BSER, it ``simply announc[ed] what the market
share of coal, natural gas, wind, and solar must be, and then
require[ed] plants to reduce operations or subsidize their competitors
to get there.'' Id. at 2613 n.4. The Court also emphasized ``the
magnitude and consequence'' of the CPP. Id. at 2616. It noted ``the
magnitude of this unprecedented power over American industry,'' id. at
2612 (internal quotation marks and citation omitted), and added that
the EPA's adoption of generation shifting ``represent[ed] a
transformative expansion in its regulatory authority.'' Id. at 2610
(internal quotation marks and citation omitted). The Court also viewed
the CPP as promulgating ``a program that . . . Congress had considered
and rejected multiple times.'' Id. at 2614 (internal quotation marks
and citation omitted). For these and related reasons, the Court viewed
the CPP as raising a major question, and therefore, requiring ``clear
congressional authorization'' as a basis. Id. (internal quotation marks
and citation omitted).
The Court declined to address the D.C. Circuit's conclusion that
the text of CAA section 111 did not limit the type of ``system'' the
EPA could consider as the BSER to measures applied at and to an
individual source. See id. at 2615. Nor did the Court address the scope
of the states' compliance flexibilities.
7. D.C. Circuit Order Reinstating the ACE Rule
On October 27, 2022, the D.C. Circuit responded to the U.S. Supreme
Court's reversal by recalling its mandate for the vacatur of the ACE
Rule. American Lung Ass'n v. EPA, No. 19-1140, Order (October 27,
2022). Accordingly, at that time, the ACE Rule came back into effect.
The court also revised its judgment to deny petitions for review
challenging the CPP Repeal Rule, consistent with the judgment in West
Virginia, so that the CPP remains repealed. The court took further
action denying several of the petitions for review unaffected by the
Supreme Court's decision in West Virginia, which means that certain
parts of its 2021 decision in American Lung Association remain in
effect. These parts include the holding that the EPA's prior regulation
of mercury emissions from coal-fired electric power plants under CAA
section 112 does not preclude the Agency from regulating CO2
from coal-fired electric power plants under CAA section 111, and the
holding, discussed above, that the 2015 NSPS included a valid
significant contribution determination and therefore provided a
sufficient basis for a CAA section 111(d) rule regulating greenhouse
gases from existing fossil fuel-fired EGUs. The court's holding to
invalidate amendments to the implementing regulations applicable to
emission guidelines under CAA section 111(d) that extended the
preexisting schedules
[[Page 39828]]
for state and Federal actions and sources' compliance, also remains in
force. Based on the EPA's stated intention to replace the ACE Rule, the
court stayed further proceedings with respect to the ACE Rule,
including the various challenges that its BSER was flawed because it
did not achieve sufficient emission reductions and failed to specify an
appropriately specific degree of emission limitation.
C. Detailed Discussion of CAA Section 111 Requirements
This section discusses in more detail the key requirements of CAA
section 111 for both new and existing sources that are relevant for
these rulemakings.
1. Approach to the Source Category and Subcategorizing
CAA section 111 requires the EPA first to list stationary source
categories that cause or contribute to air pollution which may
reasonably be anticipated to endanger public health or welfare and then
to regulate new sources within each such source category. CAA section
111(b)(2) grants the EPA discretion whether to ``distinguish among
classes, types, and sizes within categories of new sources for the
purpose of establishing [new source] standards,'' which we refer to as
``subcategorizing.'' Whether and how to subcategorize is a decision for
which the EPA is entitled to a ``high degree of deference'' because it
entails ``scientific judgment.'' Lignite Energy Council v. EPA, 198
F.3d 930, 933 (D.C. Cir. 1999).
Although CAA section 111(d)(1) does not explicitly address
subcategorization, since its first regulations implementing the CAA,
the EPA has interpreted it to authorize the Agency to exercise
discretion as to whether and, if so, how to subcategorize, for the
following reasons. CAA section 111(d)(1) grants the EPA authority to
``prescribe regulations which shall establish a procedure . . . under
which each State shall submit to the Administrator a plan [with
standards of performance for existing sources.]'' The EPA promulgates
emission guidelines under this provision directing the states to
regulate existing sources. The Supreme Court has recognized that, under
CAA section 111(d), the ``Agency, not the States, decides the amount of
pollution reduction that must ultimately be achieved. It does so by
again determining, as when setting the new source rules, `the best
system of emission reduction . . . that has been adequately
demonstrated for [existing covered] facilities.' West Virginia, 597
U.S. at 710 (citations omitted).
The EPA's authority to determine the BSER includes the authority to
create subcategories that tailor the BSER for differently situated sets
of sources. Again, for new sources, CAA section 111(b)(2) confers
authority for the EPA to ``distinguish among classes, types, and sizes
within categories.'' Though CAA section 111(d) does not speak
specifically to the creation of subcategories for a category of
existing sources, the authority to identify the ``best'' system of
emission reduction for existing sources includes the discretion to
differentiate between differently situated sources in the category, and
group those sources into subcategories in appropriate circumstances.
The size, type, class, and other characteristics can make different
emission controls more appropriate for different sources. A system of
emission reduction that is ``best'' for some sources may not be
``best'' for others with different characteristics. For more than four
decades, the EPA has interpreted CAA section 111(d) to confer authority
on the Agency to create subcategories. The EPA's implementing
regulations under CAA section 111(d), promulgated in 1975, 40 FR 53340
(November 17, 1975), provide that the Administrator will specify
different emission guidelines or compliance times or both ``for
different sizes, types, and classes of designated facilities when
[based on] costs of control, physical limitations, geographical
location, or [based on] similar factors.'' \187\ This regulation
governs the EPA's general authority to subcategorize under CAA section
111(d), and the EPA is not reopening that issue here. At the time of
promulgation, the EPA explained that subcategorization allows the EPA
to take into account ``differences in sizes and types of facilities and
similar considerations, including differences in control costs that may
be involved for sources located in different parts of the country'' so
that the ``EPA's emission guidelines will in effect be tailored to what
is reasonably achievable by particular classes of existing sources. . .
.'' Id. at 53343. The EPA's authority to ``distinguish among classes,
types, and sizes within categories,'' as provided under CAA section
111(b)(2), generally allows the Agency to place types of sources into
subcategories. This is consistent with the commonly understood meaning
of the term ``type'' in CAA section 111(b)(2): ``a particular kind,
class, or group,'' or ``qualities common to a number of individuals
that distinguish them as an identifiable class.'' See https://www.merriam-webster.com/dictionary/type.
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\187\ 40 CFR 60.22(b)(5), 60.22a(b)(5). Because the definition
of subcategories depends on characteristics relevant to the BSER,
and because those characteristics can differ as between new and
existing sources, the EPA may establish different subcategories as
between new and existing sources.
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The EPA has developed subcategories in many rulemakings under CAA
section 111 since the 1970s. These rulemakings have included
subcategories on the basis of the size of the sources, see 40 CFR
60.40b(b)(1)-(2) (subcategorizing certain coal-fired steam generating
units on the basis of heat input capacity); the types of fuel
combusted, see Sierra Club, v. EPA, 657 F.2d 298, 318-19 (D.C. Cir.
1981) (upholding a rulemaking that established different NSPS ``for
utility plants that burn coal of varying sulfur content''), 2015 NSPS,
80 FR 64510, 64602 (table 15) (October 23, 2015) (subdividing new
combustion turbines on the basis of type of fuel combusted); the types
of equipment used to produce products, see 81 FR 35824 (June 3, 2016)
(promulgating separate NSPS for many types of oil and gas sources, such
as centrifugal compressors, pneumatic controllers, and well sites);
types of manufacturing processes used to produce product, see 42 FR
12022 (March 1, 1977) (announcing availability of final guideline
document for control of atmospheric fluoride emissions from existing
phosphate fertilizer plants) and ``Final Guideline Document: Control of
Fluoride Emissions From Existing Phosphate Fertilizer Plants,'' EPA-
450/2-77-005 1-7 to 1-9, including table 1-2 (applying different
control requirements for different manufacturing operations for
phosphate fertilizer); levels of utilization of the sources, see 2015
NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015) (dividing new
natural gas-fired combustion turbines into the subcategories of base
load and non-base load); the activity level of the sources, see 81 FR
59276, 59278-79 (August 29, 2016) (dividing municipal solid waste
landfills into the subcategories of active and closed landfills); and
geographic location of the sources, see 71 FR 38482 (July 6, 2006)
(SO2 NSPS for stationary combustion turbines subcategorizing
turbines on the basis of whether they are located in, for example, a
continental area, a non-continental area, the part of Alaska north of
the Arctic Circle, and the rest of Alaska). Thus, the EPA has
subcategorized many times in rulemaking under CAA sections 111(b) and
111(d) and based on a wide variety of physical, locational, and
operational characteristics.
Regardless of whether the EPA subcategorizes within a source
category
[[Page 39829]]
for purposes of determining the BSER and the degree of emission
limitation achievable, a state retains certain flexibility in assigning
standards of performance to its affected EGUs. The statutory framework
for CAA section 111(d) emission guidelines, and the flexibilities
available to states within that framework, are discussed below.
2. Key Elements of Determining a Standard of Performance
Congress first included the definition of ``standard of
performance'' when enacting CAA section 111 in the 1970 Clean Air Act
Amendments (CAAA), amended it in the 1977 CAAA, and then amended it
again in the 1990 CAAA to largely restore the definition as it read in
the 1970 CAAA. The current text of CAA section 111(a)(1) reads: ``The
term `standard of performance' means a standard for emission of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' The
D.C. Circuit has reviewed CAA section 111 rulemakings on numerous
occasions since 1973,\188\ and has developed a body of caselaw that
interprets the term ``standard of performance,'' as discussed
throughout this preamble.
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\188\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981);
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999);
Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011);
American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021), rev'd in
part, West Virginia v. EPA, 597 U.S. 697 (2022). See also Delaware
v. EPA, No. 13-1093 (D.C. Cir. May 1, 2015).
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The basis for standards of performance, whether promulgated by the
EPA under CAA section 111(b) or established by the states under CAA
section 111(d), is that the EPA determines the ``degree of emission
limitation'' that is ``achievable'' by the sources by application of a
``system of emission reduction'' that the EPA determines is
``adequately demonstrated,'' ``taking into account'' the factors of
``cost . . . and any nonair quality health and environmental impact and
energy requirements,'' and that the EPA determines to be the ``best.''
The D.C. Circuit has stated that in determining the ``best'' system,
the EPA must also take into account ``the amount of air pollution''
\189\ reduced and the role of ``technological innovation.'' \190\ The
D.C. Circuit has also stated that to determine the ``best'' system, the
EPA may weigh the various factors identified in the statute and caselaw
against each other, and has emphasized that the EPA has discretion in
weighing the factors.191 192
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\189\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981).
\190\ See Sierra Club v. Costle, 657 F.2d at 347.
\191\ See Lignite Energy Council, 198 F.3d at 933.
\192\ CAA section 111(a)(1), by its terms states that the
factors enumerated in the parenthetical are part of the ``adequately
demonstrated'' determination. In addition, the D.C. Circuit's
caselaw makes clear that the EPA may consider these same factors
when it determines which adequately demonstrated system of emission
reduction is the ``best.'' See Sierra Club v. Costle, 657 F.2d at
330 (recognizing that CAA section 111 gives the EPA authority ``when
determining the best technological system to weigh cost, energy, and
environmental impacts'').
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The EPA's overall approach to determining the BSER and degree of
emission limitation achievable, which incorporates the various
elements, is as follows: The EPA identifies ``system[s] of emission
reduction'' that have been ``adequately demonstrated'' for a particular
source category and determines the ``best'' of these systems after
evaluating the amount of emission reductions, costs, any non-air health
and environmental impacts, and energy requirements. As discussed below,
for each of numerous subcategories, the EPA followed this approach to
determine the BSER on the basis that the identified costs are
reasonable and that the BSER is rational in light of the statutory
factors, including the amount of emission reductions, that the EPA
examined in its BSER analysis, consistent with governing precedent.
After determining the BSER, the EPA determines an achievable
emission limit based on application of the BSER.\193\ For a CAA section
111(b) rule, the EPA determines the standard of performance that
reflects the achievable emission limit. For a CAA section 111(d) rule,
the states have the obligation of establishing standards of performance
for the affected sources that reflect the degree of emission limitation
that the EPA has determined. As discussed below, the EPA is finalizing
these determinations in association with each of the BSER
determinations.
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\193\ See, e.g., Oil and Natural Gas Sector: New Source
Performance Standards and National Emission Standards for Hazardous
Air pollutants Reviews (77 FR 49494; August 16, 2012) (describing
the three-step analysis in setting a standard of performance).
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The remainder of this subsection discusses each element in our
general analytical approach.
a. System of Emission Reduction
The CAA does not define the phrase ``system of emission
reduction.'' In West Virginia v. EPA, the Supreme Court recognized that
historically, the EPA had looked to ``measures that improve the
pollution performance of individual sources and followed a
``technology-based approach'' in identifying systems of emission
reduction. In particular, the Court identified ``the sort of `systems
of emission reduction' [the EPA] had always before selected,'' which
included `` `efficiency improvements, fuel-switching,' and `add-on
controls'.'' 597 U.S. at 727 (quoting the Clean Power Plan).\194\
Section 111 itself recognizes that such systems may include off-site
activities that may reduce a source's pollution contribution,
identifying ``precombustion cleaning or treatment of fuels'' as a
``system'' of ``emission reduction.'' 42 U.S.C. 7411(a)(7)(B). A
``system of emission reduction'' thus, at a minimum, includes measures
that an individual source applies that improve the emissions
performance of that source. Measures are fairly characterized as
improving the pollution performance of a source where they reduce the
individual source's overall contribution to pollution.
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\194\ As noted in section V.B.4 of this preamble, the ACE Rule
adopted the interpretation that CAA section 111(a)(1), by its plain
language, limits ``system of emission reduction'' to those control
measures that could be applied at and to each source to reduce
emissions at each source. 84 FR 32523-24 (July 8, 2019). The EPA has
subsequently rejected that interpretation as too narrow. See
Adoption and Submittal of State Plans for Designated Facilities:
Implementing Regulations Under Clean Air Act Section 111(d), 88 FR
80535 (November 17, 2023).
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In West Virginia, the Supreme Court did not define the term
``system of emissions reduction,'' and so did not rule on whether
``system of emission reduction'' is limited to those measures that the
EPA has historically relied upon. It did go on to apply the major
questions doctrine to hold that the term ``system'' does not provide
the requisite clear authorization to support the Clean Power Plan's
BSER, which the Court described as ``carbon emissions caps based on a
generation shifting approach.'' Id. at 2614. While the Court did not
define the outer bounds of the meaning of ``system,'' systems of
emissions reduction like fuel switching, add-on controls, and
efficiency improvements fall comfortably within the scope of prior
practice as recognized by the Supreme Court.
b. ``Adequately Demonstrated''
Under CAA section 111(a)(1), an essential, although not sufficient,
condition for a ``system of emission
[[Page 39830]]
reduction'' to serve as the basis for an ``achievable'' emission
standard is that the Administrator must determine that the system is
``adequately demonstrated.'' The concepts of adequate demonstration and
achievability are closely related: as the D.C. Circuit has stated,
``[i]t is the system which must be adequately demonstrated and the
standard which must be achievable,'' \195\ through application of the
system. An achievable standard means a standard based on the EPA's
record-based finding that sufficient evidence exists to reasonably
determine that the affected sources in the source category can adopt a
specific system of emission reduction to achieve the specified degree
of emission limitation. As discussed below, consistent with Congress's
use of the word ``demonstrated,'' the caselaw has approved the EPA's
``adequately demonstrated'' determinations concerning systems utilized
at test sources or other individual sources operating at commercial
scale. The case law also authorizes the EPA to set an emissions
standard at levels more stringent than has regularly been achieved,
based on the understanding that sources will be able to adopt specific
technological improvements to the system in question that will enable
them to achieve the lower standard. Importantly, and contrary to some
comments received on the proposed rule, CAA section 111(a)(1) does not
require that a system of emission reduction exist in widespread
commercial use in order to satisfy the ``adequately demonstrated''
requirement.\196\ Instead, CAA section 111(a)(1) authorizes the EPA to
establish standards which encourage the deployment of more effective
systems of emission reduction that have been adequately demonstrated
but that are not yet in widespread use. This aligns with Congress's
purpose in enacting the CAA, in particular its recognition that
polluting sources were not widely adopting emission control technology
on a voluntary basis and that Federal regulation was necessary to spur
the development and deployment of those technologies.\197\
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\195\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (1973)
(emphasis omitted).
\196\ See, e.g., Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427
(D.C. Cir. 1973) (in which the D.C. Circuit upheld a CAA section 111
standard based on a system which had been extensively used in Europe
but at the time of promulgation was only in use in the United States
at one plant).
\197\ In introducing the respective bills which ultimately
became the 1970 Clean Air Act upon Conference Committee review, both
the House and Senate emphasized the urgency of the matter at hand,
the intended power of the new legislation, and in particular its
technology-forcing nature. The first page of the House report
declared that ``[t]he purpose of the legislation reported
unanimously by [Committee was] to speed up, expand, and intensify
the war against air pollution in the United States . . .'' H.R. Rep.
No. 17255 at 1 (1970). It was clear, stated the House report, that
until that point ``the strategies which [the United States had]
pursued in the war against air pollution [had] been inadequate in
several important respects, and the methods employed in implementing
those strategies often [had] been slow and less effective than they
might have been.'' Id. The Senate report agreed, stating that their
bill would ``provide a much more intensive and comprehensive attack
on air pollution,'' 1 S. 4358 at 4 (1970), including, crucially, by
increased federal involvement. See id.
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i. Plain Text, Statutory Context, and Legislative History of the
``Adequately Demonstrated'' Provision in CAA Section 111(a)(1)
Analysis of the plain text, statutory context, and legislative
history of CAA section 111(a)(1) establishes two primary themes. First,
Congress assigned the task of determining the appropriate BSER to the
Administrator, based on a reasonable review of available evidence.
Second, Congress authorized the EPA to set a standard, based on the
evidence, that encourages broader adoption of an emissions-reducing
technological approach that may not yet be in widespread use.
The plain text of CAA section 111(a)(1), and in particular the
phrase ``the Administrator determines'' and the term ``adequately,''
confer discretion to the EPA in identifying the appropriate system.
Rather than providing specific criteria for determining what
constitutes appropriate evidence, Congress directed the Administrator
to ``determine[ ]'' that the demonstration is ``adequate[ ].'' Courts
have typically deferred to the EPA's scientific and technological
judgments in making such determinations.\198\ Further, use of the term
``adequate'' in provisions throughout the CAA highlights EPA
flexibility and discretion in setting standards and in analyzing data
that forms the basis for standard setting.
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\198\ The D.C. Circuit stated in Nat'l Asphalt Pavement Ass'n v.
Train, 539 F.2d 775, 786 (D.C. Cir. 1976) ``The standard of review
of actions of the Administrator in setting standards of performance
is an appropriately deferential one, and we are to affirm the action
of the Administrator unless it is ``arbitrary, capricious, an abuse
of discretion, or otherwise not in accordance with law,'' 5 U.S.C.
706(2)(A) (1970). Since this is one of those ``highly technical
areas, where our understanding of the import of the evidence is
attenuated, our readiness to review evidentiary support for
decisions must be correspondingly restrained.'' Ethyl Corporation v.
EPA, 96 S. Ct. 2663 (1976). ``Our `expertise' is not in setting
standards for emission control, but in determining if the standards
as set are the result of reasoned decision-making.'' Essex Chem.
Corp. v. Ruckelshaus, 486 F.2d 427, 434 (D.C. Cir. 1973)) (cleaned
up).''
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In setting NAAQS under CAA section 109, for example, the EPA is
directed to determine, according to ``the judgment of the
Administrator,'' an ``adequate margin of safety.'' \199\ The D.C.
Circuit has held that the use of the term ``adequate'' confers
significant deference to the Administrator's scientific and
technological judgment. In Mississippi v. EPA,\200\ for example, the
D.C. Circuit in 2013 upheld the EPA's choice to set the NAAQS for ozone
below 0.08 ppm, and noted that any disagreements with the EPA's
interpretations of the scientific evidence that underlay this decision
``must come from those who are qualified to evaluate the science, not
[the court].'' \201\ This Mississippi v. EPA precedent aligns with the
general standard for judicial review of the EPA's understanding of the
evidence under CAA section 307(d)(9)(A) (``arbitrary, capricious, an
abuse of discretion, or otherwise not in accordance with law'').
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\199\ 42 U.S.C. 7409(b)(1).
\200\ 744 F.3d 1334 (D.C. Cir. 2013).
\201\ Id.
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The plain language of the phrase ``has been adequately
demonstrated,'' in context, and in light of the legislative history,
further strongly indicates that the system in question need not be in
widespread use at the time the EPA's rule is published. To the
contrary, CAA section 111(a)(1) authorizes technology forcing, in the
sense that the EPA is authorized to promote a system which is not yet
in widespread use; provided the technology is in existence and the EPA
has adequate evidence to extrapolate.\202\
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\202\ While not relevant here, because CCS is already in
existence, the text, case law, and legislative history make a
compelling case that EPA is authorized to go farther than this, and
may make a projection regarding the way in which a particular system
will develop to allow for greater emissions reductions in the
future. See 80 FR 64556-58 (discussion of ``adequately
demonstrated'' in 2015 NSPS).
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Some commenters argued that use of the phrase ``has been'' in ``has
been adequately demonstrated'' means that the system must be in
widespread commercial use at the time of rule promulgation. We
disagree. Considering the plain text, the use of the past tense, ``has
been adequately demonstrated'' indicates a requirement that the
technology currently be demonstrated. However, ``demonstrated'' in
common usage at the time of enactment meant to ``explain or make clear
by using examples, experiments, etc.'' \203\ As a general matter, and
as this definition indicates, the term ``to demonstrate'' suggests the
need for a test or study--as in, for example, a ``demonstration
[[Page 39831]]
project'' or ``demonstration plant''--that is, examples of
technological feasibility.
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\203\ Webster's New World Dictionary: Second College Edition
(David B. Guralnik, ed., 1972).
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The statutory context is also useful in establishing that where
Congress wanted to specify the availability of the control system, it
did so. The only other use of the exact term ``adequately
demonstrated'' occurs in CAA section 119, which establishes that, in
order for the EPA to require a particular ``means of emission
limitation'' for smelters, the Agency must establish that such means
``has been adequately demonstrated to be reasonably available. . . .''
\204\ The lack of the phrase ``reasonably available'' in CAA section
111(a)(1) is notable, and suggests that a system may be ``adequately
demonstrated'' under CAA section 111 even if it is not ``reasonably
available'' for every single source.\205\
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\204\ The statutory text at CAA section 119 continues, ``as
determined by the Administrator, taking into account the cost of
compliance, nonair quality health and environmental impact, and
energy consideration.'' 42 U.S.C. 7419(b)(3).
\205\ It should also be noted that the section 119 language was
added as part of the 1977 Clean Air Act amendments, while the
section 111 language was established in 1970. Thus, Congress was
aware of section 111's more permissive language when it added the
``reasonably available'' language to section 119.
---------------------------------------------------------------------------
The term ``demonstration'' also appears in CAA section 103 in an
instructive context. CAA section 103, which establishes a ``national
research and development program for the prevention and control of air
pollution'' directs that as part of this program, the EPA shall
``conduct, and promote the coordination and acceleration of, research,
investigations, experiments, demonstrations, surveys, and studies
relating to'' the issue of air pollution.\206\ According to the canon
of noscitur a sociis, associated words in a list bear on one another's
meaning.\207\ In CAA section 103, the word ``demonstrations'' appears
alongside ``research,'' ``investigations,'' ``experiments,'' and
``studies''--all words suggesting the development of new and emerging
technology. This supports interpreting CAA section 111(a)(1) to
authorize the EPA to determine a system of emission reduction to be
``adequately demonstrated'' based on demonstration projects, testing,
examples, or comparable evidence.
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\206\ 42 U.S.C. 7403(a)(1).
\207\ As the Supreme Court recently explained in Dubin v. United
States, even words that might be indeterminate alone may be more
easily interpreted in ``company,'' because per noscitur a sociis ``a
word is known by the company it keeps.'' 599 U.S. 110, 244 (2023).
---------------------------------------------------------------------------
Finally, the legislative history of the CAA in general, and section
111 in particular, strongly supports the point that BSER technology
need not be in widespread use at the time of rule enactment. The final
language of CAA section 111(a)(1), requiring that systems of emission
reduction be ``adequately demonstrated,'' was the result of compromise
in the Conference Committee between the House and Senate bill language.
The House bill would have required that the EPA give ``appropriate
consideration to technological and economic feasibility'' when
establishing standards.\208\ The Senate bill would have required that
standards ``reflect the greatest degree of emission control which the
Secretary determines to be achievable through application of the latest
available control technology, processes, operating methods, or other
alternatives.'' \209\ Although the exact language of neither the House
nor Senate bill was adopted in the final bill, both reports made clear
their intent that CAA section 111 would be significantly technology-
forcing. In particular, the Senate Report referred to ``available
control technology''--a phrase that, as just noted, the Senate bill
included--but clarified that the technology need not ``be in actual,
routine use somewhere.'' \210\ The House Report explained that EPA
regulations would ``prevent and control such emissions to the fullest
extent compatible with the available technology and economic
feasibility as determined by [the EPA],'' and ``[i]n order to be
considered `available' the technology may not be one which constitutes
a purely theoretical or experimental means of preventing or controlling
air pollution.'' \211\ This last statement implies that the House
Report anticipated that the EPA's determination may be technology
forcing. Nothing in the legislative history suggests that Congress
intended that the technology already be in widespread commercial use.
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\208\ H.R. Rep. No. 17255 at 921 (1970) (quoting CAA Sec.
112(a), as proposed).
\209\ S. Rept. 4358 at 91 (quoting CAA Sec. 113(b)(2), as
proposed).
\210\ S. Rep. 4358 at 15-16 (1970). The Senate Report went on to
say that the EPA should ``examine the degree of emission control
that has been or can be achieved through the application of
technology which is available or normally can be made available . .
. at a cost and at a time which [the Agency] determines to be
reasonable.'' Id. Again, this language rebuts any suggestion that a
BSER technology must be in widespread use at the time of rule
enactment--Congress assumed only that the technology would be
``available'' or even that it ``[could] be made available,'' not
that it would be already broadly used.
\211\ H.R. Rep. No. 17255 at 900.
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ii. Caselaw
In a series of cases reviewing standards for new sources, the D.C.
Circuit has held that an adequately demonstrated standard of
performance may reflect the EPA's reasonable projection of what that
particular system may be expected to achieve going forward,
extrapolating from available data from pilot projects or individual
commercial-scale sources. A standard may be considered achievable even
if the system upon which the standard is based has not regularly
achieved the standard in testing. See, e.g., Essex Chem. Corp. v.
Ruckelshaus \212\ (upholding a standard of 4.0 lbs per ton based on a
system whose average control rate was 4.6 lbs per ton, and which had
achieved 4.0 lbs per ton on only three occasions and ```nearly equaled'
[the standard] on the average of nineteen different readings.'') \213\
The Ruckelshaus court concluded that the EPA's extrapolation from
available data was ``the result of the exercise of reasoned discretion
by the Administrator'' and therefore ``[could not] be upset by [the]
court.'' \214\ The court also emphasized that in order to be considered
achievable, the standard set by the EPA need not be regularly or even
specifically achieved at the time of rule promulgation. Instead,
according to the court, ``[a]n achievable standard is one which is
within the realm of the adequately demonstrated system's efficiency and
which, while not at a level that is purely theoretical or experimental,
need not necessarily be routinely achieved within the industry prior to
its adoption.'' \215\
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\212\ 486 F.2d 427 (D.C. Cir. 1973).
\213\ Id. at 437.
\214\ Id. at 437.
\215\ Id. at 433-34 (D.C. Cir. 1973). See also Sierra Club v.
Costle, 657 F.2d 298 (D.C. Cir. 1981), which supports the point that
EPA may extrapolate from testing results, rather than relying on
consistent performance, to identify an appropriate system and
standard based on that system. In that case, EPA analyzed scrubber
performance by considering performance during short-term testing
periods. See id. at 377.
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Case law also establishes that the EPA may set a standard more
stringent than has regularly been achieved based on its identification
of specific available technological improvements to the system. See
Sierra Club v. Costle \216\ (upholding a 90 percent standard for
SO2 emissions from coal-fired steam generators despite the
fact that not all plants had previously achieved this standard, based
on the EPA's expectations for improved performance with specific
technological fixes and the use of ``coal washing'' going
forward).\217\ Further, the EPA may extrapolate based on testing at a
particular kind of source to conclude that the technology at issue will
also be effective at a different,
[[Page 39832]]
related, source. See Lignite Energy Council v. EPA \218\ (holding it
permissible to base a standard for industrial boilers on application of
SCR based on extrapolated information about the application of SCR on
utility boilers).\219\ The Lignite court clarified that ``where data
are unavailable, EPA may not base its determination that a technology
is adequately demonstrated or that a standard is achievable on mere
speculation or conjecture,'' but the ``EPA may compensate for a
shortage of data through the use of other qualitative methods,
including the reasonable extrapolation of a technology's performance in
other industries.'' \220\
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\216\ 657 F.2d 298 (D.C. Cir. 1981).
\217\ Id. at 365, 370-73; 365.
\218\ 198 F.3d 930 (D.C. Cir. 1999).
\219\ See id. at 933-34.
\220\ Id. at 934 (emphasis added).
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As a general matter, the case law is clear that at the time of Rule
promulgation, the system which the EPA establishes as BSER need not be
in widespread use. See, e.g., Ruckelshaus \221\ (upholding a standard
based on a relatively new system which was in use at only one United
States plant at the time of rule promulgation. Although the system was
in use more extensively in Europe at the time of rule promulgation, the
EPA based its analysis on test results from the lone U.S. plant only.)
\222\ This makes good sense, because, as discussed above, CAA section
111(a)(1) authorizes a technology-forcing standard that encourages
broader adoption of an emissions-reducing technological approach that
is not yet broadly used. It follows that at the time of promulgation,
not every source will be prepared to adopt the BSER at once. Instead,
as discussed next, the EPA's responsibility is to determine that the
technology can be adopted in a reasonable period of time, and to base
its requirements on this understanding.
---------------------------------------------------------------------------
\221\ 486 F.2d 375 (D.C. Cir. 1973). See also Sierra Club v.
Costle, 657 F.2d 298 (D.C. Cir. 1981), which supports the point that
EPA may extrapolate from testing results, rather than relying on
consistent performance, to identify an appropriate system and
standard based on that system. In that case, EPA analyzed scrubber
performance by considering performance during short-term testing
periods. See id. at 377.
\222\ 486 F.2d at 435-36.
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iii. Compliance Timeframe
The preceding subsections have shown various circumstances under
which the EPA may determine that a system of emission reduction is
``adequately demonstrated.'' In order to establish that a system is
appropriate for the source category as a whole, the EPA must also
demonstrate that the industry can deploy the technology at scale in the
compliance timeframe. The D.C. Circuit has stated that the EPA may
determine a ``system of emission reduction'' to be ``adequately
demonstrated'' if the EPA reasonably projects that it may be more
broadly deployed with adequate lead time. This view is well-grounded in
the purposes of CAA section 111(a)(1), discussed above, which aim to
control dangerous air pollution by allowing for standards which
encourage more widespread adoption of a technology demonstrated at
individual plants.
As a practical matter, CAA section 111's allowance for lead time
recognizes that existing pollution control systems may be complex and
may require a predictable amount of time for sources across the source
category to be able to design, acquire, install, test, and begin to
operate them.\223\ Time may also be required to allow for the
development of skilled labor, and materials like steel, concrete, and
speciality parts. Accordingly, in setting 111 standards for both new
and existing sources, the EPA has typically allowed for some amount of
time before sources must demonstrate compliance with the standards. For
instance, in the 2015 NSPS for residential wood heaters, the EPA
established a ``stepped compliance approach'' which phased in
requirements over 5 years to ``allow manufacturers lead time to
develop, test, field evaluate and certify current technologies'' across
their model lines.\224\ The EPA also allowed for a series of phase-ins
of various requirements in the 2023 oil and gas NSPS.\225\ For example:
the EPA finalized a compliance deadline for process controllers
allowing for 1 year from the effective date of the final rule, to allow
for delays in equipment availability; \226\ the EPA established a 1-
year lead time period for pumps, also in response to possible equipment
and labor shortages; \227\ and the EPA built in 24 months between
publication in the Federal Register and the commencement of a
requirement to end routine flaring and route associated gas to a sales
line.\228\
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\223\ As discussed above, although the EPA is not relying on
this point for purposes of these rules, it should be noted that the
EPA may determine a system of emission reduction to be adequately
demonstrated based on some amount of projection, even if some
aspects of the system are still in development. Thus, the
authorization for lead time accommodates the development of
projected technology.
\224\ See Standards of Performance for New Residential Wood
Heaters, New Residential Hydronic Heaters and Forced-Air Furnaces,
80 FR 13672, 13676 (March 16, 2015).
\225\ See Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. 89 FR 16943 (March 8, 2024).
\226\ See id. at 16929.
\227\ See id. at 16937.
\228\ See id. at 16886.
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Finally, the EPA's longstanding regulations for new source
performance standards under CAA section 111 specifically authorize a
minimum period for lead time. Pursuant to 40 CFR 60.11, compliance with
CAA section 111 standards is generally determined in accordance with
performance tests conducted under 40 CFR 60.8. Both of these regulatory
provisions were adopted in 1971. Under 40 CFR 60.8, source performance
is generally measured via performance tests, which must typically be
carried out ``within 60 days after achieving the maximum production
rate at which the affected facility will be operated, but not later
than 180 days after initial startup of such facility, or at such other
times specified by this part, and at such other times as may be
required by the Administrator under section 114 of the Act. . . .''
\229\ The fact that this provision has been in place for over 50 years
indicates that the EPA has long recognized the need for lead time for
at least one component of control development.\230\
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\229\ 40 CFR 60.8.
\230\ For further discussion of lead time in the context of this
rulemaking, see section VIII.F.
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c. Costs
Under CAA section 111(a)(1), in determining whether a particular
emission control is the ``best system of emission reduction . . .
adequately demonstrated,'' the EPA is required to take into account
``the cost of achieving [the emission] reduction.'' Although the CAA
does not describe how the EPA is to account for costs to affected
sources, the D.C. Circuit has formulated the cost standard in various
ways, including stating that the EPA may not adopt a standard the cost
of which would be ``excessive'' or ``unreasonable.'' 231 232
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\231\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
See 79 FR 1430, 1464 (January 8, 2014); Lignite Energy Council, 198
F.3d at 933 (costs may not be ``exorbitant''); Portland Cement Ass'n
v. EPA, 513 F.2d 506, 508 (D.C. Cir. 1975) (costs may not be
``greater than the industry could bear and survive'').
\232\ These cost formulations are consistent with the
legislative history of CAA section 111. The 1977 House Committee
Report noted:
In the [1970] Congress [sic: Congress's] view, it was only right
that the costs of applying best practicable control technology be
considered by the owner of a large new source of pollution as a
normal and proper expense of doing business.
1977 House Committee Report at 184. Similarly, the 1970 Senate
Committee Report stated:
The implicit consideration of economic factors in determining
whether technology is ``available'' should not affect the usefulness
of this section. The overriding purpose of this section would be to
prevent new air pollution problems, and toward that end, maximum
feasible control of new sources at the time of their construction is
seen by the committee as the most effective and, in the long run,
the least expensive approach.
S. Comm. Rep. No. 91-1196 at 16.
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[[Page 39833]]
The EPA has discretion in its consideration of cost under section
111(a), both in determining the appropriate level of costs and in
balancing costs with other BSER factors.\233\ To determine the BSER,
the EPA must weigh the relevant factors, including the cost of controls
and the amount of emission reductions, as well as other factors.\234\
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\233\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\234\ Id. (EPA's conclusion that the high cost of control was
acceptable was ``a judgment call with which we are not inclined to
quarrel'').
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The D.C. Circuit has repeatedly upheld the EPA's consideration of
cost in reviewing standards of performance. In several cases, the court
upheld standards that entailed significant costs, consistent with
Congress's view that ``the costs of applying best practicable control
technology be considered by the owner of a large new source of
pollution as a normal and proper expense of doing business.'' \235\ See
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir.
1973); \236\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 387-88
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir.
1981) (upholding NSPS imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . . .
is substantial. The EPA estimates that utilities will have to spend
tens of billions of dollars by 1995 on pollution control under the new
NSPS.'').
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\235\ 1977 House Committee Report at 184.
\236\ The costs for these standards were described in the
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5769 (March
21, 1972).
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In its CAA section 111 rulemakings, the EPA has frequently used a
cost-effectiveness metric, which determines the cost in dollars for
each ton or other quantity of the regulated air pollutant removed
through the system of emission reduction. See, e.g., 81 FR 35824 (June
3, 2016) (NSPS for GHG and VOC emissions for the oil and natural gas
source category); 71 FR 9866, 9870 (February 27, 2006) (NSPS for
NOX, SO2, and PM emissions from fossil fuel-fired
electric utility steam generating units); 61 FR 9905, 9910 (March 12,
1996) (NSPS and emission guidelines for nonmethane organic compounds
and landfill gas from new and existing municipal solid waste
landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO2
emissions from sweetening and sulfur recovery units in natural gas
processing plants). This metric allows the EPA to compare the amount a
regulation would require sources to pay to reduce a particular
pollutant across regulations and industries. In rules for the electric
power sector, the EPA has also looked at a metric that determines the
dollar increase in the cost of a MWh of electricity generated by the
affected sources due to the emission controls, which shows the cost of
controls relative to the output of electricity. See section
VII.C.1.a.ii of this preamble, which discusses $/MWh costs of the Good
Neighbor Plan for the 2015 Ozone NAAQS (88 FR 36654; June 5, 2023) and
the Cross-State Air Pollution Rule (CSAPR) (76 FR 48208; August 8,
2011). This metric facilitates comparing costs across regulations and
pollutants. In these final actions, as explained herein, the EPA looks
at both of these metrics, in addition to other cost evaluations, to
assess the cost reasonableness of the final requirements. The EPA's
consideration of cost reasonableness in this way meets the statutory
requirement that the EPA take into account ``the cost of achieving [the
emission] reduction'' under section 111(a)(1).
d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Under CAA section 111(a)(1), the EPA is required to take into
account ``any nonair quality health and environmental impact and energy
requirements'' in determining the BSER. Non-air quality health and
environmental impacts may include the impacts of the disposal of
byproducts of the air pollution controls, or requirements of the air
pollution control equipment for water. Portland Cement Ass'n v.
Ruckelshaus, 465 F.2d 375, 387-88 (D.C. Cir. 1973), cert. denied, 417
U.S. 921 (1974). Energy requirements may include the impact, if any, of
the air pollution controls on the source's own energy needs.
e. Sector or Nationwide Component of Factors in Determining the BSER
Another component of the D.C. Circuit's interpretations of CAA
section 111 is that the EPA may consider the various factors it is
required to consider on a national or regional level and over time, and
not only on a plant-specific level at the time of the rulemaking.\237\
The D.C. Circuit based this interpretation--which it made in the 1981
Sierra Club v. Costle case regarding the NSPS for new power plants--on
a review of the legislative history, stating,
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\237\ See 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club
v. Costle, 657 F.2d at 351).
[T]he Reports from both Houses on the Senate and House bills
illustrate very clearly that Congress itself was using a long-term
lens with a broad focus on future costs, environmental and energy
effects of different technological systems when it discussed section
111.\238\
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\238\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted)
(citing legislative history).
The court has upheld EPA rules that the EPA ``justified . . . in
terms of the policies of the Act,'' including balancing long-term
national and regional impacts. For example, the court upheld a standard
of performance for SO2 emissions from new coal-fired power
---------------------------------------------------------------------------
plants on grounds that it--
reflects a balance in environmental, economic, and energy
consideration by being sufficiently stringent to bring about
substantial reductions in SO2 emissions (3 million tons
in 1995) yet does so at reasonable costs without significant energy
penalties. . . .\239\
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\239\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR
33583-84; June 11, 1979).
The EPA interprets this caselaw to authorize it to assess the
impacts of the controls it is considering as the BSER, including their
costs and implications for the energy system, on a sector-wide,
regional, or national basis, as appropriate. For example, the EPA may
assess whether controls it is considering would create risks to the
reliability of the electricity system in a particular area or
nationwide and, if they would, to reject those controls as the BSER.
f. ``Best''
In determining which adequately demonstrated system of emission
reduction is the ``best,'' the EPA has broad discretion. In AEP v.
Connecticut, 564 U.S. 410, 427 (2011), the Supreme Court explained that
under CAA section 111, ``[t]he appropriate amount of regulation in any
particular greenhouse gas-producing sector cannot be prescribed in a
vacuum: . . . informed assessment of competing interests is required.
Along with the environmental benefit potentially achievable, our
Nation's energy needs and the possibility of economic disruption must
weigh in the balance. The Clean Air Act entrusts such complex balancing
to the EPA in the first instance, in combination with state regulators.
Each ``standard of performance'' the EPA sets must ``tak[e] into
account the cost of achieving [emissions] reduction and any nonair
quality health and environmental impact and energy requirements.''
(paragraphing revised; citations omitted)).
[[Page 39834]]
Likewise, in Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981),
the court explained that ``section 111(a) explicitly instructs the EPA
to balance multiple concerns when promulgating a NSPS,'' \240\ and
emphasized that ``[t]he text gives the EPA broad discretion to weigh
different factors in setting the standard,'' including the amount of
emission reductions, the cost of the controls, and the non-air quality
environmental impacts and energy requirements.\241\ And in Lignite
Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999), the court
reiterated:
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\240\ Sierra Club v. Costle, 657 F.2d at 319.
\241\ Sierra Club v. Costle, 657 F.2d at 321; see also New York
v. Reilly, 969 F.2d at 1150 (because Congress did not assign the
specific weight the Administrator should assign to the statutory
elements, ``the Administrator is free to exercise [her] discretion''
in promulgating an NSPS).
Because section 111 does not set forth the weight that should be
assigned to each of these factors, we have granted the agency a
great degree of discretion in balancing them . . . . EPA's choice
[of the `best system'] will be sustained unless the environmental or
economic costs of using the technology are exorbitant . . . . EPA
[has] considerable discretion under section 111.\242\
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\242\ Lignite Energy Council, 198 F.3d at 933 (paragraphing
revised for convenience). See New York v. Reilly, 969 F.2d 1147,
1150 (D.C. Cir. 1992) (``Because Congress did not assign the
specific weight the Administrator should accord each of these
factors, the Administrator is free to exercise his discretion in
this area.''); see also NRDC v. EPA, 25 F.3d 1063, 1071 (D.C. Cir.
1994) (The EPA did not err in its final balancing because ``neither
RCRA nor EPA's regulations purports to assign any particular weight
to the factors listed in subsection (a)(3). That being the case, the
Administrator was free to emphasize or deemphasize particular
factors, constrained only by the requirements of reasoned agency
decisionmaking.'').
Importantly, the courts recognize that the EPA must consider
several factors and that determining what is ``best'' depends on how
much weight to give the factors. In promulgating certain standards of
performance, the EPA may give greater weight to particular factors than
it does in promulgating other standards of performance. Thus, the
determination of what is ``best'' is complex and necessarily requires
an exercise of judgment. By analogy, the question of who is the
``best'' sprinter in the 100-meter dash primarily depends on only one
criterion--speed--and therefore is relatively straightforward, whereas
the question of who is the ``best'' baseball player depends on a more
complex weighing of multiple criteria and therefore requires a greater
exercise of judgment.
The term ``best'' also authorizes the EPA to consider factors in
addition to the ones enumerated in CAA section 111(a)(1), that further
the purpose of the statute. In Portland Cement Ass'n v. Ruckelshaus,
486 F.2d 375 (D.C. Cir. 1973), the D.C. Circuit held that under CAA
section 111(a)(1) as it read prior to the enactment of the 1977 CAA
Amendments that added a requirement that the EPA take account of non-
air quality environmental impacts, the EPA must consider ``counter-
productive environmental effects'' in Determining the BSER. Id. at 385.
The court elaborated: ``The standard of the `best system' is
comprehensive, and we cannot imagine that Congress intended that `best'
could apply to a system which did more damage to water than it
prevented to air.'' Id., n.42. In Sierra Club v. Costle, 657 F.2d at
326, 346-47, the court added that the EPA must consider the amount of
emission reductions and technology advancement in determining BSER, as
discussed in section V.C.2.g of this preamble.
The court's view that ``best'' includes additional factors that
further the purpose of CAA section 111 is a reasonable interpretation
of that term in its statutory context. The purpose of CAA section 111
is to reduce emissions of air pollutants that endanger public health or
welfare. CAA section 111(b)(1)(A). The court reasonably surmised that
the EPA's determination of whether a system of emission reduction that
reduced certain air pollutants is ``best'' should be informed by
impacts that the system may have on other pollutants that affect public
or welfare. Portland Cement Ass'n, 486 F.2d at 385. The Supreme Court
confirmed the D.C. Circuit's approach in Michigan v. EPA, 576 U.S. 743
(2015), explaining that administrative agencies must engage in
``reasoned decisionmaking'' that, in the case of pollution control,
cannot be based on technologies that ``do even more damage to human
health'' than the emissions they eliminate. Id. at 751-52. After
Portland Cement Ass'n, Congress revised CAA section 111(a)(1) to make
explicit that in determining whether a system of emission reduction is
the ``best,'' the EPA should account for non-air quality health and
environmental impacts. By the same token, the EPA takes the position
that in determining whether a system of emission reduction is the
``best,'' the EPA may account for the impacts of the system on air
pollutants other than the ones that are the subject of the CAA section
111 regulation.\243\ We discuss immediately below other factors that
the D.C. Circuit has held the EPA should account for in determining
what system is the ``best.''
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\243\ See generally Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Notice of Proposed Rulemaking, 87 FR 74765 (December 6,
2022) (proposing the BSER for reducing methane and VOC emissions
from natural gas-driven controllers in the oil and natural gas
sector on the basis of, among other things, impacts on emissions of
criteria pollutants). In this preamble, for convenience, the EPA
generally discusses the effects of controls on non-GHG air
pollutants along with the effects of controls on non-air quality
health and environmental impacts.
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g. Amount of Emissions Reductions
Consideration of the amount of emissions from the category of
sources or the amount of emission reductions achieved as factors the
EPA must consider in determining the ``best system of emission
reduction'' is implicit in the plain language of CAA section
111(a)(1)--the EPA must choose the best system of emission reduction.
Indeed, consistent with this plain language and the purpose of CAA
section 111, the EPA must consider the quantity of emissions at issue.
See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (``we can
think of no sensible interpretation of the statutory words ``best . . .
system'' which would not incorporate the amount of air pollution as a
relevant factor to be weighed when determining the optimal standard for
controlling . . . emissions'').\244\ The fact that the purpose of a
``system of emission reduction'' is to reduce emissions, and that the
term itself explicitly incorporates the concept of reducing emissions,
supports the court's view that in determining whether a ``system of
emission reduction'' is the ``best,'' the EPA must consider the amount
of emission reductions that the system would yield. Even if the EPA
were not required to consider the amount of emission reductions, the
EPA has the discretion to do so, on grounds that either the term
``system of emission reduction'' or the term ``best'' may reasonably be
read to allow that discretion.
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\244\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was
governed by the 1977 CAAA version of the definition of ``standard of
performance,'' which revised the phrase ``best system of emission
reduction'' to read, ``best technological system of continuous
emission reduction.'' As noted above, the 1990 CAAA deleted
``technological'' and ``continuous'' and thereby returned the phrase
to how it read under the 1970 CAAA. The court's interpretation of
the 1977 CAAA phrase in Sierra Club v. Costle to require
consideration of the amount of air emissions focused on the term
``best,'' and the terms ``technological'' and ``continuous'' were
irrelevant to its analysis. It thus remains valid for the 1990 CAAA
phrase ``best system of emission reduction.''
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h. Expanded Use and Development of Technology
The D.C. Circuit has long held that Congress intended for CAA
section 111
[[Page 39835]]
to create incentives for new technology and therefore that the EPA is
required to consider technological innovation as one of the factors in
determining the ``best system of emission reduction.'' See Sierra Club
v. Costle, 657 F.2d at 346-47. The court has grounded its reading in
the statutory text of CAA 111(a)(1), defining the term ``standard of
performance.'' \245\ In addition, the court's interpretation finds
support in the legislative history.\246\ The legislative history
identifies three different ways that Congress designed CAA section 111
to authorize standards of performance that promote technological
improvement: (1) The development of technology that may be treated as
the ``best system of emission reduction . . . adequately
demonstrated;'' under CAA section 111(a)(1); \247\ (2) the expanded use
of the best demonstrated technology; \248\ and (3) the development of
emerging technology.\249\ Even if the EPA were not required to consider
technological innovation as part of its determination of the BSER, it
would be reasonable for the EPA to consider it because technological
innovation may be considered an element of the term ``best,''
particularly in light of Congress's emphasis on technological
innovation.
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\245\ Sierra Club v. Costle, 657 F.2d at 346 (``Our
interpretation of section 111(a) is that the mandated balancing of
cost, energy, and non-air quality health and environmental factors
embraces consideration of technological innovation as part of that
balance. The statutory factors which EPA must weigh are broadly
defined and include within their ambit subfactors such as
technological innovation.'').
\246\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of
performance should provide an incentive for industries to work
toward constant improvement in techniques for preventing and
controlling emissions from stationary sources''); S. Rep. No. 95-127
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n.174)
(``The section 111 Standards of Performance . . . sought to assure
the use of available technology and to stimulate the development of
new technology'').
\247\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (the best system of emission reduction must ``look[
] toward what may fairly be projected for the regulated future,
rather than the state of the art at present'').
\248\ 1970 Senate Committee Report No. 91-1196 at 15 (``The
maximum use of available means of preventing and controlling air
pollution is essential to the elimination of new pollution
problems'').
\249\ Sierra Club v. Costle, 657 F.2d at 351 (upholding a
standard of performance designed to promote the use of an emerging
technology).
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i. Achievability of the Degree of Emission Limitation
For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that
the EPA must establish ``standards of performance,'' which are
standards for emissions that reflect the degree of emission limitation
that is ``achievable'' through the application of the BSER. A standard
of performance is ``achievable'' if a technology can reasonably be
projected to be available to an individual source at the time it is
constructed that will allow it to meet the standard.\250\ Moreover,
according to the court, ``[a]n achievable standard is one which is
within the realm of the adequately demonstrated system's efficiency and
which, while not at a level that is purely theoretical or experimental,
need not necessarily be routinely achieved within the industry prior to
its adoption.'' \251\ To be achievable, a standard ``must be capable of
being met under most adverse conditions which can reasonably be
expected to recur and which are not or cannot be taken into account in
determining the `costs' of compliance.'' \252\ To show a standard is
achievable, the EPA must ``(1) identify variable conditions that might
contribute to the amount of expected emissions, and (2) establish that
the test data relied on by the agency are representative of potential
industry-wide performance, given the range of variables that affect the
achievability of the standard.'' \253\
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\250\ Sierra Club v. Costle, 657 F.2d 298, 364, n.276 (D.C. Cir.
1981).
\251\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\252\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C.
Cir. 1980).
\253\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981)
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In
considering the representativeness of the source tested, the EPA may
consider such variables as the `` `feedstock, operation, size and
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize
from a sample of one when one is the only available sample, or when
that one is shown to be representative of the regulated industry
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416,
434, n.52 (D.C. Cir. 1980).
---------------------------------------------------------------------------
Although the courts have established these standards for
achievability in cases concerning CAA section 111(b) new source
standards of performance, generally comparable standards for
achievability should apply under CAA section 111(d), although the BSER
may differ in some cases as between new and existing sources due to,
for example, higher costs of retrofit. 40 FR 53340 (November 17, 1975).
For existing sources, CAA section 111(d)(1) requires the EPA to
establish requirements for state plans that, in turn, must include
``standards of performance.'' As the Supreme Court has recognized, this
provision requires the EPA to promulgate emission guidelines that
determine the BSER for a source category and then identify the degree
of emission limitation achievable by application of the BSER. See West
Virginia v. EPA, 597 U.S. at 710.\254\
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\254\ 40 CFR 60.21(e), 60.21a(e).
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The EPA has promulgated emission guidelines on the basis that the
existing sources can achieve the degree of emission limitation
described therein, even though under the RULOF provision of CAA section
111(d)(1), the state retains discretion to apply standards of
performance to individual sources that are less stringent, which
indicates that Congress recognized that the EPA may promulgate emission
guidelines that are consistent with CAA section 111(d) even though
certain individual sources may not be able to achieve the degree of
emission limitation identified therein by applying the controls that
the EPA determined to be the BSER. Note further that this requirement
that the emission limitation be ``achievable'' based on the ``best
system of emission reduction . . . adequately demonstrated'' indicates
that the technology or other measures that the EPA identifies as the
BSER must be technically feasible.
3. EPA Promulgation of Emission Guidelines for States To Establish
Standards of Performance
CAA section 111(d)(1) directs the EPA to promulgate regulations
establishing a procedure similar to that provided by CAA section 110
under which states submit state plans that establish ``standards of
performance'' for emissions of certain air pollutants from sources
which, if they were new sources, would be regulated under CAA section
111(b), and that provide for the implementation and enforcement of such
standards of performance. The term ``standard of performance'' is
defined under CAA section 111(a)(1), quoted above. Thus, CAA sections
111(a)(1) and (d)(1) collectively require the EPA to determine the
degree of emission limitation achievable through application of the
BSER to existing sources and to establish regulations under which
states establish standards of performance reflecting that degree of
emission limitation. The EPA addresses both responsibilities through
its emission guidelines, as well as through its general implementing
regulations for CAA section 111(d). Consistent with the statutory
requirements, the general implementing regulations require that the
EPA's emission guidelines reflect--
the degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into account
the cost of such reduction and any non-air quality health and
environmental
[[Page 39836]]
impact and energy requirements) the Administrator has determined has
been adequately demonstrated from designated facilities.\255\
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\255\ 40 CFR 60.21a(e).
Following the EPA's promulgation of emission guidelines, each state
must establish standards of performance for its existing sources, which
the EPA's regulations call ``designated facilities.'' \256\ Such
standards of performance must reflect the degree of emission limitation
achievable through application of the best system of emission reduction
as determined by the EPA, which the Agency may express as a presumptive
standard of performance in the applicable emission guidelines.
---------------------------------------------------------------------------
\256\ 40 CFR 60.21a(b), 60.24a(b).
---------------------------------------------------------------------------
While the standards of performance that states establish in their
plans must generally be no less stringent than the degree of emission
limitation determined by the EPA,\257\ CAA section 111(d)(1) also
requires that the EPA's regulations ``permit the State in applying a
standard of performance to any particular source . . . to take into
consideration, among other factors, the remaining useful life of the
existing source to which such standard applies.'' Consistent with this
statutory direction, the EPA's general implementing regulations for CAA
section 111(d) provide a framework for states' consideration of
remaining useful life and other factors (referred to as ``RULOF'') when
applying a standard of performance to a particular source. In November
2023, the EPA finalized clarifications to its regulations governing
states' consideration of RULOF to apply less stringent standards of
performance to particular existing sources. As amended, these
regulations provide that states may apply a standard of performance to
a particular designated facility that is less stringent than, or has a
longer compliance schedule than, otherwise required by the applicable
emission guideline taking into consideration that facility's remaining
useful life and other factors. To apply a less stringent standard of
performance or longer compliance schedule, the state must demonstrate
with respect to each facility (or class of such facilities), that the
facility cannot reasonably achieve the degree of emission limitation
determined by the EPA based on unreasonable cost of control resulting
from plant age, location, or basic process design; physical
impossibility or technical infeasibility of installing necessary
control equipment; or other circumstances specific to the facility. In
doing so, the state must demonstrate that there are fundamental
differences between the information specific to a facility (or class of
such facilities) and the information the EPA considered in determining
the degree of emission limitation achievable through application of the
BSER or the compliance schedule that make achieving such degree of
emission reduction or meeting such compliance schedule unreasonable for
that facility.
---------------------------------------------------------------------------
\257\ As the Supreme Court explained in West Virginia v. EPA,
``Although the States set the actual rules governing existing power
plants, EPA itself still retains the primary regulatory role in
Section 111(d).'' 597 U.S. at 710. The Court elaborated that ``[t]he
Agency, not the States, decides the amount of pollution reduction
that must ultimately be achieved. It does so by again determining,
as when setting the new source rules, `the best system of emission
reduction . . . that has been adequately demonstrated for [existing
covered] facilities.' 40 CFR 60.22(b)(5) (2021); see also 80 FR
64664, and n.1. The States then submit plans containing the
emissions restrictions that they intend to adopt and enforce in
order not to exceed the permissible level of pollution established
by EPA. See Sec. Sec. 60.23, 60.24; 42 U.S.C. 7411(d)(1).'' Id.
---------------------------------------------------------------------------
In addition, under CAA section 116, states may establish standard
of performances that are more stringent than the presumptive standards
of performance contained in the EPA's emission guidelines.\258\ The
state must include the standards of performance in their state plans
and submit the plans to the EPA for review according to the procedures
established in the Agency's general implementing regulations for CAA
section 111(d).\259\ Under CAA section 111(d)(2)(A), the EPA approves
state plans that are determined to be ``satisfactory.'' CAA section
111(d)(2)(A) also gives the Agency ``the same authority'' as under CAA
section 110(c) to promulgate a Federal plan in cases where a state
fails to submit a satisfactory state plan.
---------------------------------------------------------------------------
\258\ 40 CFR 60.24a(i).
\259\ See generally 40 CFR 60.23a-60.28a.
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VI. ACE Rule Repeal
The EPA is finalizing repeal of the ACE Rule. The EPA proposed to
repeal the ACE Rule and did not receive significant comments objecting
to the proposal. The EPA is finalizing the proposal largely as
proposed. A general summary of the ACE Rule, including its regulatory
and judicial history, is included in section V.B.4 of this preamble.
The EPA repeals the ACE Rule on three grounds that each independently
justify the rule's repeal.
First, as a policy matter, the EPA concludes that the suite of heat
rate improvements (HRI) the ACE Rule selected as the BSER is not an
appropriate BSER for existing coal-fired EGUs. In the EPA's technical
judgment, the suite of HRI set forth in the ACE Rule provide negligible
CO2 reductions at best and, in many cases, may increase
CO2 emissions because of the ``rebound effect,'' as
explained in section VII.D.4.a.iii of this preamble. These concerns,
along with the EPA's experience in implementing the ACE Rule, cast
doubt that the ACE Rule would achieve emission reductions and increase
the likelihood that the ACE Rule could make CO2 pollution
worse. As a result, the EPA has determined it is appropriate to repeal
the rule, and to reevaluate whether other technologies constitute the
BSER.
Second, even assuming the ACE Rule's rejection of CCS and natural
gas co-firing was supported at the time, the ACE Rule's rationale for
rejecting CCS and natural gas co-firing as the BSER no longer applies
because of new factual developments. Since the ACE Rule was
promulgated, changes in the power industry, developments in the costs
of controls, and new federal subsidies have made other controls more
broadly available and less expensive. Considering these developments,
the EPA has determined that co-firing with natural gas and CCS are the
BSER for certain subcategories of sources as described in section VII.C
of this preamble, and that the HRI technologies adopted by the ACE Rule
are not the BSER. Thus, repeal of the ACE Rule is proper on this ground
as well.
Third, the EPA concludes that the ACE Rule conflicted with CAA
section 111 and the EPA's implementing regulations because it did not
specifically identify the BSER or the ``degree of emission limitation
achievable though application of the [BSER].'' Instead, the ACE Rule
described only a broad range of values as the ``degree of emission
limitation achievable.'' In doing so, the rule did not provide the
states with adequate guidance on the degree of emission limitation that
must be reflected in the standards of performance so that a state plan
would be approvable by the EPA. The ACE Rule is repealed for this
reason also.
A. Summary of Selected Features of the ACE Rule
The ACE Rule determined that the BSER for coal-fired EGUs was a
``list of `candidate technologies,' '' consisting of seven types of the
``most impactful HRI technologies, equipment upgrades, and best
operating and maintenance practices,'' (84 FR 32536; July 8, 2019),
including, among others, ``Boiler Feed Pumps'' and ``Redesign/Replace
Economizer.'' Id. at 32537 (table 1). The rule provided a range of
improvements
[[Page 39837]]
in heat rate that each of the seven ``candidate technologies'' could
achieve if applied to coal-fired EGUs of different capacities. For six
of the technologies, the expected level of improvement in heat rate
ranged from 0.1-0.4 percent to 1.0-2.9 percent, and for the seventh
technology, ``Improved Operating and Maintenance (O&M) Practices,'' the
range was ``0 to >2%.'' Id. The ACE Rule explained that states must
review each of their designated facilities, on either a source-by-
source or group-of-sources basis, and ``evaluate the applicability of
each of the candidate technologies.'' Id. at 32550. States were to use
the list of HRI technologies ``as guidance but will be expected to
conduct unit-specific evaluations of HRI potential, technical
feasibility, and applicability for each of the BSER candidate
technologies.'' Id. at 32538.
The ACE Rule emphasized that states had ``inherent flexibility'' in
evaluating candidate technologies with ``a wide range of potential
outcomes.'' Id. at 32542. The ACE Rule provided that states could
conclude that it was not appropriate to apply some technologies. Id. at
32550. Moreover, if a state decided to apply a particular technology to
a particular source, the state could determine the level of heat rate
improvement from the technology could be anywhere within the range that
the EPA had identified for that technology, or even outside that range.
Id. at 32551. The ACE Rule stated that after the state evaluated the
technologies and calculated the amount of HRI in this way, it should
determine the standard of performance 0that the source could achieve,
Id. at 32550, and then adjust that standard further based on the
application of source-specific factors such as remaining useful life.
Id. at 32551.
The ACE Rule then identified the process by which states had to
take these actions. States must ``evaluat[e] each'' of the seven
candidate technologies and provide a summary, which ``include[s] an
evaluation of the . . . degree of emission limitation achievable
through application of the technologies.'' Id. at 32580. Then, the
state must provide a variety of information about each power plant,
including, the plant's ``annual generation,'' ``CO2
emissions,'' ``[f]uel use, fuel price, and carbon content,''
``operation and maintenance costs,'' ``[h]eat rates,'' ``[e]lectric
generating capacity,'' and the ``timeline for implementation,'' among
other information. Id. at 32581. The EPA explained that the purpose of
this data was to allow the Agency to ``adequately and appropriately
review the plan to determine whether it is satisfactory.'' Id. at
32558.
The ACE Rule projected a very low level of overall emission
reduction if states generally applied the set of candidate technologies
to their sources. The rule was projected to achieve a less-than-1-
percent reduction in power-sector CO2 emissions by
2030.\260\ Further, the EPA also projected that it would increase
CO2 emissions from power plants in 15 states and the
District of Columbia because of the ``rebound effect'' as coal-fired
sources implemented HRI measures and became more efficient. This
phenomenon is explained in more detail in section VII.D.4.a.iii of this
document.\261\
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\260\ ACE Rule RIA 3-11, table 3-3.
\261\ The rebound effect becomes evident by comparing the
results of the ACE Rule IPM runs for the 2018 reference case, EPA,
IPM State-Level Emissions: EPAv6 November 2018 Reference Case,
Document ID No. EPA-HQ-OAR-2017-0355-26720, and for the
``Illustrative ACE Scenario. IPM State-Level Emissions: Illustrative
ACE Scenario, Document ID No. EPA-HQ-OAR-2017-0355-26724.
---------------------------------------------------------------------------
The ACE Rule considered several other control measures as the BSER,
including co-firing with natural gas and CCS, but rejected them. The
ACE Rule rejected co-firing with natural gas primarily on grounds that
it was too costly in general. 84 FR 32545 (July 8, 2019). The rule also
concluded that generating electricity by co-firing natural gas in a
utility boiler would be an inefficient use of the gas when compared to
combusting it in a combustion turbine. Id. The ACE Rule rejected CCS on
grounds that it was too costly. Id. at 32548. The rule identified the
high capital and operating costs of CCS and noted the fact that the IRC
section 45Q tax credit, as it then applied, would provide only limited
benefit to sources. Id. at 32548-49.
B. Developments Undermining ACE Rule's Projected Emission Reductions
The EPA's first basis for repealing the ACE Rule is that it is
unlikely that--if implemented--the rule would reduce emissions, and
implementation could increase CO2 emissions instead. Thus,
the EPA concludes that as a matter of policy it is appropriate to
repeal the rule and evaluate anew whether other technologies qualify as
the BSER.
Two factors, taken together, undermine the ACE Rule's projected
emission reductions and create the risk that implementation of the ACE
Rule could increase--rather than reduce--CO2 emissions from
coal-fired EGUs. First, HRI technologies achieve only limited GHG
emission reductions. The ACE Rule projected that if states generally
applied the set of candidate technologies to their sources, the rule
would achieve a less-than-1-percent reduction in power-sector
CO2 emissions by 2030.\262\ The EPA now doubts that even
these minimal reductions would be achieved. The ACE Rule's projected
benefits were premised in part on a 2009 technical report by Sargent &
Lundy that evaluated the effects of HRI technologies. In 2023, Sargent
& Lundy issued an updated report which details that the HRI selected as
the BSER in the ACE Rule would bring fewer emissions reductions than
estimated in 2009. The 2023 report concludes that, with few exceptions,
HRI technologies are less effective at reducing CO2
emissions than assumed in 2009. Further reinforcing the conclusion that
HRIs would bring few reductions, the 2023 report also concluded that
most sources had already optimized application of HRIs, and so there
are fewer opportunities to reduce emissions than previously
anticipated.\263\
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\262\ ACE Rule RIA 3-11, table 3-3.
\263\ Sargent and Lundy. Heat Rate Improvement Method Costs and
Limitations Memo. Available in Docket ID No. EPA-HQ-OAR-2023-0072.
---------------------------------------------------------------------------
Second, for a subset of sources, HRI are likely to cause a
``rebound effect'' leading to an increase in GHG emissions for those
sources. The rebound effect is explained in detail in section
VII.D.4.a.iii of this preamble. The ACE Rule's analysis projected that
the rule would increase CO2 emissions from power plants in
15 states and the District of Columbia. The EPA's modeling projections
assumed that, consistent with the rule, some sources would impose a
small degree of efficiency improvements. The modeling showed that, as a
consequence of these improvements, the rule would increase absolute
emissions at some coal-fired sources as these sources became more
efficient and displaced lower emitting sources like natural gas-fired
EGUs.\264\
---------------------------------------------------------------------------
\264\ See EPA, IPM State-Level Emissions: EPAv6 November 2018
Reference Case, Document ID No. EPA-HQ-OAR-2017-0355-26720
(providing ACE reference case); IPM State-Level Emissions:
Illustrative ACE Scenario, Document ID No. EPA-HQ-OAR-2017-0355-
26724 (providing illustrative scenario).
---------------------------------------------------------------------------
Even though the ACE Rule was projected to increase emissions in
many states, these states were nevertheless obligated under the rule to
assemble detailed state plans that evaluated available technologies and
the performance of each existing coal-fired power plant, as described
in section IX.A of this preamble. For example, the state was required
to analyze the plant's ``annual generation,'' ``CO2
emissions,'' ``[f]uel use, fuel price, and carbon content,''
``operation and maintenance
[[Page 39838]]
costs,'' ``[h]eat rates,'' ``[e]lectric generating capacity,'' and the
``timeline for implementation,'' among other information. 84 FR 32581
(July 8, 2019). The risk of an increase in emissions raises doubts that
the HRI for coal-fired sources satisfies the statutory criteria to
constitute the BSER for this category of sources. The core element of
the BSER analysis is whether the emission reduction technology selected
reduces emissions. See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427,
441 (D.C. Cir. 1973) (noting ``counter productive environmental
effects'' raises questions as to whether the BSER selected was in fact
the ``best''). Moreover, this evaluation and the imposition of
standards of performance was mandated even though the state plan would
lead to an increase rather than decrease CO2 emissions.
Imposing such an obligation on states under these circumstances was
arbitrary.
The EPA's experience in implementing the ACE Rule reinforces these
concerns. After the ACE Rule was promulgated, one state drafted a state
plan that set forth a standard of performance that allowed the affected
source to increase its emission rate. The draft partial plan would have
applied to one source, the Longview Power, LLC facility, and would have
established a standard of performance, based on the state's
consideration of the ``candidate technologies,'' that was higher (i.e.,
less stringent) than the source's historical emission rate. Thus, the
draft plan would not have achieved any emission reductions from the
source, and instead would have allowed the source to increase its
emissions, if it had been finalized.\265\
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\265\ West Virginia CAA Sec. 111(d) Partial Plan for Greenhouse
Gas Emissions from Existing Electric Utility Generating Units
(EGUs), https://dep.wv.gov/daq/publicnoticeandcomment/Documents/Proposed%20WV%20ACE%20State%20Partial%20Plan.pdf.
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Because there is doubt that the minimal reductions projected by the
ACE Rule would be achieved, and because the rebound effect could lead
to an increase in emissions for many sources in many states, the EPA
concludes that it is appropriate to repeal the ACE Rule and reevaluate
the BSER for this category of sources.
C. Developments Showing That Other Technologies Are the BSER for This
Source Category
Since the promulgation of the ACE Rule in 2019, the factual
underpinnings of the rule have changed in several ways and lead the EPA
to determine that HRI are not the BSER for coal-fired power plants.
This reevaluation is consistent with FCC v. Fox Television Stations,
Inc., 556 U.S. 502 (2009). There, the Supreme Court explained that an
agency issuing a new policy ``need not demonstrate to a court's
satisfaction that the reasons for the new policy are better than the
reasons for the old one.'' Instead, ``it suffices that the new policy
is permissible under the statute, that there are good reasons for it,
and that the agency believes it to be better, which the conscious
change of course adequately indicates.'' Id. at 514-16 (emphasis in
original; citation omitted).
Along with changes in the anticipated reductions from HRI, it makes
sense for the EPA to reexamine the BSER because the costs of two
control measures, co-firing with natural gas and CCS, have fallen for
sources with longer-term operating horizons. As noted, the ACE Rule
rejected natural gas co-firing as the BSER on grounds that it was too
costly and would lead to inefficient use of natural gas. But as
discussed in section VII.C.2.b of this preamble, the costs of natural
gas co-firing are presently reasonable, and the EPA concludes that the
costs of co-firing 40 percent by volume natural gas are cost-effective
for existing coal-fired EGUs that intend to operate after January 1,
2032, and cease operation before January 1, 2039. In addition, changed
circumstances--including that natural gas is available in greater
amounts, that many coal-fired EGUs have begun co-firing with natural
gas or converted wholly to natural-gas, and that there are fewer coal-
fired EGUs in operation--mitigate the concerns the ACE Rule identified
about inefficient use of natural gas.
Similarly, the ACE Rule rejected CCS as the BSER on grounds that it
was too costly. But the costs of CCS have substantially declined, as
discussed in section VII.C.1.a.ii of the preamble, partly because of
developments in the technology that have lowered capital costs, and
partly because the IRA extended and increased the IRS section 45Q tax
credit so that it defrays a higher portion of the costs of CCS.
Accordingly, for coal-fired EGUs that will continue to operate past
2039, the EPA concludes that the costs of CCS are reasonable, as
described in section VII.C.1.a.ii of the preamble.
The emission reductions from these two technologies are
substantial. For long-term coal-fired steam generating units, the BSER
of 90 percent capture CCS results in substantial CO2
emissions reductions amounting to emission rates that are 88.4 percent
lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/MWh-net
basis compared to units without capture, as described in section
VII.C.2.b.iv of this preamble. For medium term units, the BSER of 40
percent natural gas co-firing achieves CO2 stack emissions
reductions of 16 percent, as described in section VII.C.2.b.iv of this
preamble. Given the availability of more effective, cost-reasonable
technology, the EPA concludes that HRIs are not the BSER for all coal-
fired EGUs.
The EPA is thus finalizing a new policy for coal-fired power
plants. This rule applies to those sources that intend to operate past
January 1, 2032. For sources that intend to cease operations after
January 1, 2032, but before January 1, 2039, the EPA concludes that the
BSER is co-firing 40 percent by volume natural gas. The EPA concludes
this control measure is appropriate because it achieves substantial
reductions at reasonable cost. In addition, the EPA believes that
because a large supply of natural gas is available, devoting part of
this supply for fuel for a coal-fired steam generating unit in place of
a percentage of the coal burned at the unit is an appropriate use of
natural gas and will not adversely impact the energy system, as
described in section VII.C.2.b.iii(B) of this preamble. For sources
that intend to operate past January 1, 2039, the EPA concludes that the
BSER is CCS with 90 percent capture of CO2. The EPA believes
that this control measure is appropriate because it achieves
substantial reductions at reasonable cost, as described in section
VII.C.1 of this preamble.
The EPA is not concluding that HRI is the BSER for any coal-fired
EGUs. As discussed in section VII.D.4.a, the EPA does not consider HRIs
an appropriate BSER for coal-fired EGUs because these technologies
would achieve few, if any, emissions reductions and may increase
emissions due to the rebound effect. Most importantly, changed
circumstances show that co-firing natural gas and CCS are available at
reasonable cost, and will achieve more GHG emissions reductions.
Accordingly, the EPA believes that HRI do not qualify as the BSER for
any coal-fired EGUs, and that other approaches meet the statutory
standard. On this basis, the EPA repeals the ACE Rule.
D. Insufficiently Precise Degree of Emission Limitation Achievable From
Application of the BSER
The third independent reason why the EPA is repealing the ACE Rule
is that the rule did not identify with sufficient specificity the BSER
or the degree of emission limitation achievable through the application
of the BSER. Thus, states lacked adequate guidance on the BSER they
should consider and
[[Page 39839]]
level of emission reduction that the standards of performance must
achieve. The ACE Rule determined the BSER to be a suite of HRI
``candidate technologies,'' but did not identify with specificity the
degree of emission limitation states should apply in developing
standards of performance for their sources. As a result, the ACE Rule
conflicted with CAA section 111 and the implementing regulations, and
thus failed to provide states adequate guidance so that they could
ensure that their state plans were satisfactory and approvable by the
EPA.
CAA section 111 and the EPA's longstanding implementing regulations
establish a clear process for the EPA and states to regulate emissions
of certain air pollutants from existing sources. ``The statute directs
the EPA to (1) `determine[ ],' taking into account various factors, the
`best system of emission reduction which . . . has been adequately
demonstrated,' (2) ascertain the `degree of emission limitation
achievable through the application' of that system, and (3) impose an
emissions limit on new stationary sources that `reflects' that
amount.'' West Virginia v. EPA, 597 U.S. at 709 (quoting 42 U.S.C.
7411(d)). Further, ``[a]lthough the States set the actual rules
governing existing power plants, EPA itself still retains the primary
regulatory role in Section 111(d) . . . [and] decides the amount of
pollution reduction that must ultimately be achieved.'' Id. at 2602.
Once the EPA makes these determinations, the state must establish
``standards of performance'' for its sources that are based on the
degree of emission limitation that the EPA determines in the emission
guidelines. CAA section 111(a)(1) makes this clear through its
definition of ``standard of performance'' as ``a standard for emissions
of air pollutants which reflects the degree of emission limitation
achievable through the application of the [BSER].'' After the EPA
determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission
limitation achievable from application of the BSER, ``the States then
submit plans containing the emissions restrictions that they intend to
adopt and enforce in order not to exceed the permissible level of
pollution established by EPA.'' 597 U.S. at 710 (citing 40 CFR 60.23,
60.24; 42 U.S.C. 7411(d)(1)).
The EPA then reviews the plan and approves it if the standards of
performance are ``satisfactory,'' under CAA section 111(d)(2)(A). The
EPA's longstanding implementing regulations make clear that the EPA's
basis for determining whether the plan is ``satisfactory'' includes
that the plan must contain ``emission standards . . . no less stringent
than the corresponding emission guideline(s).'' 40 CFR 60.24(c), 40 CFR
60.24a(c). In addition, under CAA section 111(d)(1), in ``applying a
standard of performance to any particular source'' a state may
consider, ``among other factors, the remaining useful life of the
existing source to which such standard applies.'' This is also known as
the RULOF provision and is discussed in section X.C.2 of this preamble.
In the ACE Rule, the EPA recognized that the CAA required it to
determine the BSER and identify the degree of emission limitation
achievable through application of the BSER. 84 FR 32537 (July 8, 2019).
But the rule did not make those determinations. Rather, the ACE Rule
described the BSER as a list of ``candidate technologies.'' And the
rule described the degree of emission limitation achievable by
application of the BSER as ranges of reductions from the HRI
technologies. The rule thus shifted the responsibility for determining
the BSER and degree of emission limitation achievable from the EPA to
the states. Accordingly, the ACE Rule did not meet the CAA section 111
requirement that the EPA determine the BSER or the degree of emission
limitation from application of the BSER.
As described above, the ACE Rule identified the HRI in the form of
a list of seven ``candidate technologies,'' accompanied by a wide range
of percentage improvements to heat rate that these technologies could
provide. Indeed, for one of them, improved ``O&M'' practices (that is,
operation and management practices), the range was ``0 to >2%,'' which
is effectively unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE
Rule was clear that this list was simply the starting point for a state
to calculate the standards of performance for its sources. That is, the
seven sets of technologies were ``candidate[s]'' that the state could
apply to determine the standard of performance for a source, and if the
state did choose to apply one or more of them, the state could do so in
a manner that yielded any percentage of heat rate improvement within
the range that the EPA identified, or even outside that range. Thus, as
a practical matter, the ACE Rule did not determine the BSER or any
degree of emission limitation from application of the BSER, and so
states had no guidance on how to craft approvable state plans. In this
way, the ACE Rule did not adhere to the applicable statutory
obligations. See 84 FR 32537-38 (July 8, 2019).
The only constraints that the ACE Rule imposed on the states were
procedural ones, and those did not give the EPA any benchmark to
determine whether a plan could be approved or give the states any
certainty on whether their plan would be approved. As noted above, when
a state submitted its plan, it needed to show that it evaluated each
candidate technology for each source or group of sources, explain how
it determined the degree of emission limitation achievable, and include
data about the sources. But because the ACE Rule did not identify a
BSER or include a degree of emission limitation that the standards must
reflect, the states lacked specific guidance on how to craft adequate
standards of performance, and the EPA had no benchmark against which to
evaluate whether a state's submission was ``satisfactory'' under CAA
section 111(d)(2)(A). Thus, the EPA's review of state plans would be
essentially a standardless exercise, notwithstanding the Agency's
longstanding view that it was ``essential'' that ``EPA review . . .
[state] plans for their substantive adequacy.'' 40 FR 53342-43
(November 17, 1975). In 1975, the EPA explained that it was not
appropriate to limit its review based ``solely on procedural criteria''
because otherwise ``states could set extremely lenient standards . . .
so long as EPA's procedural requirements were met.'' Id. at 53343.
Finally, the ACE Rule's approach to determining the BSER and degree
of emission limitation departed from prior emission guidelines under
CAA section 111(d), in which the EPA included a numeric degree of
emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977)
(limiting emission rate of acid mist from sulfuric acid plants to 0.25
grams per kilogram of acid); 44 FR 29829 (May 22, 1979) (limiting
concentrations of total reduced sulfur from most of the subcategories
of kraft pulp mills, such as digester systems and lime kilns, to 5, 20,
or 25 ppm over 12-hour averages); 61 FR 9919 (March 12, 1996) (limiting
concentration of non-methane organic compounds from solid waste
landfills to 20 parts per million by volume or a 98 percent reduction).
The ACE Rule did not grapple with this change in position as required
by FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009), or
explain why it was appropriate to provide a boundless degree of
emission limitation achievable in this context.
The EPA is finalizing the repeal the ACE Rule on this ground as
well. The ACE Rule's failure to determine the BSER and the associated
degree of emission limitation achievable from
[[Page 39840]]
application of the BSER deviated from CAA section 111 and the
implementing regulations. Without these determinations, the ACE Rule
lacked any benchmark that would guide the states in developing their
state plans, and by which the EPA could determine whether those state
plans were satisfactory.
For each of these three, independent reasons, repeal of the ACE
Rule is proper.
E. Withdrawal of Proposed NSR Revisions
In addition to repealing the ACE Rule, the Agency is withdrawing
the proposed revisions to the NSR applicability provisions that were
included the ACE Rule proposal (83 FR 44756, 44773-83; August 31,
2018). These proposed revisions would have included an hourly emissions
rate test to determine NSR applicability for a modified EGU, with the
expressed purpose of alleviating permitting burdens for sources
undertaking HRI projects pursuant to the ACE Rule emission guidelines.
The ACE Rule final action did not include the NSR revisions, and the
EPA indicated in that preamble that it intended to take final action on
the NSR proposal in a separate action at a later date. However, the EPA
did not take a final action on the NSR revisions, and the EPA has
decided to no longer pursue them and to withdraw the proposed
revisions.
Withdrawal of the proposal to establish an hourly emissions test
for NSR applicability for EGUs is appropriate because of the repeal of
the ACE rule and the EPA's conclusion that HRI is not the BSER for
coal-fired EGUs. The EPA's basis for proposing the NSR revisions was to
ease permitting burdens for state agencies and sources that may result
from implementing the ACE Rule. There was concern that, for sources
that modified their EGU to improve the heat rate, if a source were to
be dispatched more frequently because of improved efficiency (the
``rebound effect''), the source could experience an increase in
absolute emissions for one or more pollutants and potentially trigger
major NSR requirements. The hourly emissions rate test was proposed to
relieve such sources that were undertaking HRI projects to comply with
their state plans from the burdens of NSR permitting, particularly in
cases in which a source has an increase in annual emissions of a
pollutant. However, given that this final rule BSER is not based on
HRIs for coal-fired EGUs, the NSR revisions proposed as part of the ACE
Rule would no longer serve the purpose that the EPA expressed in that
proposal preamble.
Furthermore, in the event that any sources are increasing their
absolute emissions after modifying an EGU, applicability of the NSR
program is beneficial as a backstop that provides review of those
situations to determine if additional controls or other emission
limitations are necessary on a case-by-case basis to protect air
quality. In addition, given that considerable time has passed since
these EGU-specific NSR applicability revisions were proposed in 2018,
should the EPA decide to pursue them at a later time, it is prudent for
the Agency to propose them again at that time, accompanied with the
EPA's updated context and justification to support re-proposing the NSR
revisions, rather than relying on the proposal from 2018. Therefore,
the EPA is withdrawing these proposed NSR revisions.
VII. Regulatory Approach for Existing Fossil Fuel-Fired Steam
Generating Units
Existing fossil fuel-fired steam generation units are the largest
stationary source of CO2 emissions, emitting 909 MMT
CO2e in 2021. Recent developments in control technologies
offer opportunities to reduce CO2 emissions from these
sources. The EPA's regulatory approach for these units is to require
emissions reduction consistent with these technologies, where their use
is cost-reasonable.
A. Overview
In this section of the preamble, the EPA identifies the BSER and
degree of emission limitation achievable for the regulation of GHG
emissions from existing fossil fuel-fired steam generating units. As
detailed in section V of this preamble, to meet the requirements of CAA
section 111(d), the EPA promulgates ``emission guidelines'' that
identify the BSER and the degree of emission limitation achievable
through the application of the BSER, and states then establish
standards of performance for affected sources that reflect that level
of stringency. To determine the BSER for a source category, the EPA
identifies systems of emission reduction (e.g., control technologies)
that have been adequately demonstrated and evaluates the potential
emissions reduction, costs, any non-air health and environmental
impacts, and energy requirements. As described in section V.C.1 of this
preamble, the EPA has broad authority to create subcategories under CAA
section 111(d). Therefore, where the sources in a category differ from
each other by some characteristic that is relevant for the suitability
of the emission controls, the EPA may create separate subcategories and
make separate BSER determinations for those subcategories.
The EPA considered the characteristics of fossil fuel-fired steam
generating units that may impact the suitability of different control
measures. First, the EPA observed that the type and amounts of fossil
fuels--coal, oil, and natural gas--fired in the steam generating unit
affect the performance and emissions reductions achievable by different
control technologies, in part due to the differences in the carbon
content of those fuels. The EPA recognized that many sources fire
multiple types of fossil fuel. Therefore, the EPA is finalizing
subcategories of coal-fired, oil-fired, and natural gas-fired steam
generating units. The EPA is basing these subcategories, in part, on
the amount of fuel combusted by the steam generating unit.
The EPA then considered the BSER that may be suitable for each of
those subcategories of fuel type. For coal-fired steam generating
units, of the available control technologies, the EPA is determining
that CCS with 90 percent capture of CO2 meets the
requirements for BSER, including being adequately demonstrated and
achieving significant emission reductions at reasonable cost for units
operating in the long-term, as detailed in section VII.C.1.a of this
preamble. Application of this BSER results in a degree of emission
limitation equivalent to an 88.4 percent reduction in emission rate (lb
CO2/MWh-gross). The compliance date for these sources is
January 1, 2032.
Typically, the EPA assumes that sources subject to controls operate
in the long-term.\266\ See, for example, the 2015 NSPS (80 FR 64509;
October 23, 2015) or the 2011 CSAPR (76 FR 48208; August 8, 2011).
Under that assumption, fleet average costs for CCS are comparable to
the cost metrics the EPA has previously considered to be reasonable.
However, the EPA observes that about half of the capacity (87 GW out of
181 GW) of existing coal-fired steam generating units have announced
plans to permanently cease operation prior to 2039, as detailed in
section IV.D.3.b of this preamble, affecting the period available for
those sources to amortize the capital costs of CCS.
[[Page 39841]]
Accordingly, the EPA evaluated the costs of CCS for different
amortization periods. For an amortization period of more than 7 years--
such that sources operate after January 1, 2039--annualized fleet
average costs are comparable to or less than the metrics of costs for
controls that the EPA has previously found to be reasonable. However,
the group of sources ceasing operation prior to January 1, 2039, have
less time available to amortize the capital costs of CCS, resulting in
higher annualized costs.
---------------------------------------------------------------------------
\266\ Typically, the EPA assumes that the capital costs can be
amortized over a period of 15 years. As discussed in section
VII.C.1.a.ii of this preamble, in the case of CCS, the IRC section
45Q tax credit, which defrays a significant portion of the costs of
CCS, is available for the first 12 years of operation. Accordingly,
EPA generally assumed a 12-year amortization period in determining
CCS costs.
---------------------------------------------------------------------------
Because the costs of CCS depend on the available amortization
period, the EPA is creating a subcategory for sources demonstrating
that they plan to permanently cease operation prior to January 1, 2039.
Instead, for this subcategory of sources, the EPA is determining that
natural gas co-firing at 40 percent of annual heat input meets the
requirements of BSER. Application of the natural gas co-firing BSER
results in a degree of emission limitation equivalent to a 16 percent
reduction in emission rate (lb CO2/MWh-gross). Co-firing at
40 percent entails significantly less control equipment and
infrastructure than CCS, and as a result, the EPA has determined that
affected sources are able to implement it more quickly than CCS, by
January 1, 2030. Importantly, co-firing at 40 percent also entails
significantly less capital cost than CCS, and as a result, the costs of
co-firing are comparable to or less than the metrics for cost
reasonableness with an amortization period that is significantly
shorter than the period for CCS. The EPA has determined that the costs
of co-firing meet the metrics for cost reasonableness for the majority
of the capacity that permanently cease operation more than 2 years
after the January 1, 2030, implementation date, or after January 1,
2032 (and up to December 31, 2038), and that therefore have an
amortization period of more than 2 years (and up to 9 years).
The EPA is also determining that sources demonstrating that they
plan to permanently cease operation before January 1, 2032, are not
subject to the 40 percent co-firing requirement. This is because their
amortization period would be so short--2 years or less--that the costs
of co-firing would, in general, be less comparable to the cost metrics
for reasonableness for that group of sources. Accordingly, the EPA is
defining the medium-term subcategory to include those sources
demonstrating that they plan to permanently cease operating after
December 31, 2031, and before January 1, 2039.
Considering the limited emission reductions available in light of
the cost reasonableness of controls with short amortization periods,
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.
For natural gas- and oil-fired steam generating units, the EPA is
finalizing subcategories based on capacity factor. Because natural gas-
and oil-fired steam generating units with similar annual capacity
factors perform similarly to one another, the EPA is finalizing a BSER
of routine methods of operation and maintenance and a degree of
emission limitation of no increase in emission rate for intermediate
and base load subcategories. For low load natural gas- and oil-fired
steam generating units, the EPA is finalizing a BSER of uniform fuels
and respective degrees of emission limitation defined on a heat input
basis (130 lb CO2/MMBtu and 170 lb CO2/MMBtu).
Furthermore, the EPA is finalizing presumptive standards for natural
gas- and oil-fired steam generating units as follows: base load sources
(those with annual capacity factors greater than 45 percent) have a
presumptive standard of 1,400 lb CO2/MWh-gross, intermediate
load sources (those with annual capacity factors greater than 8 percent
and or less than or equal to 45 percent) have a presumptive standard of
1,600 lb CO2/MWh-gross. For low load oil-fired sources, the
EPA is finalizing a presumptive standard of 170 lb CO2/
MMBtu, while for low load natural gas-fired sources the EPA is
finalizing a presumptive standard of 130 lb CO2/MMBtu. A
compliance date of January 1, 2030, applies for all natural gas- and
oil-fired steam generating units.
The final subcategories and BSER are summarized in table 1 of this
document.
Table 1--Summary of Final BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
----------------------------------------------------------------------------------------------------------------
Presumptively
Subcategory Degree of emission approvable
Affected EGUs definition BSER limitation standard of
performance *
----------------------------------------------------------------------------------------------------------------
Long-term existing coal-fired Coal-fired steam CCS with 90 88.4 percent 88.4 percent
steam generating units. generating units percent capture reduction in reduction in
that are not of CO2. emission rate (lb annual emission
medium-term units. CO2/MWh-gross). rate (lb CO2/MWh-
gross) from the
unit-specific
baseline.
Medium-term existing coal-fired Coal-fired steam Natural gas co- A 16 percent A 16 percent
steam generating units. generating units firing at 40 reduction in reduction in
that have percent of the emission rate (lb annual emission
demonstrated that heat input to the CO2/MWh-gross). rate (lb CO2/MWh-
they plan to unit. gross) from the
permanently cease unit-specific
operations after baseline.
December 31,
2031, and before
January 1, 2039.
Base load existing oil-fired Oil-fired steam Routine methods of No increase in An annual emission
steam generating units. generating units operation and emission rate (lb rate limit of
with an annual maintenance. CO2/MWh-gross). 1,400 lb CO2/MWh-
capacity factor gross.
greater than or
equal to 45
percent.
Intermediate load existing oil- Oil-fired steam Routine methods of No increase in An annual emission
fired steam generating units. generating units operation and emission rate (lb rate limit of
with an annual maintenance. CO2/MWh-gross). 1,600 lb CO2/MWh-
capacity factor gross.
greater than or
equal to 8
percent and less
than 45 percent.
Low load existing oil-fired Oil-fired steam lower-emitting 170 lb CO2/MMBtu.. 170 lb CO2/MMBtu.
steam generating units. generating units fuels.
with an annual
capacity factor
less than 8
percent.
Base load existing natural gas- Natural gas-fired Routine methods of No increase in An annual emission
fired steam generating units. steam generating operation and emission rate (lb rate limit of
units with an maintenance. CO2/MWh-gross). 1,400 lb CO2/MWh-
annual capacity gross.
factor greater
than or equal to
45 percent.
Intermediate load existing Natural gas-fired Routine methods of No increase in An annual emission
natural gas-fired steam steam generating operation and emission rate (lb rate limit of
generating units. units with an maintenance. CO2/MWh-gross). 1,600 lb CO2/MWh-
annual capacity gross.
factor greater
than or equal to
8 percent and
less than 45
percent.
[[Page 39842]]
Low load existing natural gas- Oil-fired steam lower-emitting 130 lb CO2/MMBtu.. 130 lb CO2/MMBtu.
fired steam generating units. generating units fuels.
with an annual
capacity factor
less than 8
percent.
----------------------------------------------------------------------------------------------------------------
* 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. Inclusion in this table is for completeness.
B. Applicability Requirements and Fossil Fuel-Type Definitions for
Subcategories of Steam Generating Units
In this section of the preamble, the EPA describes the rationale
for the final applicability requirements for existing fossil fuel-fired
steam generating units. The EPA also describes the rationale for the
fuel type definitions and associated subcategories.
1. Applicability Requirements
For the emission guidelines, the EPA is finalizing that a
designated facility \267\ is any fossil fuel-fired electric utility
steam generating unit (i.e., utility boiler or IGCC unit) that: (1) was
in operation or had commenced construction on or before January 8,
2014; \268\ (2) serves a generator capable of selling greater than 25
MW to a utility power distribution system; and (3) has a base load
rating greater than 260 GJ/h (250 million British thermal units per
hour (MMBtu/h)) heat input of fossil fuel (either alone or in
combination with any other fuel). Consistent with the implementing
regulations, the term ``designated facility'' is used throughout this
preamble to refer to the sources affected by these emission
guidelines.\269\ For the emission guidelines, consistent with prior CAA
section 111 rulemakings concerning EGUs, the term ``designated
facility'' refers to a single EGU that is affected by these emission
guidelines. The rationale for the final applicability requirements is
the same as that for 40 CFR part 60, subpart TTTT (80 FR 64543-44;
October 23, 2015). The EPA includes that discussion by reference here.
---------------------------------------------------------------------------
\267\ The term ``designated facility'' means ``any existing
facility . . . which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
\268\ Under CAA section 111, the determination of whether a
source is a new source or an existing source (and thus potentially a
designated facility) is based on the date that the EPA proposes to
establish standards of performance for new sources.
\269\ The EPA recognizes, however, that the word ``facility'' is
often understood colloquially to refer to a single power plant,
which may have one or more EGUs co-located within the plant's
boundaries.
---------------------------------------------------------------------------
Section 111(a)(6) of the CAA defines an ``existing source'' as
``any stationary source other than a new source.'' Therefore, the
emission guidelines do not apply to any steam generating units that are
new after January 8, 2014, or reconstructed after June 18, 2014, the
applicability dates of 40 CFR part 60, subpart TTTT. Moreover, because
the EPA is now finalizing revised standards of performance for coal-
fired steam generating units that undertake a modification, a modified
coal-fired steam generating unit would be considered ``new,'' and
therefore not subject to these emission guidelines, if the modification
occurs after the date the proposal was published in the Federal
Register (May 23, 2023). Any coal-fired steam generating unit that has
modified prior to that date would be considered an existing source that
is subject to these emission guidelines.
In addition, the EPA is finalizing in the applicability
requirements of the emission guidelines many of the same exemptions as
discussed for 40 CFR part 60, subpart TTTT, in section VIII.E.1 of this
preamble. EGUs that may be excluded from the requirement to establish
standards under a state plan are: (1) units that are subject to 40 CFR
part 60, subpart TTTT, as a result of commencing a qualifying
modification or reconstruction; (2) steam generating units subject to a
federally enforceable permit limiting net-electric sales to one-third
or less of their potential electric output or 219,000 MWh or less on an
annual basis and annual net-electric sales have never exceeded one-
third or less of their potential electric output or 219,000 MWh; (3)
non-fossil fuel units (i.e., units that are capable of deriving at
least 50 percent of heat input from non-fossil fuel at the base load
rating) that are subject to a federally enforceable permit limiting
fossil fuel use to 10 percent or less of the annual capacity factor;
(4) combined heat and power (CHP) units that are subject to a federally
enforceable permit limiting annual net-electric sales to no more than
either 219,000 MWh or the product of the design efficiency and the
potential electric output, whichever is greater; (5) units that serve a
generator along with other affected EGU(s), where the effective
generation capacity (determined based on a prorated output of the base
load rating of EGU) is 25 MW or less; (6) municipal waste combustor
units subject to 40 CFR part 60, subpart Eb; (7) commercial or
industrial solid waste incineration units that are subject to 40 CFR
part 60, subpart CCCC; (8) EGUs that derive greater than 50 percent of
the heat input from an industrial process that does not produce any
electrical or mechanical output or useful thermal output that is used
outside the affected EGU; or (9) coal-fired steam generating units that
have elected to permanently cease operation prior to January 1, 2032.
The exemptions listed above at (4), (5), (6), and (7) are among the
current exemptions at 40 CFR 60.5509(b), as discussed in section
VIII.E.1 of this preamble. The exemptions listed above at (2), (3), and
(8) are exemptions the EPA is finalizing revisions for 40 CFR part 60,
subpart TTTT, and the rationale for the exemptions is in section
VIII.E.1 of this preamble. For consistency with the applicability
requirements in 40 CFR part 60, subpart TTTT, and 40 CFR part 60,
subpart TTTTa, the Agency is finalizing these same exemptions for the
applicability of the emission guidelines.
2. Coal-Fired Units Permanently Ceasing Operation Before January 1,
2032
The EPA is not addressing existing coal-fired steam generating
units demonstrating that they plan to permanently cease operating
before January 1, 2032, in these emission guidelines. Sources ceasing
operation before that date have far less emission reduction potential
than sources that will be operating longer, because there are unlikely
to be appreciable, cost-reasonable emission reductions available on
average for the group of sources operating in that timeframe. This is
because controls that entail capital expenditures are unlikely to be
[[Page 39843]]
of reasonable cost for these sources due to the relatively short period
over which they could amortize the capital costs of controls.
In particular, in developing the emission guidelines, the EPA
evaluated two systems of emission reduction that achieve substantial
emission reductions for coal-fired steam generating units: CCS with 90
percent capture; and natural gas co-firing at 40 percent of heat input.
For CCS, the EPA has determined that controls can be installed and
fully operational by the compliance date of January 1, 2032, as
detailed in section VII.C.1.a.i(E) of this preamble. CCS would
therefore, in most cases, be unavailable to coal-fired steam generating
units planning to cease operation prior to that date. Furthermore, the
EPA evaluated the costs of CCS for different amortization periods. For
an amortization period of more than 7 years--such that sources operate
after January 1, 2039--annualized fleet average costs are comparable to
or less than the costs of controls the EPA has previously determined to
be reasonable ($18.50/MWh of generation and $98/ton of CO2
reduced), as detailed in section VII.C.1.a.ii of this preamble.
However, the costs for shorter amortization periods are higher. For
sources ceasing operation by January 1, 2032, it would be unlikely that
the annualized costs of CCS would be reasonable even were CCS installed
at an earlier date (e.g., by January 1, 2030) due to the shorter
amortization period available.
Because the costs of CCS would be higher for shorter amortization
periods, the EPA is finalizing a separate subcategory for sources
demonstrating that they plan to permanently cease operating by January
1, 2039, with a BSER of 40 percent natural gas co-firing, as detailed
in section VII.C.2.b.ii of this preamble. For natural gas co-firing,
the EPA is finalizing a compliance date of January 1, 2030, as detailed
in section VII.C.2.b.i(C) of this preamble. Therefore, the EPA assumes
sources subject to a natural gas co-firing BSER can amortize costs for
a period of up to 9 years. The EPA has determined that the costs of
natural gas co-firing at 40 percent meet the metrics for cost
reasonableness for the majority of the capacity that operate more than
2 years after the January 1, 2030, implementation date, i.e., that
operate after January 1, 2032 (and up to December 31, 2038), and that
therefore have an amortization period of more than 2 years (and up to 9
years).
However, for sources ceasing operation prior to January 1, 2032,
the EPA believes that establishing a best system of emission reduction
corresponding to a substantial level of natural gas co-firing would
broadly entail costs of control that are above those that the EPA is
generally considering reasonable. Sources permanently ceasing operation
before January 1, 2032 would have less than 2 years to amortize the
capital costs, as detailed in section VII.C.2.a of this preamble.
Compared to the metrics for cost reasonableness that EPA has previously
deemed reasonable ($18.50/MWh of generation and $98/ton of
CO2 reduced), very few sources can co-fire 40 percent
natural gas at costs comparable to these metrics with an amortization
period of only one year; only 1 percent of units have costs that are
below both $18.50/MWh of generation and $98/ton of CO2
reduced. The number of sources that can co-fire lower amounts of
natural gas at costs comparable to these metrics is likewise limited--
only approximately 34 percent of units can co-fire with 20 percent
natural gas at costs lower than both cost metrics. Furthermore, the
period that these sources would operate with co-firing for would be
short, so that the emission reductions from that group of sources would
be limited.
By contrast, assuming a two-year amortization period, many more
units can co-fire with meaningful amounts of natural gas at a cost that
is consistent with the metrics EPA has previously used: 18 percent of
units can co-fire with 40 percent natural gas at costs less than $98/
ton and $18.50/MWh, and 50 percent of units can co-fire with 20 percent
natural gas at costs lower than both metrics. Because a substantial
number of sources can implement 40-percent co-firing with natural gas
with an amortization period of two years or longer with reasonable
costs, and even more can co-fire with lesser amounts with reasonable
costs with amortization periods longer than two years,\270\ the EPA
determined that a technology-based BSER was available for coal-fired
units operating past January 1, 2032.
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\270\ As described in detail in section X.C.2 of this preamble,
the EPA recognizes that particular affected EGUs may have
characteristics that make it unreasonable to achieve the degree of
emission limitation corresponding to 40 percent co-firing with
natural gas. For example, a state may be able to demonstrate a
fundamental difference between the costs the EPA considered in these
emission guidelines and the costs to an affected EGU that plans to
cease operation in late 2032. If such costs make it unreasonable for
a particular unit to meet the degree of emission limitation
corresponding to 40 percent co-firing with natural gas, the state
may apply a less stringent standard of performance to that unit.
Consistent with the requirements for calculating a less stringent
standard of performance at 40 CFR 60.24a(f), under these emission
guidelines states would consider whether it is reasonable for units
that cannot cost-reasonably co-fire natural gas at 40 percent to co-
fire at levels lower than 40 percent. It is thus appropriate that
coal-fired EGUs that can reasonably co-fire any amount of natural
gas be subject to these emission guidelines.
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Sources that retire before that date, however, are differently
situated as described above. In light of the small number of sources
that are planning to retire before January 1, 2032 that could cost-
effectively co-fire with natural gas, coupled with the small amount of
emissions reductions that can be achieved from co-firing in such a
short time span, the EPA is choosing not to establish a BSER for these
sources.\271\
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\271\ For the reasons described at length in section VI.B, the
EPA does not believe that heat rate improvement measures or HRI are
appropriate for sources retiring before January 1, 2032 because HRI
applied to coal-fired sources achieve few emission reductions, and
can lead to the ``rebound effect'' where CO2 emissions
from the source increase rather than decrease as a consequence of
imposing the technologies.
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Because, at this time, the EPA has determined that CCS and natural
gas co-firing are not available at reasonable cost for sources ceasing
operation before January 1, 2032, the EPA is not finalizing a BSER for
such sources. Not finalizing a BSER for these sources is consistent
with the Agency's discretion to take incremental steps to address
CO2 from sources in the category, and to direct the EPA's
limited resources at regulation of those sources that can achieve the
most emission reductions. The EPA is therefore providing that existing
coal-fired steam generating EGUs that have elected to cease operating
before January 1, 2032, are not regulated by these emission guidelines.
This exemption applies to a source until the earlier of December 31,
2031, or the date it demonstrates in the state plan that it plans to
cease operation. If a source continues to operate past this date, it is
no longer exempt from these emission guidelines. See section X.E.1 of
this preamble for discussion of how state plans should address sources
subject to exemption (9).\272\
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\272\ The EPA notes that this applicability exemption does not
conflict with states' ability to consider the remaining useful lives
of ``particular'' sources that are subject to these emission
guidelines. 42 U.S.C. 7411(d)(1). As the EPA's implementing
regulations specify, the provision for states' consideration of
RULOF is intended address the specific conditions of particular
sources, whereas the EPA is responsible for determining generally
how to regulate a source category under an emission guideline.
Moreover, RULOF applies only to when a state is applying a standard
of performance to an affected source--and the state would not apply
a standard of performance to exempted sources.
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3. Sources Outside of the Contiguous U.S.
The EPA proposed the same emission guidelines for fossil fuel-fired
steam
[[Page 39844]]
generating units in non-continental areas (i.e., Hawaii, the U.S.
Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico,
and the Northern Mariana Islands) and non-contiguous areas (non-
continental areas and Alaska) as the EPA proposed for comparable units
in the contiguous 48 states. The EPA notes that the modeling that
supports the final emission guidelines focus on sources in the
contiguous U.S. Further, the EPA notes that few, if any, coal-fired
steam generating units operate outside of the contiguous 48 states and
meet the applicability criteria. Finally, the EPA notes that the
proposed BSER and degree of emissions limitation for non-continental
oil-fired steam generating units would have achieved few emission
reductions. Therefore, the EPA is not finalizing emission guidelines
for existing steam generating units in states and territories
(including Alaska, Hawaii, Guam, Puerto Rico, and the U.S. Virgin
Islands) that are outside of the contiguous U.S. at this time.
4. IGCC Units
The EPA notes that existing IGCC units were included in the
proposed applicability requirements and that, in section VII.B of this
preamble, the EPA is finalizing inclusion of those units in the
subcategory of coal-fired steam generating units. IGCC units gasify
coal or solid fossil fuel (e.g., pet coke) to produce syngas (a mixture
of carbon monoxide and hydrogen), and either burn the syngas directly
in a combined cycle unit or use a catalyst for water-gas shift (WGS) to
produce a pre-combustion gas stream with a higher concentration of
CO2 and hydrogen, which can be burned in a hydrogen turbine
combined cycle unit. As described in section VII.C of this preamble,
the final BSER for coal-fired steam generating units includes co-firing
natural gas and CCS. The few IGCC units that now operate in the U.S.
either burn natural gas exclusively--and as such operate as natural gas
combined cycle units--or in amounts near to the 40 percent level of the
natural gas co-firing BSER. Additionally, IGCC units may be suitable
for pre-combustion CO2 capture. Because the CO2
concentration in the pre-combustion gas, after WGS, is high relative to
coal-combustion flue gas, pre-combustion CO2 capture for
IGCC units can be performed using either an amine-based (or other
solvent-based) capture process or a physical absorption capture
process. Alternatively, post-combustion CO2 capture can be
applied to the source. The one existing IGCC unit that still uses coal
was recently awarded funding from DOE for a front-end engineering
design (FEED) study for CCS targeting a capture efficiency of more than
95 percent.\273\ For these reasons, the EPA is not distinguishing IGCC
units from other coal-fired steam generating EGUs, so that the BSER of
co-firing for medium-term coal-fired units and CCS for long-term coal-
fired units apply to IGCC units.\274\
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\273\ Duke Edwardsport DOE FEED Study Fact Sheet. https://www.energy.gov/sites/default/files/2024-01/OCED_CCFEEDs_AwardeeFactSheet_Duke_1.5.2024.pdf.
\274\ For additional details on pre-combustion CO2
capture, please see the final TSD, GHG Mitigation Measures for Steam
Generating Units.
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5. Fossil Fuel-Type Definitions for Subcategories of Steam Generating
Units
In this action, the EPA is finalizing definitions for subcategories
of existing fossil fuel-fired steam generating units based on the type
and amount of fossil fuel used in the unit. The EPA is finalizing
separate subcategories based on fuel type because the carbon content of
the fuel combusted affects the output emission rate (i.e., lb
CO2/MWh). Fuels with a higher carbon content produce a
greater amount of CO2 emissions per unit of fuel combusted
(on a heat input basis, MMBtu) and per unit of electricity generated
(i.e., MWh).
The EPA proposed fossil fuel type subcategory definitions based on
the definitions in 40 CFR part 63, subpart UUUUU, and the fossil fuel
definitions in 40 CFR part 60, subpart TTTT. Those proposed definitions
were determined by the relative heat input contribution of the
different fuels combusted in a unit during the 3 years prior to the
proposed compliance date of January 1, 2030. Further, to be considered
an oil-fired or natural gas-fired unit for purposes of this emission
guideline, a source would no longer retain the capability to fire coal
after December 31, 2029.
The EPA proposed a 3-year lookback period, so that the proposed
fuel-type subcategorization would have been based, in part, on the fuel
type fired between January 1, 2027, and January 1, 2030. However, the
intent of the proposed fuel type subcategorization was to base the fuel
type definition on the state of the source on January 1, 2030.
Therefore, the EPA is finalizing the following fuel type subcategory
definitions:
A coal-fired steam generating unit is an electric utility
steam generating unit or IGCC unit that meets the definition of
``fossil fuel-fired'' and that burns coal for more than 10.0 percent of
the average annual heat input during any continuous 3-calendar-year
period after December 31, 2029, or for more than 15.0 percent of the
annual heat input during any one calendar year after December 31, 2029,
or that retains the capability to fire coal after December 31, 2029.
An oil-fired steam generating unit is an electric utility
steam generating unit meeting the definition of ``fossil fuel-fired''
that is not a coal-fired steam generating unit, that no longer retains
the capability to fire coal after December 31, 2029, and that burns oil
for more than 10.0 percent of the average annual heat input during any
continuous 3-calendar-year period after December 31, 2029, or for more
than 15.0 percent of the annual heat input during any one calendar year
after December 31, 2029.
A natural gas-fired steam generating unit is an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired,'' that is not a coal-fired or oil-fired steam generating unit,
that no longer retains the capability to fire coal after December 31,
2029, and that burns natural gas for more than 10.0 percent of the
average annual heat input during any continuous 3-calendar-year period
after December 31, 2029, or for more than 15.0 percent of the annual
heat input during any one calendar year after December 31, 2029.
The EPA received some comments on the fuel type definitions. Those
comments and responses are as follows.
Comment: Some industry stakeholders suggested changes to the
proposed definitions for fossil fuel type. Specifically, some
commenters requested that the reference to the initial compliance date
be removed and that the fuel type determination should instead be
rolling and continually update after the initial compliance date. Those
commenters suggested this would, for example, allow sources in the
coal-fired subcategory that begin natural gas co-firing in 2030 to
convert to the natural-gas fired subcategory prior to the proposed date
of January 1, 2040, instead of ceasing operation.
Other industry commenters suggested that to be a natural gas-fired
steam generating unit, a source could either meet the heat input
requirements during the 3 years prior to the compliance date or
(emphasis added) no longer retain the capability to fire coal after
December 31, 2029. Those commenters noted that, as proposed, a source
that had planned to convert to 100 percent natural gas-firing would
essentially have to do so prior to January 1, 2027, to meet the
proposed heat input-based definition, in addition to removing the
capability to fire coal by the compliance date.
[[Page 39845]]
Response: Although full natural gas conversions are not a measure
that the EPA considered as a potential BSER, the emission guidelines do
not prohibit such conversions should a state elect to require or
accommodate them. As noted above, the EPA recognizes that many steam
EGUs that formerly utilized coal as a primary fuel have fully or
partially converted to natural gas, and that additional steam EGUs may
elect to do so during the implementation period for these emission
guidelines. However, these emission guidelines place reasonable
constraints on the timing of such a conversion in situations where a
source seeks to be regulated as a natural gas-fired steam EGU rather
than as a coal-fired steam EGU. The EPA believes that such constraints
are necessary in order to avoid creating a perverse incentive for EGUs
to defer conversions in a way that could undermine the emission
reduction purpose of the rule. Therefore, the EPA disagrees with those
commenters that suggest the EPA should, in general, allow EGUs to be
regulated as natural gas-fired steam EGUs when they undertake such
conversions past January 1, 2030.
However, the EPA acknowledges that the proposed subcategorization
would have essentially required a unit to convert to natural gas by
January 1, 2027 in order to be regulated as a natural gas-fired steam
EGU. The EPA is finalizing fuel type subcategorization based on the
state of the source on the compliance date of January 1, 2030, and
during any period thereafter, as detailed in section VII.B of this
preamble. Should a source not be able to fully convert to natural gas
by this date, it would be treated as a coal-fired steam generating EGU;
however, the state may be able to use the RULOF provisions, as
discussed in section X.C.2 of this preamble, to particularize a
standard of performance for the unit. Note that if a state relies on
operating conditions within the control of the source as the basis of
providing a less stringent standard of performance or longer compliance
schedule, it must include those operating conditions as an enforceable
requirement in the state plan. 40 CFR 60.24a(g).
C. Rationale for the BSER for Coal-Fired Steam Generating Units
This section of the preamble describes the rationale for the final
BSERs for existing coal-fired steam generating units based on the
criteria described in section V.C of this preamble.
At proposal, the EPA evaluated two primary control technologies as
potentially representing the BSER for existing coal-fired steam
generating units: CCS and natural gas co-firing. For sources operating
in the long-term, the EPA proposed CCS with 90 percent capture as BSER.
For sources operating in the medium-term (i.e., those demonstrating
that they plan to permanently cease operation by January 1, 2040), the
EPA proposed 40 percent natural gas co-firing as BSER. For imminent-
term and near-term sources ceasing operation earlier, the EPA proposed
BSERs of routine methods of operation and maintenance.
The EPA is finalizing CCS with 90 percent capture as BSER for coal-
fired steam generating units because CCS can achieve a substantial
amount of emission reductions and satisfies the other BSER criteria.
CCS has been adequately demonstrated and results in by far the largest
emissions reductions of the available control technologies. As noted
below, the EPA has also determined that the compliance date for CCS is
January 1, 2032. CCS, however, entails significant up-front capital
expenditures that are amortized over a period of years. The EPA
evaluated the cost for different amortization periods, and the EPA has
concluded that CCS is cost-reasonable for units that operate past
January 1, 2039. As noted in section IV.D.3.b of this preamble, about
half (87 GW out of 181 GW) of all coal-fired capacity currently in
existence has announced plans to permanently cease operations by
January 1, 2039, and additional sources are likely to do so because
they will be older than the age at which sources generally have
permanently ceased operations since 2000. The EPA has determined that
the remaining sources that may operate after January 1, 2039, can, on
average, install CCS at a cost that is consistent with the EPA's
metrics for cost reasonableness, accounting for an amortization period
for the capital costs of more than 7 years, as detailed in section
VII.C.1.a.ii of this preamble. If a particular source has costs of CCS
that are fundamentally different from those amounts, the state may
consider it to be a candidate for a different control requirement under
the RULOF provision, as detailed in section X.C.2 of this preamble. For
the group of sources that permanently cease operation before January 1,
2039, the EPA has concluded that CCS would in general be of higher
cost, and therefore is finalizing a subcategory for these units, termed
medium-term units, and finalizing 40 percent natural gas co-firing on a
heat input basis as the BSER.
These final subcategories and BSERs are largely consistent with the
proposal, which included a long-term subcategory for sources that did
not plan to permanently cease operations by January 1, 2040, with 90
percent capture CCS as the BSER; and a medium-term subcategory for
sources that permanently cease operations by that date and were not in
any of the other proposed subcategories, discussed next, with 40
percent co-firing as the BSER. For both subcategories, the compliance
date was January 1, 2030. The EPA also proposed an imminent-term
subcategory, for sources that planned to permanently cease operations
by January 1, 2032; and a near-term subcategory, for sources that
planned to permanently case operations by January 1, 2035, and that
limited their annual capacity utilization to 20 percent. The EPA
proposed a BSER of routine methods of operation and maintenance for
these two subcategories.
The EPA is not finalizing these imminent-term and near-term
subcategories. In addition, after considering the comments, the EPA
acknowledges that some additional time from what was proposed may be
beneficial for the planning and installation of CCS. Therefore, the EPA
is finalizing a January 1, 2032, compliance date for long-term existing
coal-fired steam generating units. As noted above, the EPA's analysis
of the costs of CCS also indicates that CCS is cost-reasonable with a
minimum amortization period of seven years; as a result, the final
emission guidelines would apply a CCS-based standard only to those
units that plan to operate for at least seven years after the
compliance deadline (i.e., units that plan to remain in operation after
January 1, 2039). For medium-term sources subject to a natural gas co-
firing BSER, the EPA is finalizing a January 1, 2030, compliance date
because the EPA has concluded that this provides a reasonable amount of
time to begin co-firing, a technology that entails substantially less
up-front infrastructure and, relatedly, capital expenditure than CCS.
1. Long-Term Coal-Fired Steam Generating Units
The EPA is finalizing CCS with 90 percent capture of CO2
at the stack as BSER for long-term coal-fired steam generating units.
Coal-fired steam generating units are the largest stationary source of
CO2 in the United States. Coal-fired steam generating units
have higher emission rates than other generating technologies, about
twice the emission rate of a natural gas combined cycle unit.
Typically, even newer, more efficient coal-fired steam generating units
emit over 1,800 lb CO2/MWh-gross, while many existing coal-
fired steam generating units have emission rates of 2,200 lb
CO2/MWh-gross or higher. As noted in section IV.B of this
[[Page 39846]]
preamble, coal-fired sources emitted 909 MMT CO2e in 2021,
59 percent of the GHG emissions from the power sector and 14 percent of
the total U.S. GHG emissions--contributing more to U.S. GHG emissions
than any other sector, aside from transportation road sources.\275\
Furthermore, considering the sources in the long-term subcategory will
operate longer than sources with shorter operating horizons, long-term
coal-fired units have the potential to emit more total CO2.
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\275\ U.S. Environmental Protection Agency (EPA). Inventory of
U.S. Greenhouse Gas Emissions and Sinks: 1990-2021. U.S. Greenhouse
Gas Emissions by Inventory Sector, 2021. https://cfpub.epa.gov/ghgdata/inventoryexplorer/index.html#iallsectors/allsectors/allgas/inventsect/current.
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CCS is a control technology that can be applied at the stack of a
steam generating unit, achieves substantial reductions in emissions and
can capture and permanently sequester more than 90 percent of
CO2 emitted by coal-fired steam generating units. The
technology is adequately demonstrated, given that it has been operated
at scale and is widely applicable to these sources, and there are vast
sequestration opportunities across the continental U.S. Additionally,
the costs for CCS are reasonable, in light of recent technology cost
declines and policies including the tax credit under IRC section 45Q.
Moreover, the non-air quality health and environmental impacts of CCS
can be mitigated and the energy requirements of CCS are not
unreasonably adverse. The EPA's weighing of these factors together
provides the basis for finalizing CCS as BSER for these sources. In
addition, this BSER determination aligns with the caselaw, discussed in
section V.C.2.h of the preamble, stating that CAA section 111
encourages continued advancement in pollution control technology.
At proposal, the EPA also evaluated natural gas co-firing at 40
percent of heat input as a potential BSER for long-term coal-fired
steam generating units. While the unit level emission rate reductions
of 16 percent achieved by 40 percent natural gas co-firing are
appreciable, those reductions are substantially less than CCS with 90
percent capture of CO2. Therefore, because CCS achieves more
reductions at the unit level and is cost-reasonable, the EPA is not
finalizing natural gas co-firing as the BSER for these units. Further,
the EPA is not finalizing partial-CCS at lower capture rates (e.g., 30
percent) because it achieves substantially fewer unit-level reductions
at greater cost, and because CCS at 90 percent is achievable. Notably,
the IRC section 45Q tax credit may not be available to defray the costs
of partial CCS and the emission reductions would be limited. And the
EPA is not finalizing HRI as the BSER for these units because of the
limited reductions and potential rebound effect.
a. Rationale for CCS as the BSER for Long-Term Coal-Fired Steam
Generating Units
In this section of the preamble, the EPA explains the rationale for
CCS as the BSER for existing long-term coal-fired steam generating
units. This section discusses the aspects of CCS that are relevant for
existing coal-fired steam generating units and, in particular, long-
term units. As noted in section VIII.F.4.c.iv of this preamble, much of
this discussion is also relevant for the EPA's determination that CCS
is the BSER for new base load combustion turbines.
In general, CCS has three major components: CO2 capture,
transportation, and sequestration/storage. Detailed descriptions of
these components are provided in section VII.C.1.a.i of this preamble.
As an overview, post-combustion capture processes remove CO2
from the exhaust gas of a combustion system, such as a utility boiler
or combustion turbine. This technology is referred to as ``post-
combustion capture'' because CO2 is a product of the
combustion of the primary fuel and the capture takes place after the
combustion of that fuel. The exhaust gases from most combustion
processes are at atmospheric pressure, contain somewhat dilute
concentrations of CO2, and are moved through the flue gas
duct system by fans. To separate the CO2 contained in the
flue gas, most current post-combustion capture systems utilize liquid
solvents--commonly amine-based solvents--in CO2 scrubber
systems using chemical absorption (or chemisorption).\276\ In a
chemisorption-based separation process, the flue gas is processed
through the CO2 scrubber and the CO2 is absorbed
by the liquid solvent. The CO2-rich solvent is then
regenerated by heating the solvent to release the captured
CO2.
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\276\ Other technologies may be used to capture CO2,
as described in the final TSDs, GHG Mitigation Measures for Steam
Generating Units and the GHG Mitigation Measures--Carbon Capture and
Storage for Combustion Turbines, available in the rulemaking docket.
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The high purity CO2 is then compressed and transported,
generally through pipelines, to a site for geologic sequestration
(i.e., the long-term containment of CO2 in subsurface
geologic formations). Pipelines are subject to Federal safety
regulations administered by PHMSA. Furthermore, sequestration sites are
widely available across the nation, and the EPA has developed a
comprehensive regulatory structure to oversee geologic sequestration
projects and assure their safety and effectiveness.\277\
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\277\ 80 FR 64549 (October 23, 2015).
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i. Adequately Demonstrated
In this section of the preamble, the EPA explains the rationale for
finalizing its determination that 90 percent capture applied to long-
term coal-fired steam generating units is adequately demonstrated. In
this section, the EPA first describes how simultaneous operation of all
components of CCS functioning in concert with one another has been
demonstrated, including a commercial scale application on a coal-fired
steam generating unit. The demonstration of the individual components
of CO2 capture, transport, and sequestration further support
that CCS is adequately demonstrated. The EPA describes how
demonstrations of CO2 capture support that 90 percent
capture rates are adequately demonstrated. The EPA further describes
how transport and geologic sequestration are adequately demonstrated,
including the feasibility of transport infrastructure and the broad
availability of geologic sequestration reservoirs in the U.S.
(A) Simultaneous Demonstration of CO2 Capture, Transport,
and Sequestration
The EPA proposed that CCS was adequately demonstrated for
applications on combustion turbines and existing coal-fired steam
generating units.
On reviewing the available information, all components of CCS--
CO2 capture, CO2 transport, and CO2
sequestration--have been demonstrated concurrently, with each component
operating simultaneously and in concert with the other components.
(1) Industrial Applications of CCS
Solvent-based CO2 capture was patented nearly 100 years
ago in the 1930s \278\ and has been used in a variety of industrial
applications for decades. For example, since 1978, an amine-based
system has been used to capture approximately 270,000 metric tons of
CO2 per year from the flue gas of the bituminous coal-fired
steam generating units at the 63 MW Argus Cogeneration Plant at Searles
Valley Minerals (Trona,
[[Page 39847]]
California).\279\ Furthermore, thousands of miles of CO2
pipelines have been constructed and securely operated in the U.S. for
decades.\280\ And tens of millions of tons of CO2 have been
permanently stored deep underground either for geologic sequestration
or in association with EOR.\281\ There are currently at least 15
operating CCS projects in the U.S., and another 121 that are under
construction or in advanced stages of development.\282\ This broad
application of CCS demonstrates that the components of CCS have been
successfully operated simultaneously. The Shute Creek Facility has a
capture capacity of 7 million metric tons per year and has been in
operation since 1986.\283\ The facility uses a solvent-based process to
remove CO2 from natural gas, and the captured CO2
is stored in association with EOR. Another example of CCS in industrial
applications is the Great Plains Synfuels Plant has a capture capacity
of 3 million metric tons per year and has been in operation since
2000.284 285 The Great Plains Synfuels Plant (Beulah, North
Dakota) uses a solvent-based process to remove CO2 from
lignite-derived syngas, the CO2 is transported by the Souris
Valley pipeline, and stored underground in association with EOR in the
Weyburn and Midale Oil Units in Saskatchewan, Canada. Over 39 million
metric tons of CO2 has been captured since 2000.
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\278\ 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.
\279\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\280\ 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-transmission-hazardous-liquids.
\281\ GHGRP US EPA. https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide.
\282\ Carbon Capture and Storage in the United States. CBO.
December 13, 2023. https://www.cbo.gov/publication/59345.
\283\ Id.
\284\ https://netl.doe.gov/research/Coal/energy-systems/gasification/gasifipedia/great-plains.
\285\ https://co2re.co/FacilityData.
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(2) Various CO2 capture methods are used in industrial
applications and are tailored to the flue gas conditions of a
particular industry (see the TSD GHG Mitigation Measures for Steam
Generating Units for details). Of those capture technologies, amine
solvent-based capture has been demonstrated for removal of
CO2 from the post-combustion flue gas of fossil fuel-fired
EGUs. The Quest CO2 capture facility in Alberta, Canada,
uses amine-based CO2 capture retrofitted to three existing
steam methane reformers at the Scotford Upgrader facility (operated by
Shell Canada Energy) to capture and sequester approximately 80 percent
of the CO2 in the produced syngas.\286\ Amine-solvents are
also applied for post-combustion capture from fossil fuel fired EGUs.
The Quest facility has been operating since 2015 and captures
approximately 1 million metric tons of CO2 per year.
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\286\ Quest Carbon Capture and Storage Project Annual Summary
Report, Alberta Department of Energy: 2021. https://open.alberta.ca/publications/quest-carbon-capture-and-storage-project-annual-report-2021.
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Applications of CCS at Coal-Fired Steam Generating Units
For electricity generation applications, this includes operation of
CCS at Boundary Dam Unit 3 in Saskatchewan, Canada. CCS at Boundary Dam
Unit 3 includes capture of the CO2 from the flue-gas of the
fossil fuel-fired EGU, compression of the CO2 onsite and
transport via pipeline offsite, and storage of the captured
CO2 underground. Storage of the CO2 captured at
Boundary Dam primarily occurs via EOR. Moreover, CO2
captured from Boundary Dam Unit 3 is also stored in a deep saline
aquifer at the Aquistore Deep Saline CO2 Storage Project,
which has permanently stored over 550,000 tons of CO2 to
date.\287\ Other demonstrations of CCS include the 240 MWe Petra Nova
CCS project at the subbituminous coal-fired W.A. Parish plant in Texas,
which, because it was EPAct05-assisted, we cite as useful in section
VII.C.1.a.i(B)(2) of this preamble, but not essential, corroboration.
See section VII.C.1.a.i(H)(1) for a detailed description of how the EPA
considers information from EPAct05-assisted projects.
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\287\ Aquistore Project. https://ptrc.ca/media/whats-new/aquistore-co2-storage-project-reached-+500000-tonnes-stored.
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Commenters stated that that all constituent components of CCS--
carbon capture, transportation, and sequestration--have not been
adequately demonstrated in integrated, simultaneous operation. We
disagree with this comment. The record described in the preceding shows
that all components have been demonstrated simultaneously. Even if the
record only included demonstration of the individual components of CCS,
the EPA would still determine that CCS is adequately demonstrated as it
would be reasonable on a technical basis that the individual components
are capable of functioning together--they have been engineered and
designed to do so, and the record for the demonstration of the
individual components is based on decades of direct data and
experience.
(B) CO2 Capture Technology at Coal-Fired Steam Generating
Units
The EPA is finalizing the determination that the CO2
capture component of CCS has been adequately demonstrated at a capture
efficiency of 90 percent, is technically feasible, and is achievable
over long periods (e.g., a year) for the reasons summarized here and
detailed in the following subsections of this preamble. This
determination is based, in part, on the demonstration of the technology
at existing coal-fired steam generating units, including the
commercial-scale installation at Boundary Dam Unit 3. The application
of CCS at Boundary Dam follows decades of development of CO2
capture for coal-fired steam generating units, as well as numerous
smaller-scale demonstrations that have successfully implemented this
technology. Review of the available information has also identified
specific, currently available, minor technological improvements that
can be applied today to better the performance of new capture plant
retrofits, and which can assure that the capture plants achieve 90
percent capture. The EPA's determination that 90 percent capture of
CO2 is adequately demonstrated is further corroborated by
EPAct05-assisted projects, including the Petra Nova project.
Moreover, several CCS retrofit projects on coal-fired steam
generating units are in progress that apply the lessons from the prior
projects and use solvents that achieve higher capture rates. Technology
providers that supply those solvents and the associated process
technologies have made statements concluding that the technology is
commercially proven and available today and have further stated that
those solvents achieve capture rates of 95 percent or greater.
Technology providers have decades of experience and have done the work
to responsibly scale up the technology over that time across a range of
flue gas compositions. Taking all of those factors into consideration,
and accounting for the operation and flue gas conditions of the
affected sources, solvent-based capture will consistently achieve
capture rates of 90 percent or greater for the fleet of long-term coal-
fired steam generating units.
Various technologies may be used to capture CO2, the
details of which are described generally in section IV.C.1 of this
preamble and in more detail in the final TSD, GHG Mitigation Measures
for Steam Generating Units, which is
[[Page 39848]]
available in the rulemaking docket.\288\ For post-combustion capture,
these technologies include solvent-based methods (e.g., amines, chilled
ammonia), solid sorbent-based methods, membrane filtration, pressure-
swing adsorption, and cryogenic methods.\289\ Lastly, oxy-combustion
uses a purified oxygen stream from an air separation unit (often
diluted with recycled CO2 to control the flame temperature)
to combust the fuel and produce a higher concentration of
CO2 in the flue gas, as opposed to combustion with oxygen in
air which contains 80 percent nitrogen. The CO2 can then be
separated by the aforementioned CO2 capture methods. Of the
available capture technologies, solvent-based processes have been the
most widely demonstrated at commercial scale for post-combustion
capture and are applicable to use with either combustion turbines or
steam generating units.
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\288\ Technologies to capture CO2 are also discussed
in the final TSD, GHG Mitigation Measures--Carbon Capture and
Storage for Combustion Turbines.
\289\ For pre-combustion capture (as is applicable to an IGCC
unit), syngas produced by gasification passes through a water-gas
shift catalyst to produce a gas stream with a higher concentration
of hydrogen and CO2. The higher CO2
concentration relative to conventional combustion flue gas reduces
the demands (power, heating, and cooling) of the subsequent
CO2 capture process (e.g., solid sorbent-based or
solvent-based capture); the treated hydrogen can then be combusted
in the unit.
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The EPA's identification of CCS with 90 percent capture as the BSER
is premised, in part, on an amine solvent-based CO2 system.
Amine solvents used for carbon capture are typically proprietary,
although non-proprietary solvents (e.g., monoethanolamine, MEA) may be
used. Carbon capture occurs by reactive absorption of the
CO2 from the flue gas into the amine solution in an
absorption column. The amine reacts with the CO2 but will
also react with impurities in the flue gas, including SO2.
PM will also affect the capture system. Adequate removal of
SO2 and PM prior to the CO2 capture system is
therefore necessary. After pretreatment of the flue gas with
conventional SO2 and PM controls, the flue gas goes through
a quencher to cool the flue gas and remove further impurities before
the CO2 absorption column. After absorption, the
CO2-rich amine solution passes to the solvent regeneration
column, while the treated gas passes through a water and/or acid wash
column to limit emission of amines or other byproducts. In the solvent
regeneration column, the solution is heated (using steam) to release
the absorbed CO2. The released CO2 is then
compressed and transported offsite, usually by pipeline. The amine
solution from the regenerating column is then cooled, a portion of the
lean solvent is treated in a solvent reclaiming process to mitigate
degradation of the solvent, and the lean solvent streams are recombined
and sent back to the absorption column.
(1) Capture Demonstrations at Coal-Fired Steam Generating Units
(a) SaskPower's Boundary Dam Unit 3
SaskPower's Boundary Dam Unit 3, a 110 MW lignite-fired unit in
Saskatchewan, Canada, was designed to achieve CO2 capture
rates of 90 percent using an amine-based post-combustion capture system
retrofitted to the existing steam generating unit. The capture plant,
which began operation in 2014, is the first full-scale CO2
capture system retrofit on an existing coal-fired power plant. It uses
the amine-based Shell CANSOLV[supreg] process, which includes an amine-
based SO2 scrubbing process and a separate amine-based
CO2 capture process, with integrated heat and power from the
steam generating unit.\290\
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\290\ Giannaris, S., et al. Proceedings of the 15th
International Conference on Greenhouse Gas Control Technologies
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
---------------------------------------------------------------------------
After undergoing maintenance and design improvements in September
and October of 2015 to address technical and mechanical challenges
faced in its first year of operation, Boundary Dam Unit 3 completed a
72-hour test of its design capture rate (3,240 metric tons/day), and
captured 9,695 metric tons of CO2 or 99.7 percent of the
design capacity (approximately 89.7 percent capture) with a peak rate
of 3,341 metric tons/day.\291\ However, the capture plant has not
consistently operated at this total capture efficiency. In general, the
capture plant ran less than 100 percent of the flue gas through the
capture equipment and the coal-fired steam generating unit also
operates when the capture plant is offline for maintenance. As a
result, although the capture plant has consistently achieved 90 percent
capture rates of the CO2 in the processed slipstream, the
amount of CO2 captured was less than 90 percent of the total
amount of CO2 in the flue gas of the steam generating unit.
Some of the reasons for this operation were due to the economic
incentives and regulatory requirements of the project, while other
reasons were due to technical challenges. The EPA has reviewed the
record of CO2 capture at Boundary Dam Unit 3. While Boundary
Dam is in Canada and therefore not subject to this action, these
technical challenges have been sufficiently overcome or are actively
mitigated so that Boundary Dam has more recently been capable of
achieving capture rates of 83 percent when the capture plant is
online.\292\ Furthermore, the improvements already employed and
identified at Boundary Dam can be readily applied during the initial
construction of a new CO2 capture plant today.
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\291\ SaskPower Annual Report (2015-16). https://
www.saskpower.com/about-us/Our-Company/~/
link.aspx?_id=29E795C8C20D48398EAB5E3273C256AD&_z=z.
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The CO2 captured at Boundary Dam is mostly used for EOR
and CO2 is also stored geologically in a deep saline
reservoir at the Aquistore site.\293\ The amount of flue gas captured
is based in part on economic reasons (i.e., to meet related contract
requirements). The incentives for CO2 capture at Boundary
Dam beyond revenue from EOR have been limited to date, and there have
been limited regulatory requirements for CO2 capture at the
facility. As a result, a portion (about 25 percent on average) of the
flue gas bypasses the capture plant and is emitted untreated. However,
because of increasing requirements to capture CO2 in Canada,
Boundary Dam Unit 3 has more recently pursued further process
optimization.
---------------------------------------------------------------------------
\293\ Aquistore. https://ptrc.ca/aquistore.
---------------------------------------------------------------------------
Total capture efficiencies at the plant have also been affected by
technical issues, particularly with the SO2 removal system
that is upstream of the CO2 capture system. Operation of the
SO2 removal system affects downstream CO2 capture
and the amount of flue gas that can be processed. Specifically, fly ash
(PM) in the flue gas at Boundary Dam Unit 3 contributed to fouling of
SO2 system components, particularly in the SO2
reboiler and the demisters of the SO2 absorber column.
Buildup of scale in the SO2 reboiler limited heat transfer
and regeneration of the SO2 scrubbing amine, and high
pressure drop affected the flowrate of the SO2 lean-solvent
back to the SO2 absorber. Likewise, fouling of the demisters
in the SO2 absorber column caused high pressure drop and
restricted the flow of flue gas through the system, limiting the amount
of flue gas that could be processed by the downstream CO2
capture system. To address these technical issues, additional wash
systems were added, including ``demister wash systems, a pre-scrubber
flue gas inlet curtain spray wash system, flue gas cooler throat
sprays, and a booster fan wash system.'' \294\
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\294\ Id.
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[[Page 39849]]
Such issues will definitively not occur in a different type of
SO2 removal system (e.g., wet lime scrubber flue gas
desulfurization, wet-FGD). SO2 scrubbers have been
successfully operated for decades across a large number of U.S. coal-
fired sources. Of the coal-fired sources with planned operation after
2039, 60 percent have wet FGD and 23 percent have a dry FGD. In section
VII.C.1.a.ii of this preamble, the EPA accounts for the cost of adding
a wet-FGD for those sources that do not have an FGD.
To further mitigate fouling due to fly ash, the PM controls
(electrostatic precipitators) at Boundary Dam Unit 3 were upgraded in
2015/2016 by adding switch integrated rectifiers. Of the coal-fired
sources with planned operation after 2039, 31 percent have baghouses
and 67 percent have electrostatic precipitators. Sources with baghouses
have greater or more consistent degrees of emission control, and wet
FGD also provides additional PM control.
Fouling at Boundary Dam Unit 3 also affected the heat exchangers in
both the SO2 removal system and the CO2 capture
system. Additional redundancies and isolations to those key components
were added in 2017 to allow for online maintenance. Damage to the
capture plant's CO2 compressor resulted in an unplanned
outage in 2021, and the issue was corrected.\295\ The facility reported
98.3 percent capture system availability in the third quarter of
2023.\296\
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\295\ S&P Global Market Intelligence (January 6, 2022). Only
still-operating carbon capture project battled technical issues in
2021. https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/only-still-operating-carbon-capture-project-battled-technical-issues-in-2021-68302671.
\296\ SaskPower (October 18, 2022). BD3 Status Update: Q3 2023.
https://www.saskpower.com/about-us/Our-Company/Blog/2023/BD3-Status-Update-Q3-2023.
---------------------------------------------------------------------------
Regular maintenance further mitigates fouling in the SO2
and CO2 absorbers, and other challenges (e.g., foaming,
biological fouling) typical of gas-liquid absorbers can be mitigated by
standard procedures. According to the 2022 paper co-authored by the
International CCS Knowledge Centre and SaskPower, ``[a] number of
initiatives are ongoing or planned with the goal of eliminating flue
gas bypass as follows: Since 2016, online cleaning of demisters has
been effective at controlling demister pressure; Chemical cleans and
replacement of fouled packing in the absorber towers to reduce pressure
losses; Optimization of antifoam injection and other aspects of amine
health, to minimize foaming potential; [and] Optimization of Liquid-to-
Gas (L/G) ratio in the absorber and other process parameters,'' as well
as other optimization procedures.\297\ While foaming is mitigated by an
antifoam injection regimen, the EPA further notes that the extent of
foaming that could occur may be specific to the chemistry of the
solvent and the source's flue gas conditions--foaming was not reported
for MHI's KS-1 solvent when treating bituminous coal post-combustion
flue gas at Petra Nova. Lastly, while biological fouling in the
CO2 absorber wash water and the SO2 absorber
caustic polisher has been observed, ``the current mitigation plan is to
perform chemical shocking to remove this particular buildup.'' \298\
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\297\ Jacobs, B., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (October 2022).
Reducing the CO2 Emission Intensity of Boundary Dam Unit 3 Through
Optimization of Operating Parameters of the Power Plant and Carbon
Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286430.
\298\ Pradoo, P., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (October 2022).
Improving the Operating Availability of the Boundary Dam Unit 3
Carbon Capture Facility. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286503.
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Based on the experiences of Boundary Dam Unit 3, key improvements
can be implemented in future CCS deployments during initial design and
construction. Improvements to PM and SO2 controls can be
made prior to operation of the CO2 capture system. Where fly
ash is present in the flue gas, wash systems can be installed to limit
associated fouling. Additional redundancies and isolations of key heat-
exchangers can be made to allow for in-line cleaning during operation.
Redundancy of key equipment (e.g., utilizing two CO2
compressor trains instead of one) will further improve operational
availability. A feasibility study for the Shand power plant, which is
also operated by SaskPower, includes many such design improvements, at
an overall cost that was less than the cost for Boundary Dam.\299\
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\299\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
---------------------------------------------------------------------------
(b) Other Coal-Fired Demonstrations
Several other projects have successfully demonstrated the capture
component of CCS at electricity generating plants and other industrial
facilities, some of which were previously noted in the discussion in
the 2015 NSPS.\300\ Since 1978, an amine-based system has been used to
capture approximately 270,000 metric tons of CO2 per year
from the flue gas of the bituminous coal-fired steam generating units
at the 63 MW Argus Cogeneration Plant (Trona, California).\301\ Amine-
based carbon capture has further been demonstrated at AES's Warrior Run
(Cumberland, Maryland) and Shady Point (Panama, Oklahoma) coal-fired
power plants, with the captured CO2 being sold for use in
the food processing industry.\302\ At the 180 MW bituminous coal-fired
Warrior Run plant, approximately 10 percent of the plant's
CO2 emissions (about 110,000 metric tons of CO2
per year) has been captured since 2000 and sold to the food and
beverage industry. AES's 320 MW Shady Point plant fires subbituminous
and bituminous coal, and captured CO2 from an approximate 5
percent slipstream (about 66,000 metric tons of CO2 per
year) from 2001 through around 2019.\303\ These facilities, which have
operated for multiple years, clearly show the technical feasibility of
post-combustion carbon capture.
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\300\ 80 FR 64548-54 (October 23, 2015).
\301\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\302\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\303\ Shady Point Plant (River Valley) was sold to Oklahoma Gas
and Electric in 2019. https://www.oklahoman.com/story/business/columns/2019/05/23/oklahoma-gas-and-electric-acquires-aes-shady-point-after-federal-approval/60454346007/.
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(2) EPAct05-Assisted CO2 Capture Projects at Coal-Fired
Steam Generating Units \304\
---------------------------------------------------------------------------
\304\ In the 2015 NSPS, the EPA provided a legal interpretation
of the constraints on how the EPA could rely on EPAct05-assisted
projects in determining whether technology is adequately
demonstrated for the purposes of CAA section 111. Under that legal
interpretation, ``these provisions [in the EPAct05] . . . preclude
the EPA from relying solely on the experience of facilities that
received [EPAct05] assistance, but [do] not . . . preclude the EPA
from relying on the experience of such facilities in conjunction
with other information.'' As part of the rulemaking action here, the
EPA incorporates the legal interpretation and discussion of these
EPAct05 provisions with respect the appropriateness of considering
facilities that received EPAct05 assistance in determining whether
CCS is adequately demonstrated, as found in the 2015 NSPS, 80 FR
64509, 64541-43 (October 23, 2015), and the supporting response to
comments, EPA-HQ-OAR-2013-0495-11861 at pgs.113-134.
---------------------------------------------------------------------------
(a) Petra Nova
Petra Nova is a 240 MW-equivalent capture facility that is the
first at-scale application of carbon capture at a coal-fired power
plant in the U.S. The system is located at the subbituminous coal-
[[Page 39850]]
fired W.A. Parish Generating Station in Thompsons, Texas, and began
operation in 2017, successfully capturing and sequestering
CO2 for several years. The system was put into reserve
shutdown (i.e., idled) in May 2020, citing the poor economics of
utilizing captured CO2 for EOR at that time. On September
13, 2023, JX Nippon announced that the carbon capture facility at Petra
Nova had been restarted.\305\ A final report from the National Energy
Technology Laboratory (NETL) details the success of the project and
what was learned from this first-of-a-kind demonstration at scale.\306\
The project used Mitsubishi Heavy Industry's proprietary KM-CDR
Process[supreg], a process that is similar to an amine-based solvent
process but that uses a proprietary solvent. During its operation, the
project successfully captured 92.4 percent of the CO2 from
the slip stream of flue gas processed with 99.08 percent of the
captured CO2 sequestered by EOR.
---------------------------------------------------------------------------
\305\ JX Nippon Oil & Gas Exploration Corporation. Restart of
the large-scale Petra Nova Carbon Capture Facility in the U.S.
(September 2023). https://www.nex.jx-group.co.jp/english/newsrelease/upload_files/20230913EN.pdf.
\306\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
---------------------------------------------------------------------------
The amount of flue gas treated at Petra Nova was consistent with a
240 MW size coal-fired steam EGU. The properties of the flue gas--
composition, temperature, pressure, density, flowrate, etc.--are the
same as would occur for a similarly sized coal-firing unit. Therefore,
Petra Nova corroborates that the capture equipment--including the
CO2 absorption column, solvent regeneration column, balance
of plant equipment, and the solvent itself--work at commercial scale
and can achieve capture rates of 90 percent.
The Petra Nova project did experience periodic outages that were
unrelated to the CO2 capture facility and do not implicate
the basis for the EPA's BSER determination.\307\ These include outages
at either the coal-fired steam generating unit (W.A. Parish Unit 8) or
the auxiliary combined cycle facility, extreme weather events
(Hurricane Harvey), and the operation of the EOR site and downstream
oil recovery and processing. Outages at the coal-fired steam generating
unit itself do not compromise the reliability of the CO2
capture plant or the plant's ability to achieve a standard of
performance based on CCS, as there would be no CO2 to
capture. Outages at the auxiliary combined cycle facility are also not
relevant to the EPA's BSER determination, because the final BSER is not
premised on the CO2 capture plant using an auxiliary
combined cycle plant for steam and power. Rather, the final BSER
assumes the steam and power come directly from the associated steam
generating unit. Extreme weather events can affect the operation of any
facility. Furthermore, the BSER is not premised on EOR, and it is not
dependent on downstream oil recovery or processing. Outages
attributable to the CO2 capture facility were 41 days in
2017, 34 days in 2018, and 29 days in 2019--outages decreased year-on-
year and were on average less than 10 percent of the year. Planned and
unplanned outages are normal for industrial processes, including steam
generating units.
---------------------------------------------------------------------------
\307\ Id.
---------------------------------------------------------------------------
Petra Nova experienced some technical challenges that were
addressed during its first 3 years of operation.\308\ One of these
issues was leaks from heat exchangers due to the properties of the
gasket materials--replacement of the gaskets addressed the issue.
Another issue was vibration of the flue gas blower due to build-up of
slurry and solids carryover. W.A. Parish Unit 8 uses a wet limestone
FGD scrubber to remove SO2, and the flue gas connection to
the capture plant is located at the bottom of the duct running from the
wet-FGD to the original stack. A diversion wall and collection drains
were installed to mitigate solids and slurry carryover. Regular
maintenance is required to clean affected components and reduce the
amount of slurry carryover to the quencher. Solids and slurry carryover
also resulted in calcium scale buildup on the flue gas blower. Although
calcium concentrations were observed to increase in the solvent,
impacts of calcium on the quencher and capture plant chemistry were not
observed. Some scaling may have been occurring in the cooling section
of the quencher and would have been addressed during a planned outage
in 2020. Another issue encountered was scaling related to the
CO2 compressor intercoolers, compressor dehydration system,
and an associated heat exchanger. The issue was determined to be due to
a material incompatibility of the CO2 compressor
intercooler, and the components were replaced during a 2018 planned
outage. To mitigate the scaling prior to the replacement of those
components, the compressor drain was also rerouted to the reclaimer and
a backup filtering system was also installed and used, both of which
proved to be effective. Some decrease in performance was also observed
in heat exchangers. The presence of cooling tower fill (a solid medium
used to increase surface area in cooling towers) in the cooling water
system exchangers may have impacted performance. It is also possible
that there could have been some fouling in heat exchangers. Fill was
planned to be removed and fouling checked for during regular
maintenance. Petra Nova did not observe fouling of the CO2
absorber packing or high pressure drops across the CO2
absorber bed, and Petra Nova also did not report any foaming of the
solvent. Even with the challenges that were faced, Petra Nova was never
restricted in reaching its maximum capture rate of 5,200 tons of
CO2 per day, a scale that was substantially greater than
Boundary Dam Unit 3 (approximately 3,600 tons of CO2 per
day).
---------------------------------------------------------------------------
\308\ Id.
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(b) Plant Barry
Plant Barry, a bituminous coal-fired steam generating unit in
Mobile, Alabama, began using the KM-CDR Process[supreg] in 2011 for a
fully integrated 25 MWe CCS project with a capture rate of 90
percent.\309\ The CCS project at Plant Barry captured approximately
165,000 tons of CO2 annually, which was then transported via
pipeline and sequestered underground in geologic formations.\310\
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\309\ U.S. Department of Energy (DOE). National Energy
Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741.
\310\ 80 FR 64552 (October 23, 2015).
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(c) Project Tundra
Project Tundra is a carbon capture project in North Dakota at the
Milton R. Young Station lignite coal-fired power plant. Project Tundra
will capture up to 4 million metric tons of CO2 per year for
permanent geologic storage. One planned storage site is collocated with
the power plant and is already fully permitted, while permitting for a
second nearby storage site is in progress.\311\ An air permit for the
capture facility has also been issued by North Dakota Department of
Environmental Quality. The project is designed to capture
CO2 at a rate of about 95 percent of the treated flue
gas.\312\ The capture plant will treat the flue gas from the 455 MW
Unit 2 and additional flue gas from the 250 MW Unit 1, and will treat
an equivalent capacity of 530 MW.\313\ The project began a final FEED
study in February 2023 with planned completion
[[Page 39851]]
in April 2024,\314\ and, prior to selection by DOE for funding award
negotiation, the project was scheduled to begin construction in
2024.\315\ The project will use MHI's KS-21 solvent and the Advanced
KM-CDR process. The MHI solvent KS-1 and an advanced MHI solvent
(likely KS-21) were previously tested on the lignite post-combustion
flue gas from the Milton R. Young Station.\316\ To provide additional
conditioning of the flue gas, the project is utilizing a wet
electrostatic precipitator (WESP). A draft Environmental Assessment
summarizing the project and potential environmental impacts was
released by DOE.\317\ Finally, Project Tundra was selected for award
negotiation for funding from DOE.\318\
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\311\ Project Tundra--Progress, Minnkota Power Cooperative,
2023. https://www.projecttundrand.com.
\312\ See Document ID No. EPA-HQ-OAR-2023-0072-0632.
\313\ Id.
\314\ ``An Overview of Minnkota's Carbon Capture Initiative--
Project Tundra,'' 2023 LEC Annual Meeting, October 5, 2023.
\315\ Project Tundra--Progress, Minnkota Power Cooperative,
2023. https://www.projecttundrand.com.
\316\ Laum, Jason. Subtask 2.4--Overcoming Barriers to the
Implementation of Postcombustion Carbon Capture. https://www.osti.gov/biblio/1580659.
\317\ DOE-EA-2197 Draft Environmental Assessment, August 17,
2023. https://www.energy.gov/nepa/listings/doeea-2197-documents-available-download.
\318\ Carbon Capture Demonstration Projects Selections for Award
Negotiations. https://www.energy.gov/oced/carbon-capture-demonstration-projects-selections-award-negotiations.
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That this project has funding through the Bipartisan Infrastructure
Law, and that this funding is facilitated through DOE's Office of Clean
Energy Demonstration's (OCED) Carbon Capture Demonstration Projects
Program, does not detract from the adequate demonstration of CCS.
Rather, the goal of that program is, ``to accelerate the implementation
of integrated carbon capture and storage technologies and catalyze
significant follow-on investments from the private sector to mitigate
carbon emissions sources in industries across America.'' \319\ For the
commercial scale projects, the stated requirement of the funding
opportunity announcement (FOA) is not that projects demonstrate CCS in
general, but that they ``demonstrate significant improvements in the
efficiency, effectiveness, cost, operational and environmental
performance of existing carbon capture technologies.'' \320\ This
implies that the basic technology already exists and is already
demonstrated. The FOA further notes that the technologies used by the
projects receiving funding should be proven such that, ``the
technologies funded can be readily replicated and deployed into
commercial practice.'' \321\ The EPA also notes that this and other on-
going projects were announced well in advance of the FOA. Considering
these factors, Project Tundra and other similarly funded projects are
supportive of the determination that CCS is adequately demonstrated.
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\319\ DOE. https://www.energy.gov/oced/carbon-capture-demonstration-projects-program-front-end-engineering-design-feed-studies.
\320\ DE-FOA-0002962. https://oced-exchange.energy.gov/FileContent.aspx?FileID=86c47d5d-835c-4343-86e8-2ba27d9dc119.
\321\ Id.
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(d) Project Diamond Vault
Project Diamond Vault will capture up to 95 percent of
CO2 emissions from the 600 MW Madison Unit 3 at Brame Energy
Center in Lena, Louisiana. Madison Unit 3 fires approximately 70
percent petroleum coke and 30 percent bituminous (Illinois Basin) coal
in a circulating fluidized bed. The FEED study for the project is
targeted for completion on September 9, 2024.322 323
Construction is planned to begin by the end of 2025 with commercial
operation starting in 2028.\324\ From the utility: ``Government
Inflation Reduction Act (IRA) funding through 45Q tax credits makes the
project financially viable. With these government tax credits, the
company does not expect a rate increase as a result of this project.''
\325\
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\322\ Diamond Vault Carbon Capture FEED Study. https://netl.doe.gov/sites/default/files/netl-file/23CM_PSCC31_Bordelon.pdf.
\323\ Note that while the FEED study is EPAct05-assisted, the
capture plant is not.
\324\ Project Diamond Vault Overview. https://www.cleco.com/docs/default-source/diamond-vault/project_diamond_vault_overview.pdf.
\325\ Id.
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(e) Other Projects
Other projects have completed or are in the process of completing
feasibility work or FEED studies, or are taking other steps towards
installing CCS on coal-fired steam generating units. These projects are
summarized in the final TSD, GHG Mitigation Measures for Steam
Generating Units, available in the docket. In general, these projects
target capture rates of 90 percent or above and provide evidence that
sources are actively pursuing the installation of CCS.
(3) CO2 Capture Technology Vendor Statements
CO2 capture technology providers have issued statements
supportive of the application of systems and solvents for
CO2 capture at fossil fuel-fired EGUs. These statements
speak to the decades of experience that technology providers have and
as noted below, vendors attest, and offer guarantees that 90 percent
capture rates are achievable. Generally, while there are many
CO2 capture methods available, solvent-based CO2
capture from post-combustion flue gas is particularly applicable to
fossil fuel-fired EGUs. Solvent-based CO2 capture systems
are commercially available from technology providers including Shell,
Mitsubishi Heavy Industries (MHI), Linde/BASF, Fluor and ION Clean
Energy.
Technology providers have made statements asserting extensive
experience in CO2 capture and the commercial availability of
CO2 capture technologies. Solvent-based CO2
capture was first patented in the 1930s.\326\ Since then, commercial
solvent-based capture systems have been developed that are focused on
applications to post-combustion flue gas. Several technology providers
have over 30 years of experience applying solvent-based CO2
capture to the post-combustion flue gas of fossil fuel-fired EGUs. In
general, technology providers describe the technologies for
CO2 capture from post-combustion flue gas as ``proven'' or
``commercially available'' or ``commercially proven'' or ``available
now'' and describe their experience with CO2 capture from
post-combustion flue gas as ``extensive.'' CO2 capture rates
of 90 percent or higher from post-combustion flue gas have been proven
by CO2 capture technology providers using several
commercially available solvents. Many of the available solvent
technologies have over 50,000 hours of operation, equivalent to over 5
years of operation.
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\326\ 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.
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Shell has decades of experience in CO2 capture systems.
Shell notes that ``[c]apturing and safely storing carbon is an option
that's available now.'' \327\ Shell has developed the CANSOLV[supreg]
CO2 capture system for CO2 capture from post-
combustion flue gas, a regenerable amine that the company claims has
multiple advantages including ``low parasitic energy consumption, fast
kinetics and extremely low volatility.'' \328\ Shell further notes,
``Moreover, the technology has been designed for
[[Page 39852]]
reliability through its highly flexible turn-up and turndown
capacity.'' \329\ The company has stated that ``Over 90% of the
CO2 in exhaust gases can be effectively and economically
removed through the implementation of Shell's carbon capture
technology.'' \330\ Shell also notes, ``Systems can be guaranteed for
bulk CO2 removal of over 90%.'' \331\
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\327\ Shell Global--Carbon Capture and Storage. https://www.shell.com/energy-and-innovation/carbon-capture-and-storage.html.
\328\ Shell Global--CANSOLV[supreg] CO2 Capture
System. https://www.shell.com/business-customers/catalysts-technologies/licensed-technologies/emissions-standards/tail-gas-treatment-unit/cansolv-co2.html.
\329\ Shell Catalysts & Technologies--Shell CANSOLV[supreg]
CO2 Capture System. https://catalysts.shell.com/en/Cansolv-co2-fact-sheet.
\330\ Id.
\331\ Id.
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MHI in collaboration with Kansai Electric Power Co., Inc. began
developing a solvent-based capture process (the KM CDR
ProcessTM) using the KS-1TM solvent in 1990.\332\
MHI describes the extensive experience of commercial application of the
solvent, ``KS-1TM--a solvent whose high reliability has been
confirmed by a track record of deliveries to 15 commercial plants
worldwide.'' \333\ Notable applications of KS-1TM and the
KM-CDR ProcessTM include applications at Plant Barry and
Petra Nova. Previously, MHI has achieved capture rates of greater than
90 percent over long periods and at full scale at the Petra Nova
project where the KS-1TM solvent was used.\334\ MHI has
further improved on the original process and solvent by making
available the Advanced KM CDR ProcessTM using the KS-
21TM solvent. From MHI, ``Commercialization of KS-
21TM solvent was completed following demonstration testing
in 2021 at the Technology Centre Mongstad in Norway, one of the world's
largest carbon capture demonstration facilities.'' \335\ MHI has
achieved CO2 capture rates of 95 to 98 percent using both
the KS-1TM and KS-21TM solvent at the Technology
Centre Mongstad (TCM).\336\ Higher capture rates under modified
conditions were also measured, ``In addition, in testing conducted
under modified operating conditions, the KS-21TM solvent
delivered an industry-leading carbon capture rate was 99.8% and
demonstrated the successful recovery of CO2 from flue gas of
lower concentration than the CO2 contained in the
atmosphere.'' \337\
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\332\ Mitsubishi Heavy Industries--CO2 Capture
Technology--CO2 Capture Process. https://www.mhi.com/products/engineering/co2plants_process.html.
\333\ Id.
\334\ Note: Petra Nova is an EPAct05-assisted project. W.A.
Parish Post-Combustion CO2 Capture and Sequestration
Demonstration Project, Final Scientific/Technical Report (March
2020). https://www.osti.gov/servlets/purl/1608572.
\335\ Id.
\336\ Mitsubishi Heavy Industries, ``Mitsubishi Heavy Industries
Engineering Successfully Completes Testing of New KS-21TM
Solvent for CO2 Capture,'' https://www.mhi.com/news/211019.html.
\337\ Id.
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Linde engineering in partnership with BASF has made available
BASF's OASE[supreg] blue amine solvent technology for post-combustion
CO2 capture. Linde notes their experience: ``We have
longstanding experience in the design and construction of chemical wash
processes, providing the necessary amine-based solvent systems and the
CO2 compression, drying and purification system.'' \338\
Linde also notes that ``[t]he BASF OASE[supreg] process is used
successfully in more than 400 plants worldwide to scrub natural,
synthesis and other industrial gases.'' \339\ The OASE[supreg] blue
technology has been successfully piloted at RWE Power, Niederaussem,
Germany (from 2009 through 2017; 55,000 operating hours) and the
National Center for Carbon Capture in Wilsonville, Alabama (January
2015 through January 2016; 3,200 operating hours). Based on the
demonstrated performance, Linde concludes that ``PCC plants combining
Linde's engineering skills and BASF's OASE[supreg] blue solvent
technology are now commercially available for a wide range of
applications.'' \340\ Linde and BASF have demonstrated capture rates
over 90 percent and operating availability \341\ rates of more than 97
percent during 55,000 hours of operation.
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\338\ Linde Engineering--Post Combustion Capture. https://www.linde-engineering.com/en/process-plants/co2-plants/carbon-capture/post-combustion-capture/index.html.
\339\ Linde and BASF--Carbon capture storage and utilisation.
https://www.linde-engineering.com/en/images/Carbon-capture-storage-utilisation-Linde-BASF_tcm19-462558.pdf.
\340\ Id.
\341\ Operating availability is the percent of time that the
CO2 capture equipment is available relative to its
planned operation.
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Fluor provides a solvent technology (Econamine FG Plus) and EPC
services for CO2 capture. Fluor describes their technology
as ``proven,'' noting that, ``Proven technology. Fluor Econamine FG
Plus technology is a propriety carbon capture solution with more than
30 licensed plants and more than 30 years of operation.'' \342\ Fluor
further notes, ``The technology builds on Fluor's more than 400
CO2 removal units in natural gas and synthesis gas
processing.'' \343\ Fluor further states, ``Fluor is a global leader in
CO2 capture [. . .] with long-term commercial operating
experience in CO2 recovery from flue gas.'' On the status of
Econamine FG Plus, Fluor notes that the ``[the] Technology [is]
commercially proven on natural gas, coal, and fuel oil flue gases,''
and further note that ``[o]perating experience includes using steam
reformers, gas turbines, gas engines, and coal/natural gas boilers.''
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\342\ Fluor--Comprehensive Solutions for Carbon Capture. https://www.fluor.com/client-markets/energy/production/carbon-capture.
\343\ Fluor--Econamine FG Plus\SM\. https://www.fluor.com/sitecollectiondocuments/qr/econamine-fg-plus-brochure.pdf.
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ION Clean Energy is a company focused on post-combustion carbon
capture founded in 2008. ION's ICE-21 solvent has been used at NCCC and
TCM Norway.\344\ ION has achieved capture rates of 98 percent using the
ICE-31 solvent.
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\344\ ION Clean Energy--Company. https://www.ioncleanenergy.com/company.
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(4) CCS User Statements on CCS
A number of the companies who have either completed large scale
pilot projects or who are currently developing full scale projects have
also indicated that CCS technology is currently a viable technology for
large coal-fired power plants. In 2011, announcing a decision not to
move forward with the first full scale commercial CCS installation of a
carbon capture system on a coal plant, AEP did not cite any technology
concerns, but rather indicated that ``it is impossible to gain
regulatory approval to recover our share of the costs for validating
and deploying the technology without federal requirements to reduce
greenhouse gas emissions already in place.'' \345\ Enchant Energy, a
company developing CCS for coal-fired power plants explained that its
FEED study for the San Juan Generating Station, ``shows that the
technical and business case for adding carbon capture to existing coal-
fired power plants is strong.'' \346\ Rainbow Energy, who is developing
a carbon capture project at the Coal Creek Power Station in North
Dakota explains, ``CCUS technology has been proven and is an economical
option for a facility like Coal Creek Station. We see CCUS as the best
option to manage CO2 emissions at our facility.'' \347\
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\345\ https://www.aep.com/news/releases/read/1206/AEP-Places-Carbon-Capture-Commercialization-On-Hold-Citing-Uncertain-Status-Of-Climate-Policy-Weak-Economy.
\346\ Enchant Energy. What is Carbon Capture and Sequestration
(CCS)? https://enchantenergy.com/carbon-capture-technology/.
\347\ Rainbow Energy Center. Carbon Capture. https://rainbowenergycenter.com/what-we-do/carbon-capture/.
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(5) State CCS Requirements
Several states encourage or even require sources to install CCS.
These state requirements further indicate that CCS is well-established
and effective. These state laws include the Illinois 2021 Climate and
Equitable Jobs Act, which requires privately owned coal-
[[Page 39853]]
fired units to reduce emissions to zero by 2030 and requires publicly
owned coal-fired units to reduce emissions to zero by 2045.\348\
Illinois has also imposed CCS-based CO2 emission standards
on new coal-fired power plants since 2009 when the state adopted its
Clean Coal Portfolio Standard law.\349\ The statute required an initial
capture rate of 50 percent when enacted but steadily increased the
capture rate requirement to 90 percent in 2017, where it remains.
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\348\ State of Illinois General Assembly. Public Act 102-0662:
Climate and Equitable Jobs Act. 2021. https://www.ilga.gov/legislation/publicacts/102/PDF/102-0662.pdf.
\349\ State of Illinois General Assembly. Public Act 095-1027:
Clean Coal Portfolio Standard Law. https://www.ilga.gov/legislation/publicacts/95/PDF/095-1027.pdf.
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Michigan in 2023 established a 100 percent clean energy requirement
by 2040 with a nearer term 80 percent clean energy by 2035
requirement.\350\ The statute encourages the application of CCS by
defining ``clean energy'' to include generation resources that achieve
90 percent carbon capture.
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\350\ State of Michigan Legislature. Public Act 235 of 2023.
Clean and Renewable Energy and Energy Waste Reduction Act. https://legislature.mi.gov/documents/2023-2024/publicact/pdf/2023-PA-0235.pdf.
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California identifies carbon capture and sequestration as a
necessary tool to reduce GHG emissions within its 2022 scoping plan
update \351\ and, that same year, enacted a statutory requirement
through Assembly Bill 1279 \352\ requiring the state to plan and
implement policies that enable carbon capture and storage technologies.
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\351\ California Air Resources Board, 2022 Scoping Plan for
Achieving Carbon Neutrality. https://ww2.arb.ca.gov/sites/default/files/2023-04/2022-sp.pdf.
\352\ State of California Legislature. Assembly Bill 1279
(2022). The California Climate Crisis Act. https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill_id=202120220AB1279.
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Several states in different parts of the country have adopted
strategic and planning frameworks that also encourage CCS. Louisiana,
which in 2020 set an economy-wide net-zero goal by 2050, has explored
policies that encourage CCS deployment in the power sector. The state's
2022 Climate Action Plan proposes a Renewable and Clean Portfolio
Standard requiring 100 percent renewable or clean energy by 2035.\353\
That proposal defines power plants achieving 90 percent carbon capture
as a qualifying clean energy resource that can be used to meet the
standard.
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\353\ Louisiana Climate Initiatives Task Force. Louisiana
Climate Action Plan (February 1, 2022). https://gov.louisiana.gov/assets/docs/CCI-Task-force/CAP/ClimateActionPlanFinal.pdf.
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Pennsylvania's 2021 Climate Action Plan notes that the state is
well positioned to install CCS to transition the state's electric fleet
to a zero-carbon economy.\354\ The state also established an
interagency workgroup in 2019 to identify ways to speed the deployment
of CCS.
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\354\ Pennsylvania Dept. of Environmental Protection.
Pennsylvania Climate Action Plan (2021). https://www.dep.pa.gov/Citizens/climate/Pages/PA-Climate-Action-Plan.aspx.
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The Governor of North Dakota announced in 2021 an economy-wide
carbon neutral goal by 2030.\355\ The announcement singled out the
Project Tundra Initiative, which is working to apply CCS technology to
the state's Milton R. Young Power Station.
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\355\ https://www.governor.nd.gov/news/updated-waudio-burgum-addresses-williston-basin-petroleum-conference-issues-carbon-neutral.
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The Governor of Wyoming has broadly promoted a Decarbonizing the
West initiative that includes the study of CCS technologies to reduce
carbon emissions from the region.\356\ A 2024 Wyoming law also requires
utilities in the state to install CCS technologies on a portion of
their existing coal-fired power plants by 2033.\357\
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\356\ https://westgov.org/initiatives/overview/decarbonizing-the-west.
\357\ State of Wyoming Legislature. SF0042. Low-carbon Reliable
Energy Standards-amendments. https://www.wyoleg.gov/Legislation/2024/SF0042.
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(6) Variable Load and Startups and Shutdowns
In this section of the preamble, the EPA considers the effects of
variable load and startups and shutdowns on the achievability of 90
percent capture. First, the coal-fired steam generating unit can itself
turndown \358\ to only about 40 percent of its maximum design capacity.
Due to this, coal-fired EGUs have relatively high duty cycles \359\--
that is, they do not cycle as frequently as other sources and typically
have high average loads when operating. In 2021, coal-fired steam
generating units had an average duty cycle of 70 percent, and more than
75 percent of units had duty cycles greater than 60 percent.\360\ Prior
demonstrations of CO2 capture plants on coal-fired steam
generating units have had turndown limits of approximately 60 percent
of throughput for Boundary Dam Unit 3 \361\ and about 70 percent
throughput for Petra Nova.\362\ Based on the technology currently
available, turndown to throughputs of 50 percent \363\ are achievable
for a single capture train.\364\ Considering that coal units can
typically only turndown to 40 percent, a 50 percent turndown ratio for
the CO2 capture plant is likely sufficient for most sources,
although utilizing two CO2 capture trains would allow for
turndown to as low as 25 percent of throughput. When operating at less
than maximum throughputs, the CO2 capture facility actually
achieves higher capture efficiencies, as evidenced by the data
collected at Boundary Dam Unit 3.\365\ Data from the Shand Feasibility
Report suggests that, for a solvent and design achieving 90 percent
capture at 100 percent of net load, 97.5 percent capture is achievable
at 62.5 percent of net load.\366\ Considering these factors,
CO2 capture is, in general, able to meet the variable load
of coal-fired steam generating units without any adverse impact on the
CO2 capture rate. In fact, operation at lower loads may lead
to
[[Page 39854]]
higher achievable capture rates over long periods of time.
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\358\ Here, ``turndown'' is the ability of a facility to turn
down some process value, such as flowrate, throughput or capacity.
Typically, this is expressed as a ratio relative to operation at its
maximum instantaneous capability. Because processes are designed to
operate within specific ranges, turndown is typically limited by
some lower threshold.
\359\ Here, ``duty cycle'' is the ratio of the gross amount of
electricity generated relative to the amount that could be
potentially generated if the unit operated at its nameplate capacity
during every hour of operation. Duty cycle is thereby an indication
of the amount of cycling or load following a unit experiences
(higher duty cycles indicate less cycling, i.e., more time at
nameplate capacity when operating). Duty cycle is different from
capacity factor, as the latter also quantifies the amount that the
unit spends offline.
\360\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. Available from EPA's Air Markets Program
Data website: https://campd.epa.gov.
\361\ Jacobs, B., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (March 15-18,
2021). Reducing the CO2 Emission Intensity of Boundary Dam Unit 3
Through Optimization of Operating Parameters of the Power Plant and
Carbon Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286430.
\362\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
\363\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
\364\ Here, a ``train'' in this context is a series of connected
sequential process equipment. For carbon capture, a process train
can include the quencher, absorber, stripper, and compressor. Rather
than doubling the size of a single train of process equipment, a
source could use two equivalent sized trains.
\365\ Jacobs, B., et al. Proceedings of the 16th International
Conference on Greenhouse Gas Control Technologies (March 15-18,
2021). Reducing the CO2 Emission Intensity of Boundary Dam Unit 3
Through Optimization of Operating Parameters of the Power Plant and
Carbon Capture Facilities. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4286430.
\366\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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Coal-fired steam generating units also typically have few startups
and shutdowns per year, and CO2 emissions during those
periods are low. Although capacity factor has declined in recent years,
as noted in section IV.D.3 of the preamble, the number of startups per
year has been relatively stable. In 2011, coal-fired sources had about
10 startups on average. In 2021, coal-fired steam generating units had
only 12 startups on average, see the final TSD, GHG Mitigation Measures
for Steam Generating Units, available in the docket. Prior to
generation of electricity, coal-fired steam generating units use
natural gas or distillate oil--which have a lower carbon content than
coal--because of their ignition stability and low ignition temperature.
Heat input rates during startup are relatively low, to slowly raise the
temperature of the boiler. Existing natural gas- or oil-fired ignitors
designed for startup purposes are generally sized for up to 15 percent
of the maximum heat-input. Considering the low heat input rate, use of
fuel with a lower carbon content, and the relatively few startups per
year, the contribution of startup to total GHG emissions is relatively
low. Shutdowns are relatively short events, so that the contribution to
total emissions are also low. The emissions during startup and shutdown
are therefore small relative to emissions during normal operation, so
that any impact is averaged out over the course of a year.
Furthermore, the IRC section 45Q tax credit provides incentive for
units to operate more. Sources operating at higher capacity factors are
likely to have fewer startups and shutdowns and spend less time at low
loads, so that their average load would be higher. This would further
minimize the insubstantial contribution of startups and shutdowns to
total emissions. Additionally, as noted in the preceding sections of
the preamble, new solvents achieve capture rates of 95 percent at full
load, and ongoing projects are targeting capture rates of 95 percent.
Considering all of these factors, startup and shutdown, in general, do
not affect the achievability of 90 percent capture over long periods
(i.e., a year).
(7) Coal Rank
CO2 capture at coal-fired steam generating units
achieves 90 percent capture, for the reasons detailed in sections
VII.C.1.a.i(B)(1) through (6) of this preamble. Moreover, 90 percent
capture is achievable for all coal types because amine solvents have
been used to remove CO2 from a variety of flue gas
compositions including a broad range of different coal ranks,
differences in CO2 concentration are slight and the capture
process can be designed to the appropriate scale, amine solvents have
been used to capture CO2 from flue gas with much lower
CO2 concentrations, and differences in flue gas impurities
due to different coal compositions can be managed or mitigated by
controls.
As detailed in the preceding sections, CO2 capture has
been operated on flue gas from the combustion of a broad range of coal
ranks including lignite, bituminous, subbituminous, and anthracite
coals. Post-combustion CO2 capture from the flue gas of an
EGU firing lignite has been demonstrated at the Boundary Dam Unit 3 EGU
(Saskatchewan, Canada). Most lignites have a higher ash and moisture
content than other coal types and, in that respect, the flue gas can be
more challenging to manage for CO2 capture. Amine
CO2 capture has also been used to treat lignite post-
combustion flue gas in pilot studies at the Milton R. Young station
(North Dakota).\367\ CO2 capture solvents have been used to
treat subbituminous post-combustion flue gas from W.A. Parish
Generating Station (Texas),\368\ and the bituminous post-combustion
flue gas from Plant Barry (Mobile, Alabama),\369\ Warrior Run
(Maryland),\370\ and Argus Cogeneration Plant (California).\371\ Amine
solvents have also been used to remove CO2 from the flue gas
of the bituminous- and subbituminous-fired Shady Point plant.\372\
CO2 capture solvents have been used to treat anthracite
post-combustion flue gas at the Wilhelmshaven power plant
(Germany).\373\ There are also ongoing projects that will apply CCS to
the flue gas of coal-fired steam generating units. The EPA considers
these ongoing projects to be indicative of the confidence that industry
stakeholders have in CCS. These include Project Tundra at the lignite-
fired Milton R. Young station (North Dakota),\374\ Project Diamond
Vault at the petroleum coke- and subbituminous-fired Brame Energy
Center Madison Unit 3 (Louisiana) \375\ and two units at the Jim
Bridger Plant (Wyoming).\376\
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\367\ Laum, Jason. Subtask 2.4--Overcoming Barriers to the
Implementation of Postcombustion Carbon Capture. https://www.osti.gov/biblio/1580659.
\368\ W.A. Parish Post-Combustion CO2 Capture and
Sequestration Demonstration Project, Final Scientific/Technical
Report (March 2020). https://www.osti.gov/servlets/purl/1608572.
\369\ U.S. Department of Energy (DOE). National Energy
Technology Laboratory (NETL). https://www.netl.doe.gov/node/1741.
\370\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
\371\ Id.
\372\ Id.
\373\ Reddy, et al. Energy Procedia, 37 (2013) 6216-6225.
\374\ Project Tundra--Progress, Minnkota Power Cooperative,
2023. https://www.projecttundrand.com.
\375\ Project Diamond Vault Overview. https://www.cleco.com/docs/default-source/diamond-vault/project_diamond_vault_overview.pdf.
\376\ 2023 Integrated Resource Plan Update, PacifiCorp, April 1,
2024, https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2023_IRP_Update.pdf.
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Different coal ranks have different carbon contents, affecting the
concentration of CO2 in flue gas. In general, however,
CO2 concentration of coal combustion flue gas varies only
between 13 and 15 percent. Differences in CO2 concentration
can be accounted for by appropriately designing the capture equipment,
including sizing the absorber columns. As detailed in section
VIII.F.4.c.iv of the preamble, CO2 has been captured from
the post-combustion flue gas of NGCCs, which typically have a
CO2 concentration of 4 percent.
Prior to emission controls and pre-conditioning, characteristics of
different coal ranks and boiler design result in other differences in
the flue gas composition, including in the concentration of
SO2, NOX, PM, and trace impurities. Such
impurities in the flue gas can react with the solvent or cause fouling
of downstream processes. However, in general, most existing coal-fired
steam generating units in the U.S. have controls that are necessary for
the pre-conditioning of flue gas prior to the CO2 capture
plant, including PM and SO2 controls. For those sources
without an FGD for SO2 control, the EPA included the costs
of adding an FGD in its cost analysis. Other marginal differences in
flue gas impurities can be managed by appropriately designing the
polishing column (direct contact cooler) for the individual source's
flue gas. Trace impurities can be mitigated using conventional controls
in the solvent reclaiming process (e.g., an activated carbon bed).
Considering the broad range of coal post-combustion flue gases
amine solvents have been operated with, that solvents capture
CO2 from flue gases with lower CO2
concentrations, that the capture process can be designed for different
CO2 concentrations, and that flue gas impurities that may
differ by coal rank can be managed by controls, the EPA therefore
concludes that 90 percent capture is achievable across all coal ranks,
including waste coal.
[[Page 39855]]
(8) Natural Gas-Fired Combustion Turbines
Additional information supporting the EPA's determination that 90
percent capture of CO2 from steam generating units is
adequately demonstrated is the experience from CO2 capture
from natural gas-fired combustion turbines. The EPA describes this
information in section VIII.F.4.c.iv(B)(1), including explaining how
information about CO2 capture from coal-fired steam
generating units also applies to natural gas-fired combustion turbines.
The reverse is true as well; information about CO2 capture
from natural gas-fired turbines can be applied to coal fired-units, for
much the same reasons.
(9) Summary of Evidence Supporting BSER Determination Without EPAct05-
Assisted Projects
As noted above, under the EPA's interpretation of the EPAct05
provisions, the EPA may not rely on capture projects that received
assistance under EPAct05 as the sole basis for a determination of
adequate demonstration, but the EPA may rely on those projects to
support or corroborate other information that supports such a
determination. The information described above that supports the EPA's
determination that 90 percent CO2 capture from coal-fired
steam generating units is adequately demonstrated, without
consideration of the EPAct05-assisted projects, includes (i) the
information concerning Boundary Dam, coupled with engineering analysis
concerning key improvements that can be implemented in future CCS
deployments during initial design and construction (i.e., all the
information in section VII.C.1.a.i.(B)(1)(a) and the information
concerning Boundary Dam in section VII.C.1.a.i.(B)(1)(b)); (ii) the
information concerning other coal-fired demonstrations, including the
Argus Cogeneration Plant and AES's Warrior Run (i.e., all the
information concerning those sources in section VII.C.1.a.i.(B)(1)(a));
(iii) the information concerning industrial applications of CCS (i.e.,
all the information in section VII.C.1.a.i.(A)(1); (iv) the information
concerning CO2 capture technology vendor statements (i.e.,
all the information in section VII.C.1.a.i.(B)(3)); (v) information
concerning carbon capture at natural gas-fired combustion turbines
other than EPAct05-assisted projects (i.e., all the information other
than information about EPAct05-assisted projects in section
VIII.F.4.c.iv.(B)(1)). All this information by itself is sufficient to
support the EPA's determination that 90 percent CO2 capture
from coal-fired steam generating units is adequately demonstrated.
Substantial additional information from EPAct05-assisted projects, as
described in section VII.C.1.a.i.(B), provides additional support and
confirms that 90 percent CO2 capture from coal-fired steam
generating units is adequately demonstrated.
(C) CO2 Transport
The EPA is finalizing its determination that CO2
transport by pipelines as a component of CCS is adequately
demonstrated. The EPA anticipates that in the coming years, a large-
scale interstate pipeline network may develop to transport
CO2. Indeed, PHMSA is currently engaged in a rulemaking to
update and strengthen its safety regulations for CO2
pipelines, which assumes that such a pipeline network will
develop.\377\ For purposes of determining the CCS BSER in this final
action, however, the EPA did not base its analysis of the availability
of CCS on the projected existence of a large-scale interstate pipeline
network. Instead, the EPA adopted a more conservative approach. The
BSER is premised on the construction of relatively short lateral
pipelines that extend from the source to the nearest geologic storage
reservoir. While the EPA anticipates that sources would likely avail
themselves of an existing interstate pipeline network if one were
constructed and that using an existing network would reduce costs, the
EPA's analysis focuses on steps that an individual source could take to
access CO2 storage independently.
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\377\ PHMSA submitted the associated Notice of Proposed
Rulemaking to the White House Office of Management and Budget on
February 1, 2024 for pre-publication review. The notice stated that
the proposed rulemaking would enhance safety regulations to
``accommodate an anticipated increase in the number of carbon
dioxide pipelines and volume of carbon dioxide transported.'' Office
of Management and Budget. https://www.reginfo.gov/public/do/eAgendaViewRule?pubId=202310&RIN=2137-AF60.
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EGUs that do not currently capture and transport CO2
will need to construct new CO2 pipelines to access
CO2 storage sites, or make arrangements with pipeline owners
and operators who can do so. Most coal-fired steam EGUs, however, are
located in relatively close proximity to deep saline formations that
have the potential to be used as long-term CO2 storage
sites.\378\ Of existing coal-fired steam generating capacity with
planned operation during or after 2039, more than 50 percent is located
less than 32 km (20 miles) from potential deep saline sequestration
sites, 73 percent is located within 50 km (31 miles), 80 percent is
located within 100 km (62 miles), and 91 percent is within 160 km (100
miles). While the EPA's analysis focuses on the geographic availability
of deep saline formations, unmineable coal seams and depleted oil and
gas reservoirs could also potentially serve as storage formations
depending on site-specific characteristics. Thus, for the majority of
sources, only relatively short pipelines would be needed for
transporting CO2 from the source to the sequestration site.
For the reasons described below, the EPA believes that both new and
existing EGUs are capable of constructing CO2 pipelines as
needed. New EGUs may also be planned to be co-located with a storage
site so that minimal transport of the CO2 is required. The
EPA has assurance that the necessary pipelines will be safe because the
safety of existing and new supercritical CO2 pipelines is
comprehensively regulated by PHMSA.\379\
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\378\ Individual saline formations would require site-specific
characterization to determine their suitability for geologic
sequestration and the potential capacity for storage.
\379\ PHMSA additionally initiated a rulemaking in 2022 to
develop and implement new measures to strengthen its safety
oversight of CO2 pipelines following investigation into a
CO2 pipeline failure in Satartia, Mississippi in 2020.
For more information, see: https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
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(1) CO2 Transport Demonstrations
The majority of CO2 transported in the United States is
moved through pipelines. CO2 pipelines have been in use
across the country for nearly 60 years. Operation of this pipeline
infrastructure for this period of time establishes that the design,
construction, and operational requirements for CO2 pipelines
have been adequately demonstrated.\380\ PHMSA reported that 8,666 km
(5,385 miles) of CO2 pipelines were in operation in 2022, a
14 percent increase in CO2 pipeline miles since 2011.\381\
This pipeline infrastructure continues to expand with a number of
anticipated projects underway.
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\380\ For additional information on CO2
transportation infrastructure project timelines, costs and other
details, please see EPA's final TSD, GHG Mitigation Measures for
Steam Generating Units.
\381\ 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-transmission-hazardous-liquids.
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The U.S. CO2 pipeline network includes major trunkline
(i.e., large capacity) pipelines as well as shorter, smaller capacity
lateral pipelines connecting a CO2 source to a larger
trunkline or connecting a CO2 source to a nearby
CO2 end use. While CO2
[[Page 39856]]
pipelines are generally more economical, other methods of
CO2 transport may also be used in certain circumstances and
are detailed in the final TSD, GHG Mitigation Measures for Steam
Generating Units.
(a) Distance of CO2 Transport for Coal-Fired Power Plants
An important factor in the consideration of the feasibility of
CO2 transport from existing coal-fired steam generating
units to sequestration sites is the distance the CO2 must be
transported. As discussed in section VII.C.1.a.i(D), potential
sequestration formations include deep saline formations, unmineable
coal seams, and oil and gas reservoirs. Based on data from DOE/NETL
studies of storage resources, of existing coal-fired steam generating
capacity with planned operation during or after 2039, 80 percent is
within 100 km (62 miles) of potential deep saline sequestration sites,
and another 11 percent is within 160 km (100 miles).\382\ In other
words, 91 percent of this capacity is within 160 km (100 miles) of
potential deep saline sequestration sites. In gigawatts, of the 81 GW
of coal-fired steam generation capacity with planned operation during
or after 2039, only 16 GW is not within 100 km (62 miles) of a
potential saline sequestration site, and only 7 GW is not within 160 km
(100 mi). The vast majority of these units (on the order of 80 percent)
can reach these deep saline sequestration sites by building an
intrastate pipeline. This distance is consistent with the distances
referenced in studies that form the basis for transport cost estimates
for this final rule.\383\ While the EPA's analysis focuses on the
geographic availability of deep saline formations, unmineable coal
seams and depleted oil and gas reservoirs could also potentially serve
as storage formations depending on site-specific characteristics.
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\382\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\383\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
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Of the 9 percent of existing coal-fired steam generating capacity
with planned operation during or after 2039 that is not within 160 km
(100 miles) of a potential deep saline sequestration site, 5 percent is
within 241 km (150 miles) of potential saline sequestration sites, an
additional 3 percent is within 322 km (200 miles) of potential saline
sequestration sites, and another 1 percent is within 402 km (250 miles)
of potential sequestration sites. In total, assuming all existing coal-
fired steam generating capacity with planned operation during or after
2039 adopts CCS, the EPA analysis shows that approximately 8,000 km
(5,000 miles) of CO2 pipelines would be constructed by 2032.
This includes units located at any distance from sequestration. Note
that this value is not optimized for the least total pipeline length,
but rather represents the approximate total pipeline length that would
be required if each power plant constructed a lateral pipeline
connecting their power plant to the nearest potential saline
sequestration site.\384\
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\384\ Note that multiple coal-fired EGUs may be located at each
power plant.
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Additionally, the EPA's compliance modeling projects 3,300 miles of
CO2 pipeline buildout in the baseline and 4,700 miles of
pipeline buildout in the policy scenario. This is comparable to the
4,700 to 6,000 miles of CO2 pipeline buildout estimated by
other simulations examining similar scenarios of coal CCS
deployment.\385\ Over 5 years, this total projected CO2
pipeline capacity would amount to about 660 to 940 miles per year on
average.\386\ This projected pipeline mileage is comparable to other
types of pipelines that are regularly constructed in the United States
each year. For example, based on data collected by EIA, the total
annual mileage of natural gas pipelines constructed over the 2017-2021
period ranged from approximately 1,000 to 2,500 miles per year. The
projected annual average CO2 pipeline mileage is less than
each year in this historical natural gas pipeline range, and
significantly less than the upper end of this range.
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\385\ CO2 Pipeline Analysis for Existing Coal-Fired
Powerplants. Chen et. al. Los Alamos National Lab. 2024. https://permalink.lanl.gov/object/tr?what=info:lanl-repo/lareport/LA-UR-24-23321.
\386\ In the EPA's representative timeline, the CO2
pipeline is constructed in an 18-month period. In practice, all
CO2 pipeline construction projects would be spread over a
larger time period. In the Transport and Storage Timeline Summary,
ICF (2024), available in Docket ID EPA-HQ-OAR-2023-0072, permitting
is 1.5 years. Some CO2 pipeline construction would
therefore likely begin by the start of 2028, or even earlier
considering on-going projects. With the one-year compliance
extension for delays outside of the owner/operators control that
would provide extra time if there were challenges in building
pipelines, the construction on CO2 pipelines could occur
during 2032.
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The EPA also notes that the pipeline construction estimates
presented in this section are not additive with the natural gas co-
firing pipeline construction estimates presented below because
individual sources will not elect to utilize both compliance methods.
In other words, more pipeline buildout for one compliance method
necessarily means less pipeline buildout for the other method.
Therefore, there is no compliance scenario in which the total pipeline
construction is equal to the sum of the CCS and natural gas co-firing
pipeline estimates presented in this preamble.
While natural gas line construction may be easier in some
circumstances given the uniform federal regulation that governs those
such construction, the historical trends support the EPA's conclusion
that constructing less CO2 pipeline length over a several
year period is feasible.
(b) CO2 Pipeline Examples
PHMSA reported that 8,666 km (5,385 miles) of CO2
pipelines were in operation in 2022.\387\ Due to the unique nature of
each project, CO2 pipelines vary widely in length and
capacity. Examples of projects that have utilized CO2
pipelines include the following: Beaver Creek (76 km), Monell (52.6
km), Bairoil (258 km), Salt Creek (201 km), Sheep Mountain (656 km),
Slaughter (56 km), Cortez (808 km), Central Basin (231 km), Canyon Reef
Carriers (354 km), and Choctaw (294 km). These pipelines range in
capacity from 1.6 million tons per year to 27 million tons per year,
and transported CO2 for uses such as EOR.\388\
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\387\ 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-transmission-hazardous-liquids.
\388\ Noothout, Paul. Et. Al. (2014). ``CO2 Pipeline
infrastructure--lessons learnt.'' https://www.sciencedirect.com/science/article/pii/S187661021402864.
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Most sources deploying CCS are anticipated to construct pipelines
that run from the source to the sequestration site. Similar
CO2 pipelines have been successfully constructed and
operated in the past. For example, a 109 km (68 mile) CO2
pipeline was constructed from a fertilizer plant in Coffeyville,
Kansas, to the North Burbank Unit, an EOR operation in Oklahoma.\389\
Chaparral Energy entered a long-term CO2 purchase and sale
agreement with a subsidiary of CVR Energy for the capture of
CO2 from CVR's nitrogen fertilizer plant in 2011.\390\ The
pipeline
[[Page 39857]]
was then constructed, and operations started in 2013.\391\ Furthermore,
a 132 km (82 mile) pipeline was constructed from the Terrell Gas
facility (formerly Val Verde) in Texas to supply CO2 for EOR
projects in the Permian Basin.\392\ Additionally, the Kemper Country
CCS project in Mississippi, was designed to capture CO2 from
an integrated gasification combined cycle power plant, and transport
CO2 via a 96 km (60 mile) pipeline to be used in EOR.\393\
Construction for this facility commenced in 2010 and was completed in
2014.\394\ Furthermore, the Citronelle Project in Alabama, which was
the largest demonstration of a fully integrated, pulverized coal-fired
CCS project in the United States as of 2016, utilized a dedicated 19 km
(12 mile) pipeline constructed by Denbury Resources in 2011 to
transport CO2 to a saline storage site.\395\
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\389\ Rassenfoss, Stephen. (2014). ``Carbon Dioxide: From
Industry to Oil Fields.'' ttps://jpt.spe.org/carbon-dioxide-industry-oil-fields.
\390\ GlobeNewswire. ``Chaparral Energy Agrees to a CO2 Purchase
and Sale Agreement with CVR Energy for Capture of CO2 for
Enhanced Oil Recovery.'' March 29, 2011. https://www.globenewswire.com/news-release/2011/03/29/443163/10562/en/Chaparral-Energy-Agrees-to-a-CO2-Purchase-and-Sale-Agreement-With-CVR-Energy-for-Capture-of-CO2-for-Enhanced-Oil-Recovery.html.
\391\ Chaparral Energy. ``A `CO2 Midstream' Overview:
EOR Carbon Management Workshop.'' December 10, 2013. https://www.co2conference.net/wp-content/uploads/2014/01/13-Chaparral-CO2-Midstream-Overview-2013.12.09new.pdf.
\392\ ``Val Verde Fact Sheet: Commercial EOR using Anthropogenic
Carbon Dioxide.'' https://sequestration.mit.edu/tools/projects/val_verde.html.
\393\ Kemper County IGCC Fact Sheet: Carbon Dioxide Capture and
Storage Project. https://sequestration.mit.edu/tools/projects/kemper.html.
\394\ Office of Fossil Energy and Carbon Management. Southern
Company--Kemper County, Mississippi. https://www.energy.gov/fecm/southern-company-kemper-county-mississippi.
\395\ Citronelle Project. National Energy Technology Laboratory.
(2018). https://www.netl.doe.gov/sites/default/files/2018-11/Citronelle-SECARB-Project.PDF.
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(c) EPAct05-Assisted CO2 Pipelines for CCS
Consistent with the EPA's legal interpretation that the Agency can
rely on experience from EPAct05 funded facilities in conjunction with
other information, this section provides additional examples of
CO2 pipelines with EPAct05 funding. CCS projects with
EPAct05 funding have built pipelines to connect the captured
CO2 source with sequestration sites, including Illinois
Industrial Carbon Capture and Storage in Illinois, Petra Nova in Texas,
and Red Trail Energy in North Dakota. The Petra Nova project, which
restarted operations in September 2023,\396\ transports CO2
via a 131 km (81 mile) pipeline to the injection site, while the
Illinois Industrial Carbon Capture project and Red Trail Energy
transport CO2 using pipelines under 8 km (5 miles)
long.397 398 399 Additionally, Project Tundra, a saline
sequestration project planned at the lignite-fired Milton R. Young
Station in North Dakota will transport CO2 via a 0.4 km
(0.25 mile) pipeline.\400\
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\396\ Jacobs, Trent. (2023). ``A New Day Begins for Shuttered
Petra Nova CCUS.'' https://jpt.spe.org/a-new-day-begins-for-shuttered-petra-nova-ccus.
\397\ Technical Review of Subpart RR MRV Plan for Petra Nova
West Ranch Unit. (2021). https://www.epa.gov/system/files/documents/2021-09/wru_decision.pdf.
\398\ Technical Review of Subpart RR MRV Plan for Archer Daniels
Midland Illinois Industrial Carbon Capture and Storage Project.
(2017). https://www.epa.gov/sites/default/files/2017-01/documents/adm_final_decision.pdf.
\399\ Red Trail Energy Subpart RR Monitoring, Reporting, and
Verification (MRV) Plan. (2022). https://www.epa.gov/system/files/documents/2022-04/rtemrvplan.pdf.
\400\ Technical Review of Subpart RR MRV Plan for Tundra SGS LLC
at the Milton R. Young Station. (2022). https://www.epa.gov/system/files/documents/2022-04/tsgsdecision.pdf.
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(d) Existing and Planned CO2 Trunklines
Although the BSER is premised on the construction of pipelines that
connect the CO2 source to the sequestration site, in
practice some sources may construct short laterals to existing
CO2 trunklines, which can reduce the number of miles of
pipeline that may need to be constructed. A map displaying both
existing and planned CO2 pipelines, overlayed on potential
geologic sequestration sites, is available in the final TSD, GHG
Mitigation Measures for Steam Generating Units. Pipelines connect
natural CO2 sources in south central Colorado, northeast New
Mexico, and Mississippi to oil fields in Texas, Oklahoma, New Mexico,
Utah, and Louisiana. The Cortez pipeline is the longest CO2
pipeline, and it traverses over 800 km (500) miles from southwest
Colorado to Denver City, Texas CO2 Hub, where it connects
with several other CO2 pipelines. Many existing
CO2 pipelines in the U.S. are located in the Permian Basin
region of west Texas and eastern New Mexico. CO2 pipelines
in Wyoming, Texas, and Louisiana also carry CO2 captured
from natural gas processing plants and refineries to EOR projects.
Additional pipelines have been constructed to meet the demand for
CO2 transportation. A 170 km (105 mile) CO2
pipeline owned by Denbury connecting oil fields in the Cedar Creek
Anticline (located along the Montana-North Dakota border) to
CO2 produced in Wyoming was completed in 2021, and a 30 km
(18 mile) pipeline also owned by Denbury connects to the same oil field
and was completed in 2022.401 402 These pipelines form a
network with existing pipelines in the region--including the Denbury
Greencore pipeline, which was completed in 2012 and is 232 miles long,
running from the Lost Cabin gas plant in Wyoming to Bell Creek Field in
Montana.\403\
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\401\ Denbury. Detailed Pipeline and Ownership Information.
(2022) https://www.denbury.com/wp-content/uploads/2022/11/DEN-Pipeline-Schedule.pdf.
\402\ AP News. Officials mark start of CO2 pipeline
used for oil recovery. (2022) https://apnews.com/article/business-texas-north-dakota-plano-25f1dbf9a924613a56827c1c83e4ba68.
\403\ Denbury. Detailed Pipeline and Ownership Information.
(2022) https://www.denbury.com/wp-content/uploads/2022/11/DEN-Pipeline-Schedule.pdf.
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In addition to the existing pipeline network, there are a number of
large CO2 trunklines that are planned or in progress, which
could further reduce the number of miles of pipeline that a source may
need to construct. Several major projects have recently been announced
to expand the CO2 pipeline network across the United States.
For example, the Summit Carbon Solutions Midwest Carbon Express project
has proposed to add more than 3,200 km (2,000) miles of dedicated
CO2 pipeline in Iowa, Nebraska, North Dakota, South Dakota,
and Minnesota. The Midwest Carbon Express is projected to begin
operations in 2026. Further, Wolf Carbon Solutions has recently
announced that it plans to refile permit applications for the Mt. Simon
Hub, which will expand the CO2 pipeline by 450 km (280
miles) in the Midwest. Tallgrass announced in 2022 a plan to convert an
existing 630 km (392 mile) natural gas pipeline to carry CO2
from an ADM ethanol production facility in Nebraska to a planned
commercial-scale CO2 sequestration hub in Wyoming aimed for
completion in 2024.\404\ Recently, as part of agreeing to a communities
benefits plan, a number of community groups have agreed that they will
support construction of the Tallgrass pipeline in Nebraska.\405\ While
the construction of larger networks of trunklines could facilitate CCS
for power plants, the BSER is not predicated on the buildout of a
trunkline network and the existence of future trunklines was not
assumed in the EPA's feasibility or costing analysis. The EPA's
analysis is conservative in that it does not presume the buildout of
trunkline networks. The development of more robust and interconnected
pipeline systems over the next several years would merely lower the
EPA's
[[Page 39858]]
cost projections and create additional CO2 transport options
for power plants that do CCS.
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\404\ Tallgrass. Tallgrass to Capture and Sequester
CO2 Emissions from ADM Corn Processing Complex in
Nebraska. (2022). https://tallgrass.com/newsroom/press-releases/tallgrass-to-capture-and-sequester-co2-emissions-from-adm-corn-processing-complex-in-nebraska.
\405\ https://boldnebraska.org/upcoming-meetings-understanding-the-new-tallgrass-carbon-pipeline-community-benefits-agreement/.
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Moreover, pipeline projects have received funding under the IIJA to
conduct front-end engineering and design (FEED) studies.\406\ Carbon
Solutions LLC received funding to conduct a FEED study for a
commercial-scale pipeline to transport CO2 in support of the
Wyoming Trails Carbon Hub as part of a statewide pipeline system that
would be capable of transporting up to 45 million metric tons of
CO2 per year from multiple sources. In addition, Howard
Midstream Energy Partners LLC received funding to conduct a FEED study
for a 965 km (600 mi) CO2 pipeline system on the Gulf Coast
that would be capable of moving at least 250 million metric tons of
CO2 annually and connecting carbon sources within 30 mi of
the trunkline.
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\406\ Office of Fossil Energy and Carbon Management. ``Project
Selections for FOA 2730: Carbon Dioxide Transport Engineering and
Design (Round 1).'' https://www.energy.gov/fecm/project-selections-foa-2730-carbon-dioxide-transport-engineering-and-design-round-1.
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Other programs were created by the IIJA to facilitate the buildout
of large pipelines to carry carbon dioxide from multiple sources. For
example, the Carbon Dioxide Transportation Infrastructure Finance and
Innovation Act (CIFIA) was incorporated into the IIJA and provided $2.1
billion to DOE to finance projects that build shared (i.e., common
carrier) transport infrastructure to move CO2 from points of
capture to conversion facilities and/or storage wells. The program
offers direct loans, loan guarantees, and ``future growth grants'' to
provide cash payments to specifically for eligible costs to build
additional capacity for potential future demand.\407\
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\407\ https://www.energy.gov/lpo/carbon-dioxide-transportation-infrastructure.
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(2) Permitting and Rights of Way
The permitting process for CO2 pipelines often involves
a number of private, local, state, tribal, and/or Federal agencies.
States and local governments are directly involved in siting and
permitting proposed CO2 pipeline projects. CO2
pipeline siting and permitting authorities, landowner rights, and
eminent domain laws are governed by the states and vary by state.
State laws determine pipeline siting and the process for developers
to acquire rights-of-way needed to build. Pipeline developers may
secure rights-of-way for proposed projects through voluntary agreements
with landowners; pipeline developers may also secure rights-of-way
through eminent domain authority, which typically accompanies siting
permits from state utility regulators with jurisdiction over
CO2 pipeline siting.\408\ The permitting process for
interstate pipelines may take longer than for intrastate pipelines.
Whereas multiple state regulatory agencies would be involved in the
permitting process for an interstate pipeline, only one primary state
regulatory agency would be involved in the permitting process for an
intrastate pipeline.
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\408\ Congressional Research Service.2022. Carbon Dioxide
Pipelines: Safety Issues, CRS Reports, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
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Most regulation of CO2 pipeline siting and development
is conducted at the state level, and under state specific regulatory
regimes. As the interest in CO2 pipelines has grown, states
have taken steps to facilitate pipeline siting and construction. State
level regulation related to CO2 sequestration and transport
is an very active area of legislation across states in all parts of the
country, with many states seeking to facilitate pipeline siting and
construction.\409\ Many states, including Kentucky, Michigan, Montana,
Arkansas, and Rhode Island, treat CO2 pipeline operators as
common carriers or public utilities.\410\ This is an important
classification in some jurisdictions where it may be required for
pipelines seeking to exercise eminent domain.\411\ Currently, 17 states
explicitly allow CO2 pipeline operators to exercise eminent
domain authority for acquisition of CO2 pipeline rights-of-
way, should developers not secure them through negotiation with
landowners.\412\ Some states have recognized the need for a streamlined
CO2 pipeline permitting process when there are multiple
layers of regulation and developed joint permit applications. Illinois,
Louisiana, New York, and Pennsylvania have created a joint permitting
form that allows applicants to file a single application for pipeline
projects covering both state and federal permitting requirements.\413\
Even in states without this streamlined process, pipeline developers
can pursue required state permits concurrently with federal permits,
NEPA review (as applicable), and the acquisition of rights-of-way.
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\409\ Great Plains Institute State Legislative Tracker 2023.
Carbon Management State Legislative Program Tracker. https://www.quorum.us/spreadsheet/external/fVOjsTvwyeWkIqVlNmoq/?mc_cid=915706f2bc&.
\410\ National Association of Regulatory Utility Commissioners
(NARUC). (2023). Onshore U.S. Carbon Pipeline Deployment: Siting,
Safety. and Regulation. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\411\ Martin Lockman. Permitting CO2 Pipelines. Sabin Center for
Climate Change Law (2023). https://scholarship.law.columbia.edu/cgi/viewcontent.cgi?article=1208&context=sabin_climate_change.
\412\ The 17 states are: Arizona, Illinois, Indiana, Iowa,
Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, New
Mexico, North Carolina, North Dakota, Pennsylvania, South Dakota,
Texas, and Wyoming. National Association of Regulatory Utility
Commissioners (NARUC). (2023). Onshore U.S. Carbon Pipeline
Deployment: Siting, Safety. and Regulation. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\413\ Martin Lockman. Permitting CO2 Pipelines. Sabin Center for
Climate Change Law (Sept. 2023). https://scholarship.law.columbia.edu/cgi/viewcontent.cgi?article=1208&context=sabin_climate_change.
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Pipeline developers have been able to successfully secure the
necessary rights-of way for CO2 pipeline projects. For
example, Summit Carbon Solutions, which has proposed to add more than
3,200 km (2,000 mi) of dedicated CO2 pipeline in Iowa,
Nebraska, North Dakota, South Dakota, and Minnesota, has stated that as
of November 7, 2023, it had reached easement agreements with 2,100
landowners along the route.\414\ As of February 23, 2024, Summit Carbon
Solutions stated that it had acquired about 75 percent of the rights of
way needed in Iowa, about 80 percent in North Dakota, about 75 percent
in South Dakota, and about 89 percent in Minnesota. The company has
successfully navigated hurdles, such as rerouting the pipelines in
certain counties where necessary.415 416 The EPA notes that
this successful acquisition of right-of-way easements for thousands of
miles of pipeline across five states has taken place in just the three
years since the project launched in 2021.\417\ In addition, the
Citronelle Project, which was constructed in Alabama in 2011,
successfully acquired rights-of-way through 9 miles of forested and
commercial timber land and 3 miles of emergent shrub and forested
wetlands. The Citronelle Project was able to attain rights-of-way
through the habitat of an endangered species by mitigating potential
environmental
[[Page 39859]]
impacts.\418\ Even projects that require rights-of-way across multiple
ownership regimes including state, private, and federally owned land
have been successfully developed. The 170 km (105 mile) Cedar Creek
Anticline CO2 pipeline owned by Denbury required easements
for approximately 10 km (6.2 mi) to cross state school trust lands in
Montana, 27 km (17 mi) across Federal land and the remaining miles
across private lands.419 420 The pipeline was completed in
2021.\421\
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\414\ South Dakota Public Broadcasting. ``Summit reaches land
deals on more than half of CO2 pipeline route.'' (2022).
https://listen.sdpb.org/business-economics/2022-11-08/summit-reaches-land-deals-on-more-than-half-of-co2-pipeline-route.
\415\ Summit CEO: CO2 Pipeline's Time is Now. (2024). https://www.dtnpf.com/agriculture/web/ag/news/business-inputs/article/2024/02/23/summit-ceo-blank-says-company-toward.
\416\ Summit Carbon Solutions. Summit Carbon Solutions Signs 80
Percent of North Dakota Landowners. (2023). https://summitcarbonsolutions.com/summit-carbon-solutions-signs-80-percent-of-north-dakota-landowners/.
\417\ Summit Carbon Solutions. Summit Carbon Solutions Announces
Progress on Carbon Capture and Storage Project. (2022). https://summitcarbonsolutions.com/summit-carbon-solutions-announces-progress-on-carbon-capture-and-storage-project/.
\418\ SECARB. (2021). Final Project Report--SECARB Phase III,
September 2021. https://www.osti.gov/servlets/purl/1823250.
\419\ Great Falls Tribune. Texas company plans 110-mile
CO2 pipeline to enhance Montana oil recovery. (2018).
https://www.greatfallstribune.com/story/news/2018/10/09/texas-company-plans-co-2-pipeline-injection-free-montana-oil/1577657002/.
\420\ U.S. D.O.I B.L.M. Denbury-Green Pipeline-MT, LLC, Denbury
Onshore, LLC Cedar Creek Anticline CO2 Pipeline and EOR
Development Project Scoping Report. https://eplanning.blm.gov/public_projects/nepa/89883/137194/167548/BLM_Denbury_Projects_Scoping_Report_March2018.pdf.
\421\ AP News. Officials mark start of CO2 pipeline
used for oil recovery. (2022) https://apnews.com/article/business-texas-north-dakota-plano-25f1dbf9a924613a56827c1c83e4ba68.
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Federal actions (e.g., funding a CCS project) must generally comply
with NEPA, which often requires that an environmental assessment (EA)
or environmental impact statement (EIS) be conducted to consider
environmental impacts of the proposed action, including consideration
of reasonable alternatives.\422\ An EA determines whether or not a
Federal action has the potential to cause significant environmental
effects. Each Federal agency has adopted its own NEPA procedures for
the preparation of EAs.\423\ If the agency determines that the action
will not have significant environmental impacts, the agency will issue
a Finding of No Significant Impact (FONSI). Some projects may also be
``categorically excluded'' from a detailed environmental analysis when
the Federal action normally does not have a significant effect on the
human environment. Federal agencies prepare an EIS if a proposed
Federal action is determined to significantly affect the quality of the
human environment. The regulatory requirements for an EIS are more
detailed and rigorous than the requirements for an EA. The
determination of the level of NEPA review depends on the potential for
significant environmental impacts considering the whole project (e.g.,
crossings of sensitive habitats, cultural resources, wetlands, public
safety concerns). Consequently, whether a pipeline project is covered
by NEPA and the associated permitting timelines may vary depending on
site characteristics (e.g., pipeline length, whether a project crosses
a water of the U.S.) and funding source. Pipelines through Bureau of
Land Management (BLM) land, U.S. Forest Service (USFS) land, or other
Federal land would be subject to NEPA. To ensure that agencies conduct
NEPA reviews as efficiently and expeditiously as practicable, the
Fiscal Responsibility Act \424\ amendments to NEPA established
deadlines for the preparation of environmental assessments and
environmental impact statements. Environmental assessments must be
completed within 1 year and environmental impact statements must be
completed within 2 years \425\ A lead agency that determines it is not
able to meet the deadline may extend the deadline, in consultation with
the applicant, to establish a new deadline that provides only so much
additional time as is necessary to complete such environmental impact
statement or environmental assessment.\426\
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\422\ Council on Environmental Quality. (2024). CEQ NEPA
Regulations. https://ceq.doe.gov/laws-regulations/regulations.html.
\423\ Council of Environmental Quality. (2023). Agency NEPA
Implementing Procedures. https://ceq.doe.gov/laws-regulations/agency_implementing_procedures.html.
\424\ Public Law 118-5 (June 3, 2023).
\425\ NEPA Sec. 107(g)(1); 42 U.S.C. 4336a(g)(1).
\426\ NEPA sec. 107(g)(2); 42 U.S.C. 4336a(g)(2).
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As discussed above, it is anticipated that most EGUs would need
shorter, intrastate pipeline segments. For example, ADM's Decatur,
Illinois, pipeline, which spans 1.9 km (1.18 miles), was constructed
after Decatur was selected for the DOE Phase 1 research and development
grants in October 2009.\427\ Construction of the CO2
compression, dehydration, and pipeline facilities began in July 2011
and was completed in June 2013.\428\ The ADM project required only an
EA. Additionally, Air Products operates a large-scale system to capture
CO2 from two steam methane reformers located within the
Valero Refinery in Port Arthur, Texas. The recovered and purified
CO2 is delivered by pipeline for use in enhanced oil
recovery operations.\429\ This 12-mile pipeline required only an
EA.\430\ Conversely, the Petra Nova project in Texas required an EIS to
evaluate the potential environmental impacts associated with DOE's
proposed action of providing financial assistance for the project. This
EIS addressed potential impacts from both the associated 131 km (81
mile) pipeline and other aspects of the larger CCS system, including
the post-combustion CO2.\431\ For Petra Nova, a notice of
intent to issue an EIS was published on November 14, 2011, and the
record of decision was issued less than 2 years later, on May 23,
2013.\432\ Construction of the CO2 pipeline for Petra Nova
from the W.A. Parish Power Plant to the West Ranch Oilfield in Jackson
County, TX began in July 2014 and was completed in July 2016.\433\
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\427\ Massachusetts Institute of Technology. (2014). Decatur
Fact Sheet: Carbon Dioxide Capture and Storage Project. https://sequestration.mit.edu/tools/projects/decatur.html.
\428\ NETL. ``CO2 Capture from Biofuels Production and
Sequestration into the Mt. Simon Sandstone.'' Award #DE-FE0001547.
https://www.usaspending.gov/award/ASST_NON_DEFE0001547_8900.
\429\ Air Products. Carbon Capture. https://www.airproducts.com/company/innovation/carbon-capture.
\430\ Department of Energy. (2011). Final Environmental
Assessment for Air Products and Chemicals, Inc. Recovery Act:
Demonstration of CO2 Capture and Sequestration of Steam
Methane Reforming Process Gas Used for Large Scale Hydrogen
Production. https://netl.doe.gov/sites/default/files/environmental-assessments/20110622_APCI_PtA_CO2_FEA.pdf.
\431\ Department of Energy, Office of NEPA Policy and
Compliance. (2013). EIS-0473: Record of Decision. https://www.energy.gov/nepa/articles/eis-0473-record-decision.
\432\ Department of Energy. (2017). Petra Nova W.A. Parish
Project. https://www.energy.gov/fecm/petra-nova-wa-parish-project.
\433\ Kennedy, Greg. (2020). ``W.A. Parish Post Combustion
CO2 Capture and Sequestration Demonstration Project.''
Final Technical Report. https://www.osti.gov/biblio/1608572/.
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Compliance with section 7 of the Endangered Species Act related to
Federal agency consultation and biological assessment is also required
for projects on Federal lands. Specifically, the Endangered Species Act
requires consultation with the Department of Interior's Fish and
Wildlife Service and Department of Commerce's NOAA Fisheries, in order
to avoid or mitigate impacts to any threatened or endangered species
and their habitats.\434\ This agency consultation process and
biological assessment are generally conducted during preparation of the
NEPA documentation (EIS or EA) for the Federal project and generally
within the regulatory timeframes for environmental assessment or
environmental impact statement preparation. Consequently, the EPA does
not anticipate that compliance with the Endangered Species Act will
change the anticipated timeline for most projects.
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\434\ CEQ. (2021). ``Council on Environmental Quality Report to
Congress on Carbon Capture, Utilization, and Sequestration.''
https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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The EPA notes that the Fixing America's Surface Transportation Act
(FAST Act) is also relevant to CCS projects and pipelines. Title 41 of
this Act (42 U.S.C. 4370m et seq.), referred to as ``FAST-41,'' created
a new
[[Page 39860]]
governance structure, set of procedures, and funding authorities to
improve the Federal environmental review and authorization process for
covered infrastructure projects.\435\ The Utilizing Significant
Emissions with Innovative Technologies (USE IT) Act, among other
actions, clarified that CCS projects and CO2 pipelines are
eligible for this more predictable and transparent review process.\436\
FAST-41 created the Federal Permitting Improvement Steering Council
(Permitting Council), composed of agency Deputy Secretary-level members
and chaired by an Executive Director appointed by the President. FAST-
41 establishes procedures that standardize interagency consultation and
coordination practices. FAST-41 codifies into law the use of the
Permitting Dashboard \437\ to track project timelines, including
qualifying actions that must be taken by the EPA and other Federal
agencies. Project sponsor participation in FAST-41 is voluntary.\438\
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\435\ Federal Permitting Improvement Steering Council. (2022).
FAST-41 Fact Sheet. https://www.permits.performance.gov/documentation/fast-41-fact-sheet.
\436\ Galford, Chris. USE IT carbon capture bill becomes law,
incentivizing development and deployment. (2020). https://dailyenergyinsider.com/news/28522-use-it-carbon-capture-bill-becomes-law-incentivizing-development-and-deployment/.
\437\ Permitting Dashboard Federal Infrastructure Projects.
https://permits.performance.gov/.
\438\ EPA. ``FAST-41 Coordination.'' (2023). https://www.epa.gov/sustainability/fast-41-coordination.
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Community engagement also plays a role in the safe operation and
construction of CO2 pipelines. These efforts can be
supported using the CCS Pipeline Route Planning Database that was
developed by NETL, a public resource designed to support pipeline
routing decisions and increase transportation safety.\439\ The database
includes state-specific regulations and restrictions, energy and social
justice factors, land use requirements, existing infrastructure, and
areas of potential risk. The database produces weighted values ranging
from zero to one, where zero represents acceptable areas for pipeline
placement and one represents areas that should be avoided.\440\ The
database will be a key input for the CCS Pipeline Route Planning Tool
under development by NETL.\441\ The purpose of the siting tool is to
aid pipeline routing decisions and facilitate avoidance of areas that
would pose permitting challenges.
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\439\ ``CCS Pipeline Route Planning Database V1--EDX.'' https://edx.netl.doe.gov/dataset/ccs-pipeline-route-planning-database-v1.
\440\ ``CCS Pipeline Route Planning Database V1--EDX.'' https://edx.netl.doe.gov/dataset/ccs-pipeline-route-planning-database-v1.
\441\ Department of Energy. ``CCS Pipeline Route Planning
Database V1--EDX.'' https://edx.netl.doe.gov/dataset/ccs-pipeline-route-planning-database-v1.
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In sum, the permitting process for CO2 pipelines often
involves private, local, state, tribal, and/or Federal agencies, and
permitting timelines may vary depending on site characteristics.
Projects that opt in to the FAST-41 process are eligible for a more
transparent and predictable review process. EGUs can generally proceed
to obtain permits and rights-of-way simultaneously, and the EPA
anticipates that, in total, the permitting process would only take
around 2.5 years for pipelines that only need an EA, with a possible
additional year if the project requires an EIS (see the final TSD, GHG
Mitigation Measures for Steam Generating Units for additional
information). This is consistent with the anticipated timelines for CCS
discussed in section VII.C.1.a.i(E). Furthermore, the EPA notes that
there is over 60 years of experience in the CO2 pipeline
industry designing, permitting, building and operating CO2
pipelines, and that this expertise can be applied to the CO2
pipelines that would be constructed to connect to sequestration sites
and units.
As discussed above in section VII.C.1.a.i.(C)(1)(a), the core of
the EPA's analysis of pipeline feasibility focuses on units located
within 100 km (62 miles) of potential deep saline sequestration
formations. The EPA notes that the majority (80 percent) of the coal-
fired steam generating capacity with planned operation during or after
2039 is located within 100 km (62 miles) of the nearest potential deep
saline sequestration site. For these sources, as explained, units would
be required only to build relatively short pipelines, and such buildout
would be feasible within the required timeframe. For the capacity that
is more than 100 km (62 miles) away from sequestration, building a
pipeline may become more complex. Almost all (98 percent) of this
capacity's closest sequestration site is located outside state
boundaries, and access to the nearest sequestration site would require
building an interstate pipeline and coordinating with multiple state
authorities for permitting purposes. Conversely, for capacity where the
distance to the nearest potential sequestration site is less than 100
km (62 miles), only about 19 percent would require the associated
pipeline to cross state boundaries. Therefore, the EPA believes that
distance to the nearest sequestration site is a useful proxy for
considerations related to the complexity of pipeline construction and
how long it will take to build a pipeline.
A unit that is located more than 100 km away from sequestration may
face complexities in pipeline construction, including additional
permitting hurdles, difficulties in obtaining the necessary rights of
way over such a distance, or other considerations, that may make it
unreasonable for that unit to meet the compliance schedule that is
generally reasonable for sources in the subcategory as a whole.
Pursuant to the RULOF provisions of 40 CFR 60.2a(e)-(h), if a state can
demonstrate that there is a fundamental difference between the
information relevant to a particular affected EGU and the information
the EPA considered in determining the compliance deadline for sources
in the long-term subcategory, and that this difference makes it
unreasonable for the EGU to meet the compliance deadline, a longer
compliance schedule may be warranted. The EPA does not believe that the
fact that a pipeline crosses state boundaries standing alone is
sufficient to show that an extended timeframe would be appropriate--
many such pipelines could be reasonably accomplished in the required
timeframe. Rather, it is the confluence of factors, including that a
pipeline crosses state boundaries, along with others that may make
RULOF appropriate.
(3) Security of CO2 Transport
As part of its analysis, the EPA also considered the safety of
CO2 pipelines. The safety of existing and new CO2
pipelines that transport CO2 in a supercritical state is
regulated by PHMSA. These regulations include standards related to
pipeline design, pipeline construction and testing, pipeline operations
and maintenance, operator reporting requirements, operator
qualifications, corrosion control and pipeline integrity management,
incident reporting and response, and public awareness and
communications. PHMSA has regulatory authority to conduct inspections
of supercritical CO2 pipeline operations and issue notices
to operators in the event of operator noncompliance with regulatory
requirements.\442\
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\442\ See generally 49 CFR 190-199.
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CO2 pipelines have been operating safely for more than
60 years. In the past 20 years, 500 million metric tons of
CO2 moved through over 5,000 miles of CO2
pipelines with zero incidents involving fatalities.\443\ PHMSA reported
a total of
[[Page 39861]]
102 CO2 pipeline incidents between 2003 and 2022, with one
injury (requiring in-patient hospitalization) and zero fatalities.\444\
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\443\ Congressional Research Service. 2022. Carbon Dioxide
Pipelines: Safety Issues, CRS Reports, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
\444\ NARUC. (2023). Onshore U.S. Carbon Pipeline Deployment:
Siting, Safety. and Regulation. Prepared by Public Sector
Consultants for the National Association of Regulatory Utility
Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
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As noted previously in this preamble, a significant CO2
pipeline rupture occurred in 2020 in Satartia, Mississippi, following
heavy rains that resulted in a landslide. Although no one required in-
patient hospitalization as a result of this incident, 45 people
received treatment at local emergency rooms after the incident and 200
hundred residents were evacuated. Typically, when CO2 is
released into the open air, it vaporizes into a heavier-than-air gas
and dissipates. During the Satartia incident, however, unique
atmospheric conditions and the topographical features of the area
delayed this dissipation. As a result, residents were exposed to high
concentrations of CO2 in the air after the rupture.
Furthermore, local emergency responders were not informed by the
operator of the rupture and the nature of the unique safety risks of
the CO2 pipeline.\445\
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\445\ Failure Investigation Report--Denbury Gulf Coast Pipeline,
May 2022. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2022-05/Failure%20Investigation%20Report%20-%20Denbury%20Gulf%20Coast%20Pipeline.pdf.
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PHMSA initiated a rulemaking in 2022 to develop and implement new
measures to strengthen its safety oversight of supercritical
CO2 pipelines following the investigation into the
CO2 pipeline failure in Satartia.\446\ PHMSA submitted the
associated Notice of Proposed Rulemaking to the White House Office of
Management and Budget on February 1, 2024 for pre-publication
review.\447\ Following the Satartia incident, PHMSA also issued a
Notice of Probable Violation, Proposed Civil Penalty, and Proposed
Compliance Order (Notice) to the operator related to probable
violations of Federal pipeline safety regulations. The Notice was
ultimately resolved through a Consent Agreement between PHMSA and the
operator that includes the assessment of civil penalties and identifies
actions for the operator to take to address the alleged violations and
risk conditions.\448\ PHMSA has further issued an updated nationwide
advisory bulletin to all pipeline operators and solicited research
proposals to strengthen CO2 pipeline safety.\449\ Given the
Federal and state regulation of CO2 pipelines and the steps
that PHMSA is taking to further improve pipeline safety, the EPA
believes CO2 can be safely transported by pipeline.
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\446\ PHMSA. (2022). ``PHMSA Announces New Safety Measures to
Protect Americans From Carbon Dioxide Pipeline Failures After
Satartia, MS Leak.'' https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
\447\ Columbia Law School. (2024). PHMSA Advances CO2 Pipeline
Safety Regulations. https://climate.law.columbia.edu/content/phmsa-advances-co2-pipeline-safety-regulations.
\448\ Department of Transportation. (2023). Consent Order,
Denbury Gulf Coast Pipelines, LLC, CPF No. 4-2022-017-NOPV https://primis.phmsa.dot.gov/comm/reports/enforce/CaseDetail_cpf_42022017NOPV.html?nocache=7208.
\449\ Ibid.
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Certain states have authority delegated from the U.S. Department of
Transportation to conduct safety inspections and enforce state and
Federal pipeline safety regulations for intrastate CO2
pipelines.450 451 452 PHMSA's state partners employ about 70
percent of all pipeline inspectors, which covers more than 80 percent
of regulated pipelines.\453\ Federal law requires certified state
authorities to adopt safety standards at least as stringent as the
Federal standards.\454\ Further, there are required steps that
CO2 pipeline operators must take to ensure pipelines are
operated safely under PHMSA standards and related state standards, such
as the use of pressure monitors to detect leaks or initiate shut-off
valves, and annual reporting on operations, structural integrity
assessments, and inspections.\455\ These CO2 pipeline
controls and PHMSA standards are designed to ensure that captured
CO2 will be securely conveyed to a sequestration site.
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\450\ New Mexico Public Regulation Commission. 2023.
Transportation Pipeline Safety. New Mexico Public Regulation
Commission, Bureau of Pipeline Safety. https://www.nm-prc.org/transportation/pipeline-safety.
\451\ Texas Railroad Commission. 2023. Oversight & Safety
Division. Texas Railroad Commission. https://www.rrc.texas.gov/about-us/organization-and-activities/rrc-divisions/oversight-safety-division.
\452\ NARUC. (2023). Onshore U.S. Carbon Pipeline Deployment:
Siting, Safety. and Regulation. Prepared by Public Sector
Consultants for the National Association of Regulatory Utility
Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\453\ PHMSA. (2023). ``PHMSA Issues Letters to Wolf Carbon,
Summit, and Navigator Clarifying Federal, State, and Local
Government Pipeline Authorities.'' https://www.phmsa.dot.gov/news/phmsa-issues-letters-wolf-carbon-summit-and-navigator-clarifying-federal-state-and-local.
\454\ PHMSA, ``PHMSA Issues Letters to Wolf Carbon, Summit, and
Navigator Clarifying Federal, State, and Local Government Pipeline
Authorities.'' 2023. https://www.phmsa.dot.gov/news/phmsa-issues-letters-wolf-carbon-summit-and-navigator-clarifying-federal-state-and-local.
\455\ Carbon Capture Coalition. ``PHMSA/Pipeline Safety Fact
Sheet,'' November 2023. https://carboncapturecoalition.org/wp-content/uploads/2023/11/Pipeline-Safety-Fact-Sheet.pdf.
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(4) Comments Received on CO2 Transport and Responses
The EPA received comments on CO2 transport, including
CO2 pipelines. Those comments, and the EPA's responses, are
as follows.
Comment: Some commenters identified challenges to the deployment of
a national, interstate CO2 pipeline network. In particular,
those commenters discussed the experience faced by long (e.g., over
1,000 miles) CO2 pipelines seeking permitting and right-of-
way access in Midwest states including Iowa and North Dakota.
Commenters claimed those challenges make CCS as BSER infeasible. Some
commenters argued that the existing CO2 pipeline capacity is
not adequate to meet potential demand caused by this rule and that the
ability of the network to grow and meet future potential demand is
hindered by significant public opposition.
Response: The EPA acknowledges the challenges that some large
multi-state pipeline projects have faced, but does not agree that those
experiences show that the BSER is not adequately demonstrated or that
the standards finalized in these actions are not achievable. As
detailed in the preceding subsections of the preamble, the BSER is not
premised on the buildout of a national, trunkline CO2
pipeline network. Most coal-fired steam generating units are in
relatively close proximity to geologic storage, and those shorter
pipelines would not likely be as challenging to permit and build as
demonstrated by the examples of smaller pipeline discussed above.
The EPA acknowledges that some larger trunkline CO2
pipeline projects, specifically the Heartland Greenway project, have
recently been delayed or canceled. However, many projects are still
moving forward and several major projects have recently been announced
to expand the CO2 pipeline network across the United States.
The EPA notes that there are often opportunities to reroute pipelines
to minimize permitting challenges and landowner concerns. For example,
Summit Carbon Solutions changed their planned pipeline route in North
Dakota after their initial permit was denied, leading to successful
acquisition of rights of way.\456\ Additionally, Tallgrass, which
[[Page 39862]]
is planning to convert a 630 km (392 mile) natural gas pipeline to
carry CO2, announced that they had reach a community
benefits agreement, in which certain organizations have agreed not to
oppose the pipeline project while Tallgrass has agreed to terms such as
contributing funds to first responders along the pipeline route and
providing royalty checks to landowners.\457\ See section
VII.C.1.a.i(C)(1)(d) for additional discussion of planned
CO2 pipelines. While access to larger trunkline projects
would not be required for most EGUs, at least some larger trunkline
projects are likely to be constructed, which would increase
opportunities for connecting to pipeline networks.
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\456\ Summit Carbon Solutions. Summit Carbon Solutions Signs 80
Percent of North Dakota Landowners. (2023). https://summitcarbonsolutions.com/summit-carbon-solutions-signs-80-percent-of-north-dakota-landowners/.
\457\ Hammel, Paul. (2024). Pipeline company, Nebraska
environmental group strike unique `community benefits' agreement.
https://www.desmoinesregister.com/story/tech/science/environment/2024/04/11/nebraska-environmentalist-forge-peace-pact-with-pipeline-company/73282852007/.
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Comment: Some commenters disagreed with the modeling assumption
that 100 km is a typical pipeline distance. The commenters asserted
that there is data showing the actual locations of the power plants
affected by the rule, and the required pipeline distance is not always
100 km.
Response: The EPA acknowledges that the physical locations of EGUs
and the physical locations of carbon sequestration capacity and
corresponding pipeline distance will not be 100 km in all cases. As
discussed previously in section VII.C.1.a.i(C)(1)(a), the EPA modeled
the unique approximate distance from each existing coal-fired steam
generating capacity with planned operation during or after 2039 to the
nearest potential saline sequestration site, and found that the
majority (80 percent) is within 100 km (62 miles) of potential saline
sequestration sites, and another 11 percent is within 160 km (100
miles).\458\ Furthermore, the EPA disagrees with the comments
suggesting that the use of 100 km is an inappropriate economic modeling
assumption. The 100 km assumption was not meant to encompass the
physical location of every potentially affected EGU. The 100 km
assumption is intended as an economic modeling assumption and is based
on similar assumptions applied in NETL studies used to estimate
CO2 transport costs. The EPA carefully reviewed the
assumptions on which the NETL transport cost estimates are based and
continues to find them reasonable. The NETL studies referenced in
section VII.C.1.a.ii based transport costs on a generic 100 km (62
mile) pipeline and a generic 80 km pipeline.\459\ For most EGUs, the
necessary pipeline distance is anticipated to be less than 100 km and
therefore the associated costs could also be lower than these
assumptions. Other published economic models applying different
assumptions have also reached the conclusion that CO2
transport and sequestration are adequately demonstrated.\460\
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\458\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\459\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
\460\ Ogland-Hand, Jonathan D. et. al. 2022. Screening for
Geologic Sequestration of CO2: A Comparison Between SCO2TPRO and the
FE/NETL CO2 Saline Storage Cost Model. International Journal of
Greenhouse Gas Control, Volume 114, February 2022, 103557. https://www.sciencedirect.com/science/article/pii/S175058362100308X.
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Comment: Commenters also stated that the permitting and
construction processes can be time-consuming.
Response: The EPA acknowledges building CO2 pipelines
requires capital expenditure and acknowledges that the timeline for
siting, engineering design, permitting, and construction of
CO2 pipelines depends on factors including the pipeline
capacity and pipeline length, whether the pipeline route is intrastate
or interstate, and the specifics of the state pipeline regulator's
regulatory requirements. In the BSER analysis, individual EGUs that are
subject to carbon capture requirements are assumed to take a point-to-
point approach to CO2 transport and sequestration. These
smaller-scale projects require less capital and may present less
complexity than larger projects. The EPA considers the timeline to
permit and install such pipelines in section VII.C.1.a.i(E) of the
preamble, and has determined that a compliance date of January 1, 2032
allows for a sufficient amount of time.
Comment: Some commenters expressed significant concerns about the
safety of CO2 pipelines following the CO2
pipeline failure in Satartia, Mississippi in 2020.
Response: For a discussion of the safety of CO2
pipelines and the Satartia pipeline failure, see section
VII.C.1.a.i(C)(3). The EPA believes that the framework of Federal and
state regulation of CO2 pipelines and the steps that PHMSA
is taking to further improve pipeline safety, is sufficient to ensure
CO2 can be safely transported by pipeline.
(D) Geologic Sequestration of CO2
The EPA is finalizing its determination that geologic sequestration
(i.e., the long-term containment of a CO2 stream in
subsurface geologic formations) is adequately demonstrated. In this
section, we provide an overview of the availability of sequestration
sites in the U.S., discuss how geologic sequestration of CO2
is well proven and broadly available throughout the U.S, explain the
effectiveness of sequestration, discuss the regulatory framework for
UIC wells, and discuss the timing of permitting for sequestration
sites. We then provide a summary of key comments received concerning
geologic sequestration and our responses to those comments.
(1) Sequestration Sites for Coal-Fired Power Plants Subject to CCS
Requirements
(a) Broad Availability of Sequestration
Sequestration is broadly available in the United States, which
makes clear that it is adequately demonstrated. By far the most widely
available and well understood type of sequestration is that in deep
saline formations. These formations are common in the U.S. These
formations are numerous and only a small subset of the existing saline
storage capacity would be required to store the CO2 from
EGUs. Many projects are in the process of completing thorough
subsurface studies of these deep saline formations to determine their
suitability for regional-scale storage. Furthermore, sequestration
formations could also include unmineable coal seams and oil and gas
reservoirs. CO2 may be stored in oil and gas reservoirs in
association with EOR and enhanced gas recovery (EGR) technologies,
collectively referred to as enhanced recovery (ER), which include the
injection of CO2 in oil and gas reservoirs to increase
production. ER is a technology that has been used for decades in states
across the U.S.\461\
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\461\ NETL. (2010). Carbon Dioxide Enhanced Oil Recovery.
https://www.netl.doe.gov/sites/default/files/netl-file/co2_eor_primer.pdf.
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Geologic sequestration is based on a demonstrated understanding of
the trapping and containment processes that retain CO2 in
the subsurface. The presence of a low permeability seal is an important
component of demonstrating secure geologic sequestration. Analyses of
the potential availability of geologic sequestration capacity in the
United States have been conducted by DOE,
[[Page 39863]]
and the U.S. Geological Survey (USGS) has also undertaken a
comprehensive assessment of geologic sequestration resources in the
United States.462 463 Geologic sequestration potential for
CO2 is widespread and available throughout the United
States. Nearly every state in the United States has or is in close
proximity to formations with geologic sequestration potential,
including areas offshore. There have been numerous efforts
demonstrating successful geologic sequestration projects in the United
States and overseas, and the United States has developed a detailed set
of regulatory requirements to ensure the security of sequestered
CO2. Moreover, the amount of storage potential can readily
accommodate the amount of CO2 for which sequestration could
be expected under this final rule.
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\462\ U.S. DOE NETL. (2015). Carbon Storage Atlas, Fifth
Edition, September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
\463\ U.S. Geological Survey Geologic Carbon Dioxide Storage
Resources Assessment Team. (2013). National assessment of geologic
carbon dioxide storage resources--Summary: U.S. Geological Survey
Factsheet 2013-3020. http://pubs.usgs.gov/fs/2013/3020/.
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The EPA has performed a geographic availability analysis in which
the Agency examined areas of the U.S. with sequestration potential in
deep saline formations, unmineable coal seams, and oil and gas
reservoirs; information on existing and probable, planned or under
study CO2 pipelines; and areas within a 100 km (62-mile)
area of potential sequestration sites. This availability analysis is
based on resources from the DOE, the USGS, and the EPA. The distance of
100 km is consistent with the assumptions underlying the NETL cost
estimates for transporting CO2 by pipeline. The scoping
assessment by the EPA found that at least 37 states have geologic
characteristics that are amenable to deep saline sequestration, and an
additional 6 states are within 100 kilometers of potentially amenable
deep saline formations in either onshore or offshore locations. Of the
7 states that are further than 100 km (62 mi) of onshore or offshore
storage potential in deep saline formations, only New Hampshire has
coal EGUs that were assumed to be in operation after 2039, with a total
capacity of 534 MW. However, the EPA notes that as of March 27, 2024,
the last coal-fired steam EGUs in New Hampshire announced that they
would cease operation by 2028.\464\ Therefore, the EPA anticipates that
there will no existing coal-fired steam EGUs located in states that are
further than 100 km (62 mi) of potential geologic sequestration sites.
Furthermore, as described in section VII.C.1.a.i(C), new EGUs would
have the ability to consider proximity and access to geologic
sequestration sites or CO2 pipelines in the siting process.
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\464\ Vickers, Clayton. (2024). ``Last coal plants in New
England to close; renewables take their place.'' https://thehill.com/policy/energy-environment/4560375-new-hampshire-coal-plants-closing/.
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The DOE and the United States Geological Survey (USGS) have
independently conducted preliminary analyses of the availability and
potential CO2 sequestration resources in the United States.
The DOE estimates are compiled in the DOE's National Carbon
Sequestration Database and Geographic Information System (NATCARB)
using volumetric models and are published in its Carbon Utilization and
Sequestration Atlas (NETL Atlas). The DOE estimates that areas of the
United States with appropriate geology have a sequestration potential
of at least 2,400 billion to over 21,000 billion metric tons of
CO2 in deep saline formations, unmineable coal seams, and
oil and gas reservoirs. The USGS assessment estimates a mean of 3,000
billion metric tons of subsurface CO2 sequestration
potential across the United States. With respect to deep saline
formations, the DOE estimates a sequestration potential of at least
2,200 billion metric tons of CO2 in these formations in the
United States. The EPA estimates that the CO2 emissions
reductions for this rule (which is similar to the amount of
CO2 may be sequestered under this rule) are estimated in the
range of 1.3 to 1.4 billion metric tons over the 2028 to 2047
timeframe.\465\ This volume of sequestered CO2 is less than
a tenth of a percent of the storage capacity in deep saline formations
estimated to be available by DOE.
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\465\ For detailed information on the estimated emissions
reductions from this rule, see section 3 of the RIA, available in
the rulemaking docket.
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Unmineable coal seams offer another potential option for geologic
sequestration of CO2. Enhanced coalbed methane recovery is
the process of injecting and storing CO2 in unmineable coal
seams to enhance methane recovery. These operations take advantage of
the preferential chemical affinity of coal for CO2 relative
to the methane that is naturally found on the surfaces of coal. When
CO2 is injected, it is adsorbed to the coal surface and
releases methane that can then be captured and produced. This process
effectively ``locks'' the CO2 to the coal, where it remains
stored. States with the potential for sequestration in unmineable coal
seams include Iowa and Missouri, which have little to no saline
sequestration potential and have existing coal-fired EGUs. Unmineable
coal seams have a sequestration potential of at least 54 billion metric
tons of CO2, or 2 percent of total potential in the United
States, and are located in 22 states.
The potential for CO2 sequestration in unmineable coal
seams has been demonstrated in small-scale demonstration projects,
including the Allison Unit pilot project in New Mexico, which injected
a total of 270,000 tons of CO2 over a 6-year period (1995-
2001). Further, DOE Regional Carbon Sequestration Partnership projects
have injected CO2 volumes in unmineable coal seams ranging
from 90 tons to 16,700 tons, and completed site characterization,
injection, and post-injection monitoring for sites. DOE has included
unmineable coal seams in the NETL Atlas. One study estimated that in
the United States, 86.16 billion tons of CO2 could be
permanently stored in unmineable coal seams.\466\ Although the large-
scale injection of CO2 in coal seams can lead to swelling of
coal, the literature also suggests that there are available
technologies and techniques to compensate for the resulting reduction
in injectivity. Further, the reduced injectivity can be anticipated and
accommodated in sizing and characterizing prospective sequestration
sites.
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\466\ Godec, Koperna, and Gale. (2014). ``CO2-ECBM: A
Review of its Status and Global Potential'', Energy Procedia, Volume
63. https://doi.org/10.1016/j.egypro.2014.11.619.
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Depleted oil and gas reservoirs present additional potential for
geologic sequestration. The reservoir characteristics of developed
fields are well known as a result of exploration and many years of
hydrocarbon production and, in many areas, infrastructure already
exists which could be evaluated for conversion to CO2
transportation and sequestration service. Other types of geologic
formations such as organic rich shale and basalt may also have the
ability to store CO2, and DOE is continuing to evaluate
their potential sequestration capacity and efficacy.
(b) Inventory of Coal-Fired Power Plants That Are Candidates for CCS
Sequestration potential as it relates to distance from existing
coal-fired steam generating units is a key part of the EPA's regular
power sector modeling, using data from DOE/NETL studies.\467\ As
discussed in section VII.C.1.a.i(D)(1)(a), the availability
[[Page 39864]]
analysis shows that of the coal-fired steam generating capacity with
planned operation during or after 2039, more than 50 percent is less
than 32 km (20 miles) from potential deep saline sequestration sites,
73 percent is located within 50 km (31 miles), 80 percent is located
within 100 km (62 miles), and 91 percent is within 160 km (100
miles).\468\
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\467\ For details, please see Chapter 6 of the IPM
documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
\468\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
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(2) Geologic Sequestration of CO2 Is Adequately Demonstrated
Geologic sequestration is based on a demonstrated understanding of
the processes that affect the fate of CO2 in the subsurface.
Existing project and regulatory experience, along with other
information, indicate that geologic sequestration is a viable long-term
CO2 sequestration option. As discussed in this section,
there are many examples of projects successfully injecting and
containing CO2 in the subsurface.
Research conducted through the Department of Energy's Regional
Carbon Sequestration Partnerships has demonstrated geologic
sequestration through a series of field research projects that
increased in scale over time, injecting more than 12 million tons of
CO2 with no indications of negative impacts to either human
health or the environment.\469\ Building on this experience, DOE
launched the Carbon Storage Assurance Facility Enterprise (CarbonSAFE)
Initiative in 2016 to demonstrate how knowledge from the Regional
Carbon Sequestration Partnerships can be applied to commercial-scale
safe storage. This initiative is furthering the development and
refinement of technologies and techniques critical to the
characterization of sites with the potential to sequester greater than
50 million tons of CO2.\470\ In Phase I of CarbonSAFE,
thirteen projects conducted economic feasibility analyses, collected,
analyzed, and modeled extensive regional data, evaluated multiple
storage sites and infrastructure, and evaluated business plans. Six
projects were funded for Phase II which involves storage complex
feasibility studies. These projects evaluate initial reservoir
characteristics to determine if the reservoir is suitable for geologic
sequestration sites of more than 50 million tons of CO2,
address technical and non-technical challenges that may arise, develop
a risk assessment and CO2 management strategy for the
project; and assist with the validation of existing tools. Five
projects have been funded for CarbonSAFE Phase III and are currently
performing site characterization and permitting.
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\469\ Regional Sequestration Partnership Overview. https://netl.doe.gov/carbon-management/carbon-storage/RCSP.
\470\ National Energy Technology Laboratory. CarbonSAFE
Initiative. https://netl.doe.gov/carbon-management/carbon-storage/carbonsafe.
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The EPA notes that, while only sequestration facilities with
Federal funding are currently operational in the United States,
multiple commercial sequestration facilities, other than those funded
under EPAct05, are in construction or advanced development, with some
scheduled to open for operation as early as 2025.\471\ These facilities
have proposed sequestration capacities ranging from 0.03 to 6 million
tons of CO2 per year. The Great Plains Synfuel Plant
currently captures 2 million metric tons of CO2 per year,
which is exported to Canada for use in EOR; a planned addition of
sequestration in a saline formation for this facility is expected to
increase the amount of CO2 captured and sequestered (through
both geologic sequestration and EOR) to 3.5 million metric tons of
CO2 per year.\472\ The EPA and states with approved UIC
Class VI programs (including Wyoming, North Dakota, and Louisiana) are
currently reviewing UIC Class VI geologic sequestration well permit
applications for proposed sequestration sites in fourteen
states.473 474 475 As of March 15, 2024, 44 projects with
130 injection wells are under review by the EPA.\476\
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\471\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\472\ Basin Electric Power Cooperative. (2021). ``Great Plains
Synfuels Plant Potential to Be Largest Coal-Based Carbon Capture and
Storage Project to Use Geologic Storage''. https://www.basinelectric.com/News-Center/news-releases/Great-Plains-Synfuels-Plant-potential-to-be-largest-coal-based-carbon-capture-and-storage-project-to-use-geologic-storage.
\473\ UIC regulations for Class VI wells authorize the injection
of CO2 for geologic sequestration while protecting human
health by ensuring the protection of underground sources of drinking
water. The major components to be included in UIC Class VI permits
are detailed further in section VII.C.1.a.i(D)(4).
\474\ U.S. EPA Class VI Underground Injection Control (UIC)
Class VI Wells Permitted by EPA as of January 25, 2024. https://www.epa.gov/uic/table-epas-draft-and-final-class-vi-well-permits
Last updated January 19, 2024.
\475\ U.S. EPA Current Class VI Projects under Review at EPA.
2024. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
\476\ U.S. EPA. Current Class VI Projects under Review at EPA.
2024. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
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Currently, there are planned geologic sequestration facilities
across the United States in various phases of development,
construction, and operation. The Wyoming Department of Environmental
Quality issued three UIC Class VI permits in December 2023 to Frontier
Carbon Solutions. The Frontier Carbon Solutions project will sequester
5 million metric tons of CO2/year.\477\ Additionally, UIC
Class VI permit applications have been submitted to the Wyoming
Department of Environmental Quality for a proposed Eastern Wyoming
Sequestration Hub project that would sequester up to 3 million metric
tons of CO2/year.\478\ The North Dakota Oil and Gas Division
has issued UIC Class VI permits to 6 sequestration projects that
collectively will sequester 18 million metric tons of CO2/
year.\479\ Since 2014, the EPA has issued two UIC Class VI permits to
Archer Daniels Midland (ADM) in Decatur, Illinois, which authorize the
injection of up to 7 million metric tons of CO2. One of the
AMD wells is in the injection phase while the other is in the post-
injection phase. In January 2024, the EPA issued two UIC Class VI
permits to Wabash Carbon Services LLC for a project that will sequester
up to 1.67 million metric tons of CO2/year over an injection
period of 12 years.\480\ In December 2023, the EPA released for public
comment four UIC Class VI draft permits for the Carbon TerraVault
projects, to be located in California.\481\ These projects propose to
sequester CO2 captured from multiple different sources in
California including a hydrogen plant, direct air capture, and pre-
combustion gas treatment. TerraVault plans to inject 1.46 million
metric tons of CO2 annually into the four proposed wells
over a 26-year injection period with a total potential capacity of 191
million metric tons.482 483 One of the proposed wells is
[[Page 39865]]
an existing UIC Class II well that would be converted to a UIC Class VI
well for the TerraVault project.\484\
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\477\ Wyoming DEQ, Water Quality. Wyoming grants its first three
Class VI permits. By Kimberly Mazza, December 14, 2023 https://deq.wyoming.gov/2023/12/wyoming-grants-its-first-three-class-vi-permits/.
\478\ Wyoming DEQ Class VI Permit Applications. Trailblazer
permit application. https://deq.wyoming.gov/water-quality/groundwater/uic/class-vi.
\479\ North Dakota Oil and Gas Division, Class VI--Geologic
Sequestration Wells. https://www.dmr.nd.gov/dmr/oilgas/ClassVI.
\480\ EPA Approves Permits to Begin Construction of Wabash
Carbon Services Underground Injection Wells in Indiana's Vermillion
and Vigo Counties. (2024) https://www.epa.gov/uic/epa-approves-permits-wabash-carbon-services-underground-injection-wells-indianas-vigo-and
\481\ U.S. EPA Current Class VI Projects under Review at EPA.
2024. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
\482\ U.S. EPA Class VI Permit Application. ``Intent to Issue
Four (4) Class VI Geologic Carbon Sequestration Underground
Injection Control (UIC) Permits for Carbon TerraVault JV Storage
Company Sub 1, LLC. EPA-R09-OW-2023-0623.'' https://www.epa.gov/publicnotices/intent-issue-class-vi-underground-injection-control-permits-carbon-terravault-jv.
\483\ California Resources Corporation. ``Carbon TerraVault
Potential Storage Capacity.''https://www.crc.com/carbon-terravault/Vaults/default.aspx.
\484\ U.S. EPA Class VI Permit Application. ``Intent to Issue
Four (4) Class VI Geologic Carbon Sequestration Underground
Injection Control (UIC) Permits for Carbon TerraVault JV Storage
Company Sub 1, LLC. EPA-R09-OW-2023-0623.
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Geologic sequestration has been proven to be successful and safe in
projects internationally. In Norway, facilities conduct offshore
sequestration under the Norwegian continental shelf.\485\ In addition,
the Sleipner CO2 Storage facility in the North Sea, which
began operations in 1996, injects around 1 million metric tons of
CO2 per year from natural gas processing.\486\ The Snohvit
CO2 Storage facility in the Barents Sea, which began
operations in 2008, injects around 0.7 million metric tons of
CO2 per year from natural gas processing. The SaskPower
carbon capture and sequestration facility at Boundary Dam Power Station
in Saskatchewan, Canada had, as of the end of 2023, captured 5.6
million metric tons of CO2 since it began operating in
2014.\487\ Other international sequestration facilities in operation
include Glacier Gas Plant MCCS (Canada),\488\ Quest (Canada), and Qatar
LNG CCS (Qatar). The CarbFix project in Iceland injects CO2
into a geologic formation in which the CO2 reacts with
basalt rock formations to form stone. The CarbFix project has injected
approximately 100,000 metric tons of CO2 into geologic
formations since 2014.\489\
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\485\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage. https://www.ipcc.ch/report/carbon-dioxide-capture-and-storage/.
\486\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\487\ BD3 Status Update: Q3 2023. https://www.saskpower.com/
about-us/our-company/blog/2023/bd3-status-update-q3-2023.
\488\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\489\ CarbFix Operations. (2024). https://www.carbfix.com/.
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EOR, the process of injecting CO2 into oil and gas
formations to extract additional oil and gas, has been successfully
used for decades at numerous production fields throughout the United
States to increase oil and gas recovery. The oil and gas industry in
the United States has nearly 60 years of experience with EOR.\490\ This
experience provides a strong foundation for demonstrating successful
CO2 injection and monitoring technologies, which are needed
for safe and secure geologic sequestration that can be used for
deployment of CCS across geographically diverse areas. The amount of
CO2 that can be injected for an EOR project and the duration
of operations are of similar magnitude to the duration and volume of
CO2 that is expected to be captured from fossil fuel-fired
EGUs. The Farnsworth Unit, the Camrick Unit, the Shute Creek Facility,
and the Core Energy CO2-EOR facility are all examples of
operations that store anthropogenic CO2 as a part of EOR
operations.491 492 Currently, 13 states have active EOR
operations, and these states also have areas that are amenable to deep
saline sequestration in either onshore or offshore locations.\493\
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\490\ NETL. (2010). Carbon Dioxide Enhanced Oil Recovery.
https://www.netl.doe.gov/sites/default/files/netl-file/co2_eor_primer.pdf.
\491\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\492\ Greenhouse Gas Reporting Program monitoring reports for
these facilities are available at https://www.epa.gov/ghgreporting/subpart-rr-geologic-sequestration-carbon-dioxide#decisions.
\493\ U.S. DOE NETL, Carbon Storage Atlas, Fifth Edition,
September 2015. https://www.netl.doe.gov/research/coal/carbon-storage/atlasv.
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(3) EPAct05-Assisted Geologic Sequestration Projects
Consistent with the EPA's legal interpretation that the Agency can
rely on experience from EPAct05 funded facilities in conjunction with
other information, this section provides examples of EPAct05-assisted
geologic sequestration projects. While the EPA has determined that the
sequestration component of CCS is adequately demonstrated based on the
non-EPAct05 examples discussed above, adequate demonstration of
geologic sequestration is further corroborated by planned and
operational geologic sequestration projects assisted by grants, loan
guarantees, and the IRC section 48A federal tax credit for ``clean coal
technology'' authorized by the EPAct05.\494\
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\494\ 80 FR 64541-42 (October 23, 2015).
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At present, there are 13 operational and one post-injection phase
commercial carbon sequestration facilities in the United
States.495 496 Red Trail Energy CCS Project in North Dakota
and Illinois Industrial Carbon Capture and Storage in Illinois are
dedicated saline sequestration facilities, while the other facilities,
including Petra Nova in Texas, are sequestration via
EOR.497 498 Several other facilities are under
development.\499\ The Red Trail Energy CCS facility in North Dakota
began injecting CO2 captured from ethanol production plants
in 2022.\500\ This project is expected to inject 180,000 tons of
CO2 per year.\501\ The Illinois Industrial Carbon Capture
and Storage Project began injecting CO2 from ethanol
production into the Mount Simon Sandstone in April 2017. According to
the facility's report to the EPA's Greenhouse Gas Reporting Program
(GHGRP), as of 2022, 2.9 million metric tons of CO2 had been
injected into the saline reservoir.\502\ CO2 injection for
one of the two permitted Class VI wells ceased in 2021 and this well is
now in the post-operation data collection phase.\503\
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\495\ Clean Air Task Force. (August 3, 2023). U.S. Carbon
Capture Activity and Project Map. https://www.catf.us/ccsmapus/.
\496\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\497\ Reuters. (September 14, 2023) ``Carbon capture project
back at Texas coal plant after 3-year shutdown''. https://www.reuters.com/business/energy/carbon-capture-project-back-texas-coal-plant-after-3-year-shutdown-2023-09-14/.
\498\ Clean Air Task Force. (August 3, 2023). U.S. Carbon
Capture Activity and Project Map. https://www.catf.us/ccsmapus/.
\499\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\500\ Ibid.
\501\ Ibid.
\502\ EPA Greenhouse Gas Reporting Program. Data reported as of
August 12, 2022.
\503\ University of Illinois Urbana-Champaign, Prairie Research
Institute. (2022). Data from landmark Illinois Basin carbon storage
project are now available. https://blogs.illinois.edu/view/7447/54118905.
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There are additional planned geologic sequestration projects under
review by the EPA and across the United States.504 505
Project Tundra, a saline sequestration project planned at the lignite-
fired Milton R. Young Station in North Dakota is projected to capture 4
million metric tons of CO2 annually.\506\ In Wyoming, Class
VI permit
[[Page 39866]]
applications have been issued by the Wyoming Department of
Environmental Quality for the proposed Eastern Wyoming Sequestration
Hub project, a saline sequestration facility proposed to be located in
Southwestern Wyoming.\507\ At full capacity, the facility would
permanently store up to 5 million metric tons of CO2
captured from industrial facilities annually in the Nugget saline
sandstone reservoir.\508\ In Texas, three NGCCs plan to add carbon
capture equipment. Deer Park NGCC plans to capture 5 million tons per
year, Quail Run NGCC plans to capture 1.5 million tons of
CO2 per year, and Baytown NGCC plans to capture up to 2
million tons of CO2 per year.509 510
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\504\ In addition, Denbury Resources injected CO2
into a depleted oil and gas reservoir at a rate greater than 1.2
million tons/year as part of a DOE Southeast Regional Carbon
Sequestration Partnership study. The Texas Bureau of Economic
Geology tested a wide range of surface and subsurface monitoring
tools and approaches to document sequestration efficiency and
sequestration permanence at the Cranfield oilfield in Mississippi.
Texas Bureau of Economic Geology, ``Cranfield Log.'' https://www.beg.utexas.edu/gccc/research/cranfield.
\505\ EPA Class VI Permit Tracker. https://www.epa.gov/system/files/documents/2024-02/class-vi-permit-tracker_2-5-24.pdf. Accessed
February 5, 2024.
\506\ Project Tundra. ``Project Tundra.'' https://www.projecttundrand.com/.
\507\ Wyoming DEQ Class VI Permit Applications. https://deq.wyoming.gov/water-quality/groundwater/uic/class-vi/.
\508\ Id.
\509\ Calpine. (2023). Calpine Carbon Capture, Bayton, Texas.
https://calpinecarboncapture.com/wp-content/uploads/2023/04/Calpine-Baytown-One-Pager-English-1.pdf.
\510\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
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(4) Security of Geologic Sequestration and Related Regulatory
Requirements
As discussed in section VII.C.1.a.i(D)(2) of this preamble, there
have been numerous instances of geologic sequestration in the U.S. and
overseas, and the U.S. has developed a detailed set of regulatory
requirements to ensure the security of sequestered CO2. This
regulatory framework includes the UIC well regulations pursuant to SDWA
authority, and the GHGRP pursuant to CAA authority.
Regulatory oversight of geologic sequestration is built upon an
understanding of the proven mechanisms by which CO2 is
retained in geologic formations. These mechanisms include (1)
Structural and stratigraphic trapping (generally trapping below a low
permeability confining layer); (2) residual CO2 trapping
(retention as an immobile phase trapped in the pore spaces of the
geologic formation); (3) solubility trapping (dissolution in the in
situ formation fluids); (4) mineral trapping (reaction with the
minerals in the geologic formation and confining layer to produce
carbonate minerals); and (5) preferential adsorption trapping
(adsorption onto organic matter in coal and shale).
(a) Overview of Legal and Regulatory Framework
For the reasons detailed below, the UIC Program, the GHGRP, and
other regulatory requirements comprise a detailed regulatory framework
for geologic sequestration in the United States. This framework is
analyzed in a 2021 report from the Council on Environmental Quality
(CEQ),\511\ and statutory and regulatory frameworks that may be
applicable for CCS are summarized in the EPA CCS Regulations
Table.512 513 This regulatory framework includes the UIC
regulations, promulgated by the EPA under the authority of the Safe
Drinking Water Act (SDWA); and the GHGRP, promulgated by the EPA under
the authority of the CAA. The requirements of the UIC and GHGRP
programs work together to ensure that sequestered CO2 will
remain securely stored underground. Furthermore, geologic sequestration
efforts on Federal lands as well as those efforts that are directly
supported with Federal funds would need to comply with the NEPA and
other Federal laws and regulations, depending on the nature of the
project.\514\ In cases where sequestration is conducted offshore, the
SDWA, the Marine Protection, Research, and Sanctuaries Act (MPRSA) or
the Outer Continental Shelf Lands Act (OCSLA) may apply. The Department
of Interior Bureau of Safety and Environmental Enforcement and Bureau
of Ocean Energy Management are developing new regulations and creating
a program for oversight of carbon sequestration activities on the outer
continental shelf.\515\ Furthermore, Title V of the Federal Land Policy
and Management Act of 1976 (FLPMA) and its implementing regulations, 43
CFR part 2800, authorize the Bureau of Land Management (BLM) to issue
rights-of-way (ROWs) to geologically sequester CO2 in
Federal pore space, including BLM ROWs for the necessary physical
infrastructure and for the use and occupancy of the pore space itself.
The BLM has published a policy defining access to pore space on BLM
lands, including clarification of Federal policy for situations where
the surface and pore space are under the control of different Federal
agencies.\516\
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\511\ CEQ. (2021). ``Council on Environmental Quality Report to
Congress on Carbon Capture, Utilization, and Sequestration.''
https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
\512\ EPA. 2023. Regulatory and Statutory Authorities Relevant
to Carbon Capture and Sequestration (CCS) Projects. https://www.epa.gov/system/files/documents/2023-10/regulatory-and-statutory-authorities-relevant-to-carbon-capture-and-sequestration-ccs-projects.pdf.
\513\ This table serves as a reference of many possible
authorities that may affect a CCS project (including site selection,
capture, transportation, and sequestration). Many of the authorities
listed in this table would apply only in specific circumstances.
\514\ CEQ. ``Council on Environmental Quality Report to Congress
on Carbon Capture, Utilization, and Sequestration.'' 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
\515\ Department of the Interior. (2023). BSEE Budget. https://www.doi.gov/ocl/bsee-budget.
\516\ National Policy for the Right-of-Way Authorizations
Necessary for Site Characterization, Capture, Transportation,
Injection, and Permanent Geologic Sequestration of Carbon Dioxide in
Connection with Carbon Sequestration Projects. BLM IM 2022-041
Instruction Memorandum, June 8, 2022. https://www.blm.gov/policy/im-2022-041.
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(b) Underground Injection Control (UIC) Program
The UIC regulations, including the Class VI program, authorize the
injection of CO2 for geologic sequestration while protecting
human health by ensuring the protection of underground sources of
drinking water (USDW). These regulations are built upon nearly a half-
century of Federal experience regulating underground injection wells,
and many additional years of state UIC program expertise. The IIJA
established a $50 million grant program to assist states and tribal
regulatory authorities in developing and implementing UIC Class VI
programs.\517\ Major components included in UIC Class VI permits are
site characterization, area of review,\518\ corrective action,\519\
well construction and operation, testing and monitoring, financial
responsibility, post-injection site care, well plugging, emergency and
remedial response, and site closure. The EPA's UIC regulations are
included in 40 CFR parts 144-147. The UIC regulations ensure that
injected CO2 does not migrate out of the authorized
injection zone, which in turn ensures that CO2 is securely
stored underground.
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\517\ EPA. Underground Injection Control Class VI Wells
Memorandum. (December 9, 2022). https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
\518\ Per 40 CFR 146.84(a), the area of review is the region
surrounding the geologic sequestration project where USDWs may be
endangered by the injection activity. The area of review is
delineated using computational modeling that accounts for the
physical and chemical properties of all phases of the injected
carbon dioxide stream and is based on available site
characterization, monitoring, and operational data.
\519\ UIC permitting authorities may require corrective action
for existing wells within the area of review to ensure protection of
underground sources of drinking water.
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Review of a UIC permit application by the permitting authority,
including for Class VI geologic sequestration, entails a
multidisciplinary evaluation to determine whether the application
includes the required information, is technically accurate, and
supports a determination that USDWs will not be endangered by the
proposed injection
[[Page 39867]]
activity.\520\ The EPA promulgated UIC regulations to ensure
underground injection wells are constructed, operated, and closed in a
manner that is protective of USDWs and to address potential risks to
USDWs associated with injection activities.\521\ The UIC regulations
address the major pathways by which injected fluids can migrate into
USDWs, including along the injection well bore, via improperly
completed or plugged wells in the area near the injection well, direct
injection into a USDW, faults or fractures in the confining strata, or
lateral displacement into hydraulically connected USDWs. States may
apply to the EPA to be the UIC permitting authority in the state and
receive primary enforcement authority (primacy). Where a state has not
obtained primacy, the EPA is the UIC permitting authority.
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\520\ EPA. EPA Report to Congress: Class VI Permitting. 2022.
https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
\521\ See 40 CFR parts 124, 144-147.
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Recognizing that CO2 injection, for the purpose of
geologic sequestration, poses unique risks relative to other injection
activities, the EPA promulgated Federal Requirements Under the UIC
Program for Carbon Dioxide GS Wells, known as the Class VI Rule, in
December 2010.\522\ The Class VI Rule created and set requirements for
a new class of injection wells, Class VI. The Class VI Rule builds upon
the long-standing protective framework of the UIC Program, with
requirements that are tailored to address issues unique to large-scale
geologic sequestration, including large injection volumes, higher
reservoir pressures relative to other injection formations, the
relative buoyancy of CO2, the potential presence of
impurities in captured CO2, the corrosivity of
CO2 in the presence of water, and the mobility of
CO2 within subsurface geologic formations. These additional
protective requirements include more extensive geologic testing,
detailed computational modeling of the project area and periodic re-
evaluations, detailed requirements for monitoring and tracking the
CO2 plume and pressure in the injection zone, unique
financial responsibility requirements, and extended post-injection
monitoring and site care.
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\522\ EPA. (2010). Federal Requirements Under the Underground
Injection Control (UIC) Program for Carbon Dioxide (CO2) Geologic
Sequestration (GS) Wells; Final Rule, 75 FR 77230, December 10, 2010
(codified at 40 CFR part 146, subpart H).
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UIC Class VI permits are designed to ensure that geologic
sequestration does not cause the movement of injected CO2 or
formation fluids outside the authorized injection zone; if monitoring
indicates leakage of injected CO2 from the injection zone,
the leakage may trigger a response per the permittee's Class VI
Emergency and Remedial Response Plan including halting injection, and
the permitting authority may prescribe additional permit requirements
necessary to prevent such movement to ensure USDWs are protected or
take appropriate enforcement action if the permit has been
violated.\523\ Class II EOR permits are also designed to ensure the
protection of USDWs with requirements appropriate for the risks of the
enhanced recovery operation. In general, the EPA believes that the
protection of USDWs by preventing leakage of injected CO2
out of the injection zone will also ensure that CO2 is
sufficiently sequestered in the subsurface, and therefore will not leak
from the subsurface to the atmosphere.
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\523\ See 40 CFR 144.12(b) (prohibition of movement of fluid
into USDWs); 40 CFR 146.86(a)(1) (Class VI injection well
construction requirements); 40 CFR 146(a) (Class VI injection well
operation requirements); 40 CFR 146.94 (emergency and remedial
response).
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The UIC program works with injection well operators throughout the
life of the well to confirm practices do not pose a risk to USDWs. The
program conducts inspections to verify compliance with the UIC permit,
including checking for leaks.\524\ Inspections are only one way that
programs deter noncompliance. Programs also evaluate periodic
monitoring reports submitted by operators and discuss potential issues
with operators. If a well is found to be out of compliance with
applicable requirements in its permit or UIC regulations, the program
will identify specific actions that an operator must take to address
the issues. The UIC program may assist the operator in returning the
well to compliance or use administrative or judicial enforcement to
return a well to compliance.
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\524\ EPA. (2020). Underground Injection Control Program.
https://www.epa.gov/sites/default/files/2020-04/documents/uic_fact_sheet.pdf.
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UIC program requirements address potential safety concerns with
induced seismicity. More specifically, through the UIC Class VI
program, the EPA has put in place mechanisms to identify, monitor, and
reduce risks associated with induced seismicity in any areas within or
surrounding a sequestration site through permit and program
requirements such as site characterization and monitoring, and the
requirement for applicants to demonstrate that induced seismic activity
will not endanger USDWs.\525\ The National Academy of Sciences released
a report in 2012 on induced seismicity from CCS and determined that
with appropriate site selection, a monitoring program, a regulatory
system, and the appropriate use of remediation methods, the induced
seismicity risks of geologic sequestration could be mitigated.\526\
Furthermore, the Ground Water Protection Council and Interstate Oil and
Gas Compact Commission have published a ``Potential Induced Seismicity
Guide.'' This report found that the strategies for avoiding,
mitigating, and responding to potential risks of induced seismicity
should be determined based on site-specific characteristics (i.e.,
local geology). These strategies could include supplemental seismic
monitoring, altering operational parameters (such as rates and
pressures) to reduce the ground motion hazard and risk, permit
modification, partial plug back of the well, controlled restart (if
feasible), suspending or revoking injection authorization, or stopping
injection and shutting in a well.\527\ The EPA's UIC National Technical
Workgroup released technical recommendations in 2015 to address induced
seismicity concerns in Class II wells and elements of these
recommendations have been utilized in developing Class VI emergency and
remedial response plans for Class VI permits.528 529 For
example, as identified
[[Page 39868]]
by the EPA's UIC National Technical Workgroup, sufficient pressure
buildup from disposal activities, the presence of Faults of Concern
(i.e., a fault optimally oriented for movement and located in a
critically stressed region), and the existence of a pathway for
allowing the increased pressure to communicate with the fault
contribute to the risk of injection-induced seismicity. The UIC
requirements, including site characterization (e.g., ensuring the
confining zone \530\ is free of faults of concern) and operating
requirements (e.g., ensuring injection pressure in the injection zone
is below the fracture pressure), work together to address these
components and reduce the risk of injection-induced seismicity,
particularly any injection-induced seismicity that could be felt by
people at the surface.\531\ Additionally, the EPA recommends that Class
VI permits include an approach for monitoring for seismicity near the
site, including seismicity that cannot be felt at the surface, and that
injection activities be stopped or reduced in certain situations if
seismic activity is detected to ensure that no seismic activity will
endanger USDWs.\532\ This also reduces the likelihood of any future
injection-induced seismic activity that will be felt at the surface.
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\525\ See 40 CFR 146.82(a)(3)(v) (requiring the permit applicant
to submit and the permitting authority to consider information on
the seismic history including the presence and depth of seismic
sources and a determination that the seismicity would not interfere
with containment); EPA. (2018). Geologic Sequestration of Carbon
Dioxide Underground Injection Control (UIC) Program Class VI
Implementation Manual for UIC Program Directors. U.S. Environmental
Protection Agency Office of Water (4606M) EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
\526\ National Research Council. (2013). Induced Seismicity
Potential in Energy Technologies. Washington, DC: The National
Academies Press. https://doi.org/10.17226/13355.
\527\ Ground Water Protection Council and Interstate Oil and Gas
Compact Commission. (2021). Potential Induced Seismicity Guide: A
Resource of Technical and Regulatory Considerations Associated with
Fluid Injection. https://www.gwpc.org/wp-content/uploads/2022/12/FINAL_Induced_Seismicity_2021_Guide_33021.pdf.
\528\ EPA. (2015). Minimizing and Managing Potential Impacts of
Injection-Induced Seismicity from Class II Disposal Wells: Practical
Approaches. https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf.
\529\ EPA. (2018). Geologic Sequestration of Carbon Dioxide:
Underground Injection Control (UIC) Program Class VI Implementation
Manual for UIC Program Directors. EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
\530\ ``Confining zone'' means a geological formation, group of
formations, or part of a formation that is capable of limiting fluid
movement above an injection zone. 40 CFR 146.3.
\531\ EPA. (2015). Minimizing and Managing Potential Impacts of
Injection-Induced Seismicity from Class II Disposal Wells: Practical
Approaches. https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf.
\532\ See EPA. Emergency and Remedial Response Plan: 40 CFR
146.94(a) template. https://www.epa.gov/system/files/documents/2022-03/err_plan_template.docx. See also EPA. (2018). Geologic
Sequestration of Carbon Dioxide: Underground Injection Control (UIC)
Program Class VI Implementation Manual for UIC Program Directors.
EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
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Furthermore, during site characterization, if any of the geologic
or seismic data obtained indicate a substantial likelihood of seismic
activity, the EPA may require further analyses, potential planned
operational changes, and additional monitoring.\533\ The EPA has the
authority to require seismic monitoring as a condition of the UIC
permit if appropriate, or to deny the permit if the injection-induced
seismicity risk could endanger USDWs.
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\533\ 40 CFR 146.82(a)(3)(v).
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The EPA believes that meaningful engagement with local communities
is an important step in the development of geologic sequestration
projects and has programs and public participation requirements in
place to support this process. The EPA is committed to advancing EJ for
overburdened communities in all its programs, including the UIC Class
VI program.\534\ The EPA is also committed to supporting states' and
tribes' efforts to obtain UIC Class VI primacy and strongly encourages
such states and tribes to incorporate environmental justice principles
and equity into proposed UIC Class VI programs.\535\ The EPA is taking
steps to address EJ in accordance with Presidential Executive Order
14096, Revitalizing Our Nation's Commitment to Environmental Justice
for All (88 FR 25251, April 26, 2023). In 2023, the EPA released
Environmental Justice Guidance for UIC Class VI Permitting and Primacy
that builds on the 2011 UIC Quick Reference Guide: Additional Tools for
UIC Program Directors Incorporating Environmental Justice
Considerations into the Class VI Injection Well Permitting
Process.536 537 The 2023 guidance serves as an operating
framework for identifying, analyzing, and addressing EJ concerns in the
context of implementing and overseeing UIC permitting and primacy
programs, including primacy approvals. The EPA notes that while this
guidance is focused on the UIC Class VI program, EPA Regions should
apply them to the other five injection well classes wherever possible,
including class II. The guidance includes recommended actions across
five themes to address various aspects of EJ in UIC Class VI permitting
including: (1) identify communities with potential EJ concerns, (2)
enhance public involvement, (3) conduct appropriately scoped EJ
assessments, (4) enhance transparency throughout the permitting
process, and (5) minimize adverse effects to USDWs and the communities
they may serve.\538\
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\534\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
; see also EPA. Letter from the EPA Administrator Michael S. Regan
to U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
\535\ EPA. (2023). Targeted UIC program grants for Class VI
Wells. https://www.epa.gov/uic/underground-injection-control-grants#ClassVI_Grants.
\536\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
.
\537\ EPA. (2011). Geologic Sequestration of Carbon Dioxide--UIC
Quick Reference Guide. https://www.epa.gov/sites/default/files/2015-07/documents/epa816r11002.pdf.
\538\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
.
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As a part of the UIC Class VI permit application process,
applicants and the EPA Regions should complete an EJ review using the
EPA's EJScreen Tool, an online mapping tool that integrates numerous
demographic, socioeconomic, and environmental data sets that are
overlain on an applicant's UIC Area of Review to identify whether any
disadvantaged communities are encompassed.\539\ If the results indicate
a potential EJ impact, applicants and the EPA Regions should consider
potential measures to mitigate the impacts of the UIC Class VI project
on identified vulnerable communities and enhance the public
participation process to be inclusive of all potentially affected
communities (e.g., conduct early targeted outreach to communities and
identify and mitigate any communication obstacles such as language
barriers or lack of technology resources).\540\
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\539\ EPA Report to Congress: Class VI Permitting. 2022. https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
\540\ EPA Report to Congress: Class VI Permitting. 2022. https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
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ER technologies are used in oil and gas reservoirs to increase
production. Injection wells used for ER are regulated through the UIC
Class II program. Injection of CO2 is one of several
techniques used in ER. Sometimes ER uses CO2 from
anthropogenic sources such as natural gas processing, ammonia and
fertilizer production, and coal gasification facilities. Through the ER
process, much of the injected CO2 is recovered from
production wells and can be separated and reinjected into the
subsurface formation, resulting in the storage of CO2
underground. The EPA's Class II regulations were designed to regulate
ER injection wells, among other injection wells associated with oil and
natural gas production. See e.g., 40 CFR 144.6(b)(2). The EPA's Class
II program is designed to prevent Class II injection activities from
endangering USDWs. The Class II programs of states and tribes must be
approved by the EPA and must meet the EPA regulatory requirements for
Class II programs, 42 U.S.C. 300h-1, or otherwise represent an
effective program to prevent endangerment of USDWs. 42 U.S.C 300h-4.
[[Page 39869]]
In promulgating the Class VI regulations, the EPA recognized that
if the business model for ER shifts to focus on maximizing
CO2 injection volumes and permanent storage, then the risk
of endangerment to USDWs is likely to increase. As an ER project shifts
away from oil and/or gas production, injection zone pressure and carbon
dioxide volumes will likely increase if carbon dioxide injection rates
increase, and the dissipation of reservoir pressure will decrease if
fluid production from the reservoir decreases. Therefore, the EPA's
regulations require the operator of a Class II well to obtain a Class
VI permit when there is an increased risk to USDWs. 40 CFR 144.19.\541\
While the EPA's regulations require the Class II well operator to
assess whether there is an increased risk to USDWs (considering factors
identified in the EPA's regulations), the permitting authority can also
make this assessment and, in the event that an operator makes changes
to Class II operations such that the increased risk to USDWs warrants
transition to Class VI and the operator does not notify the permitting
authority, the operator may be subject to SDWA enforcement and
compliance actions to protect USDWs, including cessation of injection.
The determination of whether there is an increased risk to USDWs would
be based on factors specified in 40 CFR 144.19(b), including increase
in reservoir pressure within the injection zone; increase in
CO2 injection rates; and suitability of the Class II Area of
Review (AoR) delineation.
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\541\ EPA. (2015). Key Principles in EPA's Underground Injection
Control Program Class VI Rule Related to Transition of Class II
Enhanced Oil or Gas Recovery Wells to Class VI. https://www.epa.gov/sites/default/files/2015-07/documents/class2eorclass6memo_1.pdf.
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(c) Greenhouse Gas Reporting Program (GHGRP)
The GHGRP requires reporting of greenhouse gas (GHG) data and other
relevant information from large GHG emission sources, fuel and
industrial gas suppliers, and CO2 injection sites in the
United States. Approximately 8,000 facilities are required to report
their emissions, injection, and/or supply activity annually, and the
non-confidential reported data are made available to the public around
October of each year. To complement the UIC regulations, the EPA
included in the GHGRP air-side monitoring and reporting requirements
for CO2 capture, underground injection, and geologic
sequestration. These requirements are included in 40 CFR part 98,
subpart RR and subpart VV, also referred to as ``GHGRP subpart RR'' and
``GHGRP subpart VV.''
GHGRP subpart RR applies to ``any well or group of wells that
inject a CO2 stream for long-term containment in subsurface
geologic formations'' \542\ and provides the monitoring and reporting
mechanisms to quantify CO2 storage and to identify,
quantify, and address potential leakage. The EPA designed GHGRP subpart
RR to complement the UIC monitoring and testing requirements. See e.g.,
40 CFR 146.90-91. Reporting under GHGRP subpart RR is required for, but
not limited to, all facilities that have received a UIC Class VI permit
for injection of CO2.\543\ Under existing GHGRP regulations,
facilities that conduct ER in Class II wells are not subject to
reporting data under GHGRP subpart RR unless they have chosen to submit
a proposed monitoring, reporting, and verification (MRV) plan to the
EPA and received an approved plan from the EPA. Facilities conducting
ER and who do not choose to submit a subpart RR MRV plan to the EPA
would otherwise be required to report CO2 data under subpart
UU.\544\ GHGRP subpart RR requires facilities meeting the source
category definition (40 CFR 98.440) for any well or group of wells to
report basic information on the mass of CO2 received for
injection; develop and implement an EPA-approved monitoring, reporting,
and verification (MRV) plan; report the mass of CO2
sequestered using a mass balance approach; and report annual monitoring
activities.545 546 547 548 Extensive subsurface monitoring
is required for UIC Class VI wells at 40 CFR 146.90 and is the primary
means of determining if the injected CO2 remains in the
authorized injection zone and otherwise does not endanger any USDW, and
monitoring under a GHGRP subpart RR MRV Plan complements these
requirements. The MRV plan includes five major components: a
delineation of monitoring areas based on the CO2 plume
location; an identification and evaluation of the potential surface
leakage pathways and an assessment of the likelihood, magnitude, and
timing, of surface leakage of CO2 through these pathways; a
strategy for detecting and quantifying any surface leakage of
CO2 in the event leakage occurs; an approach for
establishing the expected baselines for monitoring CO2
surface leakage; and, a summary of considerations made to calculate
site-specific variables for the mass balance equation.\549\
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\542\ See 40 CFR 98.440.
\543\ 40 CFR 98.440.
\544\ As discussed in section X.C.5.b, entities conducting CCS
to comply with this rule would be required to send the captured
CO2 to a facility that reports data under subpart RR or
subpart VV.
\545\ 40 CFR 98.446.
\546\ 40 CFR 98.448.
\547\ 40 CFR 98.446(f)(9) and (10).
\548\ 40 CFR 98.446(f)(12).
\549\ 40 CFR 98.448(a).
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In April 2024, the EPA finalized a new GHGRP subpart, ``Geologic
Sequestration of Carbon Dioxide with Enhanced Oil Recovery (EOR) Using
ISO 27916'' (or GHGRP subpart VV).\550\ GHGRP subpart VV applies to
facilities that quantify the geologic sequestration of CO2
in association with EOR operations in conformance with the ISO standard
designated as CSA/ANSI ISO 27916:2019, Carbon Dioxide Capture,
Transportation and Geological Storage--Carbon Dioxide Storage Using
Enhanced Oil Recovery. Facilities that have chosen to submit an MRV
plan and report under GHGRP subpart RR must not report data under GHGRP
subpart VV. GHGRP subpart VV is largely modeled after the requirements
in this ISO standard and focuses on quantifying storage of
CO2. Facilities subject to GHGRP subpart VV must include in
their GHGRP annual report a copy of their EOR Operations Management
Plan (EOR OMP). The EOR OMP includes a description of the EOR complex
and engineered system, establishes that the EOR complex is adequate to
provide safe, long-term containment of CO2, and includes
site-specific and other information including a geologic
characterization of the EOR complex, a description of the facilities
within the EOR project, a description of all wells and other engineered
features in the EOR project, and the operations history of the project
reservoir.\551\
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\550\ EPA. (2024). Rulemaking Notices for GHG Reporting. https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
\551\ EPA. (2024). Rulemaking Notices for GHG Reporting. https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
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Based on the understanding developed from existing projects, the
security of sequestered CO2 is expected to increase over
time after injection ceases.\552\ This is due to trapping mechanisms
that reduce CO2 mobility over time (e.g., physical
CO2 trapping by a low-permeability geologic seal or chemical
trapping by conversion or adsorption).\553\ The EPA acknowledges the
potential for some leakage of CO2 to the atmosphere at
sequestration sites, primarily while injection operations are active.
For example, small quantities of the CO2 that were sent to
the
[[Page 39870]]
sequestration site may be emitted from leaks in pipes and valves that
are traversed before the CO2 actually reaches the
sequestration formation. However, the EPA's robust UIC regulatory
protections protect against leakage out of the injection zone. Relative
to the 46.75 million metric tons of CO2 reported as
sequestered under subpart RR of the GHGRP between 2016 to 2022, only
196,060 metric tons were reported as leakage/emissions to the
atmosphere in the same time period (representing less than 0.5% of the
sequestration amount). Of these emissions, most were from equipment
leaks and vented emissions of CO2 from equipment located on
the surface rather than leakage from the subsurface.\554\ Furthermore,
any leakage of CO2 at a sequestration facility would be
required to be quantified and reported under the GHGRP subpart RR or
subpart VV, and such data are made publicly available on the EPA's
website.
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\552\ ``Report of the Interagency Task Force on Carbon Capture
and Storage.'' 2010. https://www.osti.gov/servlets/purl/985209.
\553\ See, e.g., Intergovernmental Panel on Climate Change.
(2005). Special Report on Carbon Dioxide Capture and Storage.
\554\ Based on subpart RR data retrieved from the EPA Facility
Level Information on Greenhouse Gases Tool (FLIGHT), at https://ghgdata.epa.gov/ghgp/main.do. Retrieved March 2024.
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(5) Timing of Permitting for Sequestration Sites
As previously discussed, the EPA is the Class VI permitting
authority for states, tribes, and territories that have not obtained
primacy over their Class VI programs.\555\ The EPA is committed to
reviewing UIC Class VI permits as expeditiously as possible when the
agency is the permitting authority. The EPA has the experience to
properly regulate and review permits for UIC Class VI injection wells,
and technical experts of multiple disciplines to review permit
applications submitted to the EPA.
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\555\ See 40 CFR part 145 (State UIC Program Requirements), 40
CFR part 147 (State, Tribal, and EPA-Administered Underground
Injection Control Programs).
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The EPA has seen a considerable uptick in Class VI permit
applications over the past few years. The 2018 passage of revisions and
enhancements to the IRC section 45Q tax credit that provides tax
credits for carbon oxide (including CO2) sequestration has
led to an increase in Class VI permit applications submitted to the
EPA. The 2022 IRA further expanded the IRC section 45Q tax credit and
the 2021 IIJA established a $50 million program for grants to help
states and tribes in developing and implementing a UIC Class VI primacy
program, leading to even more interest in this area.\556\ Between 2011,
when the Class VI rule went into effect, and 2020, the EPA received a
total of 8 permit applications for Class VI wells. The EPA then
received 12 Class VI permit applications in 2021, 44 in 2022, and 123
in 2023. As of March 2024, the EPA has 130 Class VI permit applications
under review (56 permit applications were transferred to Louisiana in
February 2024 when the EPA rule granting Class VI primacy to the state
became effective). The majority of those 130 permit applications (63%)
were submitted to the EPA within the past 12 months. Also, as of March
2024, the EPA has issued eight Class VI permits, including six for
projects in Illinois and two for projects in Indiana, and has released
for public comment four additional draft permits for proposed projects
in California. Two of the permits are in the pre-operation phase, one
is in the injection phase, and one is in the post-injection monitoring
phase.
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\556\ EPA. (2023). Targeted UIC program grants for Class VI
Wells https://www.epa.gov/uic/underground-injection-control-grants#ClassVI_Grants.
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In light of the recent flurry of interest in this area, the EPA is
devoting increased resources to the Class VI program, including through
increased staffing levels in order to meet the increased demand for
action on Class VI permit applications.\557\ Reviewing a Class VI
permit application entails a multidisciplinary evaluation to determine
whether the application includes the required information, is
technically accurate, and supports a risk-based determination that
underground sources of drinking water will not be endangered by the
proposed injection activity. A wide variety of technical experts--from
geologists to engineers to physical scientists--review permit
applications submitted to the EPA. The EPA has been working to develop
staff expertise and increase capacity in the UIC program, and the
agency has effectively deployed appropriated resources over the last
five years to scale UIC program staff from a few employees to the
equivalent of more than 25 full-time employees across the agency's
headquarters and regional offices. We expect that the additional
resources and staff capacity for the Class VI program will lead to
increased efficiencies in the Class VI permitting process.
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\557\ EPA. (2023). Testimony Of Mr. Bruno Pigott, Principal
Deputy Assistant Administrator for Water, U.S. Environmental
Protection Agency, Hearing On Carbon Capture And Storage. https://www.epa.gov/system/files/documents/2023-11/testimony-pigott-senr-hearing-nov-2-2023_-cleared.pdf.
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In addition to increased staffing resources, the EPA has made
considerable improvements to the Class VI permitting process to reduce
the time needed to make final permitting decisions for Class VI wells
while maintaining a robust and thorough review process that ensures
USDWs are protected. The EPA has created additional resources for
applicants including upgrading the Geologic Sequestration Data Tool
(GSDT) to guide applicants through the application process.\558\ The
EPA has also created resources for permit writers including training
series and guidance documents to build capacity for Class VI
permitting.\559\ Additionally, the EPA issued internal guidelines to
streamline and create uniformity and consistency in the Class VI
permitting process, which should help to reduce permitting timeframes.
These internal guidelines include the expectation that EPA Regions will
classify all Class VI well applications received on or after December
12, 2023, as applications for major new UIC injection wells, which
requires the Regions to develop project decision schedules for
reviewing Class VI permit applications. The guidelines also set target
timeframes for components of the permitting process, such as the number
of days EPA Regions should set for public comment periods and for
developing responses to comments and final permit decisions. The EPA
will continue to evaluate its internal UIC permitting processes to
identify potential opportunities for streamlining and other
improvements over time. Although the available data for Class VI wells
is limited, the timeframe for processing Class I wells, which follows a
similar regulatory structure, is typically less than 2 years.\560\
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\558\ EPA. (2023). Geologic Sequestration Data Tool (GSDT).
https://www.epa.gov/system/files/documents/2023-10/geologic-sequestration-data-tool_factsheet_oct2023.pdf.
\559\ EPA. (2023). Final Class VI Guidance Documents. https://www.epa.gov/uic/final-class-vi-guidance-documents.
\560\ EPA Report to Congress: Class VI Permitting. 2022. https://www.epa.gov/system/files/documents/2022-11/EPAClassVIPermittingReporttoCongress.pdf.
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The EPA notes that a Class VI permit tracker is available on its
website.\561\ This tracker shows information for the 44 projects
(representing 130 wells) that have submitted Class VI applications to
the EPA, including details such as the current permit review stage,
whether a project has been sent a Notice of Deficiency (NOD) or Request
for Additional Information (RAI), and the applicant's response time to
any NODs or RAIs. As mentioned above, most of the permits submitted to
the EPA have been submitted within the past 12
[[Page 39871]]
months. The EPA aims to review complete Class VI applications and issue
permits when appropriate within approximately 24 months. This timeframe
is dependent on several factors, including the complexity of the
project and the quality and completeness of the submitted application.
It is important for the applicant to submit a complete application and
provide any information requested by the permitting agency in a timely
manner so as not to extend the overall time for the review.
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\561\ EPA. (2024). Current Class VI Projects under Review at
EPA. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
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States may apply to the EPA for primacy to administer the Class VI
programs within their states. The primacy application process has four
phases: (1) pre-application activities, (2) completeness review and
determination, (3) application evaluation, and (4) rulemaking and
codification. To date, three states have been granted primacy for Class
VI wells, including North Dakota, Wyoming, and most recently
Louisiana.\562\ As discussed above, North Dakota has issued 6 Class VI
permits since receiving Class VI primacy in 2018, and Wyoming issued
its first three Class VI permits in December
2023.563 564 565 The EPA finalized a rule granting Louisiana
Class VI primacy in January 2024 and the state's program became
effective in February 2024. At that time, EPA Region 6 transferred 56
Class VI permit applications for projects in Louisiana to the state for
continued review and permit issuance if appropriate. Prior to receiving
primacy, the state worked with the EPA in understanding where each
application was in the evaluation process. Currently, the EPA is
working with the states of Texas, Arizona, and West Virginia as they
are developing their UIC primacy applications.\566\ Arizona submitted a
primacy application to the EPA on February 13, 2024.\567\ Texas and
West Virginia are engaging with the EPA to complete pre-application
activities.\568\ If more states apply for and receive Class VI primacy,
the number of permits in EPA review is expected to be reduced. The EPA
has also created resources for regulators including training series and
guidance documents to build capacity for Class VI permitting within UIC
programs across the U.S. Through state primacy for Class VI programs,
state expertise and capacity can be leveraged to support effective and
efficient permit application reviews. The IIJA established a $50
million grant program to support states, Tribes, and territories in
developing and implementing UIC Class VI programs. The EPA has
allocated $1,930,000 to each state, tribe, and territory that submitted
letters of intent.\569\
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\562\ On December 28, 2023, the EPA Administrator signed a final
rule granting Louisiana's request for primacy for UIC Class VI
junction wells located within the state. See EPA. (2023).
Underground Injection Control (UIC) Primary Enforcement Authority
for the Underground Injection Control Program. U.S. Environmental
Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\563\ Wyoming Department of Environmental Quality. (2023).
Wyoming grants its first three Class VI permits. https://deq.wyoming.gov/2023/12/wyoming-grants-its-first-three-class-vi-permits/.
\564\ Ibid.
\565\ Arnold & Porter. (2023). EPA Provides Increased
Transparency in Class VI Permitting Process; Now Incorporated in
Update to Interactive CCUS State Tracker. https://www.arnoldporter.com/en/perspectives/blogs/environmental-edge/2023/11/ccus-state-legislative-tracker.
\566\ EPA. (2023). Underground Injection Control (UIC) Primary
Enforcement Authority for the Underground Injection Control Program.
U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\567\ Arizona Department of Environmental Quality. (2024).
Underground Injection Control (UIC) Program. https://azdeq.gov/UIC.
\568\ EPA. (2023). Underground Injection Control (UIC) Primary
Enforcement Authority for the Underground Injection Control Program.
U.S. Environmental Protection Agency. https://www.epa.gov/uic/primary-enforcement-authority-underground-injection-control-program-0.
\569\ EPA. (2023). Underground Injection Control (UIC) Class VI
Grant Program. https://www.epa.gov/system/files/documents/2023-11/uic-class-vi-grant-fact-sheet.pdf.
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(6) Comments Received on Geologic Sequestration and Responses
The EPA received comments on geologic sequestration. Those
comments, and the EPA's responses, are as follows.
Comment: Some commenters expressed concerns that the EPA has not
demonstrated the adequacy of carbon sequestration at a commercial
scale.
Response: The EPA disagrees that commercial carbon sequestration
capacity will be inadequate to support this rule. As detailed in
section VII.C.1.a.i(D)(1), commercial geologic sequestration capacity
is growing in the United States. Multiple commercial sequestration
facilities, other than those funded under EPAct05, are in construction
or advanced development, with some scheduled to open for operation as
early as 2025.\570\ These facilities have proposed sequestration
capacities ranging from 0.03 to 6 million tons of CO2 per
year. The EPA and states with approved UIC Class VI programs (including
Wyoming, North Dakota, and Louisiana) are currently reviewing UIC Class
VI geologic sequestration well permit applications for proposed
sequestration sites in fourteen states.571 572 573 As of
March 2024, there are 44 projects with 130 injection wells are under
review by the EPA.\574\ Furthermore, the EPA anticipates that as the
demand for commercial sequestration grows, more commercial sites will
be developed in response to financial incentives.
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\570\ Global CCS Institute. (2024). Global Status of CCS 2023.
https://www.globalccsinstitute.com/wp-content/uploads/2024/01/Global-Status-of-CCS-Report-1.pdf.
\571\ UIC regulations for Class VI wells authorize the injection
of CO2 for geologic sequestration while protecting human
health by ensuring the protection of underground sources of drinking
water. The major components to be included in UIC Class VI permits
are detailed further in section VII.C.1.a.i(D)(4).
\572\ U.S. EPA Class VI Underground Injection Control (UIC)
Class VI Wells Permitted by EPA as of January 25, 2024. https://www.epa.gov/uic/table-epas-draft-and-final-class-vi-well-permits
Last updated January 19, 2024.
\573\ EPA. (2024). Current Class VI Projects under Review at
EPA. https://www.epa.gov/uic/current-class-vi-projects-under-review-epa.
\574\ Ibid.
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Comment: Some commenters expressed concern about leakage of
CO2 from sequestration sites.
Response: The EPA acknowledges the potential for some leakage of
CO2 to the atmosphere at sequestration sites (such as leaks
through valves before the CO2 reaches the injection
formation). However, as detailed in the preceding sections of preamble,
the EPA's robust UIC permitting process is adequate to protect against
CO2 escaping the authorized injection zone (and then
entering the atmosphere). As discussed in the preceding section,
leakage out of the injection zone could trigger emergency and remedial
response action including ceasing injection, possible permit
modification, and possible enforcement action. Furthermore, the GHGRP
subpart RR and subpart VV regulations prescribe accounting
methodologies for facilities to quantify and report any potential
leakage at the surface, and the EPA makes sequestration data and
related monitoring plans publicly available on its website. The
reported emissions/leakage from sequestration sites under subpart RR is
a comparatively small fraction (less than 0.5 percent) of the
associated sequestration volumes, with most of these reported emissions
attributable to leaks or vents from surface equipment.
Comment: Some commenters expressed concern over safety due to
induced seismicity.
Response: The EPA believes that the UIC program requirements
adequately address potential safety concerns with induced seismicity at
site-adjacent communities. More specifically, through the UIC Class VI
program the EPA has put in place mechanisms to identify,
[[Page 39872]]
monitor, and mitigate risks associated with induced seismicity in any
areas within or surrounding a sequestration site through permit and
program requirements, such as site characterization and monitoring, and
the requirement for applicants to demonstrate that induced seismic
activity will not endanger USDWs.\575\ See section VII.C.1.a.i(D)(4)(b)
for further discussion of mitigating induced seismicity risk. Although
the UIC Class II program does not have specific requirements regarding
seismicity, it includes discretionary authority to add additional
conditions to a UIC permit on a case-by-case basis. The EPA created a
document outlining practical approaches for UIC Directors to use to
minimize and manage injection-induced seismicity in Class II
wells.\576\ Furthermore, during site characterization, if any of the
geologic or seismic data obtained indicate a substantial likelihood of
seismic activity, further analyses, potential planned operational
changes, and additional monitoring may be required.\577\ The EPA has
the authority to require seismic monitoring as a condition of the UIC
permit if appropriate, or to deny the permit if the injection-induced
seismicity risk could endanger USDWs.
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\575\ EPA. (2018). Geologic Sequestration of Carbon Dioxide:
Underground Injection Control (UIC) Program Class VI Implementation
Manual for UIC Program Directors. EPA 816-R-18-001. https://www.epa.gov/sites/default/files/2018-01/documents/implementation_manual_508_010318.pdf.
\576\ EPA. (2015). Minimizing and Managing Potential Impacts of
Injection-Induced Seismicity from Class II Disposal Wells: Practical
Approaches. https://www.epa.gov/sites/default/files/2015-08/documents/induced-seismicity-201502.pdf.
\577\ 40 CFR 146.82(a)(3)(v).
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Comment: Some commenters have expressed concern that the EPA has
not meaningfully engaged with historically disadvantaged and
overburdened communities who may be impacted by environmental changes
due to geologic sequestration.
Response: The EPA acknowledges that meaningful engagement with
local communities is an important step in the development of geologic
sequestration projects and has programs and public participation
requirements in place to support this process. The EPA is committed to
advancing environmental justice for overburdened communities in all its
programs, including the UIC Class VI program.\578\ The EPA's
environmental justice guidance for Class VI permitting and primacy
states that many of the expectations are broadly applicable, and EPA
Regions should apply them to the other five injection well classes,
including Class II, wherever possible.\579\ See section
VII.C.1.a.i(D)(4) for a detailed discussion of environmental justice
requirements and guidance.
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\578\ EPA. (2023). Environmental justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
; see also EPA. Letter from the EPA Administrator Michael S. Regan
to U.S. State Governors. December 9, 2022. https://www.epa.gov/system/files/documents/2022-12/AD.Regan_.GOVS_.Sig_.Class%20VI.12-9-22.pdf.
\579\ EPA. (2023). Environmental Justice Guidance for UIC Class
VI Permitting and Primacy. https://www.epa.gov/system/files/documents/2023-08/Memo%20and%20EJ%20Guidance%20for%20UIC%20Class%20VI_August%202023.pdf
.
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Comment: Commenters expressed concern that companies are not always
in compliance with reporting requirements for subpart RR when required
for other Federal programs.
Response: The EPA recognizes the need for geologic sequestration
facilities to comply with the reporting requirements of the GHGRP, and
acknowledges that there have been instances of entities claiming
geologic sequestration under non-EPA programs (e.g., to qualify for IRC
section 45Q tax credits) while not having an EPA-approved MRV plan or
reporting data under subpart RR.\580\ The EPA does not implement the
IRC section 45Q tax credit program, and it is not privy to taxpayer
information. Thus, the EPA has no role in implementing or enforcing
these tax credit claims, and it is unclear, for example, whether these
companies would have been required by GHGRP regulations to report data
under subpart RR, or if they would have been required only by the IRC
section 45Q rules to opt-in to reporting under subpart RR. The EPA
disagrees that compliance with the GHGRP would be a problem for this
rule because the rule requires any affected unit that employs CCS
technology that captures enough CO2 to meet the proposed
standard and injects the captured CO2 underground to report
under GHGRP subpart RR or GHGRP subpart VV. Unlike the IRC section 45Q
tax credit program, which is implemented by the Internal Revenue
Service (IRS), the EPA will have the information necessary to discern
whether a facility is in compliance with any applicable GHGRP
requirements. If the emitting EGU sends the captured CO2
offsite, it must transfer the CO2 to a facility that reports
in accordance with GHGRP subpart RR or GHGRP subpart VV. For more
information on the relationship to GHGRP requirements, see section
X.C.5 of this preamble.
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\580\ Letter from U.S. Treasury Inspector General for Tax
Administration (TIGTA). (2020). https://www.menendez.senate.gov/imo/media/doc/TIGTA%20IRC%2045Q%20Response%20Letter%20FINAL%2004-15-2020.pdf.
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Comment: Commenters expressed concerns that UIC regulations allow
Class II wells to be used for long-term CO2 storage if the
operator assesses that a Class VI permit is not required and asserted
that Class II regulations are less protective than Class VI
regulations.
Response: The EPA acknowledges that Class II wells for EOR may be
used to inject CO2 including CO2 captured from an
EGU. However, the EPA disagrees that the use of Class II wells for ER
will be less protective of human health than the use of Class VI wells
for geologic sequestration. Class II wells are used only to inject
fluids associated with oil and natural gas production, and Class II ER
wells are used specifically for the injection of fluids, including
CO2, for the purpose of enhanced recovery of oil or natural
gas. The EPA's UIC Class II program is designed to prevent Class II
injection activities from endangering USDWs. Any leakage out of the
designated injection zone could pose a risk to USDWs and therefore
could be subject to enforcement action or permit modification.
Therefore, the EPA believes that UIC protections for USDWs would also
ensure that the injected CO2 is contained in the subsurface
formations. The Class II programs of states and tribes must be approved
by the EPA and must meet EPA regulatory requirements for Class II
programs, 42 U.S.C. 300h-1, or otherwise represent an effective program
to prevent endangerment of USDWs. 42 U.S.C 300h-4. The EPA's
regulations require the operator of a Class II well to obtain a Class
VI permit when operations shift to geologic sequestration and there is
consequently an increased risk to USDWs. 40 CFR 144.19. UIC Class VI
regulations require that owners or operators must show that the
injection zone has sufficient volume to contain the injected carbon
dioxide stream and report any fluid migration out of the injection zone
and into or between USDWs. 40 CFR 146.83 and 40 CFR 146.91. The EPA
emphasizes that while CO2 captured from an EGU can be
injected into a Class II ER injection well, it cannot be injected into
the other two types of Class II wells, which are Class II disposal
wells and Class II wells for the storage of hydrocarbons. 40 CFR
144.6(b).
Comment: Some commenters expressed concern that because few Class
VI permits have been issued, the EPA's current level of experience in
properly regulating and reviewing permits for these wells is limited.
[[Page 39873]]
Response: The EPA disagrees that the Agency lacks experience to
properly regulate, and review permits for Class VI injection wells. We
expect that the additional resources that have been allocated for the
Class VI program will lead to increased efficiencies in the Class VI
permitting process and timeframes. For a more detailed discussion of
Class VI permitting and timeframes, see sections VII.C.1.a.i(D)(4)(b)
and VII.C.1.a.i(D)(5) of this preamble. The EPA emphasizes that
incomplete or insufficient application materials can result in
substantially delayed permitting decisions. When the EPA receives
incomplete or insufficient permit applications, the EPA communicates
the deficiencies, waits to receive additional materials from the
applicant, and then reviews any new data. This back and forth can
result in longer permitting timeframes. The EPA therefore encourages
applicants to contact their permitting authority early on so applicants
can gain a thorough understanding of the Class VI permitting process
and the permitting authority's expectations. To assist potential permit
applicants, the EPA maintains a list of UIC contacts within each EPA
Regional Office on the Agency's website.\581\ The EPA has met with more
than 100 companies and other interested parties.
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\581\ EPA. (2023). Underground Injection Control Class VI
(Geologic Sequestration) Contact Information. https://www.epa.gov/uic/underground-injection-control-class-vi-geologic-sequestration-contact-information.
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Comment: Some commenters claimed that various legal uncertainties
preclude a finding that geologic sequestration of CO2 has
been adequately demonstrated. This concern has been raised in
particular with issues of pore space ownership and the lack of long-
term liability insurance and noted uncertainties regarding long-term
liability generally.
Response: The EPA disagrees that these uncertainties are sufficient
to prohibit the development of geologic sequestration projects. An
interagency CCS task force examined sequestration-related legal issues
thoroughly and concluded that early CCS projects could proceed under
the existing legal framework with respect to issues such as property
rights and liability.\582\ The development of CCS projects may be more
complex in certain regions, due to distinct pore space ownership
regulatory regimes at the state level, except on Federal lands.\583\
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\582\ Report of the Interagency Task Force on Carbon Capture and
Storage. 2010. https://www.energy.gov/fecm/articles/ccstf-final-report.
\583\ Council on Environmental Quality Report to Congress on
Carbon Capture, Utilization, and Sequestration. 2021. https://www.whitehouse.gov/wp-content/uploads/2021/06/CEQ-CCUS-Permitting-Report.pdf.
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As discussed in section VII.C.1.a.i.(D)(4) of this preamble, Title
V of the FLPMA and its implementing regulations, 43 CFR part 2800,
authorize the BLM to issue ROWs to geologically sequester
CO2 in Federal pore space, including BLM ROWs for the
necessary physical infrastructure and for the use and occupancy of the
pore space itself. The BLM has published a policy defining access to
pore space on BLM lands, including clarification of Federal policy for
situations where the surface and pore space are under the control of
different Federal agencies.\584\
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\584\ National Policy for the Right-of-Way Authorizations
Necessary for Site Characterization, Capture, Transportation,
Injection, and Permanent Geologic Sequestration of Carbon Dioxide in
Connection with Carbon Sequestration Projects. BLM IM 2022-041
Instruction Memorandum, June 8, 2022. https://www.blm.gov/policy/im-2022-041.
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States have established legislation and regulations defining pore
space ownership and providing clarification to prospective users of
surface pore space. For example, in North Dakota, the surface owner
also owns the pore space underlying their surface estate.\585\ North
Dakota state courts have determined that in situations where the
surface ownership and mineral ownership have been legally severed the
mineral estate is the dominant estate and has the right to use as much
of the surface estate as reasonably necessary. The North Dakota
legislature codified this interpretation in 2019.\586\ Summit Carbon
Solutions, which is developing a carbon storage hub in North Dakota to
store an estimated one billion tons of CO2, indicated that
they had secured the majority of the pore space needed through long
term leases with landowners.\587\ Wyoming defines ownership of pore
space underlying surfaces within the state.\588\ Other states have also
established laws, implementing regulations and guidance defining
ownership and access to pore space. The EPA notes that many states are
actively enacting legislation addressing pore space ownership. See
e.g., Wyoming H.B. No. 89 (2008) (Wyo. Stat. Sec. 34-1-152); Montana
S.B. No. 498 (2009) (Mont. Code Ann. 82-11-180); North Dakota S.B. No.
2139 (2009) (N.D. Cent. Code Sec. 47-31-03); Kentucky H.B. 259 (2011)
(Ky. Rev. Stat. Ann. Sec. 353.800); West Virginia H.B. 4491 (2022) (W.
Va. Code Sec. 22-11B-18); California S.B. No. 905 (2022) (Cal. Pub.
Res. Code Sec. 71462); Indiana Public Law 163 (2022) (Ind. Code Sec.
14-39-2-3); Utah H.B. 244 (2022) (Utah Code Sec. 40-6-20.5).
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\585\ ND DMR 2023. Pore Space in North Dakota. North Dakota
Department of Mineral Resources https://www.dmr.nd.gov/oilgas/ND_DMR_Pore_Space_Information.pdf.
\586\ Ibid.
\587\ Summit Carbon Solutions. (2021). Summit Carbon Solutions
Announces Significant Carbon Storage Project Milestones. (2021).
https://summitcarbonsolutions.com/summit-carbon-solutions-announces-significant-carbon-storage-project-milestones/.
\588\ Wyo. Stat Sec. 34-1-152 (2022).
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Liability during operation is usually assumed by the project
operator, so liability concerns primarily arise after the period of
operations. Research has previously shown that the environmental risk
is greatest before injection stops.\589\ In terms of long-term
liability and permittee obligations under the SDWA, the EPA's Class VI
regulations impose various requirements on permittees even after
injection ceases, including regarding injection well plugging (40 CFR
146.92), post-injection site care (PISC), and site closure (40 CFR
146.93). The default time period for post-injection site care is 50
years, during which the permittee must monitor the position of the
CO2 plume and pressure front and demonstrate that USDWs are
not being endangered. 40 CFR 146.93. The permittee must also generally
maintain financial responsibility sufficient to cover injection well
plugging, corrective action, emergency and remedial response, PISC, and
site closure until the permitting authority approves site closure. 40
CFR 146.85(a)&(b). Even after the former permittee has fulfilled all
its UIC regulatory obligations, it may still be held liable for
previous regulatory noncompliance, such as where the permittee provided
erroneous data to support approval of site closure. A former permittee
may always be subject to an order that the EPA Administrator deems
necessary to protect public health if there is fluid migration that
causes or threatens imminent and substantial endangerment to a USDW. 42
U.S.C. 300i; 40 CFR 144.12(e).
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\589\ Benson, S.M. (2007). Carbon dioxide capture and storage:
research pathways, progress and potential. Presentation given at the
Global Climate & Energy Project Annual Symposium, October 1, 2007.
https://drive.google.com/file/d/1ZvfRW92OqvBBAFs69SPHIWoYFGySMgtD/view.
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The EPA notes that many states are enacting legislation addressing
long term liability. See e.g., Montana S.B. No. 498 (2009) (Mont. Code
Ann. 82-11-183); Texas H.B. 1796 (2009) (Tex. Health & Safety Code Ann.
Sec. 382.508); North Dakota S.B. No. 2095 (2009) (N.D. Cent. Code
Sec. 38-22-17); Kansas H.B.
[[Page 39874]]
2418 (2010) (Kan. Stat. Ann. Sec. 55-1637(h)); Wyoming S.F. No. 47
(2022) (Wyo. Stat. Sec. Sec. 35-11-319); Louisiana H.B. 661 (2009) &
H.B. 571 (2023) (La. Stat. Ann. Sec. 30:1109). Because states are
actively working to address pore space and liability uncertainties, the
EPA does not believe these to be issues that would delay project
implementation beyond the timelines discussed in this preamble.
(E) Compliance Date for Long-Term Coal-Fired Steam Generating Units
The EPA proposed a January 1, 2030 compliance date for long-term
coal fired steam generating units subject to a CCS BSER. That
compliance date assumed installation of CCS was concurrent with
development of state plans. While several commenters were supportive of
the proposed compliance date, the EPA also received comments on the
proposed rule that stated that the proposed compliance date was not
achievable. Commenters referenced longer project timelines for
CO2 capture. Commenters also requested that the EPA should
account for the state plan process in determining the appropriate
compliance date.
The EPA has considered the comments and information available and
is finalizing a compliance date of January 1, 2032, for long-term coal-
fired steam generating units. The EPA is also finalizing a mechanism
for a 1-year compliance date extension in cases where a source faces
delays outside its control, as detailed in section X.C.1.d of this
preamble. The justification for the January 1, 2032 compliance date
does not require substantial work to be done during the state planning
process. Rather, the justification for the compliance date reflects the
assumption that only the initial feasibility work which is necessary to
inform the state planning process would occur during state plan
development, with the start of more substantial work beginning after
the due date for state plan submission, and a longer timeline for
installation of CCS than at proposal. In total, this allows for 6 years
and 7 months for both initial feasibility and more substantial work to
occur after issuance of this rule. This is consistent with the
approximately 6 years from start to finish for Boundary Dam Unit 3 and
Petra Nova.
The timing for installation of CCS on existing coal-fired steam
generating units is based on the baseline project schedule for the
CO2 capture plant developed by Sargent and Lundy (S&L \590\
and a review of the available information for installation of
CO2 pipelines and sequestration sites.\591\ Additional
details on the timeline are in the TSD GHG Mitigation Measures for
Steam Generating Units, available in the docket. The dates for
intermediate steps are for reference. The specific sequencing of steps
may differ slightly, and, for some sources, the duration of one step
may be shorter while another may be longer, however the total duration
is expected to be the same. The resulting timeline is therefore an
accurate representation of the time necessary to install CCS in
general.
---------------------------------------------------------------------------
\590\ CO2 Capture Project Schedule and Operations
Memo, Sargent & Lundy (2024). Available in Docket ID EPA-HQ-OAR-
2023-0072.
\591\ Transport and Storage Timeline Summary, ICF (2024).
Available in Docket ID EPA-HQ-OAR-2023-0072.
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The EPA assumes that feasibility work, amounting to less than 1
year (June 2024 through June 2025) for each component of CCS (capture,
transport, and storage) occurs during the state plan development period
(June 2024 through June 2026). This feasibility work is limited to
initial conceptual design and other preliminary tasks, and the costs of
the feasibility work in general are substantially less than other
components of the project schedule. The EPA determined that it was
appropriate to assume that this work would take place during the state
plan development period because it is necessary for evaluating the
controls that the state may determine to be appropriate for a source
and is necessary for determining the resulting standard of performance
that the state may apply to the source on the basis of those controls.
In other words, without such feasibility and design work, it would be
very difficult for a state to determine whether CCS is appropriate for
a given source or the resulting standard of performance. While the EPA
accounts for up to 1 year for feasibility for the capture plant, the
S&L baseline schedule estimates this initial design activity can be
completed in 6 months. For the capture plant, feasibility includes a
preliminary technical evaluation to review the available utilities and
siting footprint for the capture plant, as well as screening of the
available capture technologies and vendors for the project, with an
associated initial economic estimate. For sequestration, in many cases,
general geologic characterization of regional areas has already been
conducted by U.S. DOE and regional initiatives; however, the EPA
assumes an up to 1 year period for a storage complex feasibility study.
For the pipeline, the feasibility includes the initial pipeline routing
analysis, taking less than 1 year. This exercise involves using
software to review existing right-of-way and other considerations to
develop an optimized pipeline route. Inputs to that analysis have been
made publicly available by DOE in NETL's Pipeline Route Planning
Database.\592\
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\592\ NETL Develops Pipeline Route Planning Database To Guide
CO2 Transport Decisions. May 31, 2023. https://netl.doe.gov/node/12580.
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When state plans are submitted 24 months after publication of the
final rule, requirements included within those state plans should be
effective at the state level. On that basis, the EPA assumes that
sources installing CCS are fully committed, and more substantial work
(e.g., FEED study for the capture plant, permitting, land use and
right-of-way acquisition) resumes in June 2026. The EPA notes, however,
that it would be possible that a source installing CCS would choose to
continue these activities as soon as the initial feasibility work is
completed even if not yet required to do so, rather than wait for state
plan submission to occur for the reasons explained in full below.
Of the components of CCS, the CO2 capture plant is the
more technically involved and time consuming, and therefore is the
primary driver for determining the compliance date. The EPA assumes
substantial work commences only after submission due date for state
plans. The S&L baseline timeline accounts for 5.78 years (301 weeks)
for final design, permitting, and installation of the CO2
capture plant. First, the EPA describes the timeline that is consistent
with the S&L baseline for substantial work. Subsequently, the EPA
describes the rationale for slight adjustments that can be made to that
timeline based upon an examination of actual project timelines.
In the S&L baseline, substantial work on the CO2 capture
plant begins with a 1-year FEED study (June 2026 to June 2027). The
information developed in the FEED study is necessary for finalizing
commercial arrangements. In the S&L baseline, the commercial
arrangements can take up to 9 months (June 2027 to March 2028).
Commercial arrangements include finalizing funding as well as
finalizing contracts with a CO2 capture technology provider
and engineering, procurement, and construction companies. The S&L
baseline accounts for 1 year for permitting, beginning when commercial
arrangements are nearly complete (December 2027 to December 2028).
After commercial arrangements are complete, a 2-year period for
engineering and procurement begins (March 2028 to March 2030).
[[Page 39875]]
Detailed engineering starts after commercial arrangements are complete
because engineers must consider details regarding the selected
CO2 capture technology, equipment providers, and
coordination with construction. Shortly after permitting is complete, 6
months of sitework (March 2029 to September 2029) occur. Sitework is
followed by 2 years of construction (July 2029 to July 2031).
Approximately 8 months prior to the completion of construction, a
roughly 14 month (60 weeks) period for startup and commissioning begins
(January 2031 to March 2032).
In many cases, the EPA believes that sources are positioned to
install CO2 capture on a slightly faster timeline than the
baseline S&L timeline detailed in the prior paragraph, because CCS
projects have been developed in a shorter timeframe. Including these
minor adjustments, the total time for detailed engineering,
procurement, construction, startup and commissioning is 4 years, which
is consistent with completed projects (Boundary Dam Unit 3 and Petra
Nova) and project schedules developed in completed FEED studies, see
the final TSD, GHG Mitigation Measures for Steam Generating Units for
additional details. In addition, the IRC tax credits incentivize
sources to begin complying earlier to reap economic benefits earlier.
Sources that have already completed feasibility or FEED studies, or
that have FEED studies ongoing are likely to be able to have CCS fully
operational well in advance of January 1, 2032. Ongoing projects have
planned dates for commercial operation that are much earlier. For
example, Project Diamond Vault has plans to be fully operational in
2028.\593\ While the EPA assumes FEED studies start after the date for
state plan submission, in practice sources are likely to install
CO2 capture as expeditiously as practicable. Moreover, the
preceding timeline is derived from project schedules developed in the
absence of any regulatory impetus. Considering these factors, sources
have opportunities to slightly condense the duration, overlap, or
sequencing of steps so that the total duration for completing
substantial work on the capture plant is reduced by 2 months. For
example, by expediting the duration for commercial arrangements from 9
months to 7 months, reasonably assuming sources immediately begin
sitework as soon as permitting is complete, and accounting for 13
months (rather than 14) for startup and testing, the CO2
capture plant will be fully operational by January 2032. Therefore, the
EPA concludes that CO2 capture can be fully operational by
January 1, 2032. To the extent additional time is needed to take into
account the particular circumstances of a particular source, the state
may take those circumstances into account to provide a different
compliance schedule, as detailed in section X.C.2 of this preamble.
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\593\ Project Diamond Vault Overview. https://www.cleco.com/docs/default-source/diamond-vault/project_diamond_vault_overview.pdf.
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The EPA also notes that there is additional time for permitting
than described in the S&L baseline. The key permitting that affects the
timeline are air permits because of the permits' impact on the ability
to construct and operate the CCS capture equipment, in which the EPA is
the expert in. The S&L baseline assumes permitting starts after the
FEED study is complete while commercial arrangements are ongoing,
however permitting can begin earlier allowing a more extended period
for permitting. Examples of CCS permitting being completed while FEED
studies are on-going include the air permits for Project Tundra,
Baytown Energy Center, and Deer Park Energy Center. Therefore, while
the FEED study is on-going, the EPA assumes that a 2-year process for
permitting can begin.
The EPA's compliance deadline assumes that storage and pipelines
for the captured CO2 can be installed concurrently with
deployment of the capture system. Substantial work on the storage site
starts with 3 years (June 2026 to June 2029) for final site
characterization, pore-space acquisition, and permitting, including at
least 2 years for permitting of Class VI wells during that period.
Lastly, construction for sequestration takes 1 year (June 2029 to June
2030). While the EPA assumes that storage can be permitted and
constructed in 4 years, the EPA notes that there is at least an
additional 12 months of time available to complete construction of the
sequestration site without impacting progress of the other components.
The EPA assumes the substantial work on the pipeline lags the start
of substantial work on the storage site by 6 months. After the 1 year
of feasibility work prior to state plan submission, the general
timeline for the CO2 pipeline assumes up to 3 years for
final routing, permitting activities, and right-of-way acquisition
(December 2026 to December 2029). Lastly, there are 1.5 years for
pipeline construction (December 2029 to June 2031).\594\
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\594\ The summary timeline for CO2 pipelines assumes
feasibility for pipelines is 1 year, followed by 1.5 years for
permitting, with the pipeline feasibility beginning 1 year after
permitting for sequestration starts. The EPA assumes initial
pipeline feasibility occurs up-front, with a longer period for final
routing, permitting, and right-of-way acquisition.
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The EPA does not assume that CCS projects are, in general, subject
to NEPA. NEPA review is required for reasons including sources
receiving federal funding (e.g., through USDA or DOE) or projects on
federal lands. NEPA may also be triggered for a CCS project if NEPA
compliance is necessary for construction of the pipeline, such as where
necessary because of a Clean Water Act section 404 permit, or for
sequestration. Generally, if one aspect of a project is subject to
NEPA, then the other project components could be as well. In cases
where a project is subject to NEPA, an environmental assessment (EA)
that takes 1 year, can be finalized concurrently during the permitting
periods of each component of CCS (capture, pipeline, and
sequestration). However, the EPA notes that the final timeline can also
accommodate a concurrent 2-year period if an EIS were required under
NEPA across all components of the project. The EPA also notes that, in
some circumstances, NEPA review may begin prior to completion of a FEED
study. For Petra Nova, a notice of intent to issue an EIS was published
on November 14, 2011, and the record of decision was issued less than 2
years later, on May 23, 2013,\595\ while the FEED study was completed
in 2014.
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\595\ Petra Nova W.A. Parish Project. https://www.energy.gov/fecm/petra-nova-wa-parish-project.
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Based on this detailed analysis, the EPA has concluded that January
1, 2032, is an achievable compliance date for CCS on existing coal-
fired steam generating units that takes into account the state plan
development period, as well as the technical and bureaucratic steps
necessary to install and implement CCS and is consistent with other
expert estimates and real-world experience.
(F) Long-Term Coal-Fired Steam Generating Units Potentially Subject to
This Rule
In this section of the preamble, the EPA estimates the size of the
inventory of coal-fired power plants in the long-term subcategory
likely subject to CCS as the BSER. Considering that capacity, the EPA
also describes the distance to storage for those sources.
(1) Capacity of Units Potentially Subject to This Rule
First, the EPA estimates the total capacity of units that are
currently operating and that have not announced plans to retire by
2039, or to cease firing
[[Page 39876]]
coal by 2030. Starting from that first estimate, the EPA then estimates
the capacity of units that would likely be subject to the CCS
requirement, based on unit age, industry trends, and economic factors.
Currently, there are 181 GW of coal-fired steam generating
units.\596\ About half of that capacity, totaling 87 GW, have announced
plans to retire before 2039, and an additional 13 GW have announced
plans to cease firing coal by that time. The remaining amount, 81 GW,
are likely to be the most that could potentially be subject to
requirements based on CCS.
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\596\ EIA December 2023 Preliminary Monthly Electric Generator
Inventory. https://www.eia.gov/electricity/data/eia860m/.
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However, the capacity of affected coal-fired steam generating units
that would ultimately be subject to a CCS BSER is likely approximately
40 GW. This determination is supported by several lines of analysis of
the historical data on the size of the fleet over the past several
years. Historical trends in the coal-fired generation fleet are
detailed in section IV.D.3 of this preamble. As coal-fired units age,
they become less efficient and therefore the costs of their electricity
go up, rendering them even more competitively disadvantaged. Further,
older sources require additional investment to replace worn parts.
Those circumstances are likely to continue through the 2030s and beyond
and become more pronounced. These factors contribute to the historical
changes in the size of the fleet.
One way to analyze historical changes in the size of the fleet is
based on unit age. As the average age of the coal-fired fleet has
increased, many sources have ceased operation. From 2000 to 2022, the
average age of a unit that retired was 53 years. At present, the
average age of the operating fleet is 45 years. Of the 81 GW that are
presently operating and that have not announced plans to retire or
convert to gas prior to 2039, 56 GW will be 53 years or older by
2039.\597\
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\597\ 81 GW is derived capacity, plant type, and retirement
dates as represented in EPA NEEDS database. Total amount of covered
capacity in this category may ultimately be slightly less
(approximately) due to CHP-related exemptions.
---------------------------------------------------------------------------
Another line of analysis is based on the rate of change of the size
of the fleet. The final TSD, Power Sector Trends, available in the
rulemaking docket, includes analysis showing sharp and steady decline
in the total capacity of the coal-fired steam generating fleet. Over
the last 15 years (2009-2023), average annual coal retirements have
been 8 GW/year. Projecting that retirements will continue at
approximately the same pace from now until 2039 is reasonable because
the same circumstances will likely continue or accelerate further given
the incentives under the IRA. Applying this level of annual retirement
would result in 45 GW of coal capacity continuing to operate by 2039.
Alternatively, the TSD also includes a graph that shows what the fleet
would look like assuming that coal units without an announced
retirement date retire at age 53 (the average retirement age of units
over the 2000-2022 period). It shows that the amount of coal-fired
capacity that remains in operation by 2039 is 38 GW.
The EPA also notes that it is often the case that coal-fired units
announce that they plan to retire only a few years in advance of the
retirement date. For instance, of the 15 GW of coal-fired EGUs that
reported a 2022 retirement year in DOE's EIA Form 860, only 0.5 GW of
that capacity had announced its retirements plans when reporting in to
the same EIA-860 survey 5 years earlier, in 2017.\598\ Thus, although
many coal-fired units have already announced plans to retire before
2039, it is likely that many others may anticipate retiring by that
date but have not yet announced it.
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\598\ The survey Form EIA-860 collects generator-level specific
information about existing and planned generators and associated
environmental equipment at electric power plants with 1 megawatt or
greater of combined nameplate capacity. Data available at https://www.eia.gov/electricity/data/eia860/.
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Finally, the EPA observes that modeling the baseline circumstances,
absent this final rule, shows additional retirements of coal-fired
steam generating units. At the end of 2022, there were 189 GW of coal
active in the U.S. By 2039, the IPM baseline projects that there will
be 42 GW of operating coal-fired capacity (not including coal-to-gas
conversions). Between 2023-2039, 95 GW of coal capacity have announced
retirement and an additional 13 have announced they will cease firing
coal. Thus, of the 81 GW that have not announced retirement or
conversion to gas by 2039, the IPM baseline projects 39 GW will retire
by 2039 due to economic reasons.
For all these reasons, the EPA considers that it is realistic to
expect that 42 GW of coal-fired generating will be operating by 2039--
based on announced retirements, historical trends, and model
projections--and therefore constitutes the affected sources in the
long-term subcategory that would be subject to requirements based on
CCS. It should be noted that the EPA does not consider the above
analysis to predict with precision which units will remain in operation
by 2039. Rather, the two sets of sources should be considered to be
reasonably representative of the inventory of sources that are likely
to remain in operation by 2039, which is sufficient for purposes of the
BSER analysis that follows.
(2) Distance to Storage for Units Potentially Subject to This Rule
The EPA believes that it is conservative to assume that all 81 GW
of capacity with planned operation during or after 2039 would need to
construct pipelines to connect to sequestration sites. As detailed in
section VII.B.2 of this preamble, the EPA is finalizing an exemption
for coal-fired sources permanently ceasing operation by January 1,
2032. About 42 percent (34 GW) of the existing coal-fired steam
generation capacity that is currently in operation and has not
announced plans to retire prior to 2039 will be 53 years or older by
2032. As discussed in section VII.C.1.a.i(F), from 2000 to 2022, the
average age of a coal unit that retired was 53 years old. Therefore,
the EPA anticipates that approximately 34 GW of the total capacity may
permanently cease operation by 2032 despite not having yet announced
plans to do so. Furthermore, of the coal-fired steam generation
capacity that has not announced plans to cease operation before 2039
and is further than 100 km (62 miles) of a potential saline
sequestration site, 45 percent (7 GW) will be over 53 years old in
2032. Therefore, it is possible that much of the capacity that is
further than 100 km (62 miles) of a saline sequestration site and has
not announced plans to retire will permanently cease operation due to
age before 2032 and thus the rule would not apply to them. Similarly,
of the coal-fired steam generation capacity that has not announced
plans to cease operation before 2039 and is further than 160 km (100
miles) of a potential saline sequestration site, 56 percent (4 GW) will
be over 53 years old in 2032. Therefore, the EPA notes that it is
possible that the majority of capacity that is further than 160 km (100
miles) of a saline sequestration and has not announced plans to retire
site will permanently cease operation due to age before 2032 and thus
be exempt from the requirements of this rule.
The EPA also notes that a majority (56 GW) of the existing coal-
fired steam generation capacity that is currently in operation and has
not announced plans to permanently cease operation prior to 2039 will
be 53 years or older by 2039. Of the coal-fired steam generation
capacity with planned operation during
[[Page 39877]]
or after 2039 that is not located within 100 km (62 miles) of a
potential saline sequestration site, the majority (58 percent or 9 GW)
of the units will be 53 years or older in 2039.\599\ Consequently, the
EPA believes that many of these units may permanently cease operation
due to age prior to 2039 despite not at this point having announced
specific plans to do so, and thereby would likely not be subject to a
CCS BSER.
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\599\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details,
please see chapter 6 of the IPM documentation available at:. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
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(G) Resources and Workforce To Install CCS
Sufficient resources and an available workforce are required for
installation and operation of CCS. Raw materials necessary for CCS are
generally available and include common commodities such as steel and
concrete for construction of the capture plant, pipelines, and storage
wells.
Drawing on data from recently published studies, the DOE completed
an order-of-magnitude assessment of the potential requirements for
specialized equipment and commodity materials for retrofitting existing
U.S. coal-fueled EGUs with CCS.\600\ Specialized equipment analyzed
included absorbers, strippers, heat exchangers, and compressors.
Commodity materials analyzed included monoethanolamine (MEA) solvent
for carbon capture, triethylene glycol (TEG) for carbon dioxide drying,
and steel and cement for construction of certain aspects of the CCS
value chain.\601\ The DOE analyzed one scenario in which 42 GW of coal-
fueled EGUs are retrofitted with CCS and a second scenario in which 73
GW of coal-fueled EGUs are retrofitted with CCS.\602\ The analysis
determined that in both scenarios, the maximum annual commodity
requirements to construct and operate the CCS systems are likely to be
much less than their respective global production rates. The maximum
requirements are expected to be at least one order of magnitude lower
than global annual production for all of the commodities considered
except MEA, which was estimated to be approximately 14 percent of
global annual production in the 42 GW scenario and approximately 24
percent of global annual production in the 73 GW scenario.\603\ For
steel and cement, the maximum annual requirements are also expected to
be at least one order of magnitude lower than U.S. annual production
rates. Finally, the DOE analysis determined that it is unlikely that
the deployment scenarios would encounter any bottlenecks in the
supplies of specialized equipment (absorbers, strippers, heat
exchangers, and compressors) because of the large pool of potential
suppliers.
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\600\ DOE. Material Requirements for Carbon Capture and Storage
Retrofits on Existing Coal-Fueled Electric Generating Units. https://www.energy.gov/policy/articles/material-requirements-carbon-capture-and-storage-retrofits-existing-coal-fueled.
\601\ Steel requirements were assessed for carbon capture,
transport and storage, but cement requirements were only assessed
for capture and storage.
\602\ DOE analyzed the resources--including specialized
equipment, commodity materials, and, as discussed below, workforce,
necessary for 73 GW of coal capacity to install CCS because that is
the amount that has not announced plans to retire by January 1,
2040. As indicated in the final TSD, Power Sector Trends, a somewhat
larger amount--81 GW--has not announced plans to retire or cease
firing coal by January 1, 2039, and it is this latter amount that is
the maximum that, at least in theory, could be subject to the CCS
requirement. DOE's conclusions that sufficient resources are
available also hold true for the larger amount.
\603\ Although the assessment assumed that all of the CCS
deployments would utilize MEA-based carbon capture technologies,
future CCS deployments could potentially use different solvents, or
capture technologies that do not use solvents, e.g., membranes,
sorbents. A number of technology providers have solvents that are
commercially available, as detailed in section VII.C.1.a.i.(B)(3) of
this preamble. In addition, a 2022 DOE carbon capture supply chain
assessment concluded that common amines used in carbon capture have
robust and resilient supply chains that could be rapidly scaled,
with low supply chain risk associated with the main inputs for
scale-up. See U.S. Department of Energy (DOE). Supply Chain Deep
Dive Assessment: Carbon Capture, Transport & Storage. https://www.energy.gov/sites/default/files/2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf.
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The workforce necessary for installing and operating CCS is readily
available. The required workforce includes construction, engineering,
manufacturing, and other skilled labor (e.g., electrical, plumbing, and
mechanical trades). The existing workforce is well positioned to meet
the demand for installation and operation of CCS. Many of the skills
needed to build and operate carbon capture plants are similar to those
used by workers in existing industries, and this experience can be
leveraged to support the workforce needed to deploy CCS. In addition,
government programs, industry workforce investments, and IRC section
45Q prevailing wage and apprenticeship provisions provide additional
significant support to workforce development and demonstrate that the
CCS industry likely has the capacity to train and expand the available
workforce to meet future needs.\604\
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\604\ DOE. Workforce Analysis of Existing Coal Carbon Capture
Retrofits. https://www.energy.gov/policy/articles/workforce-analysis-existing-coal-carbon-capture-retrofits.
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Overall, quantitative estimates of workforce needs indicates that
the total number of jobs needed for deploying CCS on coal power plants
is significantly less than the size of the existing workforce in
adjacent occupations with transferrable skills in the electricity
generation and fuels industries. The majority of direct jobs,
approximately 90 percent, are expected to be in the construction of
facilities, which tend to be project-based. The remaining 10 percent of
jobs are expected to be tied to ongoing facility operations and
maintenance.\605\ Recent project-level estimates bear this out. The
Boundary Dam CCS facility in Canada employed 1,700 people at peak
construction.\606\ A recent workforce projection estimates average
annual jobs related to investment in carbon capture retrofits at coal
power plants could range from 1,070 to 1,600 jobs per plant. A DOE
memorandum estimates that 71,400 to 107,100 average annual jobs
resulting from CCS project investments--across construction, project
management, machinery installers, sales representatives, freight, and
engineering occupations--would likely be needed over a five-year
construction period \607\ to deploy CCS at
[[Page 39878]]
a subset of coal power plants. The memorandum further estimates that
116,200 to 174,300 average annual jobs would likely be needed if CCS
were deployed at all coal-fired EGUs that currently have no firm
commitment to retire or convert to natural gas by 2040.\608\ For
comparison, the DOE memorandum further categorizes potential workforce
needs by occupation, and estimates 11,420 to 27,890 annual jobs for
construction trade workers, while the U.S. Energy and Employment Report
estimates that electric power generation and fuels accounted for more
than 292,000 construction jobs in 2022, which is an order of magnitude
greater than the potential workforce needs for CCS deployment under
this rule. Overall energy-related construction activities across the
entire energy industry accounted for nearly 2 million jobs, or 25
percent of all construction jobs in 2022, indicating that there is a
very large pool of workers potentially available.\609\
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\605\ Ibid.
\606\ SaskPower, ``SaskPower CCS.'' https://unfccc.int/files/bodies/awg/application/pdf/01_saskatchewan_environment_micheal_monea.pdf. For corroboration, we
note similar employment numbers for two EPAct-05 assisted projects:
Petra Nova estimated it would need approximately 1,100 construction-
related jobs and up to 20 jobs for ongoing operations. National
Energy Technology Laboratory and U.S. Department of Energy. W.A.
Parish Post-Combustion CO2 Capture and Sequestration Project, Final
Environmental Impact Statement. https://www.energy.gov/sites/default/files/EIS-0473-FEIS-Summary-2013_1.pdf. Project Tundra
projects a peak labor force of 600 to 700. National Energy
Technology Laboratory and U.S. Department of Energy. Draft
Environmental Assessment for North Dakota CarbonSAFE: Project
Tundra. https://www.energy.gov/sites/default/files/2023-08/draft-ea-2197-nd-carbonsafe-chapters-2023-08.pdf.
\607\ For the purposes of evaluating the actual workforce and
resources necessary for installation of CCS, the five-year
assumption in the DOE memo is reasonable. The representative
timeline for CCS includes an about 3-year period for construction
activities (including site work, construction, and startup and
testing) across the components of CCS (capture, pipeline, and
sequestration), beginning at the end of 2028. Many sources are well
positioned to install CCS, having already completed feasibility
work, FEED studies, and/or permitting, and could thereby reasonably
start construction activities (still 3-years in duration) by the
beginning of 2028 or earlier and, as a practical matter, would
likely do so notwithstanding the requirements of this rule given the
strong economic incentives provided by the tax credit. The
representative timeline also makes conservative assumptions about
the pre-construction activities for pipelines and sequestration, and
for many sources construction of those components could occur
earlier. Finally, to provide greater regulatory certainty and
incentivize the installation of controls, the EPA is finalizing a
limited one-year compliance date extension mechanism for certain
circumstances as detailed in section X.C.1.d of the preamble, and it
would also be reasonable to assume that, in practice, some sources
use that mechanism. Considering these factors, evaluating workforce
and resource requirements over a five-year period is reasonable.
\608\ DOE. Workforce Analysis of Existing Coal Carbon Capture
Retrofits. https://www.energy.gov/policy/articles/workforce-analysis-existing-coal-carbon-capture-retrofits.
\609\ U.S. Department of Energy. United States Energy &
Employment Report 2023. https://www.energy.gov/sites/default/files/2023-06/2023%20USEER%20REPORT-v2.pdf.
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As noted in section VII.C.1.a.i(F), the EPA determined that the
population of sources without announced plans to cease operation or
discontinue coal-firing by 2039, and that is therefore potentially
subject to a CCS BSER, is not more than 81 GW, as indicated in the
final TSD, Power Sector Trends. The DOE CCS Commodity Materials and
Workforce Memos evaluated material resource and workforce needs for a
similar capacity (about 73 GW), and determined that the resources and
workforce available are more than sufficient, in most cases by an order
of magnitude. Considering these factors, and the similar scale of the
population of sources considered, the EPA therefore concludes that the
workforce and resources available are more than sufficient to meet the
demands of coal-fired steam generating units potentially subject to a
CCS BSER.
(H) Determination That CCS Is ``Adequately Demonstrated''
As discussed in detail in section V.C.2.b, pursuant to the text,
context, legislative history, and judicial precedent interpreting CAA
section 111(a)(1), a technology is ``adequately demonstrated'' if there
is sufficient evidence that the EPA may reasonably conclude that a
source that applies the technology will be able to achieve the
associated standard of performance under the reasonably expected
operating circumstances. Specifically, an adequately demonstrated
standard of performance may reflect the EPA's reasonable expectation of
what that particular system will achieve, based on analysis of
available data from individual commercial scale sources, and, if
necessary, identifying specific available technological improvements
that are expected to improve performance.\610\ The law is clear in
establishing that at the time a section 111 rule is promulgated, the
system that the EPA establishes as BSER need not be in widespread use.
Instead, the EPA's responsibility is to determine that the demonstrated
technology can be implemented at the necessary scale in a reasonable
period of time, and to base its requirements on this understanding.
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\610\ A line of cases establishes that the EPA may extrapolate
based on its findings and project technological improvements in a
variety of ways. First, the EPA may reasonably extrapolate from
testing results to predict a lower emissions rate than has been
regularly achieved in testing. See Essex Chem. Corp. v. Ruckelshaus,
486 F.2d 427, 433 (D.C. Cir. 1973). Second, the EPA may forecast
technological improvements allowing a lower emissions rate or
effective control at larger plants than those previously subject to
testing, provided the agency has adequate knowledge about the needed
changes to make a reasonable prediction. See Sierra Club v. Costle
657 F.2d 298 (1981). Third, the EPA may extrapolate based on testing
at a particular kind of source to conclude that the technology at
issue will also be effective at a different, related, source. See
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999).
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In this case, the EPA acknowledged in the proposed rule, and
reaffirms now, that sources will require some amount of time to install
CCS. Installing CCS requires the building of capture facilities and
pipelines to transport captured CO2 to sequestration sites,
and the development of sequestration sites. This is true for both
existing coal plants, which will need to retrofit CCS, and new gas
plants, which must incorporate CCS into their construction planning. As
the EPA explained at proposal, D.C. Circuit caselaw supports this
approach.\611\ Moreover, the EPA has determined that there will be
sufficient resources for all coal-fired power plants that are
reasonably expected to be operating as of January 1, 2039, to install
CCS. Nothing in the comments alters the EPA's view of the relevant
legal requirements related to the EPA's determination of time necessary
to allow for adoption of the system.
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\611\ There, EPA cited Portland Cement v. Ruckelshaus, for the
proposition that ``D.C. Circuit caselaw supports the proposition
that CAA section 111 authorizes the EPA to determine that controls
qualify as the BSER--including meeting the `adequately demonstrated'
criterion--even if the controls require some amount of `lead time,'
which the court has defined as `the time in which the technology
will have to be available.' '' See 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, 88
FR 33240, 33289 (May 23, 2023) (quoting Portland Cement Ass'n v.
Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)).
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With all of the above in mind, the preceding sections show that CCS
technology with 90 percent capture is clearly adequately demonstrated
for coal-fired steam generating units, that the 90 percent standard is
achievable,\612\ and that it is reasonable for the EPA to determine
that CCS can be deployed at the necessary scale in the compliance
timeframe.
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\612\ The concepts of ``adequately demonstrated'' and
``achievable'' are closely related. As the D.C. Circuit explained in
Essex Chem. Corp. v. Ruckelshaus, ``[i]t is the system which must be
adequately demonstrated and the standard which must be achievable.''
486 F.2d 427, 433 (1973).
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(1) EPAct05
In the proposal, the EPA noted that in the 2015 NSPS, the EPA had
considered coal-fired industrial projects that had installed at least
some components of CCS technology. In doing so, the EPA recognized that
some of those projects had received assistance in the form of grants,
loan guarantees, and Federal tax credits for investment in ``clean coal
technology,'' under provisions of the Energy Policy Act of 2005
(``EPAct05''). See 80 FR 64541-42 (October 23, 2015). (The EPA refers
to projects that received assistance under that legislation as
``EPAct05-assisted projects.'') The EPA further recognized that the
EPAct05 included provisions that constrained how the EPA could rely on
EPAct05-assisted projects in determining whether technology is
adequately demonstrated for the purposes of CAA section 111.\613\
[[Page 39879]]
In the 2015 NSPS, the EPA went on to provide a legal interpretation of
those constraints. Under that legal interpretation, ``these provisions
[in the EPAct05] . . . preclude the EPA from relying solely on the
experience of facilities that received [EPAct05] assistance, but [do]
not . . . preclude the EPA from relying on the experience of such
facilities in conjunction with other information.'' \614\ Id. at 64541-
42. In this action, the EPA is adhering to the interpretation of these
provisions that it announced in the 2015 NSPS.
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\613\ The relevant EPAct05 provisions include the following:
Section 402(i) of the EPAct05, codified at 42 U.S.C. 15962(a),
provides as follows: ``No technology, or level of emission
reduction, solely by reason of the use of the technology, or the
achievement of the emission reduction, by 1 or more facilities
receiving assistance under this Act, shall be considered to be
adequately demonstrated [ ] for purposes of section 111 of the Clean
Air Act. . . .'' IRC section 48A(g), as added by EPAct05 1307(b),
provides as follows: ``No use of technology (or level of emission
reduction solely by reason of the use of the technology), and no
achievement of any emission reduction by the demonstration of any
technology or performance level, by or at one or more facilities
with respect to which a credit is allowed under this section, shall
be considered to indicate that the technology or performance level
is adequately demonstrated [ ] for purposes of section 111 of the
Clean Air Act. . . .'' Section 421(a) states: ``No technology, or
level of emission reduction, shall be treated as adequately
demonstrated for purpose [sic] of section 7411 of this title, . . .
solely by reason of the use of such technology, or the achievement
of such emission reduction, by one or more facilities receiving
assistance under section 13572(a)(1) of this title.''
\614\ In the 2015 NSPS, the EPA adopted several other legal
interpretations of these EPAct05 provisions as well. See 80 FR 64541
(October 23, 2015).
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Some commenters criticized the legal interpretation that the EPA
advanced in the 2015 NSPS, and others supported the interpretation. The
EPA has responded to these comments in the Response to Comments
Document, available in the docket for this rulemaking.
ii. Costs
The EPA has analyzed the costs of CCS for existing coal-fired long-
term steam generating units, including costs for CO2
capture, transport, and sequestration. The EPA has determined costs of
CCS for these sources are reasonable. The EPA also evaluated costs
assuming shorter amortization periods. As elsewhere in this section of
the preamble, costs are presented in 2019 dollars. In sum, the costs of
CCS are reasonable under a variety of metrics. The costs of CCS are
reasonable as compared to the costs of other controls that the EPA has
required for these sources. And the costs of CCS are reasonable when
looking to the dollars per ton of CO2 reduced. The
reasonableness of CCS as an emission control is further reinforced by
the fact that some sources are projected to install CCS even in the
absence of any EPA rule addressing CO2 emissions--11 GW of
coal-fired EGUs install CCS in the modeling base case.
Specifically, the EPA assessed the average cost of CCS for the
fleet of coal-fired steam generating units with no announced retirement
or gas conversion prior to 2039. In evaluating costs, the EPA accounts
for the IRC section 45Q tax credit of $85/metric ton (assumes
prevailing wage and apprenticeship requirements are met), a detailed
discussion of which is provided in section VII.C.1.a.ii(C) of this
preamble. The EPA also accounts for increases in utilization that will
occur for units that apply CCS due to the incentives provided by the
IRC section 45Q tax credit. In other words, because the IRC section 45Q
tax credit provides a significant economic benefit, sources that apply
CCS will have a strong economic incentive to increase utilization and
run at higher capacity factors than occurred historically. This
assumption is confirmed by the modeling, which projects that sources
that install CCS run at a high capacity factor--generally, about 80
percent or even higher. The EPA notes that the NETL Baseline study
assumes 85 percent as the default capacity factor assumption for coal
CCS retrofits, noting that coal plants in market conditions supporting
baseload operation have demonstrated the ability to operate at annual
capacity factors of 85 percent or higher.\615\ This assumption is also
supported by observations of wind generators who receive the IRC
section 45 production tax credit who continue to operate even during
periods of negative power prices.\616\ Therefore, the EPA assessed the
costs for CCS retrofitted to existing coal-fired steam generating units
assuming an 80 percent annual capacity factor. Assuming an 80 percent
capacity factor and 12-year amortization period,\617\ the average costs
of CCS for the fleet are -$5/ton of CO2 reduced or -$4/MWh
of generation. Assuming at least a 12-year amortization period is
reasonable because any unit that installs CCS and seeks to maximize its
profitability will be incentivized to recoup the full value of the 12-
year tax credit.
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\615\ See Exhibit 2-18. https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
\616\ If those generators were not receiving the tax credit,
they otherwise would cease producing power during those periods and
result in a lower overall capacity factor. As noted by EIA, ``Wind
plants can offer negative prices because of the revenue stream that
results from the federal production tax credit, which generates tax
benefits whenever the wind plant is producing electricity, and
payments from state renewable portfolio or financial incentive
programs. These alternative revenue streams make it possible for
wind generators to offer their wind power into the wholesale
electricity market at prices lower than other generators, and even
at negative prices.'' https://www.eia.gov/todayinenergy/detail.php?id=16831.
\617\ A 12-year amortization period is consistent with the
period of time during which the IRC section 45Q tax credit can be
claimed.
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Therefore for long-term coal-fired steam generating units--ones
that operate after January 1, 2039--the costs of CCS are similar or
better than the representative costs of controls detailed in section
VII.C.1.a.ii(D) of this preamble (i.e., costs for SCRs and FGDs on EGUs
of $10.60 to $18.50/MWh and the costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas source category of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015)).
The EPA also evaluated the costs for shorter amortization periods,
considering the $/MWh and $/ton metrics, as well as other cost
indicators, as described in section VII.C.1.a.ii.(D). Specifically,
with an initial compliance date of January 1, 2032, sources operating
through the end of 2039 have at least 8 years to amortize costs. For an
80 percent capacity factor and an 8-year amortization period, the
average costs of CCS for the fleet are $19/ton of CO2
reduced or $18/MWh of generation; these costs are comparable to those
costs that the EPA has previously determined to be reasonable. Sources
operating through the end of 2040, 2041, and beyond (i.e., sources with
9, 10, or more years to amortize the costs of CCS) have even more
favorable average costs per MWh and per ton of CO2 reduced.
Sources ceasing operation by January 1, 2039, have 7 years to amortize
costs. For an 80 percent capacity factor and a 7-year amortization
period, the fleet average costs are $29/ton of CO2 reduced
or $28/MWh of generation; these average costs are less comparable on a
$/MWh of generation basis to those costs the EPA has previously
determined to be reasonable, but substantially lower than costs the EPA
has previously determined to be reasonable on a $/ton of CO2
reduced basis. The EPA further notes that the costs presented are
average costs for the fleet. For a substantial amount of capacity,
costs assuming a 7-year amortization period are comparable to those
costs the EPA has previously determined to be reasonable on both a $/
MWh basis (i.e., less than $18.50/MWh) and a $/ton basis (i.e. less
than $98/ton CO2e),\618\ and the EPA concludes that a substantial
amount of capacity can install CCS at reasonable cost with a 7-year
amortization
[[Page 39880]]
period.\619\ Considering that a significant number of sources can cost
reasonably install CCS even assuming a 7-year amortization period, the
EPA concludes that sources operating in 2039 should be subject to a CCS
BSER,\620\ and for this reason, is finalizing the date of January 1,
2039 as the dividing line between the medium-term and long-term
subcategories. Moreover, the EPA underscores that given the strong
economic incentives of the IRC section 45Q tax credit, sources that
install CCS will have strong economic incentives to operate at high
capacity for the full 12 years that the tax credit is available.
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\618\ See the final TSD, GHG Mitigation Measures for Steam
Generating Units for additional details.
\619\ As indicated in section 4.7.5 of the final TSD, Greenhouse
Gas Mitigation Measures for Steam Generating Units, 24 percent of
all coal-fired steam generating units in the long-term subcategory
would have CCS costs below both $18.50/MWh and $98/ton of
CO2 with a 7-year amortization period (Table 11), and
that amount increases to 40 percent for those coal-fired units that,
in light of their age and efficiency, are most likely to operate in
the long term (and thus be subject to the CCS-based standards of
performance) (Table 12). In addition, of the 9 units in the NEEDS
data base that have announced plans to retire in 2039, and that
therefore would have a 7-year amortization period if they installed
CCS by January 1, 2032, 6 would have costs below both $18.50/MWh and
$98/ton of CO2.
\620\ The EPA determines the BSER based on considering
information on the statutory factors, including cost, on a source
category or subcategory basis. However, there may be particular
sources for which, based on source-specific considerations, the cost
of CCS is fundamentally different from the costs the EPA considered
in making its BSER determination. If such a fundamental difference
makes it unreasonable for a particular source to achieve the degree
of emission limitation associated with implementing CCS with 90
percent capture, a state may provide a less stringent standard of
performance (and/or longer compliance schedule, if applicable) for
that source pursuant to the RULOF provisions. See section X.C.2 of
this preamble for further discussion.
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As discussed in the RTC section 2.16, the EPA has also examined the
reasonableness of the costs of this rule in additional ways:
considering the total annual costs of the rule as compared to past CAA
rules for the electricity sector and as compared to the industry's
annual revenues and annual capital expenditures, and considering the
effects of this rule on electricity prices. Taking all of these into
consideration, in addition to the cost metrics just discussed, the EPA
concludes that, in general, the costs of CCS are reasonable for sources
operating after January 1, 2039.
(A) Capture Costs
The EPA developed an independent engineering cost assessment for
CCS retrofits, with support from Sargent and Lundy.\621\ The EPA cost
analysis assumes installation of one CO2 capture plant for
each coal-fired EGU, and that sources without SO2 controls
(FGD) or NOX controls (specifically, selective catalytic
reduction--SCR; or selective non-catalytic reduction--SNCR) add a wet
FGD and/or SCR.\622\
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\621\ Detailed cost information, assessment of technology
options, and demonstration of cost reasonableness can be found in
the final TSD, GHG Mitigation Measures for Steam Generating Units.
\622\ Whether an FGD and SCR or controls with lower costs are
necessary for flue gas pretreatment prior to the CO2
capture process will in practice depend on the flue gas conditions
of the source.
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(B) CO2 Transport and Sequestration Costs
To calculate the costs of CCS for coal-fired steam generating units
for purposes of determining BSER as well as for EPA modeling, the EPA
relied on transportation and storage costs consistent with the cost of
transporting and storing CO2 from each power plant to the
nearest saline reservoir.\623\ For a power plant composed of multiple
coal-fired EGUs, the EPA's cost analysis assumes installation and
operation of a single, common CO2 pipeline.
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\623\ For additional details on CO2 transport and
storage costs, see the final TSD, GHG Mitigation Measures for Steam
Generating Units.
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The EPA notes that NETL has also developed costs for transport and
storage. NETL's ``Quality Guidelines for Energy System Studies; Carbon
Dioxide Transport and Sequestration Costs in NETL Studies'' provides an
estimation of transport costs based on the CO2 Transport
Cost Model.\624\ The CO2 Transport Cost Model estimates
costs for a single point-to-point pipeline. Estimated costs reflect
pipeline capital costs, related capital expenditures, and operations
and maintenance costs.\625\
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\624\ Grant, T., et al. (2019). ``Quality Guidelines for Energy
System Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. https://www.netl.doe.gov/energy-analysis/details?id=3743.
\625\ Grant, T., et al. ``Quality Guidelines for Energy System
Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
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NETL's Quality Guidelines also provide an estimate of sequestration
costs. These costs reflect the cost of site screening and evaluation,
permitting and construction costs, the cost of injection wells, the
cost of injection equipment, operation and maintenance costs, pore
volume acquisition expense, and long-term liability protection.
Permitting and construction costs also reflect the regulatory
requirements of the UIC Class VI program and GHGRP subpart RR for
geologic sequestration of CO2 in deep saline formations.
NETL calculates these sequestration costs on the basis of generic plant
locations in the Midwest, Texas, North Dakota, and Montana, as
described in the NETL energy system studies that utilize the coal found
in Illinois, East Texas, Williston, and Powder River basins.\626\
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\626\ National Energy Technology Laboratory (NETL). (2017).
``FE/NETL CO2 Saline Storage Cost Model (2017),'' U.S.
Department of Energy, DOE/NETL-2018-1871. https://netl.doe.gov/energy-analysis/details?id=2403.
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There are two primary cost drivers for a CO2
sequestration project: the rate of injection of the CO2 into
the reservoir and the areal extent of the CO2 plume in the
reservoir. The rate of injection depends, in part, on the thickness of
the reservoir and its permeability. Thick, permeable reservoirs provide
for better injection and fewer injection wells. The areal extent of the
CO2 plume depends on the sequestration capacity of the
reservoir. Thick, porous reservoirs with a good sequestration
coefficient will present a small areal extent for the CO2
plume and have a smaller monitoring footprint, resulting in lower
monitoring costs. NETL's Quality Guidelines model costs for a given
cumulative sequestration potential.\627\
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\627\ Details on CO2 transportation and sequestration
costs can be found in the final TSD, GHG Mitigation Measures for
Steam Generating Units.
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In addition, provisions in the IIJA and IRA are expected to
significantly increase the CO2 pipeline infrastructure and
development of sequestration sites, which, in turn, are expected to
result in further cost reductions for the application of CCS at new
combined cycle EGUs. The IIJA establishes a new Carbon Dioxide
Transportation Infrastructure Finance and Innovation program to provide
direct loans, loan guarantees, and grants to CO2
infrastructure projects, such as pipelines, rail transport, ships and
barges.\628\ The IIJA also establishes a new Regional Direct Air
Capture Hubs program that includes funds to support four large-scale,
regional direct air capture hubs and more broadly support projects that
could be developed into a regional or inter-regional network to
facilitate sequestration or utilization.\629\ DOE is additionally
implementing IIJA section 40305 (Carbon Storage Validation and Testing)
through its CarbonSAFE initiative, which aims to further develop
geographically widespread, commercial-scale, safe sequestration.\630\
The IRA increases and
[[Page 39881]]
extends the IRC section 45Q tax credit, discussed next.
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\628\ Department of Energy. ``Biden-Harris Administration
Announces $2 Billion from Bipartisan Infrastructure Law to Finance
Carbon Dioxide Transportation Infrastructure.'' (2022). https://www.energy.gov/articles/biden-harris-administration-announces-2-billion-bipartisan-infrastructure-law-finance.
\629\ Department of Energy. ``Regional Direct Air Capture
Hubs.'' (2022). https://www.energy.gov/oced/regional-direct-air-capture-hubs.
\630\ For more information, see the NETL announcement. https://www.netl.doe.gov/node/12405.
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(C) IRC Section 45Q Tax Credit
In determining the cost of CCS, the EPA is taking into account the
tax credit provided under IRC section 45Q, as revised by the IRA. The
tax credit is available at $85/metric ton ($77/ton) and offsets a
significant portion of the capture, transport, and sequestration costs
noted above.
Several other aspects of the tax credit should be noted. A tax
credit offsets tax liability dollar for dollar up to the amount of the
taxpayer's tax liability. Any credits in excess of the taxpayer's
liability are eligible to be carried back (3 years in the case of IRC
section 45Q) and then carried forward up to 20 years.\631\As noted
above, the IRA also enabled additional methods to monetize tax credits
in the event the taxpayer does not have sufficient tax liability, such
as through credit transfer.
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\631\ IRC section 39.
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The EPA has determined that it is likely that EGUs installing CCS
will meet the 45Q prevailing wage and apprenticeship requirements.
First, the requirements provide a significant economic incentive,
increasing the value of the 45Q credit by five times over the base
value of the credit available if the prevailing wage and apprenticeship
requirements are not met. This provides a significant incentive to meet
the requirements. Second, the increased cost of meeting the
requirements is likely significantly less than the increase in credit
value. A recent EPRI assessment found meeting the requirements for
other types of power generation projects resulted in significant
savings across projects,\632\ and other studies indicate prevailing
wage laws and requirements for construction projects in general do not
significantly affect overall construction costs.\633\ The EPA expects a
similar dynamic for 45Q projects. Third, the use of registered
apprenticeship programs for training new employees is generally well-
established in the electric power generation sector, and apprenticeship
programs are widely available to generate additional trained workers in
this field.\634\ The overall U.S. apprentice market has more than
doubled between 2014 and 2023, growing at an average annual rate of
more than 7 percent.\635\ Additional programs support the skilled
construction trade workforce required for CCS implementation and
maintenance.\636\
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\632\ https://www.epri.com/research/products/000000003002027328.
\633\ https://journals.sagepub.com/doi/abs/10.1177/0160449X18766398.
\634\ DOE. Workforce Analysis of Existing Coal Carbon Capture
Retrofits. https://www.energy.gov/policy/articles/workforce-analysis-existing-coal-carbon-capture-retrofits.
\635\ https://www.apprenticeship.gov/data-and-statistics.
\636\ https://www.apprenticeship.gov/partner-finder.
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As discussed in section V.C.2.c of this preamble, CAA section
111(a)(1) is clear that the cost that the Administrator must take into
account in determining the BSER is the cost of the controls to the
source. It is reasonable to take the tax credit into account because it
reduces the cost of the controls to the source, which has a significant
effect on the actual cost of installing and operating CCS. In addition,
all sources that install CCS to meet the requirements of these final
actions are eligible for the tax credit. The legislative history of the
IRA makes clear that Congress was well aware that the EPA may
promulgate rulemaking under CAA section 111 based on CCS and the
utility of the tax credit in reducing the costs of CCUS (i.e., CCS).
Rep. Frank Pallone, the chair of the House Energy & Commerce Committee,
included a statement in the Congressional Record when the House adopted
the IRA in which he explained: ``The tax credit[ ] for CCUS . . .
included in this Act may also figure into CAA Section 111 GHG
regulations for new and existing industrial sources[.] . . . Congress
anticipates that EPA may consider CCUS . . . as [a] candidate[ ] for
BSER for electric generating plants . . . . Further, Congress
anticipates that EPA may consider the impact of the CCUS . . . tax
credit[ ] in lowering the costs of [that] measure[ ].'' 168 Cong. Rec.
E879 (August 26, 2022) (statement of Rep. Frank Pallone).
In the 2015 NSPS, in which the EPA determined partial CCS to be the
BSER for GHGs from new coal-fired steam generating EGUs, the EPA
recognized that the IRC section 45Q tax credit or other tax incentives
could factor into the cost of the controls to the sources.
Specifically, the EPA calculated the cost of partial CCS on the basis
of cost calculations from NETL, which included ``a range of assumptions
including the projected capital costs, the cost of financing the
project, the fixed and variable O&M costs, the projected fuel costs,
and incorporation of any incentives such as tax credits or favorable
financing that may be available to the project developer.'' 80 FR 64570
(October 23, 2015).\637\
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\637\ In fact, because of limits on the availability of the IRC
section 45Q tax credit at the time of the 2015 NSPS, the EPA did not
factor it into the cost calculation for partial CCS. 80 FR 64558-64
(October 23, 2015).
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Similarly, in the 2015 NSPS, the EPA also recognized that revenues
from utilizing captured CO2 for EOR would reduce the cost of
CCS to the sources, although the EPA did not account for potential EOR
revenues for purposes of determining the BSER. Id. At 64563-64. In
other rules, the EPA has considered revenues from sale of the by-
products of emission controls to affect the costs of the emission
controls. For example, in the 2016 Oil and Gas Methane Rule, the EPA
determined that certain control requirements would reduce natural gas
leaks and therefore result in the collection of recovered natural gas
that could be sold; and the EPA further determined that revenues from
the sale of the recovered natural gas reduces the cost of controls. See
81 FR 35824 (June 3, 2016). The EPA made the same determination in the
2024 Oil and Gas Methane Rule. See 89 FR 16820, 16865 (May 7, 2024). In
a 2011 action concerning a regional haze SIP, the EPA recognized that a
NOX control would alter the chemical composition of fly ash
that the source had previously sold, so that it could no longer be
sold; and as a result, the EPA further determined that the cost of the
NOX control should include the foregone revenues from the
fly ash sales. 76 FR 58570, 58603 (September 21, 2011). In the 2016
emission guidelines for landfill gas from municipal solid waste
landfills, the EPA reduced the costs of controls by accounting for
revenue from the sale of electricity produced from the landfill gas
collected through the controls. 81 FR 59276, 19679 (August 29, 2016).
The amount of the IRC section 45Q tax credit that the EPA is taking
into account is $85/metric ton for CO2 that is captured and
geologically stored. This amount is available to the affected source as
long as it meets the prevailing wage and apprenticeship requirements of
IRC section 45Q(h)(3)-(4). The legislative history to the IRA
specifically stated that when the EPA considers CCS as the BSER for GHG
emissions from industrial sources in CAA section 111 rulemaking, the
EPA should determine the cost of CCS by assuming that the sources would
meet those prevailing wage and apprenticeship requirements. 168 Cong.
Rec. E879 (August 26, 2022) (statement of Rep. Frank Pallone). If
prevailing wage and apprenticeship requirements are not met, the value
of the IRC section 45Q tax credit falls to $17/metric ton. The
substantially higher credit available provides a considerable incentive
to meeting the prevailing wage and apprenticeship requirements.
[[Page 39882]]
Therefore, the EPA assumes that investors maximize the value of the IRC
section 45Q tax credit at $85/metric ton by meeting those requirements.
(D) Comparison to Other Costs of Controls and Other Measures of Cost
Reasonableness
In assessing cost reasonableness for the BSER determination for
this rule, the EPA looks at a range of cost information. As discussed
in Chapter 2 of the RTC, the EPA considered the total annual costs of
the rule as compared to past CAA rules for the electricity sector and
as compared to the industry's annual revenues and annual capital
expenditures, and considered the effects of this rule on electricity
prices.
For each of the BSER determinations, the EPA also considers cost
metrics that it has historically considered in assessing costs to
compare the costs of GHG control measures to control costs that the EPA
has previously determined to be reasonable. This includes comparison to
the costs of controls at EGUs for other air pollutants, such as
SO2 and NOX, and costs of controls for GHGs in
other industries. Based on these costs, the EPA has developed two
metrics for assessing the cost reasonableness of controls: the increase
in cost of electricity due to controls, measured in $/MWh, and the
control costs of removing a ton of pollutant, measured in $/ton
CO2e. The costs presented in this section of the preamble
are in 2019 dollars.\638\
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\638\ The EPA used the NETL Baseline Report costs directly for
the combustion turbine model plant BSER analysis. Even though these
costs are in 2018 dollars, the adjustment to 2019 dollars (1.018
using the U.S. GDP Implicit Price Deflator) is well within the
uncertainty range of the report and the minor adjustment would not
impact the EPA's BSER determination.
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In different rulemakings, the EPA has required many coal-fired
steam generating units to install and operate flue gas desulfurization
(FGD) equipment--that is, wet or dry scrubbers--to reduce their
SO2 emissions or SCR to reduce their NOX
emissions. The EPA compares these control costs across technologies--
steam generating units and combustion turbines--because these costs are
indicative of what is reasonable for the power sector in general. The
facts that the EPA required these controls in prior rules, and that
many EGUs subsequently installed and operated these controls, provide
evidence that these costs are reasonable, and as a result, the cost of
these controls provides a benchmark to assess the reasonableness of the
costs of the controls in this preamble. In the 2011 CSAPR (76 FR 48208;
August 8, 2011), the EPA estimated the annualized costs to install and
operate wet FGD retrofits on existing coal-fired steam generating
units. Using those same cost equations and assumptions (i.e., a 63
percent annual capacity factor--the average value in 2011) for
retrofitting wet FGD on a representative 700 to 300 MW coal-fired steam
generating unit results in annualized costs of $14.80 to $18.50/MWh of
generation, respectively.\639\ In the Good Neighbor Plan for the 2015
Ozone NAAQS (2023 GNP), 88 FR 36654 (June 5, 2023), the EPA estimated
the annualized costs to install and operate SCR retrofits on existing
coal-fired steam generating units. Using those same cost equations and
assumptions (including a 56 percent annual capacity factor--a
representative value in that rulemaking) to retrofit SCR on a
representative 700 to 300 MW coal-fired steam generating unit results
in annualized costs of $10.60 to $11.80/MWh of generation,
respectively.\640\
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\639\ For additional details, see https://www.epa.gov/power-sector-modeling/documentation-integrated-planning-model-ipm-base-case-v410.
\640\ For additional details, see https://www.epa.gov/system/files/documents/2023-01/Updated%20Summer%202021%20Reference%20Case%20Incremental%20Documentation%20for%20the%202015%20Ozone%20NAAQS%20Actions_0.pdf.
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The EPA also compares costs to the costs for GHG controls in
rulemakings for other industries. In the 2016 NSPS regulating GHGs for
the Crude Oil and Natural Gas source category, the EPA found the costs
of reducing methane emissions of $2,447/ton to be reasonable (80 FR
56627; September 18, 2015).\641\ Converted to a ton of CO2e
reduced basis, those costs are expressed as $98/ton of CO2e
reduced.\642\
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\641\ The EPA finalized the 2016 NSPS GHGs for the Crude Oil and
Natural Gas source category at 81 FR 35824 (June 3, 2016). The EPA
included cost information in the proposed rulemaking, at 80 FR 56627
(September 18, 2015).
\642\ Based on the 100-year global warming potential for methane
of 25 used in the GHGRP (40 CFR 98 Subpart A, table A-1).
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The EPA does not consider either of these metrics, $18.50/MWh and
$98/ton of CO2e, to be bright line standards that
distinguish between levels of control costs that are reasonable and
levels that are unreasonable. But they do usefully indicate that
control costs that are generally consistent with those levels of
control costs should be considered reasonable. The EPA has required
controls with comparable costs in prior rules for the electric power
industry and the industry has successfully complied with those rules by
installing and operating the applicable controls. In the case of the $/
ton metric, the EPA has required other industries--specifically, the
oil and gas industry--to reduce their climate pollution at this level
of cost-effectiveness. In this rulemaking, the costs of the controls
that the EPA identifies as the BSER generally match up well against
both of these $/MWh and $/ton metrics for the affected subcategories of
sources. And looking broadly at the range of cost information and these
cost metrics, the EPA concludes that the costs of these rules are
reasonable.
(E) Comparison to Costs for CCS in Prior Rulemakings
In the CPP and ACE Rule, the EPA determined that CCS did not
qualify as the BSER due to cost considerations. Two key developments
have led the EPA to reevaluate this conclusion: the costs of CCS
technology have fallen and the extension and increase in the IRC
section 45Q tax credit, as included in the IRA, in effect provide a
significant stream of revenue for sequestered CO2 emissions.
The CPP and ACE Rule relied on a 2015 NETL report estimating the cost
of CCS. NETL has issued updated reports to incorporate the latest
information available, most recently in 2022, which show significant
cost reductions. The 2015 report estimated incremental levelized cost
of CCS at a new pulverized coal facility relative to a new facility
without CCS at $74/MWh (2022$),\643\ while the 2022 report estimated
incremental levelized cost at $44/MWh (2022$).\644\ Additionally, the
IRA increased the IRC section 45Q tax credit from $50/metric ton to
$85/metric ton (and, in the case of EOR or certain industrial uses,
from $35/metric ton to $60/metric ton), assuming prevailing wage and
apprenticeship conditions are met. The IRA also enhanced the realized
value of the tax credit through the elective pay (informally known as
direct pay) and transferability monetization options described in
section IV.E.1. The combination of lower costs and higher tax credits
significantly improves the cost reasonableness of CCS for purposes
[[Page 39883]]
of determining whether it qualifies as the BSER.
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\643\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 3
(July 2015). Note: The EPA adjusted reported costs to reflect $2022.
https://www.netl.doe.gov/projects/files/CostandPerformanceBaselineforFossilEnergyPlantsVolume1aBitCoalPCandNaturalGastoElectRev3_070615.pdf.
\644\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A
(October 2022). Note: The EPA adjusted reported costs to reflect
$2022. https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
The EPA considered non-GHG emissions impacts, the water use
impacts, the transport and sequestration of captured CO2,
and energy requirements resulting from CCS for steam generating units.
As discussed below, where the EPA has found potential for localized
adverse consequences related to non-air quality health and
environmental impacts or energy requirements, the EPA also finds that
protections are in place to mitigate those risks. Because the non-air
quality health and environmental impacts are closely related to the
energy requirements, we discuss the latter first.
(A) Energy Requirements
For a steam generating unit with 90 percent amine-based
CO2 capture, parasitic/auxiliary energy demand increases and
the net power output decreases. In particular, the solvent regeneration
process requires heat in the form of steam and CO2
compression requires a large amount of electricity. Heat and power for
the CO2 capture equipment can be provided either by using
the steam and electricity produced by the steam generating unit or by
an auxiliary cogeneration unit. However, any auxiliary source of heat
and power is part of the ``designated facility,'' along with the steam
generating unit. The standards of performance apply to the designated
facility. Thus, any CO2 emissions from the connected
auxiliary equipment need to be captured or they will increase the
facility's emission rate.
Using integrated heat and power can reduce the capacity (i.e., the
amount of electricity that a unit can distribute to the grid) of an
approximately 474 MW-net (501 MW-gross) coal-fired steam generating
unit without CCS to approximately 425 MW-net with CCS and contributes
to a reduction in net efficiency of 23 percent.\645\ For retrofits of
CCS on existing sources, the ductwork for flue gas and piping for heat
integration to overcome potential spatial constraints are a component
of efficiency reduction. The EPA notes that slightly greater efficiency
reductions than in the 2016 NETL retrofit report are assumed for the
BSER cost analyses, as detailed in the final TSD, GHG Mitigation
Measures for Steam Generating Units, available in the docket. Despite
decreases in efficiency, IRC section 45Q tax credit provides an
incentive for increased generation with full operation of CCS because
the amount of revenue from the tax credit is based on the amount of
captured and sequestered CO2 emissions and not the amount of
electricity generated. In this final action, the Agency considers the
energy penalty to not be unreasonable and to be relatively minor
compared to the benefits in GHG reduction of CCS.
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\645\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=d335ce79-84ee-4a0b-a27b-c1a64edbb866.
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(B) Non-GHG Emissions
As a part of considering the non-air quality health and
environmental impacts of CCS, the EPA considered the potential non-GHG
emission impacts of CO2 capture. The EPA recognizes that
amine-based CO2 capture can, under some circumstances,
result in the increase in emission of certain co-pollutants at a coal-
fired steam generating unit. However, there are protections in place
that can mitigate these impacts. For example, as discussed below, CCS
retrofit projects with co-pollutant increases may be subject to
preconstruction permitting under the New Source Review (NSR) program,
which could require the source to adopt emission limitations based on
applicable NSR requirements. Sources obtaining major NSR permits would
be required to either apply Lowest Achievable Emission Rate (LAER) and
fully offset any anticipated increases in criteria pollutant emissions
(for their nonattainment pollutants) or apply Best Available Control
Technology (BACT) and demonstrate that its emissions of criteria
pollutants will not cause or contribute to a violation of applicable
National Ambient Air Quality Standards (for their attainment
pollutants).\646\ The EPA expects facility owners, states, permitting
authorities, and other responsible parties will use these protections
to address co-pollutant impacts in situations where individual units
use CCS to comply with these emission guidelines.
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\646\ Section XI.A of this preamble provides additional
information on the NSR program and how it relates to the NSPS and
emission guidelines.
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The EPA also expects that the meaningful engagement requirements
discussed in section X.E.1.b.i of this preamble will ensure that all
interested stakeholders, including community members who might be
adversely impacted by non-GHG pollutants, will have an opportunity to
raise this concern with states and permitting authorities.
Additionally, state permitting authorities are, in general, required to
provide notice and an opportunity for public comment on construction
projects that require NSR permits. This provides additional
opportunities for affected stakeholders to engage in that process, and
it is the EPA's expectation that the responsible authorities will
consider these concerns and take full advantage of existing
protections. Moreover, the EPA through its regional offices is
committed to thoroughly review draft NSR permits associated with
CO2 capture projects and provide comments as necessary to
state permitting authorities to address any concerns or questions with
regard to the draft permit's consideration and treatment of non-GHG
pollutants.
In the following discussion, the EPA describes the potential
emissions of non-GHG pollutants resulting from installation and
operation of CO2 capture plants, the protections in place
such as the controls and processes for mitigating those emissions, as
well as regulations and permitting that may require review and
implementation of those controls. The EPA first discusses these issues
in relation to criteria air pollutants and precursor pollutants
(SO2, NOX, and PM), and subsequently provides
details regarding hazardous air pollutants (HAPs) and volatile organic
compounds (VOCs).
Operation of an amine-based CO2 capture plant on a coal-
fired steam generating unit can impact the emission of criteria
pollutants from the facility, including SO2 and PM, as well
as precursor pollutants, like NOX. Sources installing CCS
may operate more due to the incentives provided by the IRC section 45Q
tax credit, and increased utilization would--all else being equal--
result in increases in SO2, PM, and NOX. However,
certain impacts are mitigated by the flue gas conditioning required by
the CO2 capture process and by other control equipment that
the units already have or may need to install to meet other CAA
requirements. Substantial flue gas conditioning, particularly to remove
SO2 and PM, is critical to limiting solvent degradation and
maintaining reliable operation of the capture plant. To achieve the
necessary limits on SO2 levels in the flue gas for the
capture process, steam generating units will need to add an FGD
scrubber, if they do not already have one, and will usually need an
additional polishing column (i.e., quencher), thereby further reducing
the emission of SO2. A wet FGD column and a polishing column
will also reduce the emission rate of PM. Additional improvements in PM
removal may also be necessary to reduce the fouling of
[[Page 39884]]
other components (e.g., heat exchangers) of the capture process,
including upgrades to existing PM controls or, where appropriate, the
inclusion of various wash stages to limit fly ash carry-over to the
CO2 removal system. Although PM emissions from the steam
generating unit may be reduced, PM emissions may occur from cooling
towers for those sources using wet cooling for the capture process. For
some sources, a WESP may be necessary to limit the amount of aerosols
in the flue gas prior to the CO2 capture process. Reducing
the amount of aerosols to the CO2 absorber will also reduce
emissions of the solvent out of the top of the absorber. Controls to
limit emission of aerosols installed at the outlet of the absorber
could be considered, but could lead to higher pressure drops. Thus,
emission increases of SO2 and PM would be reduced through
flue gas conditioning and other system requirements of the
CO2 capture process, and NSR permitting would serve as an
added backstop to review remaining SO2 and PM increases for
mitigation.
NOX emissions can cause solvent degradation and
nitrosamine formation, depending on the chemical structure of the
solvent. Limits on NOX levels of the flue gas required to
avoid solvent degradation and nitrosamine formation in the
CO2 scrubber vary. For most units, the requisite limits on
NOX levels to assure that the CO2 capture process
functions properly may be met by the existing NOX combustion
controls. Other units may need to install SCR to achieve the required
NOx level. Most existing coal-fired steam generating units either
already have SCR or will be covered by final Federal Implementation
Plan (FIP) requirements regulating interstate transport of
NOX (as ozone precursors) from EGUs. See 88 FR 36654 (June
5, 2023).\647\ For units not otherwise required to have SCR, an
increase in utilization from a CO2 capture retrofit could
result in increased NOX emissions at the source that,
depending on the quantity of the emissions increase, may trigger major
NSR permitting requirements. Under this scenario, the permitting
authority may determine that the NSR permit requires the installation
of SCR for those units, based on applying the control technology
requirements of major NSR. Alternatively, a state could, as part of its
state plan, develop enforceable conditions for a source expected to
trigger major NSR that would effectively limit the unit's ability to
increase its emissions in amounts that would trigger major NSR. Under
this scenario, with no major NSR requirements applying due to the limit
on the emissions increase, the permitting authority may conclude for
the minor NSR permit that installation of SCR is not required for the
units and the source is to minimize its NOX emission
increases using other techniques. Finally, a source with some lesser
increase in NOX emissions may not trigger major NSR to begin
with and, as with the previous scenario, the permitting authority would
determine the NOX control requirements pursuant to its minor
NSR program requirements.
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\647\ As of September 21, 2023, the Good Neighbor Plan ``Group
3'' ozone-season NOX control program for power plants is
being implemented in the following states: Illinois, Indiana,
Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania,
Virginia, and Wisconsin. Pursuant to court orders staying the
Agency's FIP Disapproval action as to the following states, the EPA
is not currently implementing the Good Neighbor Plan ``Group 3''
ozone-season NOX control program for power plants in the
following states: Alabama, Arkansas, Kentucky, Louisiana, Minnesota,
Mississippi, Missouri, Nevada, Oklahoma, Texas, Utah, and West
Virginia.
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Recognizing that potential emission increases of SO2,
PM, and NOX from operating a CO2 capture process
are an area of concern for stakeholders, 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
co-pollutant increases from sources installing CCS. In its analysis to
support this final action, the EPA accounted for controlling these co-
pollutant increases by assuming that coal-fired units that install CCS
would be required to install SCR and/or FGD if they do not already have
those controls installed. The costs of these controls are included in
the total program compliance cost estimates through IPM modeling, as
well as in the BSER cost calculations.
An amine-based CO2 capture plant can also impact
emissions of HAP and VOC (as an ozone precursor) from the coal-fired
steam generating unit. Degradation of the solvent can produce HAP, and
organic HAP and amine solvent emissions from the absorber would
contribute to VOC emissions out of the top of the CO2
absorber. A conventional multistage water or acid wash and mist
eliminator (demister) at the exit of the CO2 scrubber is
effective at removal of gaseous amine and amine degradation products
(e.g., nitrosamine) emissions.648 649 The DOE's Carbon
Management Pathway report notes that monitoring and emission controls
for such degradation products are currently part of standard operating
procedures for amine-based CO2 capture systems.\650\
Depending on the solvent properties, different amounts of aldehydes
including acetaldehyde and formaldehyde may form through oxidative
processes, contributing to total HAP and VOC emissions. While a water
wash or acid wash can be effective at limiting emission of amines, a
separate system of controls would be required to reduce aldehyde
emissions; however, the low temperature and likely high water vapor
content of the gas emitted out of absorber may limit the applicability
of catalytic or thermal oxidation. Other controls (e.g.,
electrochemical, ultraviolet) common to water treatment could be
considered to reduce the loading of copollutants in the water wash
section, although their efficacy is still in development and it is
possible that partial treatment could result in the formation of
additional degradation products. Apart from these potential controls,
any increase in VOC emissions from a CCS retrofit project would be
mitigated through NSR permitting. As such VOC increases are not
expected to be large enough to trigger major NSR requirements, they
would likely be reviewed and addressed under a state's minor NSR
program.
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\648\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
\649\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
\650\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/uploads/2023/04/20230424-Liftoff-Carbon-Management-vPUB_update.pdf.
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There is one nitrosamine that is a listed HAP regulated under CAA
section 112. Carbon capture systems that are themselves a major source
of HAP should evaluate the applicability of CAA section 112(g) and
conduct a case-by-case MACT analysis if required, to establish MACT for
any listed HAP, including listed nitrosamines, formaldehyde, and
acetaldehyde. Because of the differences in the formation and
effectiveness of controls, such a case-by-case MACT analysis should
evaluate the performance of controls for nitrosamines and aldehydes
separately, as formaldehyde or acetaldehyde may not be a suitable
surrogate for amine and nitrosamine emissions. However, measurement of
nitrosamine emissions may be challenging when the concentration is low
(e.g., less than 1 part per billion, dry basis).
HAP emissions from the CO2 capture plant will depend on
the flue gas
[[Page 39885]]
conditions, solvent, size of the source, and process design. The air
permit application for Project Tundra \651\ includes potential-to-emit
(PTE) values for CAA section 112 listed HAP specific to the 530 MW-
equivalent CO2 capture plant, including emissions of 1.75
tons per year (TPY) of formaldehyde (CASRN 50-00-0), 32.9 TPY of
acetaldehyde (CASRN 75-07-0), 0.54 TPY of acetamide (CASRN 60-35-5),
0.018 TPY of ethylenimine (CASRN 151-56-4), 0.044 TPY of N-
nitrosodimethylamine (CASRN 62-75-9), and 0.018 TPY of N-
nitrosomorpholine (CASRN 59-89-2). Additional PTE other species that
are not CAA section 112 listed HAP were also included, including 0.022
TPY of N-nitrosodiethylamine (CASRN 55-18-5). PTE values for other
CO2 capture plants may differ. To comply with North Dakota
Department of Environmental Quality (ND-DEQ) Air Toxics Policy, an air
toxics assessment was included in the permit application. According to
that assessment, the total maximum individual carcinogenic risk was
1.02E-6 (approximately 1-in-1 million, below the ND-DEQ threshold of
1E-5) primarily driven by N-nitrosodiethylamine and N-
nitrosodimethylamine. The hazard index value was 0.022 (below the ND-
DEQ threshold of 1), with formaldehyde being the primary driver.
Results of air toxics risk assessments for other facilities would
depend on the emissions from the facility, controls in place, stack
height and flue gas conditions, local ambient conditions, and the
relative location of the exposed population.
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\651\ DCC East PTC Application. https://ceris.deq.nd.gov/ext/nsite/map/results/detail/-8992368000928857057/documents.
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Emissions of amines and nitrosamines at Project Tundra are
controlled by the water wash section of the absorber column. According
to the permit to construct issued by ND-DEQ, limits for formaldehyde
and acetaldehyde will be established based on testing after initial
operation of the CO2 capture plant. The permit does not
include a mechanism for establishing limits for nitrosamine emissions,
as they may be below the limit of detection (less than 1 part per
billion, dry basis).
The EPA received several comments related to the potential for non-
GHG emissions associated with CCS. Those comments and the EPA's
responses are as follows.
Comment: Some commenters noted that there is a potential for
increases in co-pollutants when operating amine-based CO2
capture systems. One commenter requested that the EPA proactively
regulate potential nitrosamine emissions.
Response: The EPA carefully considered these concerns as it
finalized its determination of the BSERs for these rules. The EPA takes
these concerns seriously, agrees that any impacts to local and downwind
communities are important to consider and has done so as part of its
analysis discussed at section XII.E. While the EPA acknowledges that,
in some circumstances, there is potential for some non-GHG emissions to
increase, there are several protections in place to help mitigate these
impacts. The EPA believes that these protections, along with the
meaningful engagement of potentially affected communities, can
facilitate a responsible deployment of this technology that mitigates
the risk of any adverse impacts.
There is one nitrosamine that is a listed HAP under CAA section 112
(N-Nitrosodimethylamine; CASRN 62-75-9). Other nitrosamines would have
to be listed before the EPA could establish regulations limiting their
emission. Furthermore, carbon capture systems are themselves not a
listed source category of HAP, and the listing of a source category
under CAA section 112 would first require some number of the sources to
exist for the EPA to develop MACT standards. However, if a new
CO2 capture facility were to be permitted as a separate
entity (rather than as part of the EGU) then it may be subject to case-
by-case MACT under section 112(g), as detailed in the preceding section
of this preamble.
Comment: Commenters noted that a source could attempt to permit
CO2 facilities as separate entities to avoid triggering NSR
for the EGU.
Response: For the CO2 capture plant to be permitted as a
separate entity, the source would have to demonstrate to the state
permitting authority that the EGU and CO2 capture plant are
not a single stationary source under the NSR program. In determining
what constitutes a stationary source, the EPA's NSR regulations set
forth criteria that are to be used when determining the scope of a
``stationary source.'' \652\ These criteria require the aggregation of
different pollutant-emitting activities if they (1) belong to the same
industrial grouping as defined by SIC codes, (2) are located on
contiguous or adjacent properties, and (3) are under common
control.\653\ In the case of an EGU and CO2 capture plant
that are collocated, to permit them as separate sources they should not
be under common control or not be defined by the same industrial
grouping.
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\652\ 40 CFR 51.165(a)(1)(i) and (ii); 40 CFR 51.166(b)(5) and
(6).
\653\ The EPA has issued guidance to clarify these regulatory
criteria of stationary source determination. See https://www.epa.gov/nsr/single-source-determination.
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The EPA would anticipate that, in most cases, the operation of the
EGU and the CO2 capture plant will intrinsically affect one
another--typically steam, electricity, and the flue gas of the EGU will
be provided to the CO2 capture plant. Conditions of the flue
gas will affect the operation of the CO2 capture plant,
including its emissions, and the steam and electrical load will affect
the operation of the EGU. Moreover, the emissions from the EGU will be
routed through the CO2 capture system and emitted out of the
top of the CO2 absorber. Even if the EGU and CO2
capture plant are owned by separate entities, the CO2
capture plant is likely to be on or directly adjacent to land owned by
the owners of the EGU and contractual obligations are likely to exist
between the two owners. While each of these individual factors may not
ultimately determine the outcome of whether two nominally-separate
facilities should be treated as a single stationary source for
permitting purposes, the EPA expects that in most cases an EGU and its
collocated CO2 capture plant would meet each of the
aforementioned NSR regulatory criteria necessary to make such a
determination. Thus, the EPA generally would not expect an EGU and its
CO2 capture plant to be permitted as separate stationary
sources.
(C) Water Use
Water consumption at the plant increases when applying carbon
capture, due to solvent water makeup and cooling demand. Water
consumption can increase by 36 percent on a gross basis.\654\ A
separate cooling water system dedicated to a CO2 capture
plant may be necessary. However, the amount of water consumption
depends on the design of the cooling system. For example, the cooling
system cited in the CCS feasibility study for SaskPower's Shand Power
station would rely entirely on water condensed from the flue gas and
thus would not require any increase in external water consumption--all
while achieving higher capture rates at lower cost than Boundary Dam
Unit 3.\655\ Regions with limited water supply
[[Page 39886]]
may therefore rely on dry or hybrid cooling systems. Therefore, the EPA
considers the water use requirements to be manageable and does not
expect this consideration to preclude coal-fired power plants generally
from being able to install and operate CCS.
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\654\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
\655\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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(D) CO2 Capture Plant Siting
With respect to siting considerations, CO2 capture
systems have a sizeable physical footprint and a consequent land-use
requirement. One commenter cited their analysis showing that, for a
subset of coal-fired sources greater than 300 MW, 98 percent (154 GW of
the existing fleet) have adjacent land available within 1 mile of the
facility, and 83 percent have adjacent land available within 100 meters
of the facility. Furthermore, the cited analysis did not include land
available onsite, and it is therefore possible there is even greater
land availability for siting capture equipment. Qualitatively, some
commenters claimed there is limited land available for siting
CO2 capture plants adjacent to coal-fired steam generating
units. However, those commenters provided no data or analysis to
support their assertion. The EPA has reviewed the analysis provided by
the first commenter, and the approach, methods, and assumptions are
logical. Further, the EPA has reviewed the available information,
including the location of coal-fired steam generating units and visual
inspection of the associated maps and plots. Although in some cases
longer duct runs may be required, this would not preclude coal-fired
power plants generally from being able to install and operate CCS.
Therefore, the EPA has concluded that siting and land-use requirements
for CO2 capture are not unreasonable.
(E) Transport and Geologic Sequestration
As noted in section VII.C.1.a.i(C) of this preamble, PHMSA
oversight of supercritical CO2 pipeline safety protects
against environmental release during transport. The vast majority of
CO2 pipelines have been operating safely for more than 60
years. PHMSA reported a total of 102 CO2 pipeline incidents
between 2003 and 2022, with one injury (requiring in-patient
hospitalization) and zero fatalities.\656\ In the past 20 years, 500
million metric tons of CO2 moved through over 5,000 miles of
CO2 pipelines with zero incidents involving fatalities.\657\
PHMSA initiated a rulemaking in 2022 to develop and implement new
measures to strengthen its safety oversight of supercritical
CO2 pipelines. Furthermore, UIC Class VI and Class II
regulations under the SDWA, in tandem with GHGRP subpart RR and subpart
VV requirements, ensure the protection of USDWs and the security of
geologic sequestration. The EPA believes these protections constitute
an effective framework for addressing potential health and
environmental concerns related to CO2 transportation and
sequestration, and the EPA has taken this regulatory framework into
consideration in determining that CCS represents the BSER for long-term
steam EGUs.
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\656\ NARUC. (2023). Onshore U.S. Carbon Pipeline Deployment:
Siting, Safety. and Regulation. Prepared by Public Sector
Consultants for the National Association of Regulatory Utility
Commissioners (NARUC). June 2023. https://pubs.naruc.org/pub/F1EECB6B-CD8A-6AD4-B05B-E7DA0F12672E.
\657\ Congressional Research Service. 2022. Carbon Dioxide
Pipelines: Safety Issues, CRS Reports, June 3, 2022. https://crsreports.congress.gov/product/pdf/IN/IN11944.
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(F) Impacts on the Energy Sector
Additionally, the EPA considered the impacts on the power sector,
on a nationwide and long-term basis, of determining CCS to be the BSER
for long-term coal-fired steam generating units. In this final action,
the EPA considers that designating CCS as the BSER for these units
would have limited and non-adverse impacts on the long-term structure
of the power sector or on the reliability of the power sector. Absent
the requirements defined in this action, the EPA projects that 11 GW of
coal-fired steam generating units would apply CCS by 2035 and an
additional 30 GW of coal-fired steam generating units, without
controls, would remain in operation in 2040. Designating CCS to be the
BSER for existing long-term coal-fired steam generating units may
result in more of the coal-fired steam generating unit capacity
applying CCS. The time available before the compliance deadline of
January 1, 2032, provides for adequate resource planning, including
accounting for the downtime necessary to install the CO2
capture equipment at long-term coal-fired steam generating units. For
the 12-year duration that eligible EGUs earn the IRC section 45Q tax
credit, long-term coal-fired steam generating units are anticipated to
run at or near base load conditions in order to maximize the amount of
tax credit earned through IRC section 45Q. Total generation from coal-
fired steam generating units in the medium-term subcategory would
gradually decrease over an extended period of time through 2039,
subject to the commitments those units have chosen to adopt.
Additionally, for the long-term units applying CCS, the EPA has
determined that the increase in the annualized cost of generation is
reasonable. Therefore, the EPA concludes that these elements of BSER
can be implemented while maintaining a reliable electric grid. A
broader discussion of reliability impacts of these final rules is
available in section XII.F of this preamble.
iv. Extent of Reductions in CO2 Emissions
CCS is an extremely effective technology for reducing
CO2 emissions. As of 2021, coal-fired power plants are the
largest stationary source of GHG emissions by sector. Furthermore,
emission rates (lb CO2/MWh-gross) from coal-fired sources
are almost twice those of natural gas-fired combined cycle units, and
sources operating in the long-term have the more substantial emissions
potential. CCS can be applied to coal-fired steam generating units at
the source to reduce the mass of CO2 emissions by 90 percent
or more. Increased steam and power demand have a small impact on the
reduction in emission rate (i.e., lb CO2/MWh-gross) that
occurs with 90 percent capture. According to the 2016 NETL Retrofit
report, 90 percent capture will result in emission rates that are 88.4
percent lower on a lb/MWh-gross basis and 87.1 percent lower on a lb/
MWh-net basis compared to units without capture.\658\ After capture,
CO2 can be transported and securely sequestered.\659\
Although steam generating units with CO2 capture will have
an incentive to operate at higher utilization because the cost to
install the CCS system is largely fixed and the IRC section 45Q tax
credit increases based on the amount of CO2 captured and
sequestered, any increase in utilization will be far outweighed by the
substantial reductions in emission rate.
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\658\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
\659\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
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v. Promotion of the Development and Implementation of Technology
The EPA considered the potential impact on technology advancement
of designating CCS as the BSER for long-term coal-fired steam
generating units, and in this final rule, the EPA considers
[[Page 39887]]
that designating CCS as the BSER will provide for meaningful
advancement of CCS technology. As indicated above, the EPA's IPM
modeling indicates that 11 GW of coal-fired power plants install CCS
and generate 76 terawatt-hours (TWh) per year in the base case, and
that another 8 GW of plants install CCS and generate another 57 TWh per
year in the policy case. In this manner, this rule advances CCS
technology more widely throughout the coal-fired power sector. As
discussed in section VIII.F.4.c.iv(G) of this preamble, this rule
advances CCS technology for new combined cycle base load combustion
turbines, as well. It is also likely that this rule supports advances
in the technology in other industries.
vi. Comparison With 2015 NSPS For Newly Constructed Coal-Fired EGUs
In the 2015 NSPS, the EPA determined that the BSER for newly
constructed coal-fired EGUs was based on CCS with 16 to 23 percent
capture, based on the type of coal combusted, and consequently, the EPA
promulgated standards of performance of 1,400 lb CO2/MWh-g.
80 FR 64512 (table 1), 64513 (October 23, 2015). The EPA made those
determinations based on the costs of CCS at the time of that
rulemaking. In general, those costs were significantly higher than at
present, due to recent technology cost declines as well as related
policies, including the IRC section 45Q tax credit for CCS, which were
not available at that time for purposes of consideration during the
development of the NSPS. Id. at 64562 (table 8). Based on of these
higher costs, the EPA determined that 16-23 percent capture qualified
as the BSER, rather than a significantly higher percentage of capture.
Given the substantial differences in the cost of CCS during the time of
the 2015 NSPS and the present time, the capture percentage of the 2015
NSPS necessarily differed from the capture percentage in this final
action, and, by the same token, the associated degree of emission
limitation and resulting standards of performance necessarily differ as
well. If the EPA had strong evidence to indicate that new coal-fired
EGUs would be built, it would propose to revise the 2015 NSPS to align
the BSER and emissions standards to reflect the new information
regarding the costs of CCS. Because there is no evidence to suggest
that there are any firm plans to build new coal-fired EGUs in the
future, however, it is not at present a good use of the EPA's limited
resources to propose to update the new source standard to align with
the existing source standard finalized today. While the EPA is not
revising the new source standard for new coal-fired EGUs in this
action, the EPA is retaining the ability to propose review in the
future.
vii. Requirement That Source Must Transfer CO2 to an Entity
That Reports Under the Greenhouse Gas Reporting Program
The final rule requires that EGUs that capture CO2 in
order to meet the applicable emission standard report in accordance
with the GHGRP requirements of 40 CFR part 98, including subpart PP.
GHGRP subpart RR and subpart VV requirements provide the monitoring and
reporting mechanisms to quantify CO2 storage and to
identify, quantify, and address potential leakage. Under existing GHGRP
regulations, sequestration wells permitted as Class VI under the UIC
program are required to report under subpart RR. Facilities with UIC
Class II wells that inject CO2 to enhance the recovery of
oil or natural gas can opt-in to reporting under subpart RR by
submitting and receiving approval for a monitoring, reporting, and
verification (MRV) plan. Subpart VV applies to facilities that conduct
enhanced recovery using ISO 27916 to quantify geologic storage unless
they have opted to report under subpart RR. For this rule, if injection
occurs on site, the EGU must report data accordingly under 40 CFR part
98 subpart RR or subpart VV. If the CO2 is injected off
site, the EGU must transfer the captured CO2 to a facility
that reports in accordance with the requirements of 40 CFR part 98,
subpart RR or subpart VV. They may also transfer the captured
CO2 to a facility that has received an innovative technology
waiver from the EPA.
b. Options Not Determined To Be the BSER for Long-Term Coal-Fired Steam
Generating Units
In this section, we explain why CCS at 90 percent capture best
balances the BSER factors and therefore why the EPA has determined it
to be the best of the possible options for the BSER.
i. Partial Capture CCS
Partial capture for CCS was not determined to be BSER because the
emission reductions are lower and the costs would, in general, be
higher. As discussed in section IV.B of this preamble, individual coal-
fired power plants are by far the highest-emitting plants in the
nation, and the coal-fired power plant sector is higher-emitting than
any other stationary source sector. CCS at 90 percent capture removes
very high absolute amounts of emissions. Partial capture CCS would fail
to capture large quantities of emissions. With respect to costs,
designs for 90 percent capture in general take greater advantage of
economies of scale. Eligibility for the IRC section 45Q tax credit for
existing EGUs requires design capture rates equivalent to 75 percent of
a baseline emission rate by mass. Even assuming partial capture rates
meet that definition, lower capture rates would receive fewer returns
from the IRC section 45Q tax credit (since these are tied to the amount
of carbon sequestered, and all else being equal lower capture rates
would result in lower amounts of sequestered carbon) and costs would
thereby be higher.
ii. Natural Gas Co-Firing
(A) Reasons Why Not Selected as BSER
As discussed in section VII.C.2, the EPA is determining 40 percent
natural gas co-firing to qualify as the BSER for the medium-term
subcategory of coal-fired steam generating units. This subcategory
consists of units that will permanently cease operation by January 1,
2039. In making this BSER determination, the EPA analyzed the ability
of all existing coal-fired units--not only medium-term units--to
install and operate 40 percent co-firing. As a result, all of the
determinations concerning the criteria for BSER that the EPA made for
40 percent co-firing apply to all existing coal-fired units, including
the units in the long-term subcategory. For example, 40 percent co-
firing is adequately demonstrated for the long-term subcategory, and
has reasonable energy requirements and reasonable non-air quality
environmental impacts. It would also be of reasonable cost for the
long-term subcategory. Although the capital expenditure for natural gas
co-firing is lower than CCS, the variable costs are higher. As a
result, the total costs of natural gas co-firing, in general, are
higher on a $/ton basis and not substantially lower on a $/MWh basis,
than for CCS. Were co-firing the BSER for long-term units, the cost
that industry would bear might then be considered similar to the cost
for CCS. In addition, the GHG Mitigation Measures TSD shows that all
coal-fired units would be able to achieve the requisite infrastructure
build-out and obtain sufficient quantities of natural gas to comply
with standards of performance based on 40 percent co-firing by January
1, 2030.
The EPA is not selecting 40 percent natural gas co-firing as the
BSER for the long-term subcategory, however, because it requires
substantially less emission reductions at the unit-level than 90
percent capture CCS. Natural gas co-firing at 40 percent of the heat
[[Page 39888]]
input to the steam generating unit achieves 16 percent reductions in
emission rate at the stack, while CCS achieves an 88.4 percent
reduction in emission rate. As discussed in section IV.B of this
preamble, individual coal-fired power plants are by far the highest-
emitting plants in the nation, and the coal-fired power plant sector is
higher-emitting than any other stationary source sector. Because the
unit-level emission reductions achievable by CCS are substantially
greater, and because CCS is of reasonable cost and matches up well
against the other BSER criteria, the EPA did not determine natural gas
co-firing to be BSER for the long-term subcategory although, under
other circumstances, it could be. Determining BSER requires the EPA to
select the ``best'' of the systems of emission reduction that are
adequately demonstrated, as described in section V.C.2; in this case,
there are two systems of emission reduction that match up well against
the BSER criteria, but based on weighing the criteria together, and in
light of the substantially greater unit-level emission reductions from
CCS, the EPA has determined that CCS is a better system of emission
reduction than co-firing for the long-term subcategory.
The EPA notes that if a state demonstrates that a long-term coal-
fired steam generating unit cannot install and operate CCS and cannot
otherwise reasonably achieve the degree of emission limitation that the
EPA has determined based on CCS, following the process the EPA has
specified in its applicable regulations for consideration of RULOF, the
state would evaluate natural gas co-firing as a potential basis for
establishing a less stringent standard of performance, as detailed in
section X.C.2 of this document.
iii. Heat Rate Improvements
Heat rate improvements were not considered to be BSER for long-term
steam generating units because the achievable reductions are very low
and may result in a rebound effect whereby total emissions from the
source increase, as detailed in section VII.D.4.a of this preamble.
Comment: One commenter requested that HRI be considered as BSER in
addition to CCS, so that long-term sources would be required to achieve
reductions in emission rate consistent with performing HRI and adding
CCS with 90 percent capture to the source.
Response: As described in section VII.D.4.a, the reductions from
HRI are very low and many sources have already made HRI, so that
additional reductions are not available. It is possible that a source
installing CO2 capture will make efficiency improvements as
a matter of best practices. For example, Boundary Dam Unit 3 made
upgrades to the existing steam generating unit when CCS was installed,
including installing a new steam turbine.\660\ However, the reductions
from efficiency improvements would not be additive to the reductions
from CCS because of the impact of the CO2 capture plant on
the efficiency of source due to the required steam and electricity load
of the capture plant.
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\660\ IEAGHG Report 2015-06. Integrated Carbon Capture and
Storage Project at SaskPower's Boundary Dam Power Station. August
2015. https://ieaghg.org/publications/technical-reports/reports-list/9-technical-reports/935-2015-06-integrated-ccs-project-at-saskpower-s-boundary-dam-power-station.
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c. Conclusion
Coal-fired EGUs remain the largest stationary source of dangerous
CO2 emissions. The EPA is finalizing CCS at a capture rate
of 90 percent as the BSER for long-term coal-fired steam generating
units because this system satisfies the criteria for BSER as summarized
here. CCS at a capture rate of 90 percent as the BSER for long-term
coal-fired steam generating units is adequately demonstrated, as
indicated by the facts that it has been operated at scale, is widely
applicable to these sources, and that there are vast sequestration
opportunities across the continental U.S. Additionally, accounting for
recent technology cost declines as well as policies including the tax
credit under IRC section 45Q, the costs for CCS are reasonable.
Moreover, any adverse non-air quality health and environmental impacts
and energy requirements of CCS, including impacts on the power sector
on a nationwide basis, are limited and can be effectively avoided or
mitigated. In contrast, co-firing 40 percent natural gas would achieve
far fewer emission reductions without improving the cost reasonableness
of the control strategy.
These considerations provide the basis for finalizing CCS as the
best of the systems of emission reduction for long-term coal-fired
power plants. In addition, determining CCS as the BSER promotes
advancements in control technology for CO2, which is a
relevant consideration when establishing BSER under section 111 of the
CAA.
i. Adequately Demonstrated
CCS with 90 percent capture is adequately demonstrated based on the
information in section VII.C.1.a.i of this preamble. Solvent-based
CO2 capture was patented nearly 100 years ago in the 1930s
\661\ 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.\662\ And
tens of millions of tons of CO2 have been permanently stored
deep underground either for geologic sequestration or in association
with EOR.\663\ There are currently at least 15 operating CCS projects
in the U.S., and another 121 that are under construction or in advanced
stages of development.\664\ This broad application of CCS demonstrates
the successful operation of all three components of CCS, operating both
independently and simultaneously. Various CO2 capture
methods are used in industrial applications and are tailored to the
flue gas conditions of a particular industry (see the final TSD, GHG
Mitigation Measures for Steam Generating Units for details). Of those
capture technologies, amine solvent-based capture has been demonstrated
for removal of CO2 from the post-combustion flue gas of
fossil fuel-fired EGUs.
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\661\ 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.
\662\ 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-transmission-hazardous-liquids.
\663\ US EPA. GHGRP. https://www.epa.gov/ghgreporting/supply-underground-injection-and-geologic-sequestration-carbon-dioxide.
\664\ Carbon Capture and Storage in the United States. CBO.
December 13, 2023. https://www.cbo.gov/publication/59345.
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Since 1978, an amine-based system has been used to capture
approximately 270,000 metric tons of CO2 per year from the
flue gas of the bituminous coal-fired steam generating units at the 63
MW Argus Cogeneration Plant (Trona, California).\665\ Amine solvent
capture has been further demonstrated at coal-fired power plants
including AES's Warrior Run and Shady Point. And since 2014, CCS has
been applied at the commercial scale at Boundary Dam Unit 3, a 110 MW
lignite coal-fired steam generating unit in Saskatchewan, Canada.
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\665\ Dooley, J.J., et al. (2009). ``An Assessment of the
Commercial Availability of Carbon Dioxide Capture and Storage
Technologies as of June 2009.'' U.S. DOE, Pacific Northwest National
Laboratory, under Contract DE-AC05-76RL01830.
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Impending increases in Canadian regulatory CO2 emission
requirements have prompted optimization of Boundary Dam Unit 3 so that
the facility now captures 83 percent of its total CO2
emissions. Moreover, from the flue gas
[[Page 39889]]
treated, Boundary Dam Unit 3 consistently captured 90 percent or more
of the CO2 over a 3-year period. The adequate demonstration
of CCS is further corroborated by the EPAct05-assisted 240MW-equivalent
Petra Nova CCS project at the coal-fired W.A. Parish Unit 8, which
achieved over 90 percent capture from the treated flue gas during a 3-
year period. Additionally, the technical improvements put in practice
at Boundary Dam Unit 3 and Petra Nova can be put in place on new
capture facilities during initial construction. This includes
redundancies and isolations for key equipment, and spray systems to
limit fly ash carryover. Projects that have announced plans to install
CO2 capture directly include these improvements in their
design and employ new solvents achieving higher capture rates that are
commercially available from technology providers. As a result, these
projects target capture efficiencies of at least 95 percent, well above
the BSER finalized here.
Precedent, building upon the statutory text and context, has
established that the EPA may make a finding of adequate demonstration
by drawing upon existing data from individual commercial-scale sources,
including testing at these sources,\666\ and that the agency may make
projections based on existing data to establish a more stringent
standard than has been regularly shown,\667\ in particular in cases
when the agency can specifically identify technological improvements
that can be expected to achieve the standard in question.\668\ Further,
the EPA may extrapolate based on testing at a particular kind of source
to conclude that the technology at issue will also be effective at a
different, related, source.\669\ Following this legal standard, the
available data regarding performance and testing at Boundary Dam, a
commercial-scale plant, is enough, by itself, to support the EPA's
adequate demonstration finding for a 90 percent standard. In addition
to this, however, in the 9 years since Boundary Dam began operating,
operators and the EPA have developed a clear understanding of specific
technological improvements which, if implemented, the EPA can
reasonably expect to lead to a 90 percent capture rate on a regular and
ongoing basis. The D.C. Circuit has established that this information
is more than enough to establish that a 90 percent standard is
achievable.\670\ And per Lignite Energy Council, the findings from
Boundary Dam can be extrapolated to other, similarly operating power
plants, including natural gas plants.\671\
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\666\ See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Nat'l Asphalt Pavement Ass'n v. Train, 539 F.2d 775
(D.C. Cir. 1976).
\667\ See id.
\668\ See Sierra Club v. Costle, 657 F.2d 298 (1981).
\669\ Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir.
1999).
\670\ See, e.g., Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (1981).
\671\ 198 F.3d 930 (D.C. Cir. 1999).
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Transport of CO2 and geological storage of
CO2 have also been adequately demonstrated, as detailed in
VII.C.1.a.i(B)(7) and VII.C.1.a.i(D)(2). CO2 has been
transported through pipelines for over 60 years, and in the past 20
years, 500 million metric tons of CO2 moved through over
5,000 miles of CO2 pipelines. CO2 pipeline
controls and PHMSA standards ensure that captured CO2 will
be securely conveyed to a sequestration site. Due to the proximity of
sources to storage, it would be feasible for most sources to build
smaller and shorter source-to-sink laterals, rather than rely on a
trunkline network buildout. In addition to pipelines, CO2
can also be transported via vessel, highway, or rail. Geological
storage is proven and broadly available, and of the coal-fired steam
generating units with planned operation during or after 2030, 77
percent are within 40 miles of the boundary of a saline reservoir.
The EPA also considered the timelines, materials, and workforce
necessary for installing CCS, and determined they are sufficient.
ii. Cost
Process improvements have resulted in a decrease in the projected
costs to install CCS on existing coal-fired steam generating units.
Additionally, the IRC section 45Q tax credit provides $85 per metric
ton ($77 per ton) of CO2. It is reasonable to account for
the IRC section 45Q tax credit because the costs that should be
accounted for are the costs to the source. For the fleet of coal-fired
steam generating units with planned operation during or after 2033, and
assuming a 12-year amortization period and 80 percent annual capacity
factor and including source specific transport and storage costs, the
average total costs of CCS are -$5/ton of CO2 reduced and -
$4/MWh. And even for shorter amortization periods, the $/MWh costs are
comparable to or less than the costs for other controls ($10.60-$18.50/
MWh) for a substantial number of sources. Notably, the EPA's IPM model
projects that even without this final rule--that is, in the base case,
without any CAA section 111 requirements--some units would deploy CCS.
Similarly, the IPM model projects that even if this rule determined 40
percent co-firing to be the BSER for long-term coal, instead of CCS,
some additional units would deploy CCS. Therefore, the costs of CCS
with 90 percent capture are reasonable.
iii. Non-Air Quality Health and Environmental Impacts and Energy
Requirements
The CO2 capture plant requires substantial pre-treatment
of the flue gas to remove SO2 and fly ash (PM) while other
controls and process designs are necessary to minimize solvent
degradation and solvent loss. Although CCS has the potential to result
in some increases in non-GHG emissions, a robust regulatory framework,
generally implemented at the state level, is in place to mitigate other
non-GHG emissions from the CO2 capture plant. For transport,
pipeline safety is regulated by PHMSA, while UIC Class VI regulations
under the SDWA, in tandem with GHGRP subpart RR requirements, ensure
the protection of USDWs and the security of geologic sequestration.
Therefore, the potential non-air quality health and environmental
impacts do not militate against designating CCS as the BSER for long-
term steam EGUs. The EPA also considered energy requirements. While the
CO2 capture plant requires steam and electricity to operate,
the incentives provided by the IRC section 45Q tax credit will likely
result in increased total generation from the source. Therefore, the
energy requirements are not unreasonable, and there would be limited,
non-adverse impacts on the broader energy sector.
2. Medium-Term Coal-Fired Steam Generating Units
The EPA is finalizing its conclusion that 40 percent natural gas
co-firing on a heat input basis is the BSER for medium-term coal-fired
steam generating units. Co-firing 40 percent natural gas, on an annual
average heat input basis, results in a 16 percent reduction in
CO2 emission rate. The technology has been adequately
demonstrated, can be implemented at reasonable cost, does not have
significant adverse non-air quality health and environmental impacts or
energy requirements, including impacts on the energy sector, and
achieves meaningful reductions in CO2 emissions. Co-firing
also advances useful control technology, which provides additional,
although not essential, support for treating it as the BSER.
[[Page 39890]]
a. Rationale for the Medium-Term Coal-Fired Steam Generating Unit
Subcategory
For the development of the emission guidelines, the EPA first
considered CCS as the BSER for existing coal-fired steam generating
units. CCS generally achieves significant emission reductions at
reasonable cost. Typically, in setting the BSER, the EPA assumes that
regulated units will continue to operate indefinitely. However, that
assumption is not appropriate for all coal-fired steam generating
units. 62 percent of existing coal-fired steam generating units greater
than 25 MW have already announced that they will retire or convert from
coal to gas by 2039.\672\ CCS is capital cost-intensive, entailing a
certain period to amortize the capital costs. Therefore, the EPA
evaluated the costs of CCS for different amortization periods, as
detailed in section VII.C.1.a.ii of the preamble, and determined that
CCS was cost reasonable, on average, for sources operating more than 7
years after the compliance date of January 1, 2032. Accordingly, units
that cease operating before January 1, 2039, will generally have less
time to amortize the capital costs, and the costs for those sources
would be higher and thereby less comparable to those the EPA has
previously determined to be reasonable. Considering this, and the other
factors evaluated in determining BSER, the EPA is not finalizing CCS as
BSER for units demonstrating that they plan to permanently cease
operation prior to January 1, 2039.
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\672\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v7. December 2023. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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Instead, the EPA is subcategorizing these units into the medium-
term subcategory and finalizing a BSER based on 40 percent natural gas
co-firing on a heat input basis for these units. Co-firing natural gas
at 40 percent has significantly lower capital costs than CCS and can be
implemented by January 1, 2030. For sources that expect to continue in
operation until January 1, 2039, and that therefore have a 9-year
amortization period, the costs of 40 percent co-firing are $73/ton of
CO2 reduced or $13/MWh of generation, which supports their
reasonableness because they are comparable to or less than the costs
detailed in section VII.C.1.a.ii(D) of this preamble for other controls
on EGUs ($10.60 to $18.50/MWh) and for GHGs for the Crude Oil and
Natural Gas source category in the 2016 NSPS of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015). Co-firing is
also cost-reasonable for sources permanently ceasing operations sooner,
and that therefore have a shorter amortization period. As discussed in
section VII.B.2 of this preamble, with a two-year amortization period,
many units can co-fire with meaningful amounts of natural gas at
reasonable cost. Of course, even more can co-fire at reasonable costs
with amortization periods longer than two years. For example, the EPA
has determined that 33 percent of sources with an amortization period
of at least three years have costs for 40 percent co-firing below both
of the $/ton and $/MWh metrics, and 68 percent of those sources have
costs for 20 percent co-firing below both of those metrics. Therefore,
recognizing that operating horizon affects the cost reasonableness of
controls, the EPA is finalizing a separate subcategory for coal-fired
steam generating units operating in the medium-term--those
demonstrating that they plan to permanently cease operation after
December 31, 2031, and before January 1, 2039--with 40 percent natural
gas co-firing as the BSER.
i. Legal Basis for Establishing the Medium-Term Subcategory
As noted in section V.C.1 of this preamble, the EPA has broad
authority under CAA section 111(d) to identify subcategories. As also
noted in section V.C.1, the EPA's authority to ``distinguish among
classes, types, and sizes within categories,'' as provided under CAA
section 111(b)(2) and as we interpret CAA section 111(d) to provide as
well, generally allows the Agency to place types of sources into
subcategories when they have characteristics that are relevant to the
controls that the EPA may determine to be the BSER for those sources.
One element of the BSER is cost reasonableness. See CAA section
111(d)(1) (requiring the EPA, in setting the BSER, to ``tak[e] into
account the cost of achieving such reduction''). As noted in section V,
the EPA's longstanding regulations under CAA section 111(d) explicitly
recognize that subcategorizing may be appropriate for sources based on
the ``costs of control.'' \673\ Subcategorizing on the basis of
operating horizon is consistent with a key characteristic of the coal-
fired power industry that is relevant for determining the cost
reasonableness of control requirements: A large percentage of the
sources in the industry have already announced, and more are expected
to announce, dates for ceasing operation, and the fact that many coal-
fired steam generating units intend to cease operation in the near term
affects what controls are ``best'' for different subcategories.\674\ At
the outset, installation of emission control technology takes time,
sometimes several years. Whether the costs of control are reasonable
depends in part on the period of time over which the affected sources
can amortize those costs. Sources that have shorter operating horizons
will have less time to amortize capital costs. Thus, the annualized
cost of controls may thereby be less comparable to the costs the EPA
has previously determined to be reasonable.\675\
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\673\ 40 CFR 60.22(b)(5), 60.22a(b)(5).
\674\ The EPA recognizes that section 111(d) provides that in
applying standards of performance, a state may take into account,
among other factors, the remaining useful life of a facility. The
EPA believes that provision is intended to address exceptional
circumstances at particular facilities, while the EPA has the
responsibility to determine how to address the source category as a
whole. See 88 FR 80480, 80511 (November 17, 2023) (``Under CAA 111,
EPA must provide BSER and degree of emission limitation
determinations that are, to the extent reasonably practicable,
applicable to all designated facilities in the source category. In
many cases, this requires the EPA to create subcategories of
designated facilities, each of which has a BSER and degree of
emission limitation tailored to its circumstances. . . . However, as
Congress recognized, this may not be possible in every instance
because, for example, it is not be feasible [sic] for the Agency to
know and consider the idiosyncrasies of every designated facility or
because the circumstances of individual facilities change after the
EPA determined the BSER.'') (internal citations omitted). That a
state may take into account the remaining useful life of an
individual source, however, does not bar the EPA from considering
operating horizon as a factor in determining whether
subcategorization is appropriate. As discussed, the authority to
subcategorize is encompassed within the EPA's authority to identify
the BSER. Here, where many units share similar characteristics and
have announced intended shorter operating horizons, it is
permissible for the EPA to take operating horizon into account in
determining the BSER for this subcategory of sources. States may
continue to take RULOF factors into account for particular units
where the information relevant to those units is fundamentally
different than the information the EPA took into account in
determining the degree of emission limitation achievable through
application of the BSER. Should a court conclude that the EPA does
not have the authority to create a subcategory based on the date at
which units intend to cease operation, then the EPA believes it
would be reasonable for states to consider co-firing as an
alternative to CCS as an option for these units through the states'
authority to consider, among other factors, remaining useful life.
\675\ Steam Electric Reconsideration Rule, 85 FR 64650, 64679
(October 13, 2020) (distinguishes between EGUs retiring before 2028
and EGUs remaining in operation after that time).
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In addition, subcategorizing by length of period of continued
operation is similar to two other bases for subcategorization on which
the EPA has relied in prior rules, each of which implicates the cost
reasonableness of controls: The first is load level, noted in section
V.C.1. of this preamble. For
[[Page 39891]]
example, in the 2015 NSPS, the EPA divided new natural gas-fired
combustion turbines into the subcategories of base load and non-base
load. 80 FR 64602 (table 15) (October 23, 2015). The EPA did so because
the control technologies that were ``best''--including consideration of
feasibility and cost reasonableness--depended on how much the unit
operated. The load level, which relates to the amount of product
produced on a yearly or other basis, bears similarity to a limit on a
period of continued operation, which concerns the amount of time
remaining to produce the product. In both cases, certain technologies
may not be cost-reasonable because of the capacity to produce product--
i.e., the costs are spread over less product produced.
Subcategorization on this basis is also supported by how utilities
manage their assets over the long term, and was widely supported by
industry commenters.
The second basis for subcategorization on which EPA has previously
relied is fuel type, as also noted in section V.C.1 of this preamble.
The 2015 NSPS provides an example of this type of subcategorization as
well. There, the EPA divided new combustion turbines into subcategories
on the basis of type of fuel combusted. Id. Subcategorizing on the
basis of the type of fuel combusted may be appropriate when different
controls have different costs, depending on the type of fuel, so that
the cost reasonableness of the control depends on the type of fuel. In
that way, it is similar to subcategorizing by operating horizon because
in both cases, the subcategory is based upon the cost reasonableness of
controls. Subcategorizing by operating horizon is also tantamount to
the length of time over which the source will continue to combust the
fuel. Subcategorizing on this basis may be appropriate when different
controls for a particular fuel have different costs, depending on the
length of time when the fuel will continue to be combusted, so that the
cost reasonableness of controls depends on that timeframe. Some prior
EPA rules for coal-fired sources have made explicit the link between
length of time for continued operation and type of fuel combusted by
codifying federally enforceable retirement dates as the dates by which
the source must ``cease burning coal.'' \676\
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\676\ See 79 FR 5031, 5192 (January 30, 2014) (explaining that
``[t]he construction permit issued by Wyoming requires Naughton Unit
3 to cease burning coal by December 31, 2017, and to be retrofitted
to natural gas as its fuel source by June 30, 2018'' (emphasis
added)).
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As noted above, creating a subcategory on the basis of operating
horizon does not preclude a state from considering RULOF in applying a
standard of performance to a particular source. The EPA's authority to
set BSER for a source category (including subcategories) and a state's
authority to invoke RULOF for individual sources within a category or
subcategory are distinct. The EPA's statutory obligation is to
determine a generally applicable BSER for a source category, and where
that source category encompasses different classes, types, or sizes of
sources, to set generally applicable BSERs for subcategories accounting
for those differences. By contrast, states' authority to invoke RULOF
is premised on the state's ability to take into account information
relevant to individual units that is fundamentally different than the
information the EPA took into account in determining BSER generally. As
noted, the EPA may subcategorize on the basis of cost of controls, and
operating horizon may factor into the cost of controls. Moreover,
through section 111(d)(1), Congress also required the EPA to develop
regulations that permit states to consider ``among other factors, the
remaining useful life'' of a particular existing source. The EPA has
interpreted these other factors to include costs or technical
feasibility specific to a particular source, even though these are
factors the EPA itself considers in setting the BSER. In other words,
the factors the EPA may consider in setting the BSER and the factors
the states may consider in applying standards of performance are not
distinct. As noted above, the EPA is finalizing these subcategories in
response to requests by power sector representatives that this rule
accommodate the fact that there is a class of sources that plan to
voluntarily cease operations in the near term. Although the EPA has
designed the subcategories to accommodate those requests, a particular
source may still present source-specific considerations--whether
related to its remaining useful life or other factors--that the state
may consider relevant for the application of that particular source's
standard of performance, and that the state should address as described
in section X.C.2 of this preamble.
ii. Comments Received on Existing Coal-Fired Subcategories
Comment: The EPA received several comments on the proposed
subcategories for coal-fired steam generating units. Many commenters,
including industry commenters, supported these subcategories. Some
commenters opposed these proposed subcategories. They argued that the
subcategories were designed to force coal-fired power plants to retire.
Response: We disagree with comments suggesting that the
subcategories for existing coal-fired steam EGUs that the EPA has
finalized in this rule were designed to force retirements. The
subcategories were not designed for that purpose, and the commenters do
not explain their allegations to the contrary. The subcategories were
designed, at industry's request,\677\ to ensure that subcategories of
units that can feasibly and cost-reasonably employ emissions reduction
technologies--and only those subcategories of units that can do so--are
required to reduce their emissions commensurate with those
technologies. As explained above, in determining the BSER, the EPA
generally assumes that a source will operate indefinitely, and
calculates expected control costs on that basis. Under that assumption,
the BSER for existing fossil-fuel fired EGUs is CCS. Nevertheless, the
EPA recognizes that many fossil-fuel fired EGUs have already announced
plans to cease operation. In recognition of this unique, distinguishing
factor, the EPA determined whether a different BSER would be
appropriate for fossil fuel-fired EGUs that do not intend to operate
over the long term, and concluded, for the reasons stated above, that
natural gas co-firing was appropriate for these sources that intended
to cease operation before 2039. This subcategory is not intended to
force retirements, and the EPA is not directing any state or any unit
as to the choice of when to cease operation. Rather, the EPA has
created this subcategory to accommodate these sources' intended
operation plans. In fact, a number of industry commenters specifically
requested and supported subcategories based on retirement dates in
recognition of the reality that many operators are choosing to retire
these units and that whether or not a control technology is feasible
and cost-reasonable depends upon how long a unit intends to operate.
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\677\ As described in the proposal, during the early engagement
process, industry stakeholders requested that the EPA ``[p]rovide
approaches that allow for the retirement of units as opposed to
investments in new control technologies, which could prolong the
lives of higher-emitting EGUs; this will achieve maximum and durable
environmental benefits.'' Industry stakeholders also suggested that
the EPA recognize that some units may remain operational for a
several-year period but will do so at limited capacity (in part to
assure reliability), and then voluntarily cease operations entirely.
88 FR 33245 (May 23, 2023).
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Specifically, as noted in section VII.B of this preamble, in this
final action, the
[[Page 39892]]
medium-term subcategory includes a date for permanently ceasing
operation, which applies to coal-fired plants demonstrating that they
plan to permanently cease operating after December 31, 2031, and before
January 1, 2039. The EPA is retaining this subcategory because 55
percent of existing coal-fired steam generating units greater than 25
MW have already announced that they will retire or convert from coal to
gas by January 1, 2039.\678\ Accordingly, the costs of CCS--the high
capital costs of which require a lengthy amortization period from its
January 1, 2032, implementation date--are higher than the traditional
metric for cost reasonableness for these sources. As discussed in
section VII.C.2 of this preamble, the BSER for these sources is co-
firing 40 percent natural gas. This is because co-firing, which has an
implementation date of January 1, 2030, has lower capital costs and is
therefore cost-reasonable for sources continuing to operate on or after
January 1, 2032. It is further noted that this subcategory is elective.
Furthermore, states also have the authority to establish a less
stringent standard through RULOF in the state plan process, as detailed
in section X.C.2 of this preamble.
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\678\ U.S. Environmental Protection Agency. National Electric
Energy Data System (NEEDS) v7. December 2023. https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs.
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In sum, these emission guidelines do not require any coal-fired
steam EGU to retire, nor are they intended to induce retirements.
Rather, these emission guidelines simply set forth presumptive
standards that are cost-reasonable and achievable for each subcategory
of existing coal-fired steam EGUs. See section VII.E.1 of this preamble
(responding to comments that this rule violates the major questions
doctrine).
Comment: The EPA broadly solicited comment on the dates and values
defining the proposed subcategories for coal-fired steam generating
units. Regarding the proposed dates for the subcategories, one industry
stakeholder commented that the ``EPA's proposed retirement dates for
applicability of the various subcategories are appropriate and broadly
consistent with system reliability needs.'' \679\ More specifically,
industry commenters requested that the cease-operation-by date for the
imminent-term subcategory be changed from January 1, 2032, to January
1, 2033. Industry commenters also stated that the 20 percent
utilization limit in the definition of the near-term subcategory was
overly restrictive and inconsistent with the emissions stringency of
either the proposed medium term or imminent term subcategory--
commenters requested greater flexibility for the near-term subcategory.
Other comments from NGOs and other groups suggested various other
changes to the subcategory definitions. One commenter requested moving
the cease-operation-by date for the medium-term subcategory up to
January 1, 2038, while eliminating the imminent-term subcategory and
extending the near-term subcategory to January 1, 2038.
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\679\ See Document ID No. EPA-HQ-OAR-2023-0072-0772.
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Response: The EPA is not finalizing the proposed imminent-term or
near-term subcategories. The EPA is finalizing an applicability
exemption for sources demonstrating that they plan to permanently cease
operation prior to January 1, 2032, as detailed in section VII.B of
this preamble. The EPA is finalizing the cease operating by date of
January 1, 2039, for medium-term coal-fired steam generating units.
These dates are all based on costs of co-firing and CCS, driven by
their amortization periods, as discussed in the preceding sections of
this preamble.
b. Rationale for Natural Gas Co-Firing as the BSER for Medium-Term
Coal-Fired Steam Generating Units
In this section of the preamble, the EPA describes its rationale
for natural gas co-firing as the final BSER for medium-term coal-fired
steam generating units.
For a coal-fired steam generating unit, the substitution of natural
gas for some of the coal, so that the unit fires a combination of coal
and natural gas, is known as ``natural gas co-firing.'' The EPA is
finalizing natural gas co-firing at a level of 40 percent of annual
heat input as BSER for medium-term coal-fired steam generating units.
i. Adequately Demonstrated
The EPA is finalizing its determination that natural gas co-firing
at the level of 40 percent of annual heat input is adequately
demonstrated for coal-fired steam generating units. Many existing coal-
fired steam generating units already use some amount of natural gas,
and several have co-fired at relatively high levels at or above 40
percent of heat input in recent years.
(A) Boiler Modifications
Existing coal-fired steam generating units can be modified to co-
fire natural gas in any desired proportion with coal, up to 100 percent
natural gas. Generally, the modification of existing boilers to enable
or increase natural gas firing typically involves the installation of
new gas burners and related boiler modifications, including, for
example, new fuel supply lines and modifications to existing air ducts.
The introduction of natural gas as a fuel can reduce boiler efficiency
slightly, due in large part to the relatively high hydrogen content of
natural gas. However, since the reduction in coal can result in reduced
auxiliary power demand, the overall impact on net heat rate can range
from a 2 percent increase to a 2 percent decrease.
It is common practice for steam generating units to have the
capability to burn multiple fuels onsite, and of the 565 coal-fired
steam generating units operating at the end of 2021, 249 of them
reported consuming natural gas as a fuel or startup source. Coal-fired
steam generating units often use natural gas or oil as a startup fuel,
to warm the units up before running them at full capacity with coal.
While startup fuels are generally used at low levels (up to roughly 1
percent of capacity on an annual average basis), some coal-fired steam
generating units have co-fired natural gas at considerably higher
shares. Based on hourly reported CO2 emission rates from the
start of 2015 through the end of 2020, 29 coal-fired steam generating
units co-fired with natural gas at rates at or above 60 percent of
capacity on an hourly basis.\680\ The capability of those units on an
hourly basis is indicative of the extent of boiler burner modifications
and sizing and capacity of natural gas pipelines to those units, and
implies that those units are technically capable of co-firing at least
60 percent natural gas on a heat input basis on average over the course
of an extended period (e.g., a year). Additionally, during that same
2015 through 2020 period, 29 coal-fired steam generating units co-fired
natural gas at over 40 percent on an annual heat input basis. Because
of the number of units that have demonstrated co-firing above 40
percent of heat input, the EPA is finalizing that co-firing at 40
percent is adequately demonstrated. A more detailed discussion of the
record of natural gas co-firing, including current trends, at coal-
fired steam generating units is included in the final TSD, GHG
Mitigation Measures for Steam Generating Units.
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\680\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. Available from EPA's Air Markets Program
Data website: https://campd.epa.gov.
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(B) Natural Gas Pipeline Development
In addition to any potential boiler modifications, the supply of
natural gas is necessary to enable co-firing at existing coal-fired
steam boilers. As
[[Page 39893]]
discussed in the previous section, many plants already have at least
some access to natural gas. In order to increase natural gas access
beyond current levels, plants may find it necessary to construct
natural gas supply pipelines.
The U.S. natural gas pipeline network consists of approximately 3
million miles of pipelines that connect natural gas production with
consumers of natural gas. To increase natural gas consumption at a
coal-fired boiler without sufficient existing natural gas access, it is
necessary to connect the facility to the natural gas pipeline
transmission network via the construction of a lateral pipeline. The
cost of doing so is a function of the total necessary pipeline capacity
(which is characterized by the length, size, and number of laterals)
and the location of the plant relative to the existing pipeline
transmission network. The EPA estimated the costs associated with
developing new lateral pipeline capacity sufficient to meet 60 percent
of the net summer capacity at each coal-fired steam generating unit
that could be included in this subcategory. As discussed in the final
TSD, GHG Mitigation Measures for Steam Generating Units, the EPA
estimates that this lateral capacity would be sufficient to enable each
unit to achieve 40 percent natural gas co-firing on an annual average
basis.
The EPA considered the availability of the upstream natural gas
pipeline capacity to satisfy the assumed co-firing demand implied by
these new laterals. This analysis included pipeline development at all
EGUs that could be included in this subcategory, including those
without announced plans to cease operating before January 1, 2039. The
EPA's assessment reviewed the reasonableness of each assumed new
lateral by determining whether the peak gas capacity of that lateral
could be satisfied without modification of the transmission pipeline
systems to which it is assumed to be connected. This analysis found
that most, if not all, existing pipeline systems are currently able to
meet the peak needs implied by these new laterals in aggregate,
assuming that each existing coal-fired unit in the analysis co-fired
with natural gas at a level implied by these new laterals, or 60
percent of net summer generating capacity. While this is a reasonable
assumption for the analysis to support this mitigation measure in the
BSER context, it is also a conservative assumption that overstates the
amount of natural gas co-firing expected under the final rule.\681\
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\681\ In practice, not all sources would necessarily be subject
to a natural gas co-firing BSER in compliance. E.g., some portion of
that population of sources could install CCS, so the resulting
amount of natural gas co-firing would be less.
---------------------------------------------------------------------------
Most of these individual laterals are less than 15 miles in length.
The maximum aggregate amount of pipeline capacity, if all coal-fired
steam capacity that could be included in the medium-term subcategory
(i.e., all capacity that has not announced that it plans to retire by
2032) implemented the final BSER by co-firing 40 percent natural gas,
would be comparable to pipeline capacity constructed recently. The EPA
estimates that this maximum total capacity would be nearly 14.7 billion
cubic feet per day, which would require about 3,500 miles of pipeline
costing roughly $11.5 billion. Over 2 years,\682\ this maximum total
incremental pipeline capacity would amount to less than 1,800 miles per
year, with a total annual capacity of roughly 7.35 billion cubic feet
per day. This represents an estimated annual investment of
approximately $5.75 billion per year in capital expenditures, on
average. By comparison, based on data collected by EIA, the total
annual mileage of natural gas pipelines constructed over the 2017-2021
period ranged from approximately 1,000 to 2,500 miles per year, with a
total annual capacity of 10 to 25 billion cubic feet per day. This
represents an estimated annual investment of up to nearly $15 billion.
The upper end of these historical annual values is much higher than the
maximum annual values that could be expected under this final BSER
measure--which, as noted above, represent a conservative estimate that
significantly overstates the amount of co-firing that the EPA projects
would occur under this final rule.
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\682\ The average time for permitting for a natural gas pipeline
lateral is 1.5 years, and many sources could be permitted faster
(about 1 year) so that it is reasonable to assume that many sources
could begin construction by June 2027. The average time for
construction of an individual pipeline is about 1 year or less.
Considering this, the EPA assumes construction of all of the natural
gas pipeline laterals in the analysis occurs over a 2-year period
(June 2027 through June 2029), and notes that in practice some of
these projects could be constructed outside of this period.
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These conservatively high estimates of pipeline requirements also
compare favorably to industry projections of future pipeline capacity
additions. Based on a review of a 2018 industry report, titled ``North
America Midstream Infrastructure through 2035: Significant Development
Continues,'' investment in midstream infrastructure development is
expected to range between $10 to $20 billion per year through 2035.
Approximately $5 to $10 billion annually is expected to be invested in
natural gas pipelines through 2035. This report also projects that an
average of over 1,400 miles of new natural gas pipeline will be built
through 2035, which is similar to the approximately 1,670 miles that
were built on average from 2013 to 2017. These values are consistent
with the average annual expenditure of $5.75 billion on less than 1,800
miles per year of new pipeline construction that would be necessary for
the entire operational fleet of existing coal-fired steam generating
units to co-fire with natural gas. The actual pipeline investment for
this subcategory would be substantially lower.
(C) Compliance Date for Medium-Term Coal-Fired Steam Generating Units
The EPA is finalizing a compliance date for medium-term coal-fired
steam generating units of January 1, 2030.
As in the timeline for CCS for the long term coal-fired steam
generating units described in section VII.C.1.a.i(E), the EPA assumes
here that feasibility work occurs during the state plan development
period, and that all subsequent work occurs after the state plan is
submitted and thereby effective at the state level. The EPA assumes 12
months of feasibility work for the natural gas pipeline lateral and 6
months of feasibility work for boiler modifications (both to occur over
June 2024 to June 2025). As with the feasibility analysis for CCS, the
feasibility analysis for co-firing will inform the state plan and
therefore it is reasonable to assume units will perform it during the
state planning window. Feasibility for the pipeline includes a right-
of-way and routing analysis. Feasibility for the boiler modifications
includes conceptual studies and design basis.
The timeline for the natural gas pipeline permitting and
construction is based on a review of recently completed permitting
approvals and construction.\683\ The average time to complete
permitting and approval is less than 1.5 years, and the average time to
complete actual construction is less than 1 year. Of the 31 reviewed
pipeline projects, the vast majority (27 projects) took less than a
total of 3 years for permitting and construction, and none took more
than 3.5 years. Therefore, it is reasonable to assume that permitting
and construction would take no more than 3 years for most sources (June
2026 to June 2029), noting that permitting
[[Page 39894]]
and construction for many sources would be faster.
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\683\ Documentation for the Lateral Cost Estimation (2024), ICF
International. Available in Docket ID EPA-HQ-OAR-2023-0072.
---------------------------------------------------------------------------
The timeline for boiler modifications based on the baseline
duration co-firing conversion project schedule developed by Sargent and
Lundy.\684\ The EPA assumes that, with the exception of the feasibility
studies discussed above, work on the boiler modifications begins after
the state plan submission due date. The EPA also assumes permitting for
the boiler modifications is required and takes 12 months (June 2026 to
June 2027). In the schedule developed by Sargent and Lundy, commercial
arrangements for the boiler modification take about 6 months (June 2026
to December 2026). Detailed engineering and procurement takes about 7
months (December 2026 to July 2027), and begins after commercial
arrangements are complete. Site work takes 3 months (July 2027 to
October 2027), followed by 4 months of construction (October 2027 to
February 2028). Lastly, startup and testing takes about 2 months (June
2029 to August 2029), noting that the EPA assumes this occurs after the
natural gas pipeline lateral is constructed. Considering the preceding
information, the EPA has determined January 1, 2030 is the compliance
date for medium-term coal-fired steam generating units.
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\684\ Natural Gas Co-Firing Memo, Sargent & Lundy (2023).
Available in Docket ID EPA-HQ-OAR-2023-0072.
---------------------------------------------------------------------------
ii. Costs
The capital costs associated with the addition of new gas burners
and other necessary boiler modifications depend on the extent to which
the current boiler is already able to co-fire with some natural gas and
on the amount of gas co-firing desired. The EPA estimates that, on
average, the total capital cost associated with modifying existing
boilers to operate at up to 100 percent of heat input using natural gas
is approximately $52/kW. These costs could be higher or lower,
depending on the equipment that is already installed and the expected
impact on heat rate or steam temperature.
While fixed O&M (FOM) costs can potentially decrease as a result of
decreasing the amount of coal consumed, it is common for plants to
maintain operation of one coal pulverizer at all times, which is
necessary for maintaining several coal burners in continuous service.
In this case, coal handling equipment would be required to operate
continuously and therefore natural gas co-firing would have limited
effect on reducing the coal-related FOM costs. Although, as noted,
coal-related FOM costs have the potential to decrease, the EPA does not
anticipate a significant increase in impact on FOM costs related to co-
firing with natural gas.
In addition to capital and FOM cost impacts, any additional natural
gas co-firing would result in incremental costs related to the
differential in fuel cost, taking into consideration the difference in
delivered coal and gas prices, as well as any potential impact on the
overall net heat rate. The EPA's reference case projects that in 2030,
the average delivered price of coal will be $1.56/MMBtu and the average
delivered price of natural gas will be $2.95/MMBtu. Thus, assuming the
same level of generation and no impact on heat rate, the additional
fuel cost would be $1.39/MMBtu on average in 2030. The total additional
fuel cost could increase or decrease depending on the potential impact
on net heat rate. An increase in net heat rate, for example, would
result in more fuel required to produce a given amount of generation
and thus additional cost. In the final TSD, GHG Mitigation Measures for
Steam Generating Units, the EPA's cost estimates assume a 1 percent
average increase in net heat rate.
Finally, for plants without sufficient access to natural gas, it is
also necessary to construct new natural gas pipelines (``laterals'').
Pipeline costs are typically expressed in terms of dollars per inch of
pipeline diameter per mile of pipeline distance (i.e., dollars per
inch-mile), reflecting the fact that costs increase with larger
diameters and longer pipelines. On average, the cost for lateral
development within the contiguous U.S. is approximately $280,000 per
inch-mile (2019$), which can vary based on site-specific factors. The
total pipeline cost for each coal-fired steam generating unit is a
function of this cost, as well as a function of the necessary pipeline
capacity and the location of the plant relative to the existing
pipeline transmission network. The pipeline capacity required depends
on the amount of co-firing desired as well as on the desired level of
generation--a higher degree of co-firing while operating at full load
would require more pipeline capacity than a lower degree of co-firing
while operating at partial load. It is reasonable to assume that most
plant owners would develop sufficient pipeline capacity to deliver the
maximum amount of desired gas use in any moment, enabling higher levels
of co-firing during periods of lower fuel price differentials. Once the
necessary pipeline capacity is determined, the total lateral cost can
be estimated by considering the location of each plant relative to the
existing natural gas transmission pipelines as well as the available
excess capacity of each of those existing pipelines.
The EPA determined the costs of 40 percent co-firing based on the
fleet of coal-fired steam generating units that existed in 2021 and
that do not have known plans to cease operations or convert to gas by
2032, and assuming that each of those units continues to operate at the
same level as it operated over 2017-2021. The EPA assessed those costs
against the cost reasonableness metrics, as described in section
VII.C.1.a.ii(D) of this preamble (i.e., emission control costs on EGUs
of $10.60 to $18.50/MWh and the costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas source category of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015)). On average,
the EPA estimates that the weighted average cost of co-firing with 40
percent natural gas as the BSER on an annual average basis is
approximately $73/ton CO2 reduced, or $13/MWh. The costs
here reflect an amortization period of 9 years. These estimates support
a conclusion that co-firing is cost-reasonable for sources that
continue to operate up until the January 1, 2039, threshold date for
the subcategory. The EPA also evaluated the fleet average costs of
natural gas co-firing for shorter amortization periods and has
determined that the costs are consistent with the cost reasonableness
metrics for the majority of sources that will operate past January 1,
2032, and therefore have an amortization period of at least 2 years and
up to 9 years. These estimates and all underlying assumptions are
explained in detail in the final TSD, GHG Mitigation Measures for Steam
Generating Units. Based on this cost analysis, alongside the EPA's
overall assessment of the costs of this rule, the EPA is finalizing
that the costs of natural gas co-firing are reasonable for the medium-
term coal-fired steam generating unit subcategory. If a particular
source has costs of 40 percent co-firing that are fundamentally
different from the cost reasonability metrics, the state may consider
this fact under the RULOF provisions, as detailed in section X.C.2 of
this preamble. The EPA previously estimated the cost of natural gas co-
firing in the Clean Power Plan (CPP). 80 FR 64662 (October 23, 2015).
The cost-estimates for co-firing presented in this section are lower
than in the CPP, for several reasons. Since then, the expected
difference between coal and gas prices has decreased significantly,
from over $3/MMBtu to less than $1.50/MMBtu in this final rule.
Additionally,
[[Page 39895]]
a recent analysis performed by Sargent and Lundy for the EPA supports a
considerably lower capital cost for modifying existing boilers to co-
fire with natural gas. The EPA also recently conducted a highly
detailed facility-level analysis of natural gas pipeline costs, the
median value of which is slightly lower than the value used by the EPA
previously to approximate the cost of co-firing at a representative
unit.
iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Natural gas co-firing for steam generating units is not expected to
have any significant adverse consequences related to non-air quality
health and environmental impacts or energy requirements.
(A) Non-GHG Emissions
Non-GHG emissions are reduced when steam generating units co-fire
with natural gas because less coal is combusted. SO2,
PM2.5, acid gas, mercury and other hazardous air pollutant
emissions that result from coal combustion are reduced proportionally
to the amount of natural gas consumed, i.e., under this final rule, by
40 percent. Natural gas combustion does produce NOX
emissions, but in lesser amounts than from coal-firing. However, the
magnitude of this reduction is dependent on the combustion system
modifications that are implemented to facilitate natural gas co-firing.
Sufficient regulations also exist related to natural gas pipelines
and transport that assure natural gas can be safely transported with
minimal risk of environmental release. PHMSA develops and enforces
regulations for the safe, reliable, and environmentally sound operation
of the nation's 2.6 million mile pipeline transportation system.
Recently, PHMSA finalized a rule that will improve the safety and
strengthen the environmental protection of more than 300,000 miles of
onshore gas transmission pipelines.\685\ PHMSA also recently
promulgated a separate rule covering natural gas transmission,\686\ as
well as a rule that significantly expanded the scope of safety and
reporting requirements for more than 400,000 miles of previously
unregulated gas gathering lines.\687\ FERC is responsible for the
regulation of the siting, construction, and/or abandonment of
interstate natural gas pipelines, gas storage facilities, and Liquified
Natural Gas (LNG) terminals.
---------------------------------------------------------------------------
\685\ Pipeline Safety: Safety of Gas Transmission Pipelines:
Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments (87
FR 52224; August 24, 2022).
\686\ Pipeline Safety: Safety of Gas Transmission Pipelines:
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other
Related Amendments (84 FR 52180; October 1, 2019).
\687\ Pipeline Safety: Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments (86 FR 63266; November
15, 2021).
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(B) Energy Requirements
The introduction of natural gas co-firing will cause steam boilers
to be slightly less efficient due to the high hydrogen content of
natural gas. Co-firing at levels between 20 percent and 100 percent can
be expected to decrease boiler efficiency between 1 percent and 5
percent. However, despite the decrease in boiler efficiency, the
overall net output efficiency of a steam generating unit that switches
from coal- to natural gas-firing may change only slightly, in either a
positive or negative direction. Since co-firing reduces coal
consumption, the auxiliary power demand related to coal handling and
emissions controls typically decreases as well. While a site-specific
analysis would be required to determine the overall net impact of these
countervailing factors, generally the effect of co-firing on net unit
heat rate can vary within approximately plus or minus 2 percent.
The EPA previously determined in the ACE Rule (84 FR 32545; July 8,
2019) that ``co-firing natural gas in coal-fired utility boilers is not
the best or most efficient use of natural gas and [. . .] can lead to
less efficient operation of utility boilers.'' That determination was
informed by the more limited supply of natural gas, and the larger
amount of coal-fired EGU capacity and generation, in 2019. Since that
determination, the expected supply of natural gas has expanded
considerably, and the capacity and generation of the existing coal-
fired fleet has decreased, reducing the total mass of natural gas that
might be required for sources to implement this measure.
Furthermore, regarding the efficient operation of boilers, the ACE
determination was based on the observation that ``co-firing can
negatively impact a unit's heat rate (efficiency) due to the high
hydrogen content of natural gas and the resulting production of water
as a combustion by-product.'' That finding does not consider the fact
that the effect of co-firing on net unit heat rate can vary within
approximately plus or minus 2 percent, and therefore the net impact on
overall utility boiler efficiency for each steam generating unit is
uncertain.
For all of these reasons, the EPA is finalizing that natural gas
co-firing at medium-term coal-fired steam generating units does not
result in any significant adverse consequences related to energy
requirements.
Additionally, the EPA considered longer term impacts on the energy
sector, and the EPA is finalizing these impacts are reasonable.
Designating natural gas co-firing as the BSER for medium-term coal-
fired steam generating units would not have significant adverse impacts
on the structure of the energy sector. Steam generating units that
currently are coal-fired would be able to remain primarily coal-fired.
The replacement of some coal with natural gas as fuel in these sources
would not have significant adverse effects on the price of natural gas
or the price of electricity.
iv. Extent of Reductions in CO2 Emissions
One of the primary benefits of natural gas co-firing is emission
reduction. CO2 emissions are reduced by approximately 4
percent for every additional 10 percent of co-firing. When moving from
100 percent coal to 60 percent coal and 40 percent natural gas,
CO2 stack emissions are reduced by approximately 16 percent.
Non-CO2 emissions are reduced as well, as noted earlier in
this preamble.
v. Technology Advancement
Natural gas co-firing is already well-established and widely used
by coal-fired steam boiler generating units. As a result, this final
rule is not likely to lead to technological advances or cost reductions
in the components of natural gas co-firing, including modifications to
boilers and pipeline construction. However, greater use of natural gas
co-firing may lead to improvements in the efficiency of conducting
natural gas co-firing and operating the associated equipment.
c. Options Not Determined To Be the BSER for Medium-Term Coal-Fired
Steam Generating Units
i. CCS
As discussed earlier in this preamble, the compliance date for CCS
is January 1, 2032. Accordingly, sources in the medium-term
subcategory--which have elected to commit to permanently cease
operations prior to 2039--would have less than 7 years to amortize the
capital costs of CCS. As a result, for these sources, the overall costs
of CCS would exceed the metrics for cost reasonableness that the EPA is
using in
[[Page 39896]]
this rulemaking, which are detailed in section VII.C.1.a.ii(D). For
this reason, the EPA is not finalizing CCS as the BSER for the medium-
term subcategory.
ii. Heat Rate Improvements
Heat rate improvements were not considered to be BSER for medium-
term steam generating units because the achievable reductions are low
and may result in rebound effect whereby total emissions from the
source increase, as detailed in section VII.D.4.a.
d. Conclusion
The EPA is finalizing that natural gas co-firing at 40 percent of
heat input is the BSER for medium-term coal-fired steam generating
units because natural gas co-firing is adequately demonstrated, as
indicated by the facts that it has been operated at scale and is widely
applicable to sources. Additionally, the costs for natural gas co-
firing are reasonable. Moreover, natural gas co-firing can be expected
to reduce emissions of several other air pollutants in addition to
GHGs. Any adverse non-air quality health and environmental impacts and
energy requirements of natural gas co-firing are limited. In contrast,
CCS, although achieving greater emission reductions, would be of higher
cost, in general, for the subcategory of medium-term units, and HRI
would achieve few reductions and, in fact, may increase emissions.
3. Degree of Emission Limitation for Final Standards
Under CAA section 111(d), once the EPA determines the BSER, it must
determine the ``degree of emission limitation'' achievable by the
application of the BSER. States then determine standards of performance
and include them in the state plans, based on the specified degree of
emission limitation. Final presumptive standards of performance are
detailed in section X.C.1.b of this preamble. There is substantial
variation in emission rates among coal-fired steam generating units--
the range is, approximately, from 1,700 lb CO2/MWh-gross to
2,500 lb CO2/MWh-gross--which makes it challenging to
determine a single, uniform emission limit. Accordingly, the EPA is
finalizing the degrees of emission limitation by a percentage change in
emission rate, as follows.
a. Long-Term Coal-Fired Steam Generating Units
As discussed earlier in this preamble, the EPA is finalizing the
BSER for long-term coal-fired steam generating units as ``full-
capture'' CCS, defined as 90 percent capture of the CO2 in
the flue gas. The degree of emission limitation achievable by applying
this BSER can be determined on a rate basis. A capture rate of 90
percent results in reductions in the emission rate of 88.4 percent on a
lb CO2/MWh-gross basis, and this reduction in emission rate
can be observed over an extended period (e.g., an annual calendar-year
basis). Therefore, the EPA is finalizing that the degree of emission
limitation for long-term units is an 88.4 percent reduction in emission
rate on a lb CO2/MWh-gross basis over an extended period
(e.g., an annual calendar-year basis).
b. Medium-Term Coal-Fired Steam Generating Units
As discussed earlier in this preamble, the BSER for medium-term
coal-fired steam generating units is 40 percent natural gas co-firing.
The application of 40 percent natural gas co-firing results in
reductions in the emission rate of 16 percent. Therefore, the degree of
emission limitation for these units is a 16 percent reduction in
emission rate on a lb CO2/MWh-gross basis over an extended
period (e.g., an annual calendar-year basis).
D. Rationale for the BSER for Natural Gas-Fired And Oil-Fired Steam
Generating Units
This section of the preamble describes the rationale for the final
BSERs for existing natural gas- and oil-fired steam generating units
based on the criteria described in section V.C of this preamble.
1. Subcategorization of Natural Gas- and Oil-Fired Steam Generating
Units
The EPA is finalizing subcategories based on load level (i.e.,
annual capacity factor), specifically, units that are base load,
intermediate load, and low load. The EPA is finalizing routine methods
of operation and maintenance as BSER for intermediate and base load
units. Applying that BSER would not achieve emission reductions but
would prevent increases in emission rates. The EPA is finalizing
presumptive standards of performance that differ between intermediate
and base load units due to their differences in operation, as detailed
in section X.C.1.b.iii of this preamble. The EPA proposed a separate
subcategory for non-continental oil-fired steam generating units, which
operate differently from continental units; however, the EPA is not
finalizing emission guidelines for sources outside of the contiguous
U.S., as described in section VII.B. At proposal, the EPA solicited
comment on a BSER of ``uniform fuels'' for low load natural gas- and
oil-fired steam generating units, and the EPA is finalizing this
approach for those sources.
Natural gas- and oil-fired steam generating units combust natural
gas or distillate fuel oil or residual fuel oil in a boiler to produce
steam for a turbine that drives a generator to create electricity. In
non-continental areas, existing natural gas- and oil-fired steam
generating units may provide base load power, but in the continental
U.S., most existing units operate in a load-following manner. There are
approximately 200 natural gas-fired steam generating units and fewer
than 30 oil-fired steam generating units in operation in the
continental U.S. Fuel costs and inefficiency relative to other
technologies (e.g., combustion turbines) result in operation at lower
annual capacity factors for most units. Based on data reported to EIA
and the EPA \688\ for the contiguous U.S., for natural gas-fired steam
generating units in 2019, the average annual capacity factor was less
than 15 percent and 90 percent of units had annual capacity factors
less than 35 percent. For oil-fired steam generating units in 2019, no
units had annual capacity factors above 8 percent. Additionally, their
load-following method of operation results in frequent cycling and a
greater proportion of time spent at low hourly capacities, when
generation is less efficient. Furthermore, because startup times for
most boilers are usually long, natural gas steam generating units may
operate in standby mode between periods of peak demand. Operating in
standby mode requires combusting fuel to keep the boiler warm, and this
further reduces the efficiency of natural gas combustion.
---------------------------------------------------------------------------
\688\ Clean Air Markets Program Data at https://campd.epa.gov.
---------------------------------------------------------------------------
Unlike coal-fired steam generating units, the CO2
emission rates of oil- and natural gas-fired steam generating units
that have similar annual capacity factors do not vary considerably
between units. This is partly due to the more uniform qualities (e.g.,
carbon content) of the fuel used. However, the emission rates for units
that have different annual capacity factors do vary considerably, as
detailed in the final TSD, Natural Gas- and Oil-fired Steam Generating
Units. Low annual capacity factor units cycle frequently, have a
greater proportion of CO2 emissions that may be attributed
to startup, and have a greater proportion of generation at inefficient
hourly capacities. Intermediate annual capacity factor units operate
more often at higher hourly capacities, where CO2 emission
rates are lower. High annual capacity factor units operate still more
at base load conditions, where units are more
[[Page 39897]]
efficient and CO2 emission rates are lower.
Based on these performance differences between these load levels,
the EPA, in general, proposed subcategories based on dividing natural
gas- and oil-fired steam generating units into three groups each--low
load, intermediate load, and base load.
The EPA is finalizing subcategories for oil-fired and natural gas-
fired steam generating units, based on load levels. The EPA proposed
the following load levels: ``low'' load, defined by annual capacity
factors less than 8 percent; ``intermediate'' load, defined by annual
capacity factors greater than or equal to 8 percent and less than 45
percent; and ``base'' load, defined by annual capacity factors greater
than or equal to 45 percent.
The EPA is finalizing January 1, 2030, as the compliance date for
natural gas- and oil-fired steam generating units and this date is
consistent with the dates in the fuel type definitions.
The EPA received comments that were generally supportive of the
proposed subcategory definitions,\689\ and the EPA is finalizing the
subcategory definitions as proposed.
---------------------------------------------------------------------------
\689\ See, for example, Document ID No. EPA-HQ-OAR-2023-0072-
0583.
---------------------------------------------------------------------------
2. Options Considered for BSER
The EPA has considered various methods for controlling
CO2 emissions from natural gas- and oil-fired steam
generating units to determine whether they meet the criteria for BSER.
Co-firing natural gas cannot be the BSER for these units because
natural gas- and oil-fired steam generating units already fire large
proportions of natural gas. Most natural gas-fired steam generating
units fire more than 90 percent natural gas on a heat input basis, and
any oil-fired steam generating units that would potentially operate
above an annual capacity factor of around 15 percent typically combust
natural gas as a large proportion of their fuel as well. Nor is CCS a
candidate for BSER. The utilization of most gas-fired units, and likely
all oil-fired units, is relatively low, and as a result, the amount of
CO2 available to be captured is low. However, the capture
equipment would still need to be sized for the nameplate capacity of
the unit. Therefore, the capital and operating costs of CCS would be
high relative to the amount of CO2 available to be captured.
Additionally, again due to lower utilization, the amount of IRC section
45Q tax credits that owner/operators could claim would be low. Because
of the relatively high costs and the relatively low cumulative emission
reduction potential for these natural gas- and oil-fired steam
generating units, the EPA is not determining CCS as the BSER for them.
The EPA has reviewed other possible controls but is not finalizing
any of them as the BSER for natural gas- and oil-fired units either.
Co-firing hydrogen in a boiler is technically possible, but there is
limited availability of hydrogen now and in the near future and it
should be prioritized for more efficient units. Additionally, for
natural gas-fired steam generating units, setting a future standard
based on hydrogen would likely have limited GHG reduction benefits
given the low utilization of natural gas- and oil-fired steam
generating units. Lastly, HRI for these types of units would face many
of the same issues as for coal-fired steam generating units; in
particular, HRI could result in a rebound effect that would increase
emissions.
However, the EPA recognizes that natural gas- and oil-fired steam
generating units could possibly, over time, operate more, in response
to other changes in the power sector. Additionally, some coal-fired
steam generating units have converted to 100 percent natural gas-fired,
and it is possible that more may do so in the future. The EPA also
received several comments from industry stating plans to do so.
Moreover, in part because the fleet continues to age, the plants may
operate with degrading emission rates. In light of these possibilities,
identifying the BSER and degrees of emission limitation for these
sources would be useful to provide clarity and prevent backsliding in
GHG performance. Therefore, the EPA is finalizing BSER for intermediate
and base load natural gas- and oil-fired steam generating units to be
routine methods of operation and maintenance, such that the sources
could maintain the emission rates (on a lb/MWh-gross basis) currently
maintained by the majority of the fleet across discrete ranges of
annual capacity factor. The EPA is finalizing this BSER for
intermediate load and base load natural gas- and oil-fired steam
generating units, regardless of the operating horizon of the unit.
A BSER based on routine methods of operation and maintenance is
adequately demonstrated because units already operate with those
practices. There are no or negligible additional costs because there is
no additional technology that units are required to apply and there is
no change in operation or maintenance that units must perform.
Similarly, there are no adverse non-air quality health and
environmental impacts or adverse impacts on energy requirements. Nor do
they have adverse impacts on the energy sector from a nationwide or
long-term perspective. The EPA's modeling, which supports this final
rule, indicates that by 2040, a number of natural gas-fired steam
generating units will have remained in operation since 2030, although
at reduced annual capacity factors. There are no CO2
reductions that may be achieved at the unit level, but applying routine
methods of operation and maintenance as the BSER prevents increases in
emission rates. Routine methods of operation and maintenance do not
advance useful control technology, but this point is not significant
enough to offset their benefits.
At proposal, the EPA also took comment on a potential BSER of
uniform fuels for low load natural gas- and oil-fired steam generating
units. As noted earlier in this preamble, non-coal fossil fuels
combusted in utility boilers typically include natural gas, distillate
fuel oil (i.e., fuel oil No. 1 and No. 2), and residual fuel oil (i.e.,
fuel oil No. 5 and No. 6). The EPA previously established heat-input
based fuel composition as BSER in the 2015 NSPS (termed ``clean fuels''
in that rulemaking) for new non-base load natural gas- and multi-fuel-
fired stationary combustion turbines (80 FR 64615-17; October 23,
2015), and the EPA is similarly finalizing lower-emitting fuels as BSER
for new low load combustion turbines as described in section VIII.F of
this preamble. For low load natural gas- and oil-fired steam generating
units, the high variability in emission rates associated with the
variability of load at the lower-load levels limits the benefits of a
BSER based on routine maintenance and operation. That is because the
high variability in emission rates would make it challenging to
determine an emission rate (i.e., on a lb CO2/MWh-gross
basis) that could serve as the presumptive standard of performance that
would reflect application of a BSER of routine operation and
maintenance. On the other hand, for those units, a BSER of ``uniform
fuels'' and an associated presumptive standard of performance based on
a heat input basis, as described in section X.C.1.b.iii of this
preamble, is reasonable. Therefore, the EPA is finalizing a BSER of
uniform fuels for low load natural gas- and oil-fired steam generating
units, with presumptive standards depending on fuel type detailed in
section X.C.1.b.iii.
[[Page 39898]]
3. Degree of Emission Limitation
As discussed above, because the BSER for base load and intermediate
load natural gas- and oil-fired steam generating units is routine
operation and maintenance, which the units are, by definition, already
employing, the degree of emission limitation by application of this
BSER is no increase in emission rate on a lb CO2/MWh-gross
basis over an extended period of time (e.g., a year).
For low load natural gas- and oil-fired steam generating units, the
EPA is finalizing a BSER of uniform fuels, with a degree of emission
limitation on a heat input basis consistent with a fixed 130 lb
CO2/MMBtu for natural gas-fired steam generating units and
170 lb CO2/MMBtu for oil-fired steam generating units. The
degree of emission limitation for natural gas- and oil-fired steam
generating units is higher than the corresponding values under 40 CFR
part 60, subpart TTTT, because steam generating units may fire fuels
with slightly higher carbon contents.
4. Other Emission Reduction Measures Not Considered BSER
a. Heat Rate Improvements
Heat rate is a measure of efficiency that is commonly used in the
power sector. The heat rate is the amount of energy input, measured in
Btu, required to generate 1 kilowatt-hour (kWh) of electricity. The
lower an EGU's heat rate, the more efficiently it operates. As a
result, an EGU with a lower heat rate will consume less fuel and emit
lower amounts of CO2 and other air pollutants per kWh
generated as compared to a less efficient unit. HRI measures include a
variety of technology upgrades and operating practices that may achieve
CO2 emission rate reductions of 0.1 to 5 percent for
individual EGUs. The EPA considered HRI to be part of the BSER in the
CPP and to be the BSER in the ACE Rule. However, the reductions that
may be achieved by HRI are small relative to the reductions from
natural gas co-firing and CCS. Also, some facilities that apply HRI
would, as a result of their increased efficiency, increase their
utilization and therefore increase their CO2 emissions (as
well as emissions of other air pollutants), a phenomenon that the EPA
has termed the ``rebound effect.'' Therefore, the EPA is not finalizing
HRI as a part of BSER.
i. CO2 Reductions From HRI in Prior Rulemakings
In the CPP, the EPA quantified emission reductions achievable
through heat rate improvements on a regional basis by an analysis of
historical emission rate data, taking into consideration operating load
and ambient temperature. The Agency concluded that EGUs can achieve on
average a 4.3 percent improvement in the Eastern Interconnection, a 2.1
percent improvement in the Western Interconnection, and a 2.3 percent
improvement in the Texas Interconnection. See 80 FR 64789 (October 23,
2015). The Agency then applied all three of the building blocks to 2012
baseline data and quantified, in the form of CO2 emission
rates, the reductions achievable in Each interconnection in 2030, and
then selected the least stringent as a national performance rate. Id.
at 64811-19. The EPA noted that building block 1 measures could not by
themselves constitute the BSER because the quantity of emission
reductions achieved would be too small and because of the potential for
an increase in emissions due to increased utilization (i.e., the
``rebound effect'').
ii. Updated CO2 Reductions From HRI
The HRI measures include improvements to the boiler island (e.g.,
neural network system, intelligent sootblower system), improvements to
the steam turbine (e.g., turbine overhaul and upgrade), and other
equipment upgrades (e.g., variable frequency drives). Some regular
practices that may recover degradation in heat rate to recent levels--
but that do not result in upgrades in heat rate over recent design
levels and are therefore not HRI measures--include practices such as
in-kind replacements and regular surface cleaning (e.g., descaling,
fouling removal). Specific details of the HRI measures are described in
the 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. Most HRI
upgrade measures achieve reductions in heat rate of less than 1
percent. In general, the 2023 Sargent and Lundy HRI report, which
updates the 2009 Sargent and Lundy HRI report, shows that HRI achieve
less reductions than indicated in the 2009 report, and shows that
several HRI either have limited applicability or have already been
applied at many units. Steam path overhaul and upgrade may achieve
reductions up to 5.15 percent, with the average being around 1.5
percent. Different combinations of HRI measures do not necessarily
result in cumulative reductions in emission rate (e.g., intelligent
sootblowing systems combined with neural network systems). Some of the
HRI measures (e.g., variable frequency drives) only impact heat rate on
a net generation basis by reducing the parasitic load on the unit and
would thereby not be observable for emission rates measured on a gross
basis. Assuming many of the HRI measures could be applied to the same
unit, adding together the upper range of some of the HRI percentages
could yield an emission rate reduction of around 5 percent. However,
the reductions that the fleet could achieve on average are likely much
smaller. As noted, the 2023 Sargent and Lundy HRI report notes that, in
many cases, units have already applied HRI upgrades or that those
upgrades would not be applicable to all units. The unit level
reductions in emission rate from HRI are small relative to CCS or
natural gas co-firing. In the CPP and ACE Rule, the EPA viewed CCS and
natural gas co-firing as too costly to qualify as the BSER; those costs
have fallen since those rules and, as a result, CCS and natural gas co-
firing do qualify as the BSER for the long-term and medium-term
subcategories, respectively.
iii. Potential for Rebound in CO2 Emissions
Reductions achieved on a rate basis from HRI may not result in
overall emission reductions and could instead cause a ``rebound
effect'' from increased utilization. A rebound effect would occur
where, because of an improvement in its heat rate, a steam generating
unit experiences a reduction in variable operating costs that makes the
unit more competitive relative to other EGUs and consequently raises
the unit's output. The increase in the unit's CO2 emissions
associated with the increase in output would offset the reduction in
the unit's CO2 emissions caused by the decrease in its heat
rate and rate of CO2 emissions per unit of output. The
extent of the offset would depend on the extent to which the unit's
generation increased. The CPP did not consider HRI to be BSER on its
own, in part because of the potential for a rebound effect. Analysis
for the ACE Rule, where HRI was the entire BSER, observed a rebound
effect for certain sources in some cases.\690\ In this action, where
different subcategories of units are to be subject to different BSER
measures, steam generating units in a hypothetical subcategory with HRI
as BSER could experience a rebound effect. Because of this potential
for perverse GHG emission outcomes resulting from deployment of HRI at
certain steam generating units, coupled with the
[[Page 39899]]
relatively minor overall GHG emission reductions that would be expected
from this measure, the EPA is not finalizing HRI as the BSER for any
subcategory of existing coal-fired steam generating units.
---------------------------------------------------------------------------
\690\ 84 FR 32520 (July 8, 2019).
---------------------------------------------------------------------------
E. Additional Comments Received on the Emission Guidelines for Existing
Steam Generating Units and Responses
1. Consistency With West Virginia v. EPA and the Major Questions
Doctrine
Comment: Some commenters argued that the EPA's determination that
CCS is the BSER for existing coal-fired power plants is invalid under
West Virginia v. EPA, 597 U.S. 697 (2022), and the major questions
doctrine (MQD). Commenters state that for various reasons, coal-fired
power plants will not install CCS and instead will be forced to retire
their units. They point to the EPA's IPM modeling which, they say,
shows that many coal-fired power plants retire rather than install CCS.
They add that, in this way, the rule effectively results in the EPA's
requiring generation-shifting from coal-fired generation to renewable
and other generation, and thus is like the Clean Power Plan (CPP). For
those reasons, they state that the rule raises a major question, and
further that CAA section 111(d) does not contain a clear authorization
for this type of rule.
Response: The EPA discussed West Virginia and its articulation of
the MQD in section V.B.6 of this preamble.
The EPA disagrees with these comments. This rule is fully
consistent with the Supreme Court's interpretation of the EPA's
authority in West Virginia. The EPA's determination that CCS--a
traditional, add-on emissions control--is the BSER is consistent with
the plain text of section 111. As explained in detail in section
VII.C.1.a, for long-term coal-fired steam generating units, CCS meets
all of the BSER factors: it is adequately demonstrated, of reasonable
cost, and achieves substantial emissions reductions. That some coal-
fired power plants will choose not to install emission controls and
will instead retire does not raise major questions concerns.
In West Virginia, the U.S. Supreme Court held that ``generation-
shifting'' as the BSER for coal- and gas-fired units ``effected a
fundamental revision of the statute, changing it from one sort of
scheme of regulation into an entirely different kind.'' 597 U.S. at 728
(internal quotation marks, brackets, and citation omitted). The Court
explained that prior CAA section 111 rules were premised on ``more
traditional air pollution control measures'' that ``focus on improving
the performance of individual sources.'' Id. at 727 (citing ``fuel-
switching'' and ``add-on controls''). The Court said that generation-
shifting as the BSER was ``unprecedented'' because it was designed to
``improve the overall power system by lowering the carbon intensity of
power generation . . . by forcing a shift throughout the power grid
from one type of energy source to another.'' Id. at 727-28 (internal
quotation marks, emphasis, and citation omitted). The Court cited
statements by the then-Administrator describing the CPP as ``not about
pollution control so much as it was an investment opportunity for
States, especially investments in renewables and clean energy.'' Id. at
728. The Court further concluded that the EPA's view of its authority
was virtually unbounded because the ``EPA decides, for instance, how
much of a switch from coal to natural gas is practically feasible by
2020, 2025, and 2030 before the grid collapses, and how high energy
prices can go as a result before they become unreasonably exorbitant.''
Id. at 729.
Here, the EPA's determination that CCS is the BSER does not affect
a fundamental revision of the statute, nor is it unbounded. CCS is not
directed at improvement of the overall power system. Rather, CCS is a
traditional ``add-on [pollution] control[ ]'' akin to measures that the
EPA identified as BSER in prior CAA section 111 rules. See id. at 727.
It ``focus[es] on improving the performance of individual sources''--it
reduces CO2 pollution from each individual source--because
each affected source is able to apply it to its own facility to reduce
its own emissions. Id. at 727. Further, the EPA determined that CCS
qualifies as the BSER by applying the criteria specified in CAA section
111(a)(1)--including adequate demonstration, costs of control, and
emissions reductions. See section VII.C.1.a of this preamble. Thus, CCS
as the BSER does not ``chang[e]'' the statute ``from one sort of scheme
of regulation into an entirely different kind.'' Id. at 728 (internal
quotation marks, brackets, and citation omitted).
Commenters contend that notwithstanding these distinctions, the
choice of CCS as the BSER has the effect of shifting generation because
modeling projections for the rule show that coal-fired generation will
become less competitive, and gas-fired and renewable-generated
electricity will be more competitive and dispatched more frequently.
That some coal-fired sources may retire rather than reduce their
CO2 pollution does not mean that the rule ``represents a
transformative expansion [of EPA's] regulatory authority''. Id. at 724.
To be sure, this rule's determination that CCS is the BSER imposes
compliance costs on coal-fired power plants. That sources will incur
costs to control their emissions of dangerous pollution is an
unremarkable consequence of regulation, which, as the Supreme Court
recognized, ``may end up causing an incidental loss of coal's market
share.'' Id. at 731 n.4.\691\ Indeed, ensuring that sources internalize
the full costs of mitigating their impacts on human health and the
environment is a central purpose of traditional environmental
regulation.
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\691\ As discussed in section VII.C.1.a.ii.(D), the costs of CCS
are reasonable based on the EPA's $/MWh and $/ton metrics. As
discussed in RTC section 2.16, the total annual costs of this rule
are a small fraction of the revenues and capital costs of the
electric power industry.
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In particular, for the power sector, grid operators constantly
shift generation as they dispatch electricity from sources based upon
their costs. The EPA's IPM modeling, which is based on the costs of the
various types of electricity generation, projects these impacts. Viewed
as a whole, these projected impacts show that, collectively, coal-fired
power plants will likely produce less electricity, and other sources
(like gas-fired units and renewable sources) will likely produce more
electricity, but this pattern does not constitute a transformative
expansion of statutory authority (EPA's Power Sector Platform 2023
using IPM; final TSD, Power Sector Trends.)
These projected impacts are best understood by comparing the IPM
model's ``base case,'' i.e., the projected electricity generation
without any rule in place, to the model's ``policy case,'' i.e., the
projected electricity generation expected to result from this rule. The
base case projects that many coal-fired units will retire over the next
20 years (EPA's Power Sector Platform 2023 using IPM; final TSD, Power
Sector Trends). Those projected retirements track trends over the past
two decades where coal-fired units have retired in high numbers because
gas-fired units and renewable sources have become increasingly able to
generate lower-cost electricity. As more gas-fired and renewable
generation sources deploy in the future, and as coal-fired units
continue to age--which results in decreased efficiency and increased
costs--the coal-fired units will become increasingly marginal and
continue to retire (EPA's Power Sector Platform 2023 using IPM; final
TSD, Power Sector Trends.) That is true in the absence of this rule.
The EPA's modeling results also project that even if the EPA had
[[Page 39900]]
determined BSER for long-term sources to be 40 percent co-firing, which
requires significantly less capital investment, and not 90 percent
capture CCS, a comparable number of sources would retire instead of
installing controls. These results confirm that the primary cause for
the projected retirements is the marginal profitability of the sources.
Importantly, the base-case projections also show that some coal-
fired units install CCS and run at high capacity factors, in fact,
higher than they would have had they not installed CCS. This is because
the IRC section 45Q tax credit significantly reduces the variable cost
of operation for qualifying sources. This incentivizes sources to
increase generation to maximize the tons of CO2 the CCS
equipment captures, and thereby increase the amount of the tax credit
they receive. In the ``policy case,'' beginning when the CCS
requirement applies in the 2035 model year,\692\ some additional coal-
fired units will likely install CCS, and also run at high capacity
factors, again, significantly higher than they would have without CCS.
Other units may retire rather than install emission controls (EPA's
Power Sector Platform 2023 using IPM; final TSD, Power Sector Trends).
On balance, the coal-fired units that install CCS collectively generate
nearly the same amount of electricity in the 2040 model year as do the
group of coal-fired units in the base case.
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\692\ Under the rule, sources are required to meet their CCS-
based standard of performance by January 1, 2032. IPM groups
calendar years into 5-year periods, e.g., the 2035 model year and
the 2040 model year. January 1, 2032, falls into the 2035 model
year.
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The policy case also shows that in the 2045 model year, by which
time the 12-year period for sources to claim the IRC section 45Q tax
credit will have expired, most sources that install CCS retire due to
the costs of meeting the CCS-based standards without the benefit of the
tax credit. However, in fact, these projected outcomes are far from
certain as the modeling results generally do not account for numerous
potential changes that may occur over the next 20 or more years, any of
which may enable these units to continue to operate economically for a
longer period. Examples of potential changes include reductions in the
operational costs of CCS through technological improvements, or the
development of additional potential revenue streams for captured
CO2 as the market for beneficial uses of CO2
continues to develop, among other possible changed economic
circumstances (including the possible extension of the tax credits). In
light of these potential significant developments, the EPA is
committing to review and, if appropriate, revise the requirements of
this rule by January 1, 2041, as described in section VII.F.
In any event, the modeling projections showing that many sources
retire instead of installing controls are in line with the trends for
these units in the absence of the rule--as the coal-fired fleet ages
and lower-cost alternatives become increasingly available, more
operators will retire coal-fired units with or without this rule. In
2045, the average age of coal-fired units that have not yet announced
retirement dates or coal-to-gas conversion by 2039 will be 61 years
old. And, on average, between 2000 and 2022, even in the absence of
this rule, coal-fired units generally retired at 53 years old. Thus,
taken as a whole, this rule does not dramatically reduce the expected
operating horizon of most coal-fired units. Indeed, for units that
install CCS, the generous IRC section 45Q tax credit increases the
competitiveness of these units, and it allows them to generate more
electricity with greater profit than the sources would otherwise
generate if they did not install CCS.
The projected effects of the rule do not show the BSER--here, CCS--
is akin to generation shifting, or otherwise represents an expansion of
EPA authority with vast political or economic significance. As
described above at VII.C.1.a.ii, CCS is an affordable emissions control
technology. It is also very effective, reducing CO2
emissions from coal-fired units by 90 percent, as described in section
VII.C.1.a.i. Indeed, as noted, the IRA tax credits make CCS so
affordable that coal-fired units that install CCS run at higher
capacity factors than they would otherwise.
Considered as a whole, and in context with historical retirement
trends, the projected impacts of this rule on coal-fired generating
units do not raise MQD concerns. The projected impacts are merely
incidental to the CCS control itself--the unremarkable consequence of
marginally increasing the cost of doing business in a competitive
market. Nor is the rule ``transformative.'' The rule does not
``announce what the market share of coal, natural gas, wind, and solar
must be, and then requiring plants to reduce operations or subsidize
their competitors to get there.'' 597 U.S. at 731 n.4. As noted above,
coal-fired units that install CCS are projected to generate substantial
amounts of electricity. The retirements that are projected to occur are
broadly consistent with market trends over the past two decades, which
show that coal-fired electricity production is generally less economic
and less competitive than other forms of electricity production. That
is, the retirements that the model predicts under this rule, and the
structure of the industry that results, diverge little from the prior
rate of retirements of coal-fired units over the past two decades. They
also diverge little from the rate of retirements from sources that have
already announced that they will retire, or from the additional
retirements that IPM projects will occur in the base case (EPA's Power
Sector Platform 2023 using IPM; final TSD, Power Sector Trends).
As discussed above, because much of the coal-fired fleet is
operating on the edge of viability, many sources would retire instead
of installing any meaningful CO2 emissions control--whether
CCS, natural gas co-firing, or otherwise. Under commenters' view that
such retirements create a major question, any form of meaningful
regulation of these sources would create a major question and effect a
fundamental revision of the statute. That cannot possibly be so.
Section 111(d)(1) plainly mandates regulation of these units, which are
the biggest stationary source of dangerous CO2 emissions.
The legislative history for the CAA further makes clear that
Congress intended the EPA to promulgate regulations even where
emissions controls had economic costs. At the time of the 1970 CAA
Amendments, Congress recognized that the threats of air pollution to
public health and welfare had grown urgent and severe. Sen. Edmund
Muskie (D-ME), manager of the bill and chair of the Public Works
Subcommittee on Air and Water Pollution, which drafted the bill,
regularly referred to the air pollution problem as a ``crisis.'' As
Sen. Muskie recognized, ``Air pollution control will be cheap only in
relation to the costs of lack of control.'' \693\ The Senate Committee
Report for the 1970 CAA Amendments specifically discussed the precursor
provision to section 111(d) and noted, ``there should be no gaps in
control activities pertaining to stationary source emissions that pose
any significant danger to public health or welfare.'' \694\
Accordingly, some of the
[[Page 39901]]
EPA's prior CAA section 111 rulemakings have imposed stringent
requirements, at significant cost, in order to achieve significant
emission reductions.\695\
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\693\ Sen. Muskie, Sept. 21, 1970, LH 226.
\694\ S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA
Legis. Hist. at 420 (discussing section 114 of the Senate Committee
bill, which was the basis for CAA section 111(d)). Note that in the
1977 CAA Amendments, the House Committee Report made a similar
statement. H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA
Legis. Hist. at 2509 (discussing a provision in the House Committee
bill that became CAA section 122, requiring EPA to study and then
take action to regulate radioactive air pollutants and three other
air pollutants).
\695\ See Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir.
1981) (upholding NSPS imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . .
. is substantial. EPA estimates that utilities will have to spend
tens of billions of dollars by 1995 on pollution control under the
new NSPS.'').
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Congress's enactment of the IRA and IIJA further shows its view
that reducing air pollution--specifically, in those laws, GHG emissions
to address climate change--is a high priority. As discussed in section
IV.E.1, that law provided funds for DOE grant and loan programs to
support CCS, and extended and increased the IRC section 45Q tax credit
for carbon capture. It also adopted the Low Emission Electricity
Program (LEEP), which allocates funds to the EPA for the express
purpose of using CAA regulatory authority to reduce GHG emissions from
domestic electricity generation through use of its existing CAA
authorities. CAA section 135, added by IRA section 60107. The EPA is
promulgating the present rulemaking with those funds. The congressional
sponsor of the LEEP made clear that it authorized the type of
rulemaking that the EPA is promulgating today: he stated that the EPA
may promulgate rulemaking under CAA section 111, based on CCS, to
address CO2 emissions from fossil fuel-fired power plants,
which may be ``impactful'' by having the ``incidental effect'' of
leading some ``companies . . . to choose to retire such plants. . . .''
\696\
---------------------------------------------------------------------------
\696\ 168 Cong. Rec. E868 (August 23, 2022) (statement of Rep.
Frank Pallone, Jr.); id. E879 (August 26, 2022) (statement of Rep.
Frank Pallone, Jr.).
---------------------------------------------------------------------------
For these reasons, the rule here is consistent with the Supreme
Court's decision in West Virginia. The selection of CCS as the BSER for
existing coal-fired units is a traditional, add-on control intended to
reduce the emissions performance of individual sources. That some
sources may retire instead of controlling their emissions does not
otherwise show that the rule runs afoul of the MQD. The modeling
projections for this rule show that the anticipated retirements are
largely consistent with historical trends, and due to many coal-fired
units' advanced age and lack of competitiveness with lower cost methods
of electricity generation.
2. Redefining the Source
Comment: Some commenters contended that the proposed 40 percent
natural gas co-firing performance standard violates legal precedent
that bars the EPA from setting technology-based performance standards
that would have the effect of ``redefining the source.'' They stated
that this prohibition against the redefinition of the source bars the
EPA from adopting the proposed performance standard for medium-term
coal-fired EGUs, which requires such units to operate in a manner for
which the unit was never designed to do, namely operate as a hybrid
coal/natural gas co-firing generating unit and combusting 40 percent of
its fuel input as natural gas (instead of coal) on an annual basis.
Commenters argued that co-firing would constitute forcing one type
of source to become an entirely different kind of source, and that the
Supreme Court precluded such a requirement in West Virginia v. EPA when
it stated in footnote 3 of that case that the EPA has ``never ordered
anything remotely like'' a rule that would ``simply require coal plants
to become natural gas plants'' and the Court ``doubt[ed that EPA]
could.'' \697\
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\697\ West Virginia v. EPA, 597 U.S, 697, 728 n.3 (2022).
---------------------------------------------------------------------------
Response: The EPA disagrees with these comments.
Standards based on co-firing, as contemplated in this rule, are
based on a ``traditional pollution control measure,'' in particular,
``fuel switching,'' as the Supreme Court recognized in West
Virginia.\698\ Rules based on switching to a cleaner fuel are
authorized under the CAA, an authorization directly acknowledged by
Congress. Specifically, as part of the 1977 CAA Amendments, Congress
required that the EPA base its standards regulating certain new
sources, including power plants, on ``technological'' controls, rather
than simply the ``best system.'' \699\ Congress understood this to mean
that new sources would be required to implement add-on controls, rather
than merely relying on fuel switching, and noted that one of the
purposes of this amendment was to allow new sources to burn high sulfur
coal while still decreasing emissions, and thus to increase the
availability of low sulfur coal for existing sources, which were not
subject to the ``technological'' control requirement.\700\ In 1990,
however, Congress removed the ``technological'' language, allowing the
EPA to set fuel-switching based standards for both new and existing
power plants.\701\
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\698\ See 597 U.S. at 727.
\699\ In 1977, Congress clarified that for purposes of CAA
section 111(a)(1)(A), concerning standards of performance for new
and modified ``fossil fuel-fired stationary sources'' a standard or
performance ``shall reflect the degree of emission limitation and
the percentage reduction achievable through application of the best
technological system of continuous emission reduction which (taking
into consideration the cost of achieving such emission reduction,
any nonair quality health and environmental impact and energy
requirements) the Administrator determines has been adequately
demonstrated.'' Clean Air Act 1977 Revisions (emphasis added).
\700\ See H. Rep. No. 94-1175, 94th Cong., 2d Sess. (May 15,
1976) Part A, at 159 (listing the various purposes of the amendment
to Section 111 adding the term `technological': ``Fourth, by using
best control technology on large new fuel-burning stationary
sources, these sources could burn higher sulfur fuel than if no
technological means of reducing emissions were used. This means an
expansion of the energy resources that could be burned in compliance
with environmental requirements. Fifth, since large new fuel-burning
sources would not rely on naturally low sulfur coal or oil to
achieve compliance with new source performance standards, the low
sulfur coal or oil that would have been burned in these major new
sources could instead be used in older and smaller sources.'')
\701\ In 1990, Congress removed this reference to a
``technological system'', and the current text reads simply: ``The
term ``standard of performance'' means a standard for emissions of
air pollutants which reflects the degree of emission limitation
achievable through the application of the best system of emission
reduction which (taking into account the cost of achieving such
reduction and any nonair quality health and environmental impact and
energy requirements) the Administrator determines has been
adequately demonstrated.'' 42 U.S.C. 7411(a)(1).
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The EPA has a tradition of promulgating rules based on fuel
switching. For example, the 2006 NSPS for stationary compression
ignition internal combustion engines required the use of ultra-low
sulfur diesel.\702\ Similarly, in the 2015 NSPS for EGUs,\703\ the EPA
determined that the BSER for peaking plants was to burn primarily
natural gas, with distillate oil used only as a backup fuel.\704\ Nor
is this approach unique to CAA section 111; in the 2016 rule setting
section 112 standards for hazardous air pollutant emissions from area
sources, for example, the EPA finalized an alternative particulate
matter (PM) standard that specified that certain oil-fired boilers
would meet the applicable
[[Page 39902]]
standard if they combusted only ultra-low-sulfur liquid fuel.\705\
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\702\ Standards of Performance for Stationary Compression
Ignition Internal Combustion Engines, 71 FR 39154 (July 11, 2006).
In the preamble to the final rule, the EPA noted that for engines
which had not previously used this new ultra-low sulfur fuel,
additives would likely need to be added to the fuel to maintain
appropriate lubricity. See id. at 39158.
\703\ Standards of Performance for Greenhouse Gas Emissions From
New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units, 80 FR 64510, (October 23, 2015).
\704\ See id. at 64621.
\705\ See National Emission Standards for Hazardous Air
Pollutants for Area Sources: Industrial, Commercial, and
Institutional Boilers, 81 FR 63112-01 (September 14, 2016).
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Moreover, the West Virginia Court's statements in footnote 3 are
irrelevant to the question of the validity of a 40 percent co-firing
standard. There, the Court was referring to a complete transformation
of the coal-fired unit to a 100 percent gas fired unit--a change that
would require entirely repowering the unit. By contrast, increasing co-
firing at existing coal-fired units to 40 percent would require only
minor changes to the units' boilers. In fact, many coal-fired units are
already capable of co-firing some amount of gas without any changes at
all, and several have fired at 40 percent and above in recent years. Of
the 565 coal-fired EGUs operating at the end of 2021, 249 of them
reported consuming natural gas as a fuel or startup source, 162
reported more than one month of consumption of natural gas at their
boiler, and 29 co-fired at over 40 percent on an annual heat input
basis in at least one year while also operating with annual capacity
factors greater than 10 percent. For more on this, see section IV.C.2
of this preamble; see also the final TSD, GHG Mitigation Measures for
Steam Generating Units.
F. Commitment To Review and, If Appropriate, Revise Emission Guidelines
for Coal-Fired Units
The EPA recognizes that the IRC 45Q tax credit is a key component
to the cost of CCS, as discussed in section VII.C.1.a.ii(C) of this
preamble. The EPA further recognizes that for any affected source, the
tax credit is currently available for a 12-year period and not
subsequently. The tax credit is generally sufficient to defray the
capital costs of CCS and much, if not all, of the operating costs
during that 12-year period. Following the 12-year period, affected
sources that continue to operate the CCS equipment would have higher
costs of generation, due to the CCS operating costs, including
parasitic load. Under certain circumstances, these higher costs could
push the affected sources lower on the dispatch curve, and thereby lead
to reductions in the amount of their generation, i.e., if affected
sources are not able to replace the revenue from the tax credit with
revenue from other sources, or if the price of electricity does not
reflect any additional costs needed to minimize GHG emissions.
However, the costs of CCS and the overall economic viability of
operating CO2 capture at power plants are improving and can
be expected to continue to improve in years to come. CO2
that is captured from fossil-fuel fired sources is currently
beneficially used, including, for example, for enhanced oil recovery
and in the food and beverage industry. There is much research into
developing beneficial uses for many other industries, including
construction, chemical manufacturing, graphite manufacturing. The
demand for CO2 is expected to grow considerably over the
next several decades. As a result, in the decades to come, affected
sources may well be able to replace at least some of the revenues from
the tax credit with revenues from the sale of CO2. We
discuss these potential developments in chapter 2 of the Response to
Comments document, available in the rulemaking docket.
In addition, numerous states have imposed requirements to
decarbonize generation within their borders. Many utilities have also
announced plans to decarbonize their fleet, including building small
modular (advanced nuclear) reactors. Given the relatively high capital
and fixed costs of small modular reactors, plans for their construction
represent an expectation of higher future energy prices. This suggests
that, in the decades to come, at least in certain areas of the country,
affected sources may be able to maintain a place in the dispatch curve
that allows them to continue to generate while they continue to operate
CCS, even in the absence of additional revenues for CO2. We
discuss these potential developments in the final TSD, Power Sector
Trends, available in the rulemaking docket.
These developments, which may occur by the 2040s--the expiration of
the 12-year period for the IRC 45Q tax credit, the potential
development of the CO2 utilization market, and potential
market supports for low-GHG generation--may significantly affect the
costs to coal-fired steam EGUs of operating their CCS controls. As a
result, the EPA will closely monitor these developments. Our efforts
will include consulting with other agencies with expertise and
information, including DOE, which currently has a program, the Carbon
Conversion Program, in the Office of Carbon Management, that funds
research into CO2 utilization. We regularly consult with
stakeholders, including industry stakeholders, and will continue to do
so.
In light of these potential significant developments and their
impacts, potentially positive or negative, on the economics of
continued generation by affected sources that have installed CCS, the
EPA is committing to review and, if appropriate, revise this rule by
January 1, 2041. This commitment is included in the regulations that
the EPA is promulgating with this rule. The EPA will conduct this
review based on what we learn from monitoring these developments, as
noted above. Completing this review and any appropriate revisions by
that date will allow time for the states to revise, if necessary,
standards applicable to affected sources, and for the EPA to act on
those state revisions, by the early to mid-2040s. That is when the 12-
year period for the 45Q tax credit is expected to expire for affected
sources that comply with the CCS requirement by January 1, 2032, and
when other significant developments noted above may be well underway.
VIII. Requirements for New and Reconstructed Stationary Combustion
Turbine EGUs and Rationale for Requirements
A. Overview
This section discusses the requirements for stationary combustion
turbine EGUs that commence construction or reconstruction after May 23,
2023. The requirements are codified in 40 CFR part 60, subpart TTTTa.
The EPA explains in section VIII.B of this document the two basic
turbine technologies that are used in the power sector and are covered
by 40 CFR part 60, subpart TTTTa. Those are simple cycle combustion
turbines and combined cycle combustion turbines. The EPA also explains
how these technologies are used in the three subcategories: low load
turbines, intermediate load turbines, and base load turbines. Section
VIII.C provides an overview of how stationary combustion turbines have
been previously regulated. Section VIII.D discusses the EPA's decision
to revisit the standards for new and reconstructed turbines as part of
the statutorily required 8-year review of the NSPS. Section VIII.E
discusses changes that the EPA is finalizing in both applicability and
subcategories in the new 40 CFR part 60, subpart TTTTa, as compared to
those codified previously in 40 CFR part 60, subpart TTTT. Most
notably, for new and reconstructed natural gas-fired combustion
turbines, the EPA is finalizing BSER determinations and standards of
performance for the three subcategories mentioned above--low load,
intermediate load, and base load.
Sections VIII.F and VIII.G of this document discuss the EPA's
[[Page 39903]]
determination of the BSER for each of the three subcategories of
combustion turbines and the applicable standards of performance,
respectively. For low load combustion turbines, the EPA is finalizing a
determination that the use of lower-emitting fuels is the appropriate
BSER. For intermediate load combustion turbines, the EPA is finalizing
a determination that highly efficient simple cycle generation is the
appropriate BSER. For base load combustion turbines, the EPA is
finalizing a determination that the BSER includes two components that
correspond initially to a two-phase standard of performance. The first
component of the BSER, with an immediate compliance date (phase 1), is
highly efficient generation based on the performance of a highly
efficient combined cycle turbine and the second component of the BSER,
with a compliance date of January 1, 2032 (phase 2), is based on the
use of CCS with a 90 percent capture rate, along with continued use of
highly efficient generation. For base load turbines, the standards of
performance corresponding to both components of the BSER would apply to
all new and reconstructed sources that commence construction or
reconstruction after May 23, 2023. The EPA occasionally refers to these
standards of performance as the phase 1 or phase 2 standards.
B. Combustion Turbine Technology
For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary
combustion turbines include both simple cycle and combined cycle EGUs.
Simple cycle turbines operate in the Brayton thermodynamic cycle and
include three primary components: a multi-stage compressor, a
combustion chamber (i.e., combustor), and a turbine. The compressor is
used to supply large volumes of high-pressure air to the combustion
chamber. The combustion chamber converts fuel to heat and expands the
now heated, compressed air through the turbine to create shaft work.
The shaft work drives an electric generator to produce electricity.
Combustion turbines that recover the energy in the high-temperature
exhaust--instead of venting it directly to the atmosphere--are combined
cycle EGUs and can obtain additional useful electric output. A combined
cycle EGU includes an HRSG operating in the Rankine thermodynamic
cycle. The HRSG receives the high-temperature exhaust and converts the
heat to mechanical energy by producing steam that is then fed into a
steam turbine that, in turn, drives an electric generator. As the
thermal efficiency of a stationary combustion turbine EGU is increased,
less fuel is burned to produce the same amount of electricity, with a
corresponding decrease in fuel costs and lower emissions of
CO2 and, generally, of other air pollutants. The greater the
output of electric energy for a given amount of fuel energy input, the
higher the efficiency of the electric generation process.
Combustion turbines serve various roles in the power sector. Some
combustion turbines operate at low annual capacity factors and are
available to provide temporary power during periods of high load
demand. These turbines are often referred to as ``peaking units.'' Some
combustion turbines operate at intermediate annual capacity factors and
are often referred to as cycling or load-following units. Other
combustion turbines operate at high annual capacity factors to serve
base load demand and are often referred to as base load units. In this
rulemaking, the EPA refers to these types of combustion turbines as low
load, intermediate load, and base load, respectively.
Low load combustion turbines provide reserve capacity, support grid
reliability, and generally provide power during periods of peak
electric demand. As such, the units may operate at or near their full
capacity, but only for short periods, as needed. Because these units
only operate occasionally, capital expenses are a major factor in the
overall cost of electricity, and often, the lowest capital cost (and
generally less efficient) simple cycle EGUs are intended for use only
during periods of peak electric demand. Due to their low efficiency,
these units require more fuel per MWh of electricity produced and their
operating costs tend to be higher. Because of the higher operating
costs, they are generally some of the last units in the dispatch order.
Important characteristics for low load combustion turbines include
their low capital costs, their ability to start quickly and to rapidly
ramp up to full load, and their ability to operate at partial loads
while maintaining acceptable emission rates and efficiencies. The
ability to start quickly and rapidly attain full load is important to
maximize revenue during periods of peak electric prices and to meet
sudden shifts in demand. In contrast, under steady-state conditions,
more efficient combined cycle EGUs are dispatched ahead of low load
turbines and often operate at higher annual capacity factors.
Highly efficient simple cycle turbines and flexible fast-start
combined cycle turbines both offer different advantages and
disadvantages when operating at intermediate loads. One of the roles of
these intermediate or load following EGUs is to provide dispatchable
backup power to support variable renewable generating sources (e.g.,
solar and wind). A developer's decision as to whether to build a simple
cycle turbine or a combined cycle turbine to serve intermediate load
demand is based on several factors related to the intended operation of
the unit. These factors would include how frequently the unit is
expected to cycle between starts and stops, the predominant load level
at which the unit is expected to operate, and whether this level of
operation is expected to remain consistent or is expected to vary over
the lifetime of the unit. In areas of the U.S. with vertically
integrated electricity markets, utilities determine dispatch orders
based generally on economic merit of individual units. Meanwhile, in
areas of the U.S. inside organized wholesale electricity markets,
owner/operators of individual combustion turbines control whether and
how units will operate over time, but they do not necessarily control
the precise timing of dispatch for units in any given day or hour. Such
short-term dispatch decisions are often made by regional grid operators
that determine, on a moment-to-moment basis, which available individual
units should operate to balance supply and demand and other
requirements in an optimal manner, based on operating costs, price
bids, and/or operational characteristics. However, operating permits
for simple cycle turbines often contain restrictions on the annual
hours of operation that owners/operators incorporate into longer-term
operating plans and short-term dispatch decisions.
Intermediate load combustion turbines vary their generation,
especially during transition periods between low and high electric
demand. Both high-efficiency simple cycle turbines and flexible fast-
start combined cycle turbines can fill this cycling role. While the
ability to start quickly and quickly ramp up is important, efficiency
is also an important characteristic. These combustion turbines
generally have higher capital costs than low load combustion turbines
but are generally less expensive to operate.
Base load combustion turbines are designed to operate for extended
periods at high loads with infrequent starts and stops. Quick-start
capability and low capital costs are less important than low operating
costs. High-efficiency combined cycle turbines typically fill the role
of base load combustion turbines.
The increase in generation from variable renewable energy sources
during the past decade has impacted the
[[Page 39904]]
way in which dispatchable generating resources operate.\706\ For
example, the electric output from wind and solar generating sources
fluctuates daily and seasonally due to increases and decreases in the
wind speed or solar intensity. Due to this variable nature of wind and
solar, dispatchable EGUs, including combustion turbines as well as
other technologies like energy storage, are used to ensure the
reliability of the electric grid. This requires dispatchable power
plants to have the ability to quickly start and stop and to rapidly and
frequently change load--much more often than was previously needed.
These are important characteristics of the combustion turbines that
provide firm backup capacity. Combustion turbines are much more
flexible than coal-fired utility boilers in this regard and have played
an important role during the past decade in ensuring that electric
supply and demand are balanced.
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\706\ Dispatchable generating sources are those that can be
turned on and off and adjusted to provide power to the electric grid
based on the demand for electricity. Variable (sometimes referred to
as intermittent) generating sources are those that supply
electricity based on external factors that are not controlled by the
owner/operator of the source (e.g., wind and solar sources).
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As discussed in section IV.F.2 of this preamble, in the final TSD,
Power Sector Trends, and in the accompanying RIA, the EPA's Power
Sector Platform 2023 using IPM projects that natural gas-fired
combustion turbines will continue to play an important role in meeting
electricity demand. However, that role is projected to evolve as
additional renewable and non-renewable low-GHG generation and energy
storage technologies are added to the grid. Energy storage technologies
can store energy during periods when generation from renewable
resources is high relative to demand and can provide electricity to the
grid during other periods. Energy storage technologies are projected to
reduce the need for base load fossil fuel-fired firm dispatchable power
plants, and the capacity factors of combined cycle EGUs are forecast to
decline by 2040.
C. Overview of Regulation of Stationary Combustion Turbines for GHGs
As explained earlier in this preamble, the EPA originally regulated
new and reconstructed stationary combustion turbine EGUs for emissions
of GHGs in 2015 under 40 CFR part 60, subpart TTTT. In 40 CFR part 60,
subpart TTTT, the EPA created three subcategories: two for natural gas-
fired combustion turbines and one for multi-fuel-fired combustion
turbines. For natural gas-fired turbines, the EPA created a subcategory
for base load turbines and a separate subcategory for non-base load
turbines. Base load turbines were defined as combustion turbines with
electric sales greater than a site-specific electric sales threshold
based on the design efficiency of the combustion turbine. Non-base load
turbines were defined as combustion turbines with a capacity factor
less than or equal to the site-specific electric sales threshold. For
base load turbines, the EPA set a standard of 1,000 lb CO2/
MWh-gross based on efficient combined cycle turbine technology. For
non-base load and multi-fuel-fired turbines, the EPA set a standard
based on the use of lower-emitting fuels that varied from 120 lb
CO2/MMBtu to 160 lb CO2/MMBtu, depending upon
whether the turbine burned primarily natural gas or other lower-
emitting fuels.
D. Eight-Year Review of NSPS
CAA section 111(b)(1)(B) requires the Administrator to ``at least
every 8 years, review and, if appropriate, revise [the NSPS] . . . .''
The provision further provides that ``the Administrator need not review
any such standard if the Administrator determines that such review is
not appropriate in light of readily available information on the
efficacy of such [NSPS].''
The EPA promulgated the NSPS for GHG emissions for stationary
combustion turbines in 2015. Announcements and modeling projections
show that project developers are building new fossil fuel-fired
combustion turbines and have plans to continue building additional
capacity. Because the emissions from this added capacity have the
potential to be large and these units are likely to have long operating
lives (25 years or more), it is important to limit emissions from these
new units. Accordingly, in this final rule, the EPA is updating the
NSPS for newly constructed and reconstructed fossil fuel-fired
stationary combustion turbines.
E. Applicability Requirements and Subcategorization
This section describes the amendments to the specific applicability
criteria for non-fossil fuel-fired EGUs, industrial EGUs, CHP EGUs, and
combustion turbine EGUs not connected to a natural gas pipeline. The
EPA is also making certain changes to the applicability requirements
for stationary combustion turbines affected by this final rule as
compared to those for sources affected by the 2015 NSPS. The amendments
are described below and include the elimination of the multi-fuel-fired
subcategory, further binning non-base load combustion turbines into low
load and intermediate load subcategories and establishing a capacity
factor threshold for base load combustion turbines.
1. Applicability Requirements
In general, the EPA refers to fossil fuel-fired EGUs that would be
subject to a CAA section 111 NSPS as ``affected'' EGUs or units. An EGU
is any fossil fuel-fired electric utility steam generating unit (i.e.,
a utility boiler or IGCC unit) or stationary combustion turbine (in
either simple cycle or combined cycle configuration). To be considered
an affected EGU under the 2015 NSPS at 40 CFR part 60, subpart TTTT,
the unit must meet the following applicability criteria: The unit must:
(1) be capable of combusting more than 250 MMBtu/h (260 gigajoules per
hour (GJ/h)) of heat input of fossil fuel (either alone or in
combination with any other fuel); and (2) serve a generator capable of
supplying more than 25 MW net to a utility distribution system (i.e.,
for sale to the grid).\707\ However, 40 CFR part 60, subpart TTTT,
includes applicability exemptions for certain EGUs, including: (1) non-
fossil fuel-fired units subject to a federally enforceable permit that
limits the use of fossil fuels to 10 percent or less of their heat
input capacity on an annual basis; (2) CHP units that are subject to a
federally enforceable permit limiting annual net electric sales to no
more than either the unit's design efficiency multiplied by its
potential electric output, or 219,000 MWh, whichever is greater; (3)
stationary combustion turbines that are not physically capable of
combusting natural gas (e.g., those that are not connected to a natural
gas pipeline); (4) utility boilers and IGCC units that have always been
subject to a federally enforceable permit limiting annual net electric
sales to one-third or less of their potential electric output (e.g.,
limiting hours of operation to less than 2,920 hours annually) or
limiting annual electric sales to 219,000 MWh or less; (5) municipal
waste combustors that are subject to 40 CFR part 60, subpart Eb; (6)
commercial or industrial solid waste incineration units subject to 40
CFR part 60, subpart CCCC; and (7) certain projects under development,
as discussed in the preamble for the 2015 final NSPS.
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\707\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
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[[Page 39905]]
a. Revisions to 40 CFR Part 60, Subpart TTTT
The EPA is amending 40 CFR 60.5508 and 60.5509 to reflect that
stationary combustion turbines that commenced construction after
January 8, 2014, or reconstruction after June 18, 2014, and before May
24, 2023, and that meet the relevant applicability criteria are subject
to 40 CFR part 60, subpart TTTT. For steam generating EGUs and IGCC
units, 40 CFR part 60, subpart TTTT, remains applicable for units
constructed after January 8, 2014, or reconstructed after June 18,
2014. The EPA is finalizing 40 CFR part 60, subpart TTTTa, to be
applicable to stationary combustion turbines that commence construction
or reconstruction after May 23, 2023, and that meet the relevant
applicability criteria.
b. Revisions to 40 CFR Part 60, Subpart TTTT, That Are Also Included in
40 CFR Part 60, Subpart TTTTa
The EPA is finalizing that 40 CFR part 60, subpart TTTT, and 40 CFR
part 60, subpart TTTTa, use similar regulatory text except where
specifically stated. This section describes amendments included in both
subparts.
i. Applicability to Non-Fossil Fuel-Fired EGUs
The current non-fossil applicability exemption in 40 CFR part 60,
subpart TTTT, is based strictly on the combustion of non-fossil fuels
(e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU
must be both: (1) Capable of combusting more than 50 percent non-fossil
fuel and (2) subject to a federally enforceable permit condition
limiting the annual heat input capacity for all fossil fuels combined
of 10 percent or less. The current language does not take heat input
from non-combustion sources (e.g., solar thermal) into account. Certain
solar thermal installations have natural gas backup burners larger than
250 MMBtu/h. As currently treated in 40 CFR part 60, subpart TTTT,
these solar thermal installations are not eligible to be considered
non-fossil units because they are not capable of deriving more than 50
percent of their heat input from the combustion of non-fossil fuels.
Therefore, solar thermal installations that include backup burners
could meet the applicability criteria of 40 CFR part 60, subpart TTTT,
even if the burners are limited to an annual capacity factor of 10
percent or less. These EGUs would readily comply with the standard of
performance, but the reporting and recordkeeping would increase costs
for these EGUs.
The EPA proposed and is finalizing several amendments to align the
applicability criteria with the original intent to cover only fossil
fuel-fired EGUs. These amendments ensure that solar thermal EGUs with
natural gas backup burners, like other types of non-fossil fuel-fired
units that derive most of their energy from non-fossil fuel sources,
are not subject to the requirements of 40 CFR part 60, subpart TTTT or
TTTTa. Amending the applicability language to include heat input
derived from non-combustion sources allows these facilities to avoid
the requirements of 40 CFR part 60, subpart TTTT or TTTTa, by limiting
the use of the natural gas burners to less than 10 percent of the
capacity factor of the backup burners. Specifically, the EPA is
amending the definition of non-fossil fuel-fired EGUs from EGUs capable
of ``combusting 50 percent or more non-fossil fuel'' to EGUs capable of
``deriving 50 percent or more of the heat input from non-fossil fuel at
the base load rating'' (emphasis added). The definition of base load
rating is also being amended to include the heat input from non-
combustion sources (e.g., solar thermal).
Revising ``combusting'' to ``deriving'' in the amended non-fossil
fuel applicability language ensures that 40 CFR part 60, subparts TTTT
and TTTTa, cover the fossil fuel-fired EGUs that the original rule was
intended to cover, while minimizing unnecessary costs to EGUs fueled
primarily by steam generated without combustion (e.g., thermal energy
supplied through the use of solar thermal collectors). The
corresponding change in the base load rating to include the heat input
from non-combustion sources is necessary to determine the relative heat
input from fossil fuel and non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
In simple terms, the current applicability provisions in 40 CFR
part 60, subpart TTTT, require that an EGU be capable of combusting
more than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to
a utility distribution system to be subject to 40 CFR part 60, subpart
TTTT. These applicability provisions exclude industrial EGUs. However,
the definition of an EGU also includes ``integrated equipment that
provides electricity or useful thermal output.'' This language
facilitates the integration of non-emitting generation and avoids
energy inputs from non-affected facilities being used in the emission
calculation without also considering the emissions of those facilities
(e.g., an auxiliary boiler providing steam to a primary boiler). This
language could result in certain large processes being included as part
of the EGU and meeting the applicability criteria. For example, the
high-temperature exhaust from an industrial process (e.g., calcining
kilns, dryer, metals processing, or carbon black production facilities)
that consumes fossil fuel could be sent to a HRSG to produce
electricity. If the industrial process uses more than 250 MMBtu/h heat
input and the electric sales exceed the applicability criteria, then
the unit could be subject to 40 CFR part 60, subpart TTTT or TTTTa.
This is potentially problematic for multiple reasons. First, it is
difficult to determine the useful output of the EGU (i.e., HRSG) since
part of the useful output is included in the industrial process. In
addition, the fossil fuel that is combusted could have a relatively
high CO2 emissions rate on a lb/MMBtu basis, making it
potentially problematic to meet the standard of performance using
efficient generation. This could result in the owner/operator reducing
the electric output of the industrial facility to avoid the
applicability criteria. Finally, the compliance costs associated with
40 CFR part 60, subpart TTTT or TTTTa, could discourage the development
of environmentally beneficial projects.
To avoid these outcomes, the EPA is, as proposed, amending the
applicability provision that exempts EGUs where greater than 50 percent
of the heat input is derived from an industrial process that does not
produce any electrical or mechanical output or useful thermal output
that is used outside the affected EGU.\708\ Reducing the output or not
developing industrial electric generating projects where the majority
of the heat input is derived from the industrial process itself would
not necessarily result in reductions in GHG emissions from the
industrial facility. However, the electricity that would have been
produced from the industrial project could still be needed. Therefore,
projects of this type provide significant environmental benefit by
providing additional useful output with little if any additional
environmental impact. Including these types of projects would result in
regulatory burden without any associated environmental benefit and
could discourage project development,
[[Page 39906]]
leading to potential overall increases in GHG emissions.
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\708\ Auxiliary equipment such as boilers or combustion turbines
that provide heat or electricity to the primary EGU (including to
any control equipment) would still be considered integrated
equipment and included as part of the affected facility.
---------------------------------------------------------------------------
(B) Industrial EGUs Electric Sales Threshold Permit Requirement
The current electric sales applicability exemption in 40 CFR part
60, subpart TTTT, for non-CHP steam generating units includes the
provision that EGUs have ``always been subject to a federally
enforceable permit limiting annual net electric sales to one-third or
less of their potential electric output (e.g., limiting hours of
operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less'' (emphasis added). The
justification for this restriction includes that the 40 CFR part 60,
subpart Da, applicability language includes ``constructed for the
purpose of . . .'' and the Agency concluded that the intent was defined
by permit conditions (80 FR 64544; October 23, 2015). This
applicability criterion is important both for determining applicability
with the new source CAA section 111(b) requirements and for determining
whether existing steam generating units are subject to the existing
source CAA section 111(d) requirements. For steam generating units that
commenced construction after September 18, 1978, the applicability of
40 CFR part 60, subpart Da, would be relatively clear as to what
criteria pollutant NSPS is applicable to the facility. However, for
steam generating units that commenced construction prior to September
18, 1978, or where the owner/operator determined that criteria
pollutant NSPS applicability was not critical to the project (e.g.,
emission controls were sufficient to comply with either the EGU or
industrial boiler criteria pollutant NSPS), owners/operators might not
have requested that an electric sales permit restriction be included in
the operating permit. Under the current applicability language, some
onsite EGUs could be covered by the existing source CAA section 111(d)
requirements even if they have never sold electricity to the grid. To
avoid covering these industrial EGUs, the EPA proposed and is
finalizing amendments to the electric sales exemption in 40 CFR part
60, subparts TTTT and TTTTa, to read, ``annual net electric sales have
never exceeded one-third of its potential electric output or 219,000
MWh, whichever is greater, and is [the ``always been'' would be
deleted] subject to a federally enforceable permit limiting annual net
electric sales to one-third or less of their potential electric output
(e.g., limiting hours of operation to less than 2,920 hours annually)
or limiting annual electric sales to 219,000 MWh or less'' (emphasis
added). EGUs that reduce current generation will continue to be covered
as long as they sold more than one-third of their potential electric
output at some time in the past. The revisions make it possible for an
owner/operator of an existing industrial EGU to provide evidence to the
Administrator that the facility has never sold electricity in excess of
the electricity sales threshold and to modify their permit to limit
sales in the future. Without the amendment, owners/operators of any
non-CHP industrial EGU capable of selling 25 MW would be subject to the
existing source CAA section 111(d) requirements even if they have never
sold any electricity. Therefore, the EPA is eliminating the requirement
that existing industrial EGUs must have always been subject to a permit
restriction limiting net electric sales.
iii. Determination of the Design Efficiency
The design efficiency (i.e., the efficiency of converting thermal
energy to useful energy output) of a combustion turbine is used to
determine the electric sales applicability threshold. In 40 CFR part
60, subpart TTTT, the sales criteria are based in part on the
individual EGU design efficiency. Three methods for determining the
design efficiency are currently provided in 40 CFR part 60, subpart
TTTT.\709\ Since the 2015 NSPS was finalized, the EPA has become aware
that owners/operators of certain existing EGUs do not have records of
the original design efficiency. These units would not be able to
readily determine whether they meet the applicability criteria (and
would therefore be subject to CAA section 111(d) requirements for
existing sources) in the same way that 111(b) sources would be able to
determine if the facility meets the applicability criteria. Many of
these EGUs are CHP units that are unlikely to meet the 111(b)
applicability criteria and would therefore not be subject to any future
111(d) requirements. However, the language in the 2015 NSPS would
require them to conduct additional testing to demonstrate this. The
requirement would result in burden to the regulated community without
any environmental benefit. The electricity generating market has
changed, in some cases dramatically, during the lifetime of existing
EGUs, especially concerning ownership. As a result of acquisitions and
mergers, original EGU design efficiency documentation, as well as
performance guarantee results that affirmed the design efficiency, may
no longer exist. Moreover, such documentation and results may not be
relevant for current EGU efficiencies, as changes to original EGU
configurations, upon which the original design efficiencies were based,
render those original design efficiencies moot, meaning that there
would be little reason to maintain former design efficiency
documentation since it would not comport with the efficiency associated
with current EGU configurations. As the three specified methods would
rely on documentation from the original EGU configuration performance
guarantee testing, and results from that documentation may no longer
exist or be relevant, it is appropriate to allow other means to
demonstrate EGU design efficiency. To reduce potential future
compliance burden, the EPA proposed and is finalizing in 40 CFR part
60, subparts TTTT and TTTTa, to allow alternative methods as approved
by the Administrator on a case-by-case basis. Owners/operators of EGUs
can petition the Administrator in writing to use an alternate method to
determine the design efficiency. The Administrator's discretion is
intentionally left broad and can extend to other American Society of
Mechanical Engineers (ASME) or International Organization for
Standardization (ISO) methods as well as to operating data to
demonstrate the design efficiency of the EGU. The EPA also proposed and
is finalizing a change to the applicability of paragraph 60.8(b) in
table 3 of 40 CFR part 60, subpart TTTT, from ``no'' to ``yes'' and
that the applicability of paragraph 60.8(b) in table 3 of 40 CFR part
60, subpart TTTTa, is ``yes.'' This allows the Administrator to approve
alternatives to the test methods specified in 40 CFR part 60, subparts
TTTT and TTTTa.
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\709\ 40 CFR part 60, subpart TTTT, currently lists ``ASME PTC
22 Gas Turbines,'' ``ASME PTC 46 Overall Plant Performance,'' and
``ISO 2314 Gas turbines--acceptance tests'' as approved methods to
determine the design efficiency.
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c. Applicability for 40 CFR Part 60, Subpart TTTTa
This section describes applicability criteria that are only
incorporated into 40 CFR part 60, subpart TTTTa, and that differ from
the requirements in 40 CFR part 60, subpart TTTT.
Section 111 of the CAA defines a new or modified source for
purposes of a given NSPS as any stationary source that commences
construction or modification after the publication of the proposed
regulation. Thus, the standards of performance apply to EGUs that
commence construction or reconstruction after the date of proposal of
this rule--May 23, 2023. EGUs that commenced construction after the
date
[[Page 39907]]
of the proposal for the 2015 NSPS and by May 23, 2023, will remain
subject to the standards of performance promulgated in the 2015 NSPS. A
modification is any physical change in, or change in the method of
operation of, an existing source that increases the amount of any air
pollutant emitted to which a standard applies.\710\ The NSPS general
provisions (40 CFR part 60, subpart A) provide that an existing source
is considered a new source if it undertakes a reconstruction.\711\
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\710\ 40 CFR 60.2.
\711\ 40 CFR 60.15(a).
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The EPA is finalizing the same applicability requirements in 40 CFR
part 60, subpart TTTTa, as the applicability requirements in 40 CFR
part 60, subpart TTTT. The stationary combustion turbine must meet the
following applicability criteria: The stationary combustion turbine
must: (1) be capable of combusting more than 250 MMBtu/h (260
gigajoules per hour (GJ/h)) of heat input of fossil fuel (either alone
or in combination with any other fuel); and (2) serve a generator
capable of supplying more than 25 MW net to a utility distribution
system (i.e., for sale to the grid).\712\ In addition, the EPA proposed
and is finalizing in 40 CFR part 60, subpart TTTTa, to include
applicability exemptions for stationary combustion turbines that are:
(1) capable of deriving 50 percent or more of the heat input from non-
fossil fuel at the base load rating and subject to a federally
enforceable permit condition limiting the annual capacity factor for
all fossil fuels combined of 10 percent (0.10) or less; (2) combined
heat and power units subject to a federally enforceable permit
condition limiting annual net electric sales to no more than 219,000
MWh or the product of the design efficiency and the potential electric
output, whichever is greater; (3) serving a generator along with other
steam generating unit(s), IGCC, or stationary combustion turbine(s)
where the effective generation capacity is 25 MW or less; (4) municipal
waste combustors that are subject to 40 CFR part 60, subpart Eb; (5)
commercial or industrial solid waste incineration units subject to 40
CFR part 60, subpart CCCC; and (6) deriving greater than 50 percent of
heat input from an industrial process that does not produce any
electrical or mechanical output that is used outside the affected
stationary combustion turbine.
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\712\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------
The EPA proposed the same requirements to combustion turbines in
non-continental areas (i.e., Hawaii, the Virgin Islands, Guam, American
Samoa, the Commonwealth of Puerto Rico, and the Northern Mariana
Islands) and non-contiguous areas (non-continental areas and Alaska) as
the EPA did for comparable units in the contiguous 48 states.\713\
However, the Agency solicited comment on whether owners/operators of
new and reconstructed combustion turbines in non-continental and non-
contiguous areas should be subject to different requirements.
Commenters generally commented that due to the difference in non-
contiguous areas relative to the lower 48 states, the proposed
requirements should not apply to owners/operators of new or
reconstructed combustion turbines in non-contiguous areas. The Agency
has considered these comments and is finalizing that only the initial
BSER component will be applicable to owners/operators of combustion
turbines located in non-contiguous areas. Therefore, owners/operators
of base load combustions turbines would not be subject to the CCS-based
numerical standards in 2032 and would continue to comply with the
efficiency-based numeric standard. Based on information reported in the
2022 EIA Form EIA-860, there are no planned new combustion turbines in
either Alaska or Hawaii. In addition, since 2015 no new combustion
turbines have commenced operation in Hawaii. Two new combustion turbine
facilities totaling 190 MW have commenced operation in Alaska since
2015. One facility is a combined cycle CHP facility and the other is at
an industrial facility and neither facility would likely meet the
applicability of 40 CFR part 60, subpart TTTTa. Therefore, not
finalizing phase-2 BSER for non-continental and non-contiguous areas
will have limited, if any, impacts on emissions or costs. The EPA notes
that the Agency has the authority to amend this decision in future
rulemakings.
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\713\ 40 CFR part 60, subpart TTTT, also includes coverage for
owners/operators of combustion turbines in non-contiguous areas.
However, owners/operators of combustion turbines not capable of
combusting natural gas (e.g., not connected to a natural gas
pipeline) are not subject to the rule. This exemption covers many
combustion turbines in non-contiguous areas.
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i. Applicability to CHP Units
For 40 CFR part 60, subpart TTTT, owners/operators of CHP units
calculate net electric sales and net energy output using an approach
that includes ``at least 20.0 percent of the total gross or net energy
output consists of electric or direct mechanical output.'' It is
unlikely that a CHP unit with a relatively low electric output (i.e.,
less than 20.0 percent) would meet the applicability criteria. However,
if a CHP unit with less than 20.0 percent of the total output
consisting of electricity were to meet the applicability criteria, the
net electric sales and net energy output would be calculated the same
as for a traditional non-CHP EGU. Even so, it is not clear that these
CHP units would have less environmental benefit per unit of electricity
produced than would more traditional CHP units. For 40 CFR part 60,
subpart TTTTa, the EPA proposed and is finalizing to eliminate the
restriction that CHP units produce at least 20.0 percent electrical or
mechanical output to qualify for the CHP-specific method for
calculating net electric sales and net energy output.
In the 2015 NSPS, the EPA did not issue standards of performance
for certain types of sources--including industrial CHP units and CHPs
that are subject to a federally enforceable permit limiting annual net
electric sales to no more than the unit's design efficiency multiplied
by its potential electric output, or 219,000 MWh or less, whichever is
greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT,
for determining net electric sales for applicability purposes allows
the owner/operator to subtract the purchased power of the thermal host
facility. The intent of the approach is to determine applicability
similarly for third-party developers and CHP units owned by the thermal
host facility.\714\ However, as written in 40 CFR part 60, subpart
TTTT, each third-party CHP unit would subtract the entire electricity
use of the thermal host facility when determining its net electric
sales. It is clearly not the intent of the provision to allow multiple
third-party developers that serve the same thermal host to all subtract
the purchased power of the thermal host facility when determining net
electric sales. This would result in counting the purchased power
multiple times. In addition, it is not the intent of the provision to
allow a CHP developer to provide a trivial amount of useful thermal
output to multiple thermal hosts and then subtract all the thermal
hosts' purchased power when determining net electric sales for
applicability purposes. The EPA
[[Page 39908]]
proposed and is finalizing in 40 CFR part 60, subpart TTTTa, to limit
to the amount of thermal host purchased power that a third-party CHP
developer can subtract for electric sales when determining net electric
sales equivalent to the percentage of useful thermal output provided to
the host facility by the specific CHP unit. This approach eliminates
both circumvention of the intended applicability by sales of trivial
amounts of useful thermal output and double counting of thermal host-
purchased power.
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\714\ For contractual reasons, many developers of CHP units sell
the majority of the generated electricity to the electricity
distribution grid. Owners/operators of both the CHP unit and thermal
host can subtract the site purchased power when determining net
electric sales. Third-party developers that do not own the thermal
host can also subtract the purchased power of the thermal host when
determining net electric sales for applicability purposes.
---------------------------------------------------------------------------
Finally, to avoid potential double counting of electric sales, the
EPA proposed and is finalizing that for CHP units determining net
electric sales, purchased power of the host facility be determined
based on the percentage of thermal power provided to the host facility
by the specific CHP facility.
ii. Non-Natural Gas Stationary Combustion Turbines
There is currently an exemption in 40 CFR part 60, subpart TTTT,
for stationary combustion turbines that are not physically capable of
combusting natural gas (e.g., those that are not connected to a natural
gas pipeline). While combustion turbines not connected to a natural gas
pipeline meet the general applicability of 40 CFR part 60, subpart
TTTT, these units are not subject to any of the requirements. The EPA
is not including in 40 CFR part 60, subpart TTTTa, the exemption for
stationary combustion turbines that are not physically capable of
combusting natural gas. As described in the standards of performance
section, owners/operators of combustion turbines burning fuels with a
higher heat input emission rate than natural gas would adjust the
natural gas-fired emissions rate by the ratio of the heat input-based
emission rates. The overall result is that new stationary combustion
turbines combusting fuels with higher GHG emissions rates than natural
gas on a lb CO2/MMBtu basis must maintain the same
efficiency compared to a natural gas-fired combustion turbine and
comply with a standard of performance based on the identified BSER.
2. Subcategorization
In this final rule, the EPA is continuing to include both simple
and combined cycle turbines in the definition of a stationary
combustion turbine, and like in prior rules for this source category,
the Agency is finalizing three subcategories--low load, intermediate
load, and base load combustion turbines. These subcategories are
determined based on electric sales (i.e., utilization) relative to the
combustion turbines' potential electric output to an electric
distribution network on both a 12-operating month and 3-year rolling
average basis. The applicable subcategory is determined each operating
month and a stationary combustion turbine can switch subcategories if
the owner/operator changes the way the facility is operated.
Subcategorization based on percent electric sales is a proxy for how a
combustion turbine operates and for determining the BSER and
corresponding emission standards. For example, low load combustion
turbines tend to spend a relatively high percentage of operating hours
starting and stopping. However, within each subcategory not all
combustion turbines operate the same. Some low load combustion turbines
operate with less starting and stopping, but in general, combustion
turbines tend to operate with fewer starts and stops (i.e., more
steady-state hours of operation) with increasing percentages of
electric sales. The BSER for each subcategory is based on
representative operation of the combustion turbines in that subcategory
and on what is achievable for the subcategory as a whole.
Subcategorization by electric sales is similar, but not identical,
to subcategorizing by heat input-based capacity factors or annual hours
of operation limits.\715\ The EPA has determined that, for NSPS
purposes, electric sales is appropriate because it reflects operational
limitations inherent in the design of certain units, and also that--
given these differences--certain emission reduction technologies are
more suitable for some units than for others.\716\ This
subcategorization approach is also consistent with industry practice.
For example, operating permits for simple cycle turbines often include
annual operating hour limitations of 1,500 to 4,000 hours annually.
When average hourly capacity factors (i.e., duty cycles) are accounted
for, these hourly restrictions are similar to annual capacity factor
restrictions of approximately 15 percent and 40 percent, respectively.
The owners or operators of these combustion turbines never intend for
them to provide base load power. In contrast, operating permits do not
typically restrict the number of hours of annual operation for combined
cycle turbines, reflecting that these types of combustion turbines are
intended to have the ability to provide base load power.
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\715\ Percent electric sales thresholds, capacity factor
thresholds, and annual hours of operation limitations all categorize
combustion turbines based on utilization.
\716\ While utilization and electric sales are often similar,
the EPA uses electric sales because the focus of the applicability
is facilities that sell electricity to the grid and not industrial
facilities where the electricity is generated primarily for use
onsite.
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The EPA evaluated the operation of the three general combustion
turbine technologies--combined cycle turbines, frame-type simple cycle
turbines, and aeroderivative simple cycle turbines--when determining
the subcategorization approach in this rulemaking.\717\ The EPA found
that, at the same capacity factor, aeroderivative simple cycle turbines
have more starts (including fewer operating hours per start) than
either frame simple cycle turbines or combined cycle turbines. The
maximum number of starts for aeroderivative simple cycle turbines
occurs at capacity factors of approximately 30 percent and the maximum
number of starts for frame simple cycle turbines and combined cycle
turbines both occur at capacity factors of approximately 25 percent. In
terms of the median hours of operation per start, the hours per starts
increases exponentially with capacity factor for each type of
combustion turbine. The rate of increase is greatest for combined cycle
turbines with the run times per start increasing significantly at
capacity factors of 40 and greater. This threshold roughly matches the
subcategorization threshold for intermediate load and base load
turbines in this final rule. As is discussed later in section VIII.F.3
and VIII.F.4, technology options including those related to efficiency
and to post combustion capture are impacted by the way units operate
and can be more effective for units with fewer stops and starts.
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\717\ The EPA used manufacturers' designations for frame and
aeroderivative combustion turbines.
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a. Legal Basis for Subcategorization
As noted in section V.C.1 of this preamble, CAA section 111(b)(2)
provides that the EPA ``may distinguish among classes, types, and sizes
within categories of new sources for the purpose of establishing . . .
standards [of performance].'' The D.C. Circuit has held that the EPA
has broad discretion in determining whether and how to subcategorize
under CAA section 111(b)(2). Lignite Energy Council, 198 F.3d at 933.
As also noted in section V.C.1 of this preamble, in prior CAA section
111 rules, the EPA has subcategorized on numerous bases, including,
among other things, fuel type and load, i.e., utilization. In
particular, as noted in section V.C.1 of this preamble, the EPA
subcategorized on the basis of utilization--for base load
[[Page 39909]]
and non-base load subcategories--in the 2015 NSPS for GHG emissions
from combustion turbines, Standards of Performance for Greenhouse Gas
Emissions From New, Modified, and Reconstructed Stationary Sources:
Electric Utility Generating Units, 80 FR 64509 (October 23, 2015), and
also in the NESHAP for Reciprocating Internal Combustion Engines; NSPS
for Stationary Internal Combustion Engines, 79 FR 48072-01 (August 15,
2014).
Subcategorizing combustion turbines based on utilization is
appropriate because it recognizes the way differently designed
combustion turbines actually operate. Project developers do not
construct combined cycle combustion turbine system to start and stop
often to serve peak demand. Similarly, project developers do not
construct and install simple cycle combustion turbines to operate at
higher capacity factors to provide base load demand. And intermediate
load demand may be served by higher efficiency simple cycle turbine
systems or by ``quick start'' combined cycle units. Thus, there are
distinguishing features (i.e., different classes, types, and sizes) of
turbines that are predominantly used in each of the utilization-based
subcategories. Further, the amount of utilization and the mode of
operation are relevant for the systems of emission reduction that the
EPA may evaluate to be the BSER and therefore for the resulting
standards of performance. See section VII.C.2.a.i for more discussion
of the legal basis to subcategorize based upon characteristics relevant
to the controls the EPA may determine to be the BSER.
As noted in sections VIII.E.2.b and VIII.F of this preamble,
combustion turbines that operate at low load have highly variable
operation and therefore highly variable emission rates. This
variability made it challenging for the EPA to specify a BSER based on
efficient design and operation and limits the BSER for purposes of this
rulemaking to lower-emitting fuels. The EPA notes that the
subcategorization threshold and the standard of performance are
related. For example, the Agency could have finalized a lower electric
sales threshold for the low load subcategory (e.g., 15 percent) and
evaluated the emission rates at the lower capacity factors. In future
rulemaking the Agency could further evaluate the costs and emissions
impacts of reducing the threshold for combustion turbines subject to a
BSER based on the use of lower emitting fuels.
Intermediate load combustion turbines (i.e., those that operate at
loads that are somewhat higher than the low load peaking units) are
most often designed to be simple cycle units rather than combined cycle
units. This is because combustion turbines operating in the
intermediate load range also start and stop and vary their load
frequently (though not as often as low load peaking units). Because of
the more frequent starts and stops, simple cycle combustion turbines
are more economical for project developers when compared to combined
cycle combustion turbines. Utilization of CCS technology is not
practicable for those simple cycle units due to the lack of a HRSG.
Therefore, the EPA has determined that efficient design and operation
is the BSER for intermediate load combustion turbines.
While use of CCS is practicable for combined cycle combustion
turbines, it is most appropriate for those units that operate at
relatively higher loads (i.e., as base load units) that do not
frequently start, stop, and change load. Moreover, with current
technology, CCS works better on units running at base load levels.
b. Electric Sales Subcategorization (Low, Intermediate, and Base Load
Combustion Turbines)
As noted earlier, in the 2015 NSPS, the EPA established separate
standards of performance for new and reconstructed natural gas-fired
base load and non-base load stationary combustion turbines. The
electric sales threshold distinguishing the two subcategories is based
on the design efficiency of individual combustion turbines. A
combustion turbine qualifies as a non-base load turbine--and is thus
subject to a less stringent standard of performance--if it has net
electric sales equal to or less than the design efficiency of the
turbine (not to exceed 50 percent) multiplied by the potential electric
output (80 FR 64601; October 23, 2015). If the net electric sales
exceed that level on both a 12-operating month and 3-calendar year
basis, then the combustion turbine is in the base load subcategory and
is subject to a more stringent standard of performance. Subcategory
applicability can change on a month-to-month basis since applicability
is determined each operating month. For additional discussion on this
approach, see the 2015 NSPS (80 FR 64609-12; October 23, 2015). The
2015 NSPS non-base load subcategory is broad and includes combustion
turbines that assure grid reliability by providing electricity during
periods of peak electric demand. These peaking turbines tend to have
low annual capacity factors and sell a small amount of their potential
electric output. The non-base load subcategory in the 2015 NSPS also
includes combustion turbines that operate at intermediate annual
capacity factors and are not considered base load EGUs. These
intermediate load EGUs provide a variety of services, including
providing dispatchable power to support variable generation from
renewable sources of electricity. The need for this service has been
expanding as the amount of electricity from wind and solar continues to
grow. In the 2015 NSPS, the EPA determined the BSER for the non-base
load subcategory to be the use of lower-emitting fuels (e.g., natural
gas and Nos. 1 and 2 fuel oils). In 2015, the EPA explained that
efficient generation did not qualify as the BSER due in part to the
challenge of determining an achievable output-based CO2
emissions rate for all combustion turbines in this subcategory.
In this action, the EPA proposed and is finalizing the
subcategories in 40 CFR part 60, subpart TTTTa, that will be applicable
to sources that commence construction or reconstruction after May 23,
2023. First, the Agency proposed and is finalizing the definition of
design efficiency so that the heat input calculation of an EGU is based
on the higher heating value (HHV) of the fuel instead of the lower
heating value (LHV), as explained immediately below. This has the
effect of lowering the calculated potential electric output and the
electric sales threshold. In addition, the EPA proposed and is
finalizing division of the non-base load subcategory into separate
intermediate and low load subcategories.
i. Higher Heating Value as the Basis for Calculation of the Design
Efficiency
The heat rate is the amount of energy used by an EGU to generate 1
kWh of electricity and is often provided in units of Btu/kWh. As the
thermal efficiency of a combustion turbine EGU is increased, less fuel
is burned per kWh generated and there is a corresponding decrease in
emissions of CO2 and other air pollutants. The electric
energy output as a fraction of the fuel energy input expressed as a
percentage is a common practice for reporting the unit's efficiency.
The greater the output of electric energy for a given amount of fuel
energy input, the higher the efficiency of the electric generation
process. Lower heat rates are associated with more efficient power
generating plants.
Efficiency can be calculated using the HHV or the LHV of the fuel.
The HHV is the heating value directly determined by calorimetric
measurement of the fuel in the laboratory. The LHV is calculated using
a formula to account for the
[[Page 39910]]
moisture in the combustion gas (i.e., subtracting the energy required
to vaporize the water in the flue gas) and is a lower value than the
HHV. Consequently, the HHV efficiency for a given EGU is always lower
than the corresponding LHV efficiency because the reported heat input
for the HHV is larger. For U.S. pipeline natural gas, the HHV heating
value is approximately 10 percent higher than the corresponding LHV
heating value and varies slightly based on the actual constituent
composition of the natural gas.\718\ The EPA default is to reference
all technologies on a HHV basis,\719\ and the Agency is basing the heat
input calculation of an EGU on HHV for purposes of the definition of
design efficiency. However, it should be recognized that manufacturers
of combustion turbines typically use the LHV to express the efficiency
of combustion turbines.\720\
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\718\ The HHV of natural gas is 1.108 times the LHV of natural
gas. Therefore, the HHV efficiency is equal to the LHV efficiency
divided by 1.108. For example, an EGU with a LHV efficiency of 59.4
percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV
ratio is dependent on the composition of the natural gas (i.e., the
percentage of each chemical species (e.g., methane, ethane,
propane)) within the pipeline and will slightly move the ratio.
\719\ Natural gas is also sold on a HHV basis.
\720\ European plants tend to report thermal efficiency based on
the LHV of the fuel rather than the HHV for both combustion turbines
and steam generating EGUs. In the U.S., boiler efficiency is
typically reported on a HHV basis.
---------------------------------------------------------------------------
Similarly, the electric energy output for an EGU can be expressed
as either of two measured values. One value relates to the amount of
total electric power generated by the EGU, or gross output. However, a
portion of this electricity must be used by the EGU facility to operate
the unit, including compressors, pumps, fans, electric motors, and
pollution control equipment. This within-facility electrical demand,
often referred to as the parasitic load or auxiliary load, reduces the
amount of power that can be delivered to the transmission grid for
distribution and sale to customers. Consequently, electric energy
output may also be expressed in terms of net output, which reflects the
EGU gross output minus its parasitic load.\721\
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\721\ It is important to note that net output values reflect the
net output delivered to the electric grid and not the net output
delivered to the end user. Electricity is lost as it is transmitted
from the point of generation to the end user and these ``line
losses'' increase the farther the power is transmitted. 40 CFR part
60, subpart TTTT, provides a way to account for the environmental
benefit of reduced line losses by crediting CHP EGUs, which are
typically located close to large electric load centers. See 40 CFR
60.5540(a)(5)(i) and the definitions of gross energy output and net
energy output in 40 CFR 60.5580.
---------------------------------------------------------------------------
When using efficiency to compare the effectiveness of different
combustion turbine EGU configurations and the applicable GHG emissions
control technologies, it is important to ensure that all efficiencies
are calculated using the same type of heating value (i.e., HHV or LHV)
and the same basis of electric energy output (i.e., MWh-gross or MWh-
net). Most emissions data are available on a gross output basis and the
EPA is finalizing output-based standards based on gross output.
However, to recognize the superior environmental benefit of minimizing
auxiliary/parasitic loads, the Agency is including optional equivalent
standards on a net output basis. To convert from gross to net output-
based standards, the EPA used a 2 percent auxiliary load for simple and
combined cycle turbines and a 7 percent auxiliary load for combined
cycle EGUs using 90 percent CCS.\722\
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\722\ The 7 percent auxiliary load for combined cycle turbines
with 90 percent CCS is specific to electric output. Additional
auxiliary load includes thermal energy that is diverted to the CCS
system instead of being used to generate additional electricity.
This additional auxiliary thermal energy is accounted for when
converting the phase 1 emissions standard to the phase 2 standard.
---------------------------------------------------------------------------
ii. Lowering the Threshold Between the Base Load and Non-Base Load
Subcategories
The subpart TTTT distinction between a base load and non-base load
combustion turbine is determined by the unit's actual electric sales
relative to its potential electric sales, assuming the EGU is operated
continuously (i.e., percent electric sales). Specifically, stationary
combustion turbines are categorized as non-base load and are
subsequently subject to a less stringent standard of performance if
they have net electric sales equal to or less than their design
efficiency (not to exceed 50 percent) multiplied by their potential
electric output (80 FR 64601; October 23, 2015). Because the electric
sales threshold is based in part on the design efficiency of the EGU,
more efficient combustion turbine EGUs can sell a higher percentage of
their potential electric output while remaining in the non-base load
subcategory. This approach recognizes both the environmental benefit of
combustion turbines with higher design efficiencies and provides
flexibility to the regulated community. In the 2015 NSPS, it was
unclear how often high-efficiency simple cycle EGUs would be called
upon to support increased generation from variable renewable generating
resources. Therefore, the Agency determined it was appropriate to
provide maximum flexibility to the regulated community. To do this, the
Agency based the numeric value of the design efficiency, which is used
to calculate the electric sales threshold, on the LHV efficiency. This
had the impact of allowing combustion turbines to sell a greater share
of their potential electric output while remaining in the non-base load
subcategory.
The EPA proposed and is finalizing that the design efficiency in 40
CFR part 60, subpart TTTTa be based on the HHV efficiency instead of
LHV efficiency and to not include the 50 percent maximum and 33 percent
minimum restrictions. When determining the potential electric output
used in calculating the electric sales threshold in 40 CFR part 60,
subpart TTTT, design efficiencies of greater than 50 percent are
reduced to 50 percent and design efficiencies of less than 33 percent
are increased to 33 percent for determining electric sales threshold
subcategorization criteria. The 50 percent criterion was established to
limit non-base load EGUs from selling greater than 55 percent of their
potential electric sales.\723\ The 33 percent criterion was included to
be consistent with applicability thresholds in the electric utility
criteria pollutant NSPS (40 CFR part 60, subpart Da).
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\723\ While the design efficiency is capped at 50 percent on a
LHV basis, the base load rating (maximum heat input of the
combustion turbine) is on a HHV basis. This mixture of LHV and HHV
results in the electric sales threshold being 11 percent higher than
the design efficiency. The design efficiency of all new combined
cycle EGUs exceed 50 percent on a LHV basis.
---------------------------------------------------------------------------
Neither of those criteria are appropriate for 40 CFR part 60,
subpart TTTTa, and the EPA proposed and is finalizing a decision that
they are not incorporated when determining the electric sales
threshold. Instead, as discussed later in the section, the EPA is
finalizing a fixed percent electric sales thresholds and the design
efficiency does not impact the subcategorization thresholds. However,
the design efficiency is still used when determining the potential
electric sales and any restriction on using the actual design
efficiency of the combustion turbine would have the impact of changing
the threshold. If this restriction were maintained, it would reduce the
regulatory incentive for manufacturers to invest in programs to develop
higher efficiency combustion turbines.
The EPA also proposed and is finalizing a decision to eliminate the
33 percent minimum design efficiency in the calculation of the
potential electric output. The EPA is unaware of any new combustion
turbines with design efficiencies meeting the general
[[Page 39911]]
applicability criteria of less than 33 percent; and this will likely
have no cost or emissions impact.
The EPA solicited comment on whether the intermediate/base load
electric sales threshold should be reduced further to a range that
would lower the base load electric sales threshold for simple cycle
turbines to between 29 to 35 percent (depending on the design
efficiency) and to between 40 to 49 percent for combined cycle turbines
(depending on the design efficiency). The specific approach the EPA
solicited comment on was reducing the design efficiency by 6 percent
(e.g., multiplying by 0.94) when determining the electric sales
threshold. Some commenters supported lowering the proposed electric
sales threshold while others supported maintaining the proposed
standards.
After considering comments, in 40 CFR part 60, subpart TTTTa, the
EPA has determined it is appropriate to eliminate the sliding scale
electric sales threshold based on the design efficiency and instead
base the subcategorization thresholds on fixed electric sales (also
referred to sometimes here as capacity factor). In 40 CFR part 60
subpart TTTTa, the EPA is finalizing that the fixed electric sales
threshold between intermediate load combustion turbines and base load
combustion turbines is 40 percent. The 40 percent electric sales
(capacity factor) threshold reflects the maximum capacity factor for
intermediate load simple cycle turbines and the minimum prorated
efficiency approach for base load combined cycle turbines that the EPA
solicited comment on in proposal.\724\
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\724\ The EPA solicited comment on basing the electric sales
threshold on a value calculated using 0.94 times the design
efficiency.
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The base load electric sales threshold is appropriate for new
combustion turbines because, as will be discussed later, the first
component of BSER for base load turbines is based on highly efficient
combined cycle generation. Combined cycle units are significantly more
efficient than simple cycle turbines; and therefore, in general, the
EPA should be focusing its determination of the BSER for base load
units on that more efficient technology. The electric sales thresholds
and the emission standards are related because, at lower capacity
factors, combustion turbines tend to have more variable operation
(e.g., more starts and stops and operation at part load conditions)
that reduces the efficiency of the combustion turbine. This is
particularly the case for combined cycle turbines because while the
turbine engine can come to full load relatively quickly, the HRSG and
steam turbine cannot, and combined cycle turbines responding to highly
variable load will have efficiencies similar to simple cycle
turbines.\725\ This has implications for the appropriate control
technologies and corresponding emission reduction potential. The EPA
determined the final standard of performance based on review of
emissions data for recently installed combined cycle combustion
turbines with 12-operating month capacity factors of 40 percent or
greater. The EPA considered a capacity factor threshold lower than 40
percent. However, expanding the subcategory to include combustion
turbines with a 12-operating month electric sales of less than 40
percent would require the EPA to consider the emissions performance of
combined cycle turbines operating at lower capacity factors and, while
it would expand the number of sources in the base load subcategory, it
would also result in a higher (i.e., less stringent) numerical emission
standard for the sources in the category.
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\725\ This discussion assumes that the combined cycle turbine
incorporates a bypass stack that allows the combustion turbine
engine to operate independent of the HRSG/steam turbine. Without a
bypass stack the combustion turbine engine could not come to full
load as quickly.
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Direct comparison of the costs of combined cycle turbines relative
to simple cycle turbines can be challenging because model plant costs
are often for combustion turbines of different sizes and do not account
for variable operation. For example, combined cycle turbine model
plants are generally for an EGU that is several hundred megawatts while
simple cycle turbine model plants are generally less than a hundred
megawatts. Direct comparison of the LCOE from these model plants is not
relevant because the facilities are not comparable. Consider a facility
with a block of 10 simple cycle turbines that are each 50 MW (so the
overall facility capacity is 500 MW). Each simple cycle turbine
operates as an individual unit and provides a different value to the
electric grid as compared to a single 500 MW combined cycle turbine.
While the minimum load of the combined cycle facility might be 200 MW,
the block of 10 simple cycle turbines can provide from approximately 20
MW to 500 MW to the electric grid.
A more accurate cost comparison accounts for economies of scale and
estimates the cost of a combined cycle turbine with the same net output
as a simple cycle turbine. Comparing the modeled LCOE of these
combustion turbines provides a meaningful comparison, at least for base
load combustion turbines. Without accounting for economies of scale and
variable operation, combined cycle turbines can appear to be more cost
effective than simple cycle turbines under almost all conditions. In
addition, without accounting for economies of scale, large frame simple
cycle turbines can appear to be more cost effective than higher
efficiency aeroderivative simple cycle turbines, even if operated at a
100 percent capacity factor. These cost models are not intended to make
direct comparisons, and the EPA appropriately accounted for economies
of scale when estimating the cost of the BSER. Since base load
combustion turbines tend to operate under steady state conditions with
few starts and stops, startup and shutdown costs and the efficiency
impact of operating at variable loads are not important for determining
the compliance costs of base load combustion turbines.
Based on an adjusted model plant comparison, combined cycle EGUs
have a lower LCOE at capacity factors above approximately 40 percent
compared to simple cycle EGUs operating at the same capacity factors.
This supports the final base load fixed electric sales threshold of 40
percent for simple cycle turbines because it would be cost-effective
for owners/operators of simple cycle turbines to add heat recovery if
they elected to operate at higher capacity factors as a base load unit.
Furthermore, based on an analysis of monthly emission rates, recently
constructed combined cycle EGUs maintain consistent emission rates at
capacity factors of less than 55 percent (which is the base load
electric sales threshold in subpart TTTT) relative to operation at
higher capacity factors. Therefore, the base load subcategory operating
range can be expanded in 40 CFR part 60, subpart TTTTa, without
impacting the stringency of the numeric standard. However, at capacity
factors of less than approximately 40 percent, emission rates of
combined cycle EGUs increase relative to their operation at higher
capacity factors. It takes much longer for a HRSG to begin producing
steam that can be used to generate additional electricity than it takes
a combustion engine to reach full power. Under operating conditions
with a significant number of starts and stops, typical of some
intermediate and especially low load combustion turbines, there may not
be enough time for the HRSG to generate steam that can be used for
additional electrical generation. To maximize overall efficiency,
combined cycle EGUs often use combustion turbine engines that are less
efficient than the most
[[Page 39912]]
efficient simple cycle turbine engines. Under operating conditions with
frequent starts and stops where the HRSG does not have sufficient time
to begin generating additional electricity, a combined cycle EGU may be
no more efficient than a highly efficient simple cycle EGU. These
distinctions in operation are thus meaningful for determining which
emissions control technologies are most appropriate for types of units.
Once a combustion turbine unit exceeds approximately 40 percent annual
capacity factor, it is economical to add a HRSG which results in the
unit becoming both more efficient and less likely to cycle its
operation. Such units are, therefore, better suited for more stringent
emission control technologies including CCS.
After the 2015 NSPS was finalized, some stakeholders expressed
concerns about the approach for distinguishing between base load and
non-base load turbines. They posited a scenario in which increased
utilization of wind and solar resources, combined with low natural gas
prices, would create the need for certain types of simple cycle
turbines to operate for longer time periods than had been contemplated
when the 2015 NSPS was being developed. Specifically, stakeholders have
claimed that in some regional electricity markets with large amounts of
variable renewable generation, some of the most efficient new simple
cycle turbines--aeroderivative turbines--could be called upon to
operate at capacity factors greater than their design efficiency.
However, if those new simple cycle turbines were to operate at those
higher capacity factors, they would become subject to the more
stringent standard of performance for base load turbines. As a result,
according to these stakeholders, the new aeroderivative turbines would
have to curtail their generation and instead, less-efficient existing
turbines would be called upon to run by the regional grid operators,
which would result in overall higher emissions. The EPA evaluated the
operation of simple cycle turbines in areas of the country with
relatively large amounts of variable renewable generation and did not
find a strong correlation between the percentage of generation from the
renewable sources and the 12-operating month capacity factors of simple
cycle turbines. In addition, most of the simple cycle turbines that
commenced operation between 2010 and 2016 (the most recent simple cycle
turbines not subject to 40 CFR part 60, subpart TTTT) have operated
well below the base load electric sales threshold in 40 CFR part 60,
subpart TTTT. Therefore, the Agency does not believe that the concerns
expressed by stakeholders necessitates any revisions to the regulatory
scheme. In fact, as noted above, the EPA is finalizing that the
electric sales threshold can be lowered without impairing the
availability of simple cycle turbines where needed, including to
support the integration of variable generation. The EPA believes that
the final threshold is not overly restrictive since a simple cycle
turbine could operate on average for more than 9 hours a day in the
intermediate load subcategory.
iii. Low and Intermediate Load Subcategories
This section discusses the EPA's rationale for subcategorizing non-
base load combustion turbines into two subcategories--low load and
intermediate load.
(A) Low Load Subcategory
The EPA proposed and is finalizing in 40 CFR part 60, subpart
TTTTa, a low load subcategory to includes combustion turbines that
operate only during periods of peak electric demand (i.e., peaking
units), which will be separate from the intermediate load subcategory.
Low load combustion turbines also provide ramping capability and other
ancillary services to support grid reliability. The EPA evaluated the
operation of recently constructed simple cycle turbines to understand
how they operate and to determine at what electric sales level or
capacity factor their emissions rate is relatively steady. (Note that
for purposes of this discussion, the terms ``electric sales'' and
``capacity factor'' are used interchangeably.) Low load combustion
turbines generally only operate for short periods of time and
potentially at relatively low duty cycles.\726\ This type of operation
reduces the efficiency and increases the emissions rate, regardless of
the design efficiency of the combustion turbine or how it is
maintained. For this reason, it is difficult to establish a reasonable
output-based standard of performance for low load combustion turbines.
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\726\ The duty cycle is the average operating capacity factor.
For example, if an EGU operates at 75 percent of the fully rated
capacity, the duty cycle would be 75 percent regardless of how often
the EGU actually operates. The capacity factor is a measure of how
much an EGU is operated relative to how much it could potentially
have been operated.
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To determine the electric sales threshold--that is, to distinguish
between the intermediate load and low load subcategories--the EPA
evaluated capacity factor electric sales thresholds of 10 percent, 15
percent, 20 percent, and 25 percent. The EPA proposed to find and is
finalizing a conclusion that the 10 percent threshold is problematic
for two reasons. First, simple cycle turbines operating at that level
or lower have highly variable emission rates, and therefore it is
difficult for the EPA to establish a meaningful output-based standard
of performance. In addition, only one-third of simple cycle turbines
that have commenced operation since 2015 have maintained 12-operating
month capacity factors of less than 10 percent. Therefore, setting the
threshold at this level would bring most new simple cycle turbines into
the intermediate load subcategory, which would subject them to a more
stringent emission rate that is only achievable for simple cycle
turbines operating at higher capacity factors. This could create a
situation where simple cycle turbines might not be able to comply with
the intermediate load standard of performance while operating at the
low end of the intermediate load capacity factor subcategorization
criteria.
Based on the EPA's review of hourly emissions data, at a capacity
factor above 15 percent, GHG emission rates for many simple cycle
turbines begin to stabilize. At higher capacity factors, more time is
typically spent at steady state operation rather than ramping up and
down; and emission rates tend to be lower while in steady-state
operation. Of recently constructed simple cycle turbines, half have
maintained 12-operating month capacity factors of 15 percent or less,
two-thirds have maintained capacity factors of 20 percent or less; and
approximately 80 percent have maintained maximum capacity factors of 25
percent or less. The emission rates clearly stabilize for most simple
cycle turbines operating at capacity factors of greater than 20
percent. Based on this information, the EPA proposed the low load
electric sales threshold--again, the dividing line to distinguish
between the intermediate and low load subcategories--to be 20 percent
and solicited comment on a range of 15 to 25 percent. The EPA also
solicited comment on whether the low load electric sales threshold
should be determined by a site-specific threshold based on three-
fourths of the design efficiency of the combustion turbine.\727\Under
this approach, simple
[[Page 39913]]
cycle turbines selling less than 18 to 22 percent of their potential
electric output (depending on the design efficiency) would still have
been considered low load combustion turbines. This ``sliding scale''
electric sales threshold approach is like the approach the EPA used in
the 2015 NSPS to recognize the environmental benefit of installing the
most efficient combustion turbines for low load applications. Using
this approach, combined cycle EGUs would have been able to sell between
26 to 31 percent of their potential electric output while still being
considered low load combustion turbines. Some commenters supported a
lower electric sales threshold while others supported a higher
threshold. Based on these comments, the EPA is finalizing the proposed
low load electric sales threshold of 20 percent of the potential
electric sales. The fixed 20 percent capacity factor threshold
represents a level of utilization at which most simple cycle combustion
turbines perform at a consistent level of efficiency and GHG emission
performance, enabling the EPA to establish a standard of performance
that reflects a BSER of efficient operation. The 20 percent capacity
factor threshold is also more environmentally protective than the
higher thresholds the EPA considered, since owners and operators of
combustion turbines operating above a 20 percent capacity factor would
be subject to an output-based emissions standard instead of a heat
input-based emissions standard based on the use of lower-emitting
fuels. This ensures that owners/operators of intermediate load combined
cycle turbines properly maintain and operate their combustion turbines.
---------------------------------------------------------------------------
\727\ The calculation used to determine the electric sales
threshold includes both the design efficiency and the base load
rating. Since the base load rating stays the same when adjusting the
numeric value of the design efficiency for applicability purposes,
adjustments to the design efficiency has twice the impact.
Specifically, using three-fourths of the design efficiency reduces
the electric sales threshold by half.
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(B) Intermediate Load Subcategory
The proposed sliding scale subcategorization approach essentially
included two subcategories within the proposed intermediate load
subcategory. As proposed, simple cycle turbines would be classified as
intermediate load combustion turbines when operated between capacity
factors of 20 percent and approximately 40 percent while combined cycle
turbines would be classified as intermediate load combustion turbines
when operated between capacity factors of 20 percent to approximately
55 percent. Owners/operators of combined cycle turbines operating at
the high end of the intermediate load subcategory would only be subject
to an emissions standard based on a BSER of high-efficiency simple
cycle turbine technology. The proposed approach provided a regulatory
incentive for owners/operators to purchase the most efficient
technologies in exchange for additional compliance flexibility. The use
of a prorated efficiency the EPA solicited comment on would have
lowered the simple cycle and combined cycle turbine thresholds to
approximately 35 percent and 50 percent, respectively.
In this final rule, the BSER for the intermediate load subcategory
is consistent with the proposal--high-efficiency simple cycle turbine
technology. While not specifically identified in the proposal, the BSER
for the base load subcategory is also consistent with the proposal--the
use of combined cycle technology.\728\
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\728\ Under the proposed subcategorization approach, for a
combustion turbine to be subcategorized as an intermediate load
combustion turbine while operating at capacity factors of greater
than 40 percent required the use of a HRSG (e.g., combined cycle
turbine technology).
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The 12-operating month electric sales (i.e., capacity factor)
thresholds for the stationary combustion turbine subcategories in this
final rule are summarized below in Table 2.
Table 2--Sales Thresholds for Subcategories of Combustion Turbine EGUs
------------------------------------------------------------------------
12-Operating month
electric sales
Subcategory threshold (percent
of potential
electric sales)
------------------------------------------------------------------------
Low Load........................................... <=20
Intermediate Load.................................. >20 and <=40
Base Load.......................................... >40
------------------------------------------------------------------------
iv. Integrated Onsite Generation and Energy Storage
Integrated equipment is currently included as part of the affected
facility, and the EPA proposed and is finalizing amended regulatory
text to clarify that the output from integrated renewables is included
as output when determining the NSPS emissions rate. The EPA also
proposed that the output from the integrated renewable generation is
not included when determining the net electric sales for applicability
purposes (i.e., generation from integrated renewables would not be
considered when determining if a combustion turbine is subcategorized
as a low, intermediate, or base load combustion turbine). In the
alternative, the EPA solicited comment on whether instead of exempting
the generation from the integrated renewables from counting toward
electric sales, the potential output from the integrated renewables
would be included when determining the design efficiency of the
facility. Since the design efficiency is used when determining the
electric sales threshold this would increase the allowable electric
sales for subcategorization purposes. Including the integrated
renewables when determining the design efficiency of the affected
facility has the impact of increasing the operational flexibility of
owners/operators of combustion turbines. Commenters generally supported
maintaining that integrated renewables are part of the affected
facility and including the output of the renewables when determining
the emissions rate of the affected facility.\729\ Therefore, the Agency
is finalizing a decision that the rated output of integrated renewables
be included when determining the design efficiency of the affected
facility, which is used to determine the potential electric output of
the affected facility, and that the output of the integrated renewables
be included in determining the emissions rate of the affected facility.
However, since the design efficiency is not a factor in determining the
subcategory thresholds in 40 CFR part 60, subpart TTTTa, the output of
the integrated renewables will not be included for determining the
applicable subcategory. If the output from the integrated renewable
generation were included for subcategorization purposes, this could
discourage the use of integrated renewables (or curtailments) because
affected facilities could move to a subcategory with a more stringent
emissions standard that could cause the owner/operator to be out of
compliance. The impact of this approach is that the electric sales
threshold of the combustion turbine island itself, not including the
integrated renewables, for an owner/operator of a combustion turbine
that includes integrated renewables that increase the potential
electric output by 1 percent would be 1 or 2 percent higher for the
stationary combustion turbine island not considering the integrated
renewables, depending on the design efficiency of the combustion
turbine itself, than an identical combustion turbine without integrated
renewables. In addition, when the output from the integrated renewables
is considered, the output from the integrated renewables
[[Page 39914]]
lowers the emissions rate of the affected facility by approximately 1
percent.
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\729\ The EPA did not propose to include, and is not finalizing
including, integrated renewables as part of the BSER. Commenters
opposed a BSER that would include integrated renewables as part of
the BSER. Commenters noted that this could result in renewables
being installed in suboptimal locations which could result in lower
overall GHG reductions.
---------------------------------------------------------------------------
For integrated energy storage technologies, the EPA solicited
comment on and is finalizing a decision to include the rated output of
the energy storage when determining the design efficiency of the
affected facility. Similar to integrated renewables, this increases the
flexibility of owner/operators to sell larger amounts of electricity
while remaining in the low, variable, and intermediate load
subcategories. While energy storage technologies have high capital
costs, operating costs are low and would dispatch prior to the
combustion turbine the technology is integrated with. Therefore, simple
cycle turbines with integrated energy storage would likely operate at
lower capacity factors than an identical simple cycle turbine at the
same location. However, while the energy storage might be charged with
renewables that would otherwise be curtailed, there is no guarantee
that low emitting generation would be used to charge the energy
storage. Therefore, the output from the energy storage is not
considered in either determining the NSPS emissions rate or as net
electric sales for subcategorization applicability purposes. In future
rulemaking the Agency could further evaluate the impact of integrated
energy storage on the operation of simple cycle turbines to determine
if the number of starts and stops are reduced and increases the
efficiency of simple cycle turbines relative to simple cycle turbines
without integrated energy storage. If this is the case, it could be
appropriate to lower the threshold for combustion turbines subject to a
lower emitting fuels BSER because emission rates would be stable at
lower capacity factors.
v. Definition of System Emergency
In 2015, the EPA included a provision that electricity sold during
hours of operation when a unit is called upon due to a system emergency
is not counted toward the percentage electric sales subcategorization
threshold in 40 CFR part 60, subpart TTTT.\730\ The Agency concluded
that this exclusion is necessary to provide flexibility, maintain
system reliability, and minimize overall costs to the sector.\731\ The
intent is that the local grid operator will determine the EGUs
essential to maintaining grid reliability. Subsequent to the 2015 NSPS,
members of the regulated community informed the EPA that additional
clarification of a system emergency is needed to determine and document
generation during system emergencies. The EPA proposed to include the
system emergency approach in 40 CFR part 60, subpart TTTTa, and
solicited comment on amending the definition of system emergency to
clarify in implementation in 40 CFR part 60, subparts TTTT and TTTTa.
Commenters generally agreed with the proposal to allow owners/operators
of EGUs called upon during a system emergency to operate without
impacting the EGUs' subcategorization (i.e., electric sales during
system emergencies would not be considered when determining net
electric sales), and that the Agency should clarify how system
emergencies are determined and documented.
---------------------------------------------------------------------------
\730\ In 40 CFR part 60, subpart TTTT, electricity sold by units
that are not called upon to operate due to a system emergency (e.g.,
units already operating when the system emergency is declared) is
counted toward the percentage electric sales threshold.
\731\ See 80 FR 64612; October 23, 2015.
---------------------------------------------------------------------------
In terms of the definition of the system emergency provision,
commenters stated that ``abnormal'' be deleted from the definition, and
instead of referencing ``the Regional Transmission Organizations (RTO),
Independent System Operators (ISO) or control area Administrator,'' the
definition should reference ``the balancing authority or reliability
coordinator.'' This change would align the regulation's definition with
the terms used by NERC. Some commenters also stated that the EPA should
specify that electric sales during periods the grid operator declares
energy emergency alerts (EEA) levels 1 through 3 be included in the
definition of system emergency.\732\ In addition, some commenters
stated that the definition should be expanded to include the concept of
energy emergencies. Specifically, the definition should also exempt
generation during periods when a load-serving entity or balancing
authority has exhausted all other resource options and can no longer
meet its expected load obligations. Finally, commenters stated that the
definition should apply to all EGUs, regardless of if they are already
operating when the system emergency is declared. This would avoid
regulatory incentive to come offline prior to a potential system
emergency to be eligible for the electric sales exemption and would
treat all EGUs similarly during system emergencies (i.e., not penalize
EGUs that are already operating to maintain grid reliability and
avoiding the need to declare grid emergencies).
---------------------------------------------------------------------------
\732\ Commenters noted that grid operators have slightly
different terms for grid emergencies, but example descriptions
include: EEA 1, all available generation online and non-firm
wholesale sales curtailed; EEA 2, load management procedures in
effect, all available generation units online, demand-response
programs in effect; and EEA 3, firm load interruption is imminent or
in progress.
---------------------------------------------------------------------------
The Agency is including the system emergency concept in 40 CFR part
60, subpart TTTTa, along with a definition that clarifies how to
determine generation during periods of system emergencies. The EPA
agrees with commenters that the definition of system emergency should
be clarified and that it should not be limited to EGUs not operating
when the system emergency is declared. Based on information provided by
entities with reliability expertise, the EPA has determined that a
system emergency should be defined to include EEA levels 2 and 3. These
EEA levels generally correspond to time-limited, well-defined, and
relatively infrequent situations in which the system is experiencing an
energy deficiency. During EEA level 2 and 3 events, all available
generation is online and demand-response or other load management
procedures are in effect, or firm load interruption is imminent or in
progress. The EPA believes it is appropriate to exclude hours of
operation during such events in order to ensure that EGUs are not
impeded from maintaining or increasing their output as needed to
respond to a declared energy emergency. Because these events tend to be
short, infrequent, and well-defined, the EPA also believes any
incremental GHG emissions associated with operations during these
periods would be relatively limited.
The EPA has determined not to include EEA level 1 in the definition
of a ``system emergency.'' The EPA's understanding is that EEA level 1
events often include situations in which an energy deficiency does not
yet exist, and in which balancing authorities are preparing to pursue
various options for either bringing additional resources online or
managing load. The EPA also understands that EEA level 1 events tend to
be more frequently declared, and longer in duration, than level 2 or 3
events. Based on this information, the EPA believes that including EEA
level 1 events in the definition of a ``system emergency'' would carry
a greater risk of increasing overall GHG emissions without making a
meaningful contribution to supporting reliability. This approach
balances the need to have operational flexibility when the grid may be
strained to help ensure that all available generating sources are
available for grid reliability, while balancing with important
considerations about potential GHG emission tradeoffs. The EPA is also
amending the definition in 40 CFR part 60, subpart TTTT, to be
[[Page 39915]]
consistent with the definition in 40 CFR part 60, subpart TTTTa.
Commenters also added that operation during system emergencies
should be subject to alternate standards of performance (e.g., owners/
operators are not required to use the CCS system during system
emergencies to increase power output). The EPA agrees with commenters
that since system emergencies are defined and historically rare events,
an alternate standard of performance should apply during these periods.
Carbon capture systems require significant amounts of energy to
operate. Allowing owners/operators of EGUs equipped with CCS systems to
temporarily reduce the capture rate or cease capture will increase the
electricity available to end users during system emergencies. In place
of the applicable output-based emissions standard, the owner/operator
of an intermediate or base load combustion turbine would be subject to
a BSER based on the combustion of lower-emitting fuels during system
emergencies.\733\ The emissions and output would not be included when
calculating the 12-operating month emissions rate. The EPA considered
an alternate emissions standard based on efficient generation but
rejected that for multiple reasons. First, since system emergencies are
limited in nature the emissions calculation would include a limited
number of hours and would not necessarily be representative of an
achievable longer-term emissions rate. In addition, EGUs that are
designed to operate with CCS will not necessarily operate as
efficiently without the CCS system operating compared to a similar EGU
without a CCS system. Therefore, the Agency is not able to determine a
reasonable efficiency-based alternate emissions standard for periods of
system emergencies. Due to both the costs and time associated with
starting and stopping the CCS system, the Agency has determined it is
unlikely that an owner/operator of an affected facility would use it
where it is not needed. System emergencies have historically been
relatively brief and any hours of operation outside of the system
emergencies are included when determining the output-based emissions
standard. During short-duration system emergencies, the costs
associated with stopping and starting the CCS system could outweigh the
increased revenue from the additional electric sales. In addition, the
time associated with starting and stopping a CCS system would likely
result in an EGU operating without the CCS system in operation during
periods of non-system emergencies. This would require the owner/
operator to overcontrol during other periods of operation to maintain
emissions below the applicable standard of performance. Therefore, it
is likely an owner/operator would unnecessarily adjust the operation of
the CCS system during EEA levels 2 and 3.
---------------------------------------------------------------------------
\733\ For owners/operators of combustion turbines the lower
emitting fuels requirement is defined to include fuels with an
emissions rate of 160 lb CO2/MMBtu or less. For owners/
operators of steam generating units or IGCC facilities the EPA is
requiring the use of the maximum amount of non-coal fuels available
to the affected facility.
---------------------------------------------------------------------------
In addition to these measures, DOE has authority pursuant to
section 202(c) of the Federal Power Act to, on its own motion or by
request, order, among other things, the temporary generation of
electricity from particular sources in certain emergency conditions,
including during events that would result in a shortage of electric
energy, when the Secretary of Energy determines that doing so will meet
the emergency and serve the public interest. An affected source
operating pursuant to such an order is deemed not to be operating in
violation of its environmental requirements. Such orders may be issued
for 90 days and may be extended in 90-day increments after consultation
with the EPA. DOE has historically issued section 202(c) orders at the
request of electric generators and grid operators such as RTOs in order
to enable the supply of additional generation in times of expected
emergency-related generation shortfalls.
c. Multi-Fuel-Fired Combustion Turbines
In 40 CFR part 60, subpart TTTT, multi-fuel-fired combustion
turbines are subcategorized as EGUs that combust 10 percent or more of
fuels not meeting the definition of natural gas on a 12-operating month
rolling average basis. The BSER for this subcategory is the use of
lower-emitting fuels with a corresponding heat input-based standard of
performance of 120 to 160 lb CO2/MMBtu, depending on the
fuel, for newly constructed and reconstructed multi-fuel-fired
stationary combustion turbines.\734\ Lower-emitting fuels for these
units include natural gas, ethylene, propane, naphtha, jet fuel
kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The
definition of natural gas in 40 CFR part 60, subpart TTTT, includes
fuel that maintains a gaseous state at ISO conditions, is composed of
70 percent by volume or more methane, and has a heating value of
between 35 and 41 megajoules (MJ) per dry standard cubic meter (dscm)
(950 and 1,100 Btu per dry standard cubic foot). Natural gas typically
contains 95 percent methane and has a heating value of 1,050 Btu/
lb.\735\ A potential issue with the multi-fuel subcategory is that
owners/operators of simple cycle turbines can elect to burn 10 percent
non-natural gas fuels, such as Nos. 1 or 2 fuel oil, and thereby remain
in that subcategory, regardless of their electric sales. As a result,
they would remain subject to the less stringent standard that applies
to multi-fuel-fired sources, the lower-emitting fuels standard. This
could allow less efficient combustion turbine designs to operate as
base load units without having to improve efficiency and could allow
EGUs to avoid the need for efficient design or best operating and
maintenance practices. These potential circumventions would result in
higher GHG emissions.
---------------------------------------------------------------------------
\734\ Combustion turbines co-firing natural gas with other fuels
must determine fuel-based site-specific standards at the end of each
operating month. The site-specific standards depend on the amount of
co-fired natural gas. 80 FR 64616 (October 23, 2015).
\735\ Note that according to 40 CFR part 60, subpart TTTT,
combustion turbines co-firing 25 percent hydrogen by volume could be
subcategorized as multi-fuel-fired EGUs because the percent methane
by volume could fall below 70 percent, the heating value could fall
below 35 MJ/Sm\3\, and 10 percent of the heat input could be coming
from a fuel not meeting the definition of natural gas.
---------------------------------------------------------------------------
To avoid these outcomes, the EPA proposed and is finalizing a
decision not to include the multi-fuel subcategory for low,
intermediate, and base load combustion turbines in 40 CFR part 60,
subpart TTTTa. This means that new multi-fuel-fired turbines that
commence construction or reconstruction after May 23, 2023, will fall
within a particular subcategory depending on their level of electric
sales. The EPA also proposed and is finalizing a decision that the
performance standards for each subcategory be adjusted appropriately
for multi-fuel-fired turbines to reflect the application of the BSER
for the subcategories to turbines burning fuels with higher GHG
emission rates than natural gas. To be consistent with the definition
of lower-emitting fuels in the 2015 NSPS, the maximum allowable heat
input-based emissions rate is 160 lb CO2/MMBtu. For example,
a standard of performance based on efficient generation would be 33
percent higher for a fuel oil-fired combustion turbine compared to a
natural gas-fired combustion turbine. This assures that the BSER, in
this case efficient generation, is applied, while at the same time
accounting for the use of multiple fuels.
[[Page 39916]]
d. Rural Areas and Small Utility Distribution Systems
As part of the original proposal and during the Small Business
Advocacy Review (SBAR) outreach the EPA solicited comment on creating a
subcategory for rural electric cooperatives and small utility
distribution systems (serving 50,000 customers or less). Commenters
expressed concerns that a BSER based on either co-firing hydrogen or
CCS may present an additional hardship on economically disadvantaged
communities and on small entities, and that the EPA should evaluate
potential increased energy costs, transmission upgrade costs, and
infrastructure encroachment which may directly affect the
disproportionately impacted communities. As described in section
VIII.F, the BSER for new stationary combustion turbines does not
include hydrogen co-firing and CCS qualifies as the BSER for base load
combustion turbines on a nationwide basis. Therefore, the EPA has
determined that a subcategory for rural cooperatives and/or small
utility distribution systems is not appropriate.
F. Determination of the Best System of Emission Reduction (BSER) for
New and Reconstructed Stationary Combustion Turbines
In this section, the EPA describes the technologies it proposed as
the BSER for each of the subcategories of new and reconstructed
combustion turbines that commence construction after May 23, 2023, as
well as topics for which the Agency solicited comment. In the following
section, the EPA describes the technologies it is determining are the
final BSER for each of the three subcategories of affected combustion
turbines and explains its basis for selecting those controls, and not
others, as the final BSER. The controls that the EPA evaluated included
combusting non-hydrogen lower-emitting fuels (e.g., natural gas and
distillate oil), using highly efficient generation, using CCS, and co-
firing with low-GHG hydrogen.
For the low load subcategory, the EPA proposed the use of lower-
emitting fuels as the BSER. This was consistent with the BSER and
performance standards established in the 2015 NSPS for the non-base
load subcategory as discussed earlier in section VIII.C.
For the intermediate load subcategory, the EPA proposed an approach
under which the BSER was made up of two components: (1) highly
efficient generation; and (2) co-firing 30 percent (by volume) low-GHG
hydrogen. Each component of the BSER represented a different set of
controls, and those controls formed the basis of corresponding
standards of performance that applied in two phases. Specifically, the
EPA proposed that affected facilities (i.e., facilities that commence
construction or reconstruction after May 23, 2023) could apply the
first component of the BSER (i.e., highly efficient generation) upon
initial startup to meet the first phase of the standard of performance.
Then, by 2032, the EPA proposed that affected facilities could apply
the second component of the BSER (i.e., co-firing 30 percent (by
volume) low-GHG hydrogen) to meet a second and more stringent standard
of performance. The EPA also solicited comment on whether the
intermediate load subcategory should apply a third component of the
BSER: co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In
addition, the EPA solicited comment on whether the low load subcategory
should also apply the second component of BSER, co-firing 30 percent
(by volume) low-GHG hydrogen, by 2032. The Agency proposed that these
latter components of the BSER would continue to include the application
of highly efficient generation.
For the base load subcategory, the EPA also proposed a multi-
component BSER and multi-phase standard of performance. The EPA
proposed that each new base load combustion turbine would be required
to meet a phase-1 standard of performance based on the application of
the first component of the BSER--highly efficient generation--upon
initial startup of the affected source. For the second component of the
BSER, the EPA proposed two potential technology pathways for base load
combustion turbines with corresponding standards of performance. One
proposed technology pathway was 90 percent CCS, which base load
combustion turbines would install and begin to operate by 2035 to meet
the phase-2 standard of performance. A second proposed technology
pathway was co-firing low-GHG hydrogen, which base load combustion
turbines would implement in two steps: (1) By co-firing 30 percent (by
volume) low-GHG hydrogen to meet the phase-2 standard of performance by
2032, and (2) by co-firing 96 percent (by volume) low-GHG hydrogen to
meet a phase 3 standard of performance by 2038. Throughout, the Agency
proposed base load turbines, like intermediate load turbines, would
remain subject to the first component of the BSER based on highly
efficient generation.
The proposed approach reflected the EPA's view that the BSER
components for the intermediate load and base load subcategories could
achieve deeper reductions in GHG emissions by implementing CCS and co-
firing low-GHG hydrogen. This proposed approach also recognized that
building the infrastructure required to support widespread use of CCS
and low-GHG hydrogen technologies in the power sector will take place
on a multi-year time scale. Accordingly, new and reconstructed
facilities would be aware of their need to ramp toward more stringent
phases of the standards, which would reflect application of the more
stringent controls in the BSER. This would occur either by co-firing a
lower percentage (by volume) of low-GHG hydrogen by 2032 and a higher
percentage (by volume) of low-GHG hydrogen by 2038, or with
installation and use of CCS by 2035. The EPA also solicited comment on
the potential for an earlier compliance date for the second phase.
For the base load subcategory, the EPA proposed two potential BSER
pathways because the Agency believed there was more than one viable
technology for these combustion turbines to significantly reduce their
CO2 emissions. The Agency also found value in receiving
comments on, and potentially finalizing, both BSER pathways to enable
project developers to elect how they would reduce their CO2
emissions on timeframes that make sense for each BSER pathway.\736\ The
EPA solicited comment on whether the co-firing of low-GHG hydrogen
should be considered a compliance pathway for sources to meet a single
standard of performance based on the application of CCS rather than a
separate BSER pathway. The EPA proposed that there would be earlier
opportunities for units to begin co-firing lower amounts of low-GHG
hydrogen than to install and begin operating 90 percent CCS systems.
However, the Agency proposed that it would likely take longer for those
units to increase their co-firing to significant quantities of low-GHG
hydrogen. Therefore, in the proposal, the EPA presented the BSER
pathways as separate subcategories and solicited comment on the option
of finalizing a single standard of performance based on the application
of CCS.
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\736\ The EPA recognizes that standards of performance are
technology neutral and that a standard based on application of CCS
could be achieved by co-firing hydrogen.
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For the low load subcategory, the EPA proposed and is finalizing
that the BSER is the use of lower-emitting fuels. For the intermediate
load subcategory, the EPA proposed and is finalizing that the
[[Page 39917]]
BSER is highly efficient generating technology--simple cycle technology
as well as operating and maintaining it efficiently.\737\ The EPA is
not finalizing a second component of the BSER or a phase-2 standard of
performance for intermediate load combustion turbines at this time. For
the base load subcategory, the EPA proposed and is finalizing that the
first component of the BSER is highly efficient generating technology--
combined cycle technology as well as operating and maintaining it
efficiently. The EPA proposed and is finalizing a second component of
the BSER or a phase-2 standard of performance for base load combustion
turbines--efficient generation in combination with 90 percent CCS.
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\737\ The EPA sometimes refers to highly efficient generating
technology in combination with the best operating and maintenance
practices as highly efficient generation. The affected sources must
meet standards based on this efficient generating technology upon
the effective date of the final rule.
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The EPA is not finalizing low-GHG hydrogen co-firing as the second
component of the BSER for the intermediate load or base load combustion
turbines at this time. (See section VIII.F.5.b for the EPA's
explanation of this decision.) With respect to the CCS pathway for base
load combustion turbines, the EPA is finalizing a second phase of the
standards of performance that includes a single CCS BSER pathway, which
includes the use of highly efficient generation and 90 percent CCS.
Owners/operators of new and reconstructed base load combustion turbines
will be required to meet the second phase standards of performance for
12-operating month rolling averages that begin on or after January
2032, that reflect application of both the phase-1 and phase-2
components of the BSER. Table 3 of this document summarizes the final
BSER for combustion turbine EGUs that commence construction or
reconstruction after May 23, 2023. The EPA is finalizing standards of
performance based on those BSER for each subcategory, as discussed in
section VIII.G.
Table 3--Final BSER for Combustion Turbine EGUs
----------------------------------------------------------------------------------------------------------------
Subcategory \1\ Fuel 1st Component BSER 2nd Component BSER
----------------------------------------------------------------------------------------------------------------
Low Load........................... All Fuels.................. lower-emitting fuels.. N/A.
Intermediate Load.................. All Fuels.................. Highly Efficient N/A.
Simple Cycle
Generation.
Base Load.......................... All Fuels.................. Highly Efficient Highly Efficient
Combined Cycle Combined Cycle
Generation. Generation Plus 90
Percent CCS Beginning
in 2032.
----------------------------------------------------------------------------------------------------------------
\1\ The low load subcategory is applicable to combustion turbines selling 20 percent or less of their potential
electric output, the intermediate load subcategory is applicable to combustion turbines selling greater than
20 percent and less than or equal to 40 percent of their potential electric output, and the base load
subcategory is applicable to combustion turbines selling greater than 40 percent of their potential electric
output.
1. BSER for Low Load Subcategory
This section describes the BSER for the low load (i.e., peaking)
subcategory at this time, which is the use of lower-emitting fuels. The
Agency proposed and is finalizing a determination that the use of
lower-emitting fuels, which the EPA determined to be the BSER for the
non-base load subcategory in the 2015 NSPS, is the BSER for this low
load subcategory. As explained in section VIII.E.2.b, the EPA is
narrowing the definition of the low load subcategory by lowering the
electric sales threshold (as compared to the electric sales threshold
for non-base load combustion turbines in the 2015 NSPS), so that
combustion turbines with higher electric sales would be placed in the
intermediate load subcategory and therefore be subject to a more
stringent standard based on the more stringent BSER.
a. Background: The Non-Base Load Subcategory in the 2015 NSPS
The 2015 NSPS defined non-base load natural gas-fired EGUs as
stationary combustion turbines that (1) burn more than 90 percent
natural gas and (2) have net electric sales equal to or less than their
design efficiency (not to exceed 50 percent) multiplied by their
potential electric output (80 FR 64601; October 23, 2015). These are
calculated on 12-operating month and 3-calendar year rolling average
bases. The EPA also determined in the 2015 NSPS that the BSER for newly
constructed and reconstructed non-base load natural gas-fired
stationary combustion turbines is the use of lower-emitting fuels. Id.
at 64515. These lower-emitting fuels are primarily natural gas with a
small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils),
which have been widely used in stationary combustion turbine EGUs for
decades.
The EPA also determined in the 2015 NSPS that the standard of
performance for sources in this subcategory is a heat input-based
standard of 120 lb CO2/MMBtu. The EPA established this
clean-fuels BSER for this subcategory because of the variability in the
operation in non-base load combustion turbines and the challenges
involved in determining a uniform output-based standard that all new
and reconstructed non-base load units could achieve.
Specifically, in the 2015 NSPS, the EPA recognized that a BSER for
the non-base load subcategory based on the use of lower-emitting fuels
results in limited GHG reductions, but further recognized that an
output-based standard of performance could not reasonably be applied to
the subcategory. The EPA explained that a combustion turbine operating
at a low capacity factor could operate with multiple starts and stops,
and that its emission rate would be highly dependent on how it was
operated and not its design efficiency. Moreover, combustion turbines
with low annual capacity factors typically operated differently from
each other, and therefore had different emission rates. The EPA
recognized that, as a result, at the time it would not be possible to
determine a standard of performance that could reasonably apply to all
combustion turbines in the subcategory. For that reason, the EPA
further recognized, efficient design \738\ and operation would not
qualify as the BSER; rather, the BSER should be lower-emitting fuels
and the associated standard of performance should be based on heat
input. Since the 2015 NSPS, all newly constructed simple cycle turbines
have been non-base load units and thus have become subject to this
standard of performance.
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\738\ Important characteristics for minimizing emissions from
low load combustion turbines include the ability to operate
efficiently while operating at part load conditions and the ability
to rapidly achieve maximum efficiency to minimize periods of
operation at lower efficiencies. These characteristics do not
necessarily always align with higher design efficiencies that are
determined under steady-state full-load conditions.
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[[Page 39918]]
b. BSER
Consistent with the rationale of the 2015 NSPS, the EPA proposed
and is finalizing that the use of fuels with an emissions rate of less
than 160 lb CO2/MMBtu (i.e., lower-emitting fuels) meets the
BSER requirements for the low load subcategory at this time. Use of
these fuels is technically feasible for combustion turbines. Natural
gas comprises the majority of the heat input for simple cycle turbines
and is the lowest cost fossil fuel. In the 2015 NSPS, the EPA
determined that natural gas comprised 96 percent of the heat input for
simple cycle turbines. See 80 FR 64616 (October 23, 2015). Therefore, a
BSER based on the use of natural gas and/or distillate oil would have
minimal, if any, costs to regulated entities. The use of lower-emitting
fuels would not have any significant adverse energy requirements or
non-air quality or environmental impacts, as the EPA determined in the
2015 NSPS. Id. at 64616. In addition, the use of fuels meeting this
criterion would result in some emission reductions by limiting the use
of fuels with higher carbon content, such as residual oil, as the EPA
also explained in the 2015 NSPS. Id. Although the use of fuels meeting
this criterion would not advance technology, in light of the other
reasons described here, the EPA proposed and is finalizing that the use
of natural gas, Nos. 1 and 2 fuel oils, and other fuels \739\ currently
specified in 40 CFR part 60, subpart TTTT, qualify as the BSER for new
and reconstructed combustion turbine EGUs in the low load subcategory
at this time. The EPA also proposed including low-GHG hydrogen on the
list of fuels meeting the uniform fuels criteria in 40 CFR part 60,
subpart TTTTa. The EPA is finalizing the inclusion of hydrogen,
regardless of the production pathway, on the list of fuels meeting the
uniform fuels criteria in 40 CFR part 60, subpart TTTTa.\740\ The
addition of hydrogen (and fuels derived from hydrogen) to 40 CFR part
60, subpart TTTTa, simplifies the recordkeeping and reporting
requirements for low load combustion turbines that elect to burn
hydrogen.
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\739\ The BSER for multi-fuel-fired combustion turbines subject
to 40 CFR part 60, subpart TTTT, is also the use of fuels with an
emissions rate of 160 lb CO2/MMBtu or less. The use of
these fuels will demonstrate compliance with the low load
subcategory.
\740\ The EPA is not finalizing a definition of low-GHG
hydrogen.
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For the reasons discussed in the 2015 NSPS and noted above, the EPA
did not propose that efficient design and operation qualify as the BSER
for the low load subcategory. The emissions rate of a low load
combustion turbine is highly dependent upon the way the specific
combustion turbine is operated. For example, a combustion turbine with
multiple startups and shutdowns and operation at part loads will have
high emissions relative to if it were operated at steady-state high-
load conditions. Important characteristics for reducing GHG emissions
from low load combustion turbines are the ability to minimize emissions
during periods of startup and shutdown and efficient operation at part
loads and while changing loads. If the combustion turbine is frequently
operated at part-load conditions with frequent starts and stops, a
combustion turbine with a high design efficiency, which is determined
at full-load steady-state conditions, would not necessarily emit at a
lower GHG rate than a combustion turbine with a lower design
efficiency. In addition, combustion turbines with higher design
efficiencies have higher initial costs compared to combustion turbines
with lower design efficiencies. Since the EPA does not have sufficient
information at this time to determine emission reduction for the
subcategory it is not possible to determine the cost effectiveness of a
BSER based on high efficiency simple cycle turbines.\741\
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\741\ The cost effectiveness calculation is highly dependent
upon assumptions concerning the increase in capital costs, the
decrease in heat rate, and the price of natural gas.
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The EPA solicited comment on whether, and the extent to which,
high-efficiency designs also operate more efficiently at part loads and
can start more quickly and reach the desired load more rapidly than
combustion turbines with less efficient design efficiencies. In
addition, the EPA solicited comment on the cost premium of high-
efficiency simple cycle turbines. To the extent the Agency received
additional relevant information, the EPA was considering promulgating
design standard requirements pursuant to CAA section 111(h). However,
the EPA did not receive comments that changed the proposal conclusions.
The EPA did not propose the use of CCS or hydrogen co-firing as the
BSER (or as a component of the BSER) for low load combustion turbines.
The EPA did not propose that CCS is the BSER for simple cycle turbines
based on the Agency's assessment that currently available post-
combustion amine-based carbon capture systems require that the exhaust
from a combustion turbine be cooled prior to entering the carbon
capture equipment. The most energy efficient way to cool the exhaust
gas is to use a HRSG, which is an integral component of a combined
cycle turbine system but is not incorporated in a simple cycle unit.
For this reason and due to the high costs of CCS for low load
combustion turbines, the Agency did not propose and is not finalizing a
determination that CCS qualifies as the BSER for this subcategory of
sources.
The EPA did not propose low-GHG hydrogen co-firing as the BSER for
low load combustion turbines because not all new combustion turbines
can necessarily co-fire higher percentages of hydrogen, there are
potential infrastructure issues specific to low load combustion
turbines, and at the relatively infrequent levels of utilization that
characterize the low load subcategory, a low-GHG hydrogen co-firing
BSER would not necessarily result in cost-effective GHG reductions for
all low load combustion turbines. As discussed later in this section,
the Agency is not determining that low-GHG hydrogen co-firing qualifies
as the BSER for combustion turbines. In future rulemaking the Agency
could further evaluate the costs and emissions performance of other
technologies to reduce emissions from low-load units to determine if
other technologies qualify as the BSER.
2. BSER for Intermediate Load Subcategory
This section describes the BSER for new and reconstructed
combustion turbines in the intermediate load subcategory. For
combustion turbines in the intermediate load subcategory, the BSER is
the use of high-efficiency simple cycle turbine technology in
combination with the best operating and maintenance practices.
a. Lower-Emitting Fuels
The EPA did not propose and is not finalizing lower-emitting fuels
as the BSER for intermediate load combustion turbines because, as
described earlier in this section, it would achieve few GHG emission
reductions compared to highly efficient generation.
b. Highly Efficient Generation
This section includes a discussion of the various highly efficient
generation technologies used by owners/operators of combustion
turbines. The appropriate technology depends on how the combustion
turbine is operated, and the EPA has determined it does not have
sufficient information to determine an appropriate output-based
emissions standard for low load combustion turbines. At higher capacity
factors, emission rates for simple cycle combustion turbines are more
consistent, and the EPA has sufficient
[[Page 39919]]
information to determine a BSER other than lower-emitting fuels.
The use of highly efficient generating technology in combination
with the best operating and maintenance practices has been demonstrated
by multiple facilities for decades. Notably, over time, as technologies
have improved, what is considered highly efficient has changed as well.
Highly efficient generating technology is available and offered by
multiple vendors for both simple cycle and combined cycle turbines.
Both types of combustion turbines can also employ best operating and
maintenance practices, which include routine operating and maintenance
practices that minimize fuel use.
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. These improved designs allow for improved operating
efficiencies and reduced emission rates. Design efficiencies of simple
cycle turbines range from 33 to 40 percent. 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, high-efficiency technology uses a
highly efficient combustion turbine engine matched with a high-
efficiency HRSG. The most efficient combined cycle EGUs use HRSG with
three different steam pressures and incorporate a steam reheat cycle to
maximize the efficiency of the Rankine cycle. It is not necessarily
practical for owners/operators of combined cycle facilities using a
turbine engine with an exhaust temperature below 593 [deg]C or a steam
turbine engine smaller than 60 MW to incorporate a steam reheat cycle.
Smaller combustion turbine engines, less than those rated at
approximately 2,000 MMBtu/h, tend to have lower exhaust temperatures
and are paired with steam turbines of 60 MW or less. These smaller
combined cycle units are limited to using a HRSG with three different
steam pressures, but without a reheat cycle. This increases the heat
rate of the combined cycle unit by approximately 2 percent. High
efficiency also includes, but is not limited to, the use of the most
efficient steam turbine and minimizing energy losses using insulation
and blowdown heat recovery. Best operating and maintenance practices
include, but are not limited to, minimizing steam leaks, minimizing air
infiltration, and cleaning and maintaining heat transfer surfaces.
A potential drawback of combined cycle turbines with the highest
design efficiencies is that the facility is relatively complicated and
startup times can be relatively long. Combustion turbine manufacturers
have invested in fast-start technologies that reduce startup times and
improve overall efficiencies. According to the NETL Baseline Flexible
Operation Report, while the design efficiencies are the same, the
capital costs of fast-start combined cycle turbines are 1.6 percent
higher than a comparable conventional start combined cycle
facility.\742\ The additional costs include design parameters that
significantly reduce start times. However, fast-start combined cycle
turbines are still significantly less flexible than simple cycle
turbines and generally do not serve the same role. The startup time to
full load from a hot start takes a simple cycle turbine 5 to 8 minutes,
while a combined cycle turbines ranges from 30 minutes for a fast-start
combined cycle turbine to 90 minutes for a conventional start combined
cycle turbine. The startup time to full load from a cold start takes a
simple cycle turbine 10 minutes, while a combined cycle turbines ranges
from 120 minutes for a fast-start combined cycle turbine to 250 minutes
for a conventional start combined cycle turbine. In addition, fast-
start combined cycle turbines require the use of an auxiliary boiler
during warm and cold starts.\743\ In addition, minimum run times for
simple cycle aeroderivative engines and combined cycle EGUs equal one
minute and 120 minutes, respectively. Minimum downtime for the same
group is five minutes and 60 minutes, respectively. Finally, simple
cycle aeroderivative turbines have no limit to the number of starts per
year. Combined cycle EGUs are limited in the number of starts, and
additional maintenance costs will occur if the hours/start ratio drops
below 25. The model combined cycle turbines in the NETL Baseline
Flexible Operation Report use a HRSG with three different steam
pressures and a reheat cycle. While the use of this type of HRSG
increases design efficiencies at steady state conditions, it increases
the capital costs and decreases the flexibility (e.g., longer start
times) of the combined cycle turbine. While less common, combined cycle
turbines can be designed with a relatively simple HRSG that produces
either a single or two pressures of steam without a reheat cycle. While
design efficiencies are lower, the combined cycle turbines are more
flexible and have the potential to operate similar to at least a
portion of the simple cycle turbines in the intermediate load
subcategory and provide the same value to the grid.
---------------------------------------------------------------------------
\742\ ``Cost and Performance Baseline for Fossil Energy Plants,
Volume 5: Natural Gas Electricity Generating Units for Flexible
Operation.'' DOE/NETL-2023/3855. May 5, 2023.
\743\ Fast start combined cycle turbine do not use an auxiliary
boiler during hot starts and conventional start combined cycle
turbine do not have auxiliary boilers.
---------------------------------------------------------------------------
The EPA solicited comment on whether additional technologies for
new simple and combined cycle EGUs that could reduce emissions beyond
what is currently being achieved by the best performing EGUs should be
included in the BSER. Specifically, the EPA sought comment on whether
pressure gain combustion should be incorporated into a standard of
performance based on an efficient generation BSER for both simple and
combined cycle turbines. In addition, the EPA sought comment on whether
the HRSG for combined cycle turbines should be designed to utilize
supercritical steam conditions or to utilize supercritical
CO2 as the working fluid instead of water; whether useful
thermal output could be recovered from a compressor intercooler and
boiler blowdown; and whether fuel preheating should be implemented.
Commenters generally noted that these technologies are promising, but
that because the EPA did not sufficiently evaluate the BSER criteria in
the proposal and none of these technologies should be incorporated as
part of the BSER. The EPA continues to believe these technologies are
promising, but the Agency is not including them as part of the BSER at
this time.
The EPA also solicited comment on whether the use of steam
injection is applicable to intermediate load combustion turbines. Steam
injection is the use of a relatively simple and low-cost HRSG to
produce steam, but instead of recovering the energy by expanding the
steam through a steam turbine, the steam is injected into the
compressor and/or through the fuel nozzles directly into the combustion
chamber and the energy is extracted by the combustion turbine
engine.\744\ Advantages of steam injection include improved efficiency
and increased output of the combustion turbine as well as reduced
NOX emissions. Combustion turbines using steam
[[Page 39920]]
injection have characteristics in-between simple cycle and combined
cycle combustion turbines. They are more efficient, but more complex
and have higher capital costs than simple cycle combustion turbines
without steam injection. Conversely, compared to combined cycle EGUs,
simple cycle combustion turbines using steam injection are simpler,
have shorter construction times, and have lower capital costs, but have
lower efficiencies.745 746 Combustion turbines using steam
injection can start quickly, have good part-load performance, and can
respond to rapid changes in demand, making the technology a potential
solution for reducing GHG emissions from intermediate load combustion
turbines. A potential drawback of steam injection is that the
additional pressure drop across the HRSG can reduce the efficiency of
the combustion turbine when the facility is running without the steam
injection operating.
---------------------------------------------------------------------------
\744\ A steam injected combustion turbine would be considered a
combined cycle combustion turbine (for NSPS purposes) because energy
from the turbine engine exhaust is recovered in a HRSG and that
energy is used to generate additional electricity.
\745\ Bahrami, S., et al. (2015). Performance Comparison between
Steam Injected Gas Turbine and Combined Cycle during Frequency
Drops. Energies 2015, Volume 8. https://doi.org/10.3390/en8087582.
\746\ Mitsubishi Power. Smart-AHAT (Advanced Humid Air Turbine).
https://power.mhi.com/products/gasturbines/technology/smart-ahat.
---------------------------------------------------------------------------
The EPA is aware of a limited number of combustion turbines that
are using steam injection that have maintained 12-operating month
emission rates of less than 1,000 lb CO2/MWh-gross.
Commenters stated that steam injection does not qualify as the BSER
because it has not been adequately demonstrated and the EPA did not
include sufficient analysis of the technology in the proposal to
determine it as the BSER for intermediate load combustion turbines. The
EPA continues to believe the technology is promising and it may be used
to comply with the standard of performance, but the Agency is not
determining that it is the BSER for intermediate load combustion
turbines at this time. In a potential future rulemaking, the Agency
could further evaluate the costs and emissions performance of steam
injection to determine if the technology qualifies as the BSER.
i. Adequately Demonstrated
The EPA proposed and is finalizing that highly efficient simple
cycle designs are adequately demonstrated because highly efficient
simple cycle turbines have been demonstrated by multiple facilities for
decades, the efficiency improvements of the most efficient designs are
incremental in nature and do not change in any significant way how the
combustion turbine is operated or maintained, and the levels of
efficiency that the EPA is proposing have been achieved by many
recently constructed combustion turbines. Therefore, efficient
generation technology described in this BSER is commercially available
and the standards of performance are achievable.
ii. Costs
In general, advanced generation technologies enhance operational
efficiency compared to lower efficiency designs. Such technologies
present little incremental capital cost compared to other types of
technologies that may be considered for new and reconstructed sources.
In addition, more efficient designs have lower fuel costs, which
offsets at least a portion of the increase in capital costs.
For the intermediate load subcategory, the EPA considers that the
costs of high-efficiency simple cycle combustion turbines are
reasonable. As described in the subcategory section, the cost of
combustion turbine engines is dependent upon many factors, but the EPA
estimates that that the capital cost of a high-efficiency simple cycle
turbine is 10 percent more than a comparable lower efficiency simple
cycle turbine. Assuming all other costs are the same and that the high-
efficiency simple cycle turbine uses 8 percent less fuel, high-
efficiency simple cycle combustion turbines have a lower LCOE compared
to standard efficiency simple cycle combustion turbines at a 12-
operating month capacity factor of approximately 31 percent. At a 20
percent and 15 percent capacity factors, the compliance costs are $1.5/
MWh and $35/metric ton and $3.0/MWh and $69/metric ton, respectively.
The EPA has determined that the incremental costs the use of high
efficiency simple cycle turbines as the BSER for intermediate load
combustion turbines is reasonable. The EPA notes that the approach the
Agency used to estimate these costs have a relatively high degree of
uncertainty and are likely high given the common use of high efficiency
simple cycle turbines without a regulatory driver.
The EPA considered but is not finalizing combined cycle unit design
for combustion turbines as the BSER for the intermediate load
subcategory because it is unclear if combined cycle turbines could
serve the same role as intermediate load simple cycle turbines as a
whole. Specifically, the EPA does not have sufficient information to
determine that an intermediate load combined cycle turbine can start
and stop with enough flexibility to provide the same level of grid
support as intermediate load simple cycle turbines as a whole. In
addition, the amount of GHG reductions that could be achieved by
operating combined cycle EGUs as intermediate load EGUs is unclear.
Intermediate load combustion turbines start and stop so frequently that
there would often not be sufficient periods of continuous operation
where the HRSG would have sufficient time to generate steam to operate
the steam turbine enough to significantly lower the emissions rate of
the EGU.
Some commenters agreed with the proposed rationale of the EPA, and
other commenters disagreed and said that combined cycle turbine
technology is cost effective and lower-emitting than simple cycle
turbine technology and therefore qualifies as the BSER for intermediate
load combustion turbines. Commenters supporting combined cycle
technology as the BSER submitted cost information that indicated that
combined cycle EGUs have lower capital costs and LCOE than simple cycle
turbines. However, the commenters compared capital costs of larger
combined cycle turbines to smaller simple cycle turbines and did not
account for economies of scale. The EPA has concluded that the
appropriate cost comparison is for combustion turbines with the same
rated net output.\747\ Comparing the costs of different size EGUs is
not appropriate because these EGUs provide different grid services. In
addition, the commenters did not account for startup costs and the time
required for a steam turbine to begin operating when determining the
LCOE.
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\747\ The costing approach used by the EPA compares a combined
cycle turbine using a smaller turbine engine plus a steam turbine to
match the output from a simple cycle turbine.
---------------------------------------------------------------------------
The EPA considered the operation of simple cycle turbine to
determine the potential for simple cycle turbine to add a HRSG while
continuing to operate in the same manner, providing the same grid
services, as current simple cycle turbines. As noted previously,
aeroderivative simple cycle turbines have shorter run times per start
than frame type simple cycle turbines at the same capacity factor. At
an annual capacity factor of 20 percent, the median run time per start
for aeroderivative and frame simple cycle turbines is 12 and 16 hours
respectively. At an annual capacity factor of 30 percent, the average
run times per start increase to 17 and 26 hours for aeroderivative and
frame turbines respectively. The higher operating times of frame type
simple cycle turbines,
[[Page 39921]]
along with the larger size of frame type turbines, indicate that
combined cycle technology could be applicable to at least a portion of
intermediate load combustion turbines. In future rulemakings addressing
GHGs from new as well as existing combustion turbines, the EPA intends
to further evaluate the costs and potential emission reductions of the
use of faster starting and lower cost HRSG technology for intermediate
load combustion turbines to determine if the technology does in fact
qualify as the BSER.
iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Use of highly efficient generation reduces all non-air quality
health and environmental impacts and energy requirements assuming it
displaces less efficient or higher-emitting generation. Even when
operating at the same input-based emissions rate, the more efficient a
unit is, the less fuel is required to produce the same level of output;
and, as a result, emissions are reduced for all pollutants. The use of
highly efficient combustion turbines, compared to the use of less
efficient combustion turbines, reduces all pollutants.\748\ By the same
token, because improved efficiency allows for more electricity
generation from the same amount of fuel, it will not have any adverse
effects on energy requirements.
---------------------------------------------------------------------------
\748\ The emission reduction comparison is done assuming the
same level of operation. Overall emission impacts would be different
if the more efficient combustion turbine operates more then the
baseline.
---------------------------------------------------------------------------
Designating highly efficient generation as part of the BSER for new
and reconstructed intermediate load combustion turbines will not have
significant impacts on the nationwide supply of electricity,
electricity prices, or the structure of the electric power sector. On a
nationwide basis, the additional costs of the use of highly efficient
generation will be small because the technology does not add
significant costs and at least some of those costs are offset by
reduced fuel costs. In addition, at least some of these new combustion
turbines would be expected to incorporate highly efficient generation
technology in any event.
iv. Extent of Reductions in CO2 Emissions
The EPA estimated the potential emission reductions associated with
a standard that reflects the application of highly efficient generation
as BSER for the intermediate load subcategory. As discussed in section
VIII.G.1, the EPA determined that the standards of performance
reflecting this BSER are 1,170 lb CO2/MWh-gross for
intermediate load combustion turbines.
Between 2015 and 2022, 113 simple cycle turbines, an average of 16
per year, commenced operation. Of these, 112 reported 12-operating
month capacity factors. The EPA estimates that 23 simple cycle turbines
operated at 12-operating month capacity factors greater than 20 percent
and potentially would be considered intermediate combustion turbines.
To estimate reductions, the EPA assumed that the number of simple cycle
turbines constructed between 2015 and 2022 and the operation of those
combustion turbines would continue on an annual basis.\749\ For each
simple cycle turbine that operated at a capacity greater than 20
percent, the EPA determined the percent reduction in emissions, based
on the maximum 12-operating months intermediate load emission rate,
that would be required to comply with the final NSPS for intermediate
load turbines. The EPA then applied that same percent reduction in
emissions to the average operating capacity factor to determine the
emission reductions from the NSPS. Using this approach, the EPA
estimates that the intermediate load standard will impact approximately
a quarter of new simple cycle turbines. The EPA divided the total
amount of calculated reductions for intermediate load simple cycle
turbines built between 2015 and 2022 and divided that value by 7 (the
number of years evaluated) to get estimated annual reductions. This
approach results in annual reductions of 31,000 tons of CO2
as well as 8 tons of NOX. The emission reductions are
projected to result primarily from building additional higher
efficiency aeroderivative simple cycle turbines instead of less
efficient frame simple cycle turbines. The reduced emissions come from
relatively small reductions in the emission rates of the intermediate
load aeroderivative simple cycle turbines. This is a snapshot of
projected emission reductions from applying the NSPS retroactively to
2022. If more intermediate load simple cycle turbines are built in the
future, the emission reductions would be higher than this estimate.
Conversely, if fewer intermediate load simple cycles are built, the
emission reductions would be lower than the EPA's estimate.
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\749\ This is a simplified assumption that does not take into
account changing market conditions that could change the makeup and
operation of new combustion turbines.
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Importantly, the ``highly efficient generation'' which the EPA has
determined to be the BSER for new and reconstructed intermediate load
combustion turbines and to be the first component BSER for base load
stationary combustions, is not the same as the ``heat rate
improvements'' (HRI, or ``efficiency improvements'') that the EPA
determined to be the BSER for existing coal-fired steam generating EGUs
in the ACE Rule. As noted earlier in this document, the EPA has
concluded that the suite of HRI in the ACE Rule is not an appropriate
BSER for existing coal-fired EGUs. In the EPA's technical judgment, the
suite of HRI set forth in the ACE Rule would provide negligible
CO2 reductions at best and, in many cases, may increase
CO2 emissions because of the ``rebound effect,'' which is
explained and discussed in section VII.D.4.a.iii of this preamble.
Increased CO2 emissions from the ``rebound effect'' can
occur when a coal-fired EGU improves its efficiency (heat rate), which
can move the unit up on the dispatch order--resulting in an EGU
operating for more hours during the year than it would have without
having done the efficiency improvements. There is also the possibility
that a more efficient coal-fired EGU could displace a lower emitting
generating source, further exacerbating the problem.
Conversely, including ``highly efficient generation'' as a
component of the BSER for new and reconstructed does not create this
risk of displacing a lower-emitting generating source. A new highly
efficient stationary combustion turbine may be dispatched more than it
would have been if it were not built as a highly efficient turbine, but
it is more likely to displace an existing coal-fired EGU or a less
efficient existing stationary combustion turbine. It would be unlikely
to displace a renewable generating source.
For base load stationary combustion turbines, ``highly efficient
generation'' is the first component of the BSER--with 90 percent
capture CCS being the second component of the BSER. This is very
similar to the Agency's BSER determination for the NSPS for new fossil
fuel-fired steam generating units. In that final rule, the EPA
established standards of performance for newly constructed fossil fuel-
fired steam generating units based on the performance of a new highly
efficient supercritical pulverized coal (SCPC) EGU implementing post-
combustion partial CCS technology, which the EPA determined to be the
BSER for these sources.\750\
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\750\ See 80 FR 64510 (October 23, 2015).
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[[Page 39922]]
v. Promotion of the Development and Implementation of Technology
The EPA also considered the potential impact of selecting highly
efficient simple cycle generation technology as the BSER for the
intermediate load subcategory in promoting the development and
implementation of improved control technology. New highly efficient
simple cycle turbines are more efficient than the average new simple
cycle turbine and a standard based on the performance of the most
efficient, best performing simple cycle turbine will promote
penetration of the most efficient units throughout the industry.
Accordingly, consideration of this factor supports the EPA's proposal
to determine this technology to be the BSER.
c. Low-GHG Hydrogen and CCS
The EPA did not propose and is not finalizing either CCS or co-
firing low-GHG hydrogen as the first component of the BSER for
intermediate load combustion turbines, for the reasons given in
sections VIII.F.4.c.iii (CCS) and VIII.F.5 (low-GHG hydrogen).
d. Summary of BSER Determinations
The EPA is finalizing that highly efficient generating technology
in combination with the best operating and maintenance practices is the
BSER for intermediate load combustion turbines. Specifically, the use
of highly efficient simple cycle technology in combination with the
best operating and maintenance practices is the BSER for intermediate
load combustion turbines.
Highly efficient generation qualifies the BSER because it is
adequately demonstrated, it can be implemented at reasonable cost, it
achieves emission reductions, and it does not have significant adverse
non-air quality health or environmental impacts or significant adverse
energy requirements. The fact that it promotes greater use of advanced
technology provides additional support; however, the EPA considers
highly efficient generation to the BSER for intermediate load
combustion turbines even without taking this factor into account.
3. BSER for Base Load Subcategory--First Component
This section describes the first component of the BSER for newly
constructed and reconstructed combustion turbines in the base load
subcategory. For combustion turbines in the base load subcategory, the
first component of the BSER is the use of high-efficiency combined
cycle technology in combination with the best operating and maintenance
practices.
a. Lower-Emitting Fuels
The EPA did not propose and is not finalizing lower-emitting fuels
as the BSER for base load combustion turbines because, as described
earlier in this section, it would achieve few GHG emission reductions
compared to highly efficient generation.
b. Highly Efficient Generation
i. Adequately Demonstrated
The EPA proposed and is finalizing that highly efficient combined
cycle designs are adequately demonstrated because highly efficient
combined cycle EGUs have been demonstrated by multiple facilities for
decades, and the efficiency improvements of the most efficient designs
are incremental in nature and do not change in any significant way how
the combustion turbine is operated or maintained. Due to the
differences in HRSG efficiencies for smaller combined cycle turbines,
the EPA proposed and is finalizing less stringent standards of
performance for smaller base load turbines with base load ratings of
less than 2,000 MMBtu/h relative to those for larger base load
turbines. The levels of efficiency that the EPA is proposing have been
achieved by many recently constructed combustion turbines. Therefore,
efficient generation technology described in this BSER is commercially
available and the standards of performance are achievable.
ii. Costs
For the base load subcategory, the EPA considers the cost of high-
efficiency combined cycle EGUs to be reasonable. While the capital
costs of a higher efficiency combined cycle EGUs are 1.9 percent higher
than standard efficiency combined cycle EGUs, fuel use is 2.6 percent
lower.\751\ The reduction in fuel costs fully offset the capital costs
at capacity factors of 40 percent or greater over the expected 30-year
life of the facility. Therefore, a BSER based on the use of high-
efficiency combined cycle combustion turbines for base load combustion
turbines would have minimal, if any, overall compliance costs since the
capital costs would be recovered through reduced fuel costs over the
expected 30-year life of the facility.
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\751\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A
(October 2022), https://www.osti.gov/servlets/purl/1893822.
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iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
Use of highly efficient generation reduces all non-air quality
health and environmental impacts and energy requirements as compared to
use of less efficient generation. Even when operating at the same
input-based emissions rate, the more efficient a unit is, the less fuel
is required to produce the same level of output; and, as a result,
emissions are reduced for all pollutants. The use of highly efficient
combustion turbines, compared to the use of less efficient combustion
turbines, reduces all pollutants. By the same token, because improved
efficiency allows for more electricity generation from the same amount
of fuel, it will not have any adverse effects on energy requirements.
Designating highly efficient generation as part of the BSER for new
and reconstructed base load combustion turbines will not have
significant impacts on the nationwide supply of electricity,
electricity prices, or the structure of the electric power sector. On a
nationwide basis, the additional costs of the use of highly efficient
generation will be small because the technology does not add
significant costs and at least some of those costs are offset by
reduced fuel costs. In addition, at least some of these new combustion
turbines would be expected to incorporate highly efficient generation
technology in any event.
iv. Extent of Reductions in CO2 Emissions
The EPA used a similar approach to estimating emission reductions
for base load combustion turbines as intermediate load combustion
turbines, except the Agency reviewed recently constructed combined
cycle EGUs. As discussed in section VIII.G.1, the EPA determined that
the standard of performance reflecting this BSER is 800 lb
CO2/MWh-gross for base load combustion turbines. The Agency
assumed all new combined cycle turbines would be impacted by the base
load emissions standard. Between the beginning of 2015 and the
beginning of 2022, 129 combined cycle turbines, an average of 18 per
year, commenced operation. Of those combined cycle turbines, 107 had
12-operating month emissions data. For each of these 107 combined cycle
turbines that had a maximum 12-operating month emissions rate greater
than 800 lb CO2/MWh-gross, the EPA determined the reductions
that would occur assuming the combined cycle turbine reduced its
[[Page 39923]]
emissions rate to 800 lb CO2/MWh-gross and continued to
operate at its average capacity factor. The EPA summed the results and
divided by 8 (the number of years evaluated) to estimate the annual GHG
reductions that will result from this final rule. The EPA estimates
that the base load standard will result in annual reductions of 313,000
tons of CO2 as well as 23 tons of NOX. The
reductions increase each year and in year 3 the annual reductions would
be 939,000 tons of CO2 and 69 tons of NOX.
v. Promotion of the Development and Implementation of Technology
The EPA also considered the potential impact of selecting highly
efficient generation technology as the BSER in promoting the
development and implementation of improved control technology. The
highly efficient combustion turbines are more efficient and lower
emitting than the average new combustion turbine generation technology.
Determining that highly efficient turbines are a component of the BSER
will advance penetration of the best performing combustion turbines
throughout the industry--and will incentivize manufacturers to offer
improved turbines that meet the final standard of performance
associated with application of the BSER. Accordingly, consideration of
this factor supports the EPA's proposal to determine this technology to
be the BSER.
c. Low-GHG Hydrogen and CCS
The EPA did not propose and is not finalizing either CCS or co-
firing low-GHG hydrogen as the first component of the BSER for base
load combustion turbines, for the reasons given in sections
VIII.F.4.c.iii (CCS) and VIII.F.5 (low-GHG hydrogen).
d. Summary of BSER Determinations
The EPA is finalizing that highly efficient generating technology
in combination with the best operating and maintenance practices is the
BSER for first component of the BSER for base load combustion turbines.
The phase-1 standards of performance are based on the application of
that technology. Specifically, the use of highly efficient combined
cycle technology in combination with best operating and maintenance
practices is the first component of the BSER for base load combustion
turbines.
Highly efficient generation qualifies as the BSER because it is
adequately demonstrated, it can be implemented at reasonable cost, it
achieves emission reductions, and it does not have significant adverse
non-air quality health or environmental impacts or significant adverse
energy requirements. The fact that it promotes greater use of advanced
technology provides additional support; however, the EPA considers
highly efficient generation to be a component of the BSER for base load
combustion turbines even without taking this factor into account.
4. BSER for Base Load Subcategory--Second Component
a. Authority To Promulgate a Multi-Part BSER and Standard of
Performance
The EPA's approach of promulgating standards of performance that
apply in multiple phases, based on determining the BSER to be a set of
controls with multiple components, is consistent with CAA section
111(b). That provision authorizes the EPA to promulgate ``standards of
performance,'' CAA section 111(b)(1)(B), defined, in the singular, as
``a standard for emissions of air pollutants which reflects the degree
of emission limitation achievable through the application of the
[BSER].'' CAA section 111(a)(1). CAA section 111(b)(1)(B) further
provides, ``[s]tandards of performance . . . shall become effective
upon promulgation.'' In this rulemaking, the EPA is determining that
the BSER is a set of controls that, depending on the subcategory,
include highly efficient generation plus use of CCS. The EPA is
determining that affected sources can apply the first component of the
BSER--highly efficient generation--by the effective date of the final
rule and can apply both the first and second components of the BSER--
highly efficient generation in combination with 90 percent CCS--in
2032.
Accordingly, the EPA is finalizing standards of performance that
reflect the application of this multi-component BSER and that take the
form of standards of performance that affected sources must comply with
in two phases. This multi-phase standard of performance ``become[s]
effective upon promulgation.'' CAA section 111(b)(1)(B). That is, upon
promulgation, affected sources become legally subject to the multi-
phase standard of performance and must comply with it by its terms.
Specifically, affected sources must comply with the first phase
standards, which are based on the application of the first component of
the BSER, upon initial startup of the facility. They must comply with
the second phase standards, which are based on the application of both
the first and second components of the BSER, beginning January 2032.
D.C. Circuit caselaw supports the proposition that CAA section 111
authorizes the EPA to determine that controls qualify as the BSER--
including meeting the ``adequately demonstrated'' criterion--even if
the controls require some amount of ``lead time,'' which the court has
defined as ``the time in which the technology will have to be
available.'' \752\ The caselaw's interpretation of ``adequately
demonstrated'' to accommodate lead time accords with common sense and
the practical experience of certain types of controls, discussed below.
Consistent with this caselaw, the phased implementation of the
standards of performance in this rule ensures that facilities have
sufficient lead time for planning and implementation of the use of CCS-
based controls necessary to comply with the second phase of the
standards, and thereby ensures that the standards are achievable. For
further discussion of this point, see section V.C.2.b.iii.
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\752\ See Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375,
391 (D.C. Cir. 1973) (citations omitted).
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The EPA has promulgated several prior rulemakings under CAA section
111(b) that have similarly provided the regulated sector with lead time
to accommodate the availability of technology, which also serve as
precedent for the two-phase implementation approach proposed in this
rule. See 81 FR 59332 (August 29, 2016) (establishing standards for
municipal solid waste landfills with 30-month compliance timeframe for
installation of control device, with interim milestones); 80 FR 13672,
13676 (March 16, 2015) (establishing stepped compliance approach to
wood heaters standards to permit manufacturers lead time to develop,
test, field evaluate and certify current technologies to meet Step 2
emission limits); 78 FR 58416, 58420 (September 23, 2013) (establishing
multi-phased compliance deadlines for revised storage vessel standards
to permit sufficient time for production of necessary supply of control
devices and for trained personnel to perform installation); 77 FR
56422, 56450 (September 12, 2012) (establishing standards for petroleum
refineries, with 3-year compliance timeframe for installation of
control devices); 71 FR 39154, 39158 (July 11, 2006) (establishing
standards for stationary compression ignition internal combustion
engines, with 2- to 3-year compliance timeframe and up to 6 years for
certain emergency fire pump engines); 70 FR 28606, 28617 (March 18,
2005) (establishing two-phase caps for
[[Page 39924]]
mercury standards of performance from new and existing coal-fired
electric utility steam generating units based on timeframe when
additional control technologies were projected to be adequately
demonstrated).\753\ Cf. 80 FR 64662, 64743 (October 23, 2015)
(establishing interim compliance period to phase in final power sector
GHG standards to allow time for planning and investment necessary for
implementation activities).\754\ In each action, the standards and
compliance timelines were effective upon the final rule, with affected
facilities required to comply consistent with the phased compliance
deadline specified in each action.
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\753\ Cf. New Jersey v. EPA, 517 F.3d 574, 583-584 (D.C. Cir.
2008) (vacating rule on other grounds).
\754\ Cf. West Virginia v. EPA, 597 U.S. 697 (2022) (vacating
rule on other grounds).
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It should be noted that the multi-phased implementation of the
standards of performance that the EPA is finalizing in this rule, like
the delayed or multi-phased standards in prior rules just described, is
distinct from the promulgation of revised standards of performance
under the 8-year review provision of CAA section 111(b)(1)(B). As
discussed in section VIII.F, the EPA has determined that the proposed
BSER--highly efficient generation and use of CCS--meet all of the
statutory criteria and are adequately demonstrated for the compliance
timeframes being finalized. Thus, the second phase of the standard of
performance applies to affected facilities that commence construction
after May 23, 2023 (the date of the proposal). In contrast, when the
EPA later reviews and (if appropriate) revises a standard of
performance under the 8-year review provision, then affected sources
that commence construction after the date of that proposal of the
revised standard of performance will be subject to that standard, but
not sources that commenced construction earlier.
Similarly, the multi-phased implementation of the standard of
performance that the EPA is including in this rule is also distinct
from the promulgation of emission guidelines for existing sources under
CAA section 111(d). Emission guidelines only apply to existing sources,
which are defined in CAA section 111(a)(6) as ``any stationary source
other than a new source.'' Because new sources are defined relative to
the proposal of standards pursuant to CAA section 111(b)(1)(B),
standards of performance adopted pursuant to emission guidelines will
only apply to sources constructed before May 23, 2023, the date of the
proposed standards of performance for new sources.
b. BSER for the Intermediate Load Subcategory--Second Component
The EPA proposed that the second component of the BSER for
intermediate load combustion turbines was co-firing 30 percent low-GHG
hydrogen in 2032. As discussed in section VIII.F.5.b, the EPA is not
determining that low-GHG hydrogen qualifies as the BSER at this time.
Therefore, the Agency is not finalizing a second component of the BSER
for intermediate load combustion turbines.
c. BSER for Base Load Subcategory--Second Component
i. Lower-Emitting Fuels
The EPA did not propose and is not finalizing lower-emitting fuels
as the second component of the BSER for intermediate or base load
combustion turbines because it would achieve few emission reductions,
compared to highly efficient generation without or in combination with
the use of CCS.
ii. Highly Efficient Generation
For the reasons described above, the EPA is determining that highly
efficient generation in combination with best operating and maintenance
practices continues to be a component of the BSER that is reflected in
the second phase of the standards of performance for base load
combustion turbine EGUs. Highly efficient generation reduces fuel use
and, therefore, the amount of CO2 that must be captured by a
CCS system. Since a highly efficient turbine system would produce less
flue gas that would need to be treated (compared to a less efficient
turbine system), physically smaller carbon capture equipment may be
used--potentially reducing capital, fixed, and operating costs.
iii. Hydrogen Co-Firing
The EPA proposed a pathway for the second component of the BSER for
base load combustion turbines of co-firing 30 percent low-GHG hydrogen
in 2032 increasing to 96 percent low-GHG hydrogen co-firing in 2038. As
discussed in section VIII.F.5.b of this preamble, the EPA is not
finalizing a determination that low-GHG hydrogen co-firing qualifies as
the BSER. Therefore, the Agency is not finalizing a second component
low-GHG hydrogen co-firing pathway of the BSER for base load combustion
turbines. As the EPA's standard of performance is technology neutral,
however, affected sources may comply with it by co-firing hydrogen.
iv. CCS
(A) Overview
In this section of the preamble, the EPA explains its rationale for
finalizing that CCS with 90 percent capture is a component of the BSER
for new base load combustion turbines. CCS is a control technology that
can be applied at the stack of a combustion turbine EGU, achieves
substantial reductions in emissions and can capture and permanently
sequester at least 90 percent of the CO2 emitted by
combustion turbines. The technology is adequately demonstrated, given
that it has been operated on a large scale and is widely applicable to
these sources, and there are vast sequestration opportunities across
the continental U.S. Additionally, the costs for CCS are reasonable in
light of recent technology cost declines and policies including the tax
credit under IRC section 45Q. Moreover, the non-air quality health and
environmental impacts of CCS can be mitigated, and the energy
requirements of CCS are not unreasonably adverse. The EPA's weighing of
these factors together provides the basis for finalizing 90 percent
capture CCS as a component of BSER for these sources. In addition, this
BSER determination aligns with the caselaw, discussed in section
V.C.2.h of the preamble, stating that CAA section 111 encourages
continued advancement in pollution control technology.
This section incorporates by reference the parts of section
VII.C.1.a. of this preamble that discuss the many aspects of CCS that
are common to both steam generating units and to new combustion
turbines. This includes the discussion of simultaneous demonstration of
CO2 capture, transport, and sequestration discussed at
VII.C.1.a.i(A); the discussion of CO2 capture technology
used at coal-fired steam generating units at VII.C.1.a.i(B) (the Agency
explains below why that record is also relevant to our BSER analysis
for new combustion turbines); the discussion of CO2
transport at VII.C.1.a.i(C); and the discussion of geologic storage of
CO2 at VII.C.1.a.i(D). And the record supporting that
transport and sequestration of CO2 from coal-fired units is
adequately demonstrated and meets the other requirements for BSER
applies as well to transport and sequestration of CO2 from
combustion turbines.
The primary differences between using post-combustion capture from
a coal combustion flue gas and a natural gas combustion flue gas are
associated with the level of CO2 in the flue gas stream and
the levels of other pollutants that must be removed. In coal
[[Page 39925]]
combustion flue gas, the concentration of CO2 is typically
approximately 13 to 15 volume percent, while the concentration of
CO2 from natural gas-fired combined cycle combustion flue
gas is approximately 3 to 4 volume percent.\755\ Capture of
CO2 at dilute concentrations is more challenging but there
are commercially available amine-based solvents that can be used with
dilute CO2 streams to achieve 90 percent capture. In
addition, flue gas from a coal-fired steam EGU contains a variety of
non-carbonaceous components that must be removed to meet environmental
limits (e.g., mercury and other metals, particulate matter (fly ash),
and acid gases (including sulfur dioxide (SO2) and hydrogen
chloride and hydrogen fluoride). When amine-based post-combustion
carbon capture is used with a coal-fired EGU, the flue gas stream must
be further cleaned, sometimes beyond required environmental standards,
to avoid the fouling of downstream process equipment and to prevent
degradation of the amine solvent. Absent pretreatment of the coal
combustion flue gas, the amines can absorb SO2 and other
acid gases to form heat stable salts, thereby degrading the performance
of the solvent. Amine solvents can also experience catalytic oxidative
degradation in the presence of some metal contaminants. Thermal
oxidation of the solvent can also occur but can be mitigated by
interstage cooling of the absorber column. Natural gas combustion flue
gas typically contains very low (if any) levels of SO2, acid
gases, fly ash, and metals. Therefore, fouling and solvent degradation
are less of a concern for carbon capture from natural gas-fired EGUs.
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\755\ NETL Carbon Dioxide Capture Approaches. https://netl.doe.gov/research/carbon-management/energy-systems/gasification/gasifipedia/capture-approaches.
---------------------------------------------------------------------------
New natural gas-fired combustion turbine EGUs also have the option
of using oxy-combustion technology--such as that currently being
demonstrated and developed by NET Power. As discussed earlier, the NET
Power system uses oxy-combustion (combustion in pure oxygen) of natural
gas and a high-pressure supercritical CO2 working fluid
(instead of steam) to produce electricity in a combined cycle turbine
configuration. The combustion products are water and high-purity,
pipeline-ready CO2 which is available for sequestration or
sale to another industry. The NET Power technology does not involve
solvent-based CO2 separation and capture since pure
CO2 is a product of the process. The NET Power technology is
not currently applicable to coal-fired steam generating utility
boilers--though it could be utilized with combustion of gasified coal
or other solid fossil fuels (e.g., petroleum coke).
For new base load combustion turbines, the EPA proposed that CCS
with a 90 percent capture rate, beginning in 2035, meets the BSER
criteria. Some commenters agreed with the EPA that CCS for base load
combustion turbines satisfies the BSER criteria. Other commenters
claimed that CCS is not a suitable BSER for new base load combustion
turbines. The EPA disagrees with these commenters.
As with existing coal-fired steam generating units, CCS applied to
new combined cycle combustion turbines has three major components:
CO2 capture, transportation, and sequestration/storage. CCS
with 90 percent capture has been adequately demonstrated for combined
cycle combustion turbines for many of the same reasons described in
section VII.C.1.a.i. The Bellingham Energy Center, a natural gas-fired
combined cycle combustion turbine in south central Massachusetts,
successfully applied post-combustion carbon capture using the Fluor
Econamine FG Plus\SM\ amine-based solvent from 1991-2005 with 85-95
percent CO2 capture.\756\ The plant captured approximately
365 tons of CO2 per day from a 40 MW slip stream \757\ and
was ultimately shut down and decommissioned primarily due to rising gas
prices.
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\756\ Fluor Econamine FG Plus\SM\ brochure. https://a.fluor.com/f/1014770/x/a744f915e1/econamine-fg-plus-brochure.pdf.
\757\ ``Commercially Available CO2 Capture
Technology'' Power, (Aug 2009). https://www.powermag.com/commercially-available-co2-capture-technology/.
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As discussed in further detail below, additional natural gas-fired
combined cycle combustion turbine CCS projects are in the planning
stage, which confirms that CCS is becoming accepted across the
industry. As discussed above, CCS with 90 percent capture has been
demonstrated for coal-fired steam generating units, and that
information forms part of the basis for the EPA's determination that
CCS with 90 percent capture has been have adequately demonstrated for
these combustion turbines. Statements from vendors and the experience
of industrial applications of CCS provide further support that post-
combustion CCS with 90 percent capture is adequately demonstrated for
these combustion turbines.
The EPA's analysis of the transportation and sequestration
components of CCS for new base load combustion turbines is similar to
its analysis of those components for existing coal-fired steam
generating units and, therefore, for much the same reasons, the EPA is
determining that each of those components is adequately demonstrated,
and that CCS as a whole--including those components when combined with
the 90 percent CO2 capture component--is adequately
demonstrated. In addition, new sources may consider access to
CO2 transport and storage sites in determining where to
build, and the EPA expects that since this rule was proposed, companies
siting new base load combustion turbines have taken into consideration
the likelihood of a regulatory regime requiring significant emissions
reductions.
The use of CCS at 90 percent capture can be implemented at
reasonable cost because it allows affected sources to maximize the
benefits of the IRC section 45Q tax credit. Finally, any adverse health
and environmental impacts and energy requirements are limited and, in
many cases, can be mitigated or avoided. It should also be noted that a
determination that CCS is the BSER for these units will promote further
use and development of this advanced technology. After balancing these
factors, the EPA is determining that utilization of CCS with 90 percent
capture for new base load combustion turbine EGUs satisfies the
criteria for BSER.
(B) Adequately Demonstrated
The legal test for an adequately demonstrated system, and an
achievable standard, has been discussed at length above. (See sections
V.C.2.b and VII.C.a.i of this preamble). As previously noted, concepts
of adequate demonstration and achievability are closely related: ``[i]t
is the system which must be adequately demonstrated and the standard
which must be achievable,'' \758\ based on application of the system.
An achievable standard means a standard based on the EPA's finding that
sufficient evidence exists to reasonably determine that the affected
sources in the source category can adopt a specific system of emission
reduction to achieve the specified degree of emission limitation. The
foregoing sections have shown that CCS, specifically using amine post-
combustion CO2 capture, is adequately demonstrated for
existing coal units,
[[Page 39926]]
and that a 90 percent capture standard is achievable.\759\
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\758\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433
(1973).
\759\ The EPA uses the two phrases (i) BSER is CCS with 90
percent capture and (ii) CCS with 90 percent capture is achievable,
or similar phrases, interchangeably.
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Pursuant to Lignite Energy Council v. EPA, the EPA may extrapolate
based on data from a particular kind of source to conclude that the
technology at issue will also be effective at a similar source.\760\
This standard is satisfied in our case, because of the essential ways
in which CO2 capture at coal-fired steam generating units is
identical to CO2 capture at natural gas-fired combined cycle
turbines. As detailed in section VII.C.1.a.i(B), amine-based
CO2 capture removes CO2 from post-combustion flue
gas by reaction of the CO2 with amine solvent. The same
technology (i.e., the same solvents and processes) that is employed on
coal-fired steam generating units--and that is employed to capture
CO2 from fossil fuel combustion in other industrial
processes--can be applied to remove CO2 from the post-
combustion flue gas of natural gas-fired combined cycle EGUs. In fact,
the only differences in application of amine-based CO2
capture on a natural gas-fired combined cycle unit relative to a coal-
fired steam generating unit are related to the differences in
composition of the respective post-combustion flue gases, and as
explained below, these differences do not preclude achieving 90 percent
capture from a gas-fired turbine.
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\760\ Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir.
1999).
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First, while coal flue gas contains impurities including
SO2, PM, and trace minerals that can affect the downstream
CO2 process, and thus coal flue gas requires substantial
pre-treatment, the post-combustion flue gas of natural gas-fired
combustion turbines has few, if any, impurities that would impact the
downstream CO2 capture plant. Where impurities are present,
SO2 in particular can cause solvent degradation, and coal-
fired sources without an FGD would likely need to install one.
Filterable PM (fly ash) from coal, if not properly managed, can cause
fouling and scale to accumulate on downstream blower fans, heat
exchangers, and absorber packing material. Further, additional care in
the solvent reclamation is necessary to mitigate solvent degradation
that could otherwise occur due to the trace elements that can be
present in coal. Because the flue gas from natural gas-fired combustion
turbines contains few, if any, impurities that would impact downstream
CO2 capture, the flue gas from natural gas-fired combined
cycle EGUs is easier to work with for CO2 capture, and many
of the challenges that were faced by earlier commercial scale
demonstrations on coal-fired units can be avoided in the application of
CCS at natural gas-fired combustion turbines.
Second, the CO2 concentration of natural gas-fired
combined cycle flue gas is lower than that of coal flue gas
(approximately 3-to-4 volume percent for natural gas combined cycle
EGUs; 13-to-15 volume percent for coal). For solvent-based
CO2 capture, CO2 concentration is the driving
force for mass transfer and the reaction of CO2 with the
solvent. However, flue gases with lower CO2 concentrations
can be readily addressed by the correct sizing and design of the
capture equipment--and such considerations have been made in evaluating
the BSER here and are reflected in the cost analysis in VII.C.1.a.ii(A)
of this preamble. Moreover, as is detailed in the following sections of
the preamble, amine-based CO2 capture has been shown to be
effective at removal of CO2 from the flue gas of natural
gas-fired combined cycle EGUs. In fact, there is not a technical limit
to removal of CO2 from flue gases with low CO2
concentrations--the EPA notes that amine solvents have been shown to be
able to remove CO2 to concentrations that are less than the
concentration of CO2 in the atmosphere.
Considering these factors, the evidence that underlies the EPA's
determination that amine post-combustion CO2 capture is
adequately demonstrated, and that a 90 percent capture standard is
achievable, at coal-fired steam generating units, also applies to
natural gas-fired combined cycle EGUs. Where differences exist, due to
differences in flue gas composition, CCS at natural gas-fired combined
cycle combustion turbines will in general face fewer challenges than
CCS at coal-fired steam generators.\761\ Moreover, in addition to the
evidence outlined above, the following sections provide additional
information specific to, including examples of, anime-based capture at
natural gas-fired combined cycle EGUs. For these reasons, the EPA has
determined that CCS at 90 percent capture is adequately demonstrated
for natural gas fired combined cycle EGUs.
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\761\ Many of the challenges faced by Boundary Dam Unit 3--which
proved to be solvable--were caused by the impurities, including fly
ash, SO2, and trace contaminants in coal-fired post-
combustion flue gas--which do not occur in the natural gas post-
combustion flue gas. As a result, for CO2 capture for
natural gas combustion, flue gas handling is simpler, solvent
degradation is easier to prevent, and fewer redundancies may be
necessary for various components (e.g., heat exchangers).
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(1) CO2 Capture for Combined Cycle Combustion Turbines
As discussed in the preceding, new stationary combustion turbines
can use amine-based post-combustion capture. Additionally, new
stationary combustion turbines may also utilize oxy-combustion, which
uses a purified oxygen stream from an air separation unit (often
diluted with recycled CO2 to control the flame temperature)
to combust the fuel and produce a nearly pure stream of CO2
in the flue gas, as opposed to combustion with oxygen in air which
contains 80 percent nitrogen. Currently available post-combustion
amine-based CO2 capture systems require that the flue gas be
cooled prior to entering the capture equipment. This holds true for the
exhaust from either a coal-fired utility boiler or from a combustion
turbine. The most energy efficient way to cool the flue gas stream is
to use a HRSG--which, as explained above, is an integral component of a
combined cycle turbine system--to generate additional useful
output.\762\
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\762\ The EPA proposed that because the BSER for non-base load
combustion turbines was simple cycle technology, CCS was not
applicable.
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CO2 capture has been successfully applied to an existing
combined cycle turbine and several other projects are in development,
as discussed immediately below.
(a) CCS on Combined Cycle EGUs
The most prominent example of the use of carbon capture technology
on a natural gas-fired combined cycle turbine EGU was at the 386 MW
Bellingham Cogeneration Facility in Bellingham, Massachusetts. The
plant used Fluor's Econamine FG Plus\SM\ amine-based CO2
capture system with a capture capacity of 360 tons of CO2
per day. The system was used to produce food-grade CO2 and
was in continuous commercial operation from 1991 to 2005 (14 years).
The capture system was able to continuously capture 85-95 percent of
the CO2 that would have otherwise been emitted from the flue
gas of a 40 MW slip stream.\763\ The natural gas combustion flue gas at
the facility contained 3.5 volume percent CO2 and 13-14
volume percent oxygen. As mentioned earlier, the flue gas from a coal
combustion flue gas stream has a typical CO2 concentration
of approximately 15 volume percent and more dilute CO2
stream are more challenging to separate and capture. Just before the
CO2 capture system was shut
[[Page 39927]]
down in 2005 (due to high natural gas price), the system had logged
more than 120,000 hours of CO2 capture \764\ and had a 98.5
percent on-stream (availability) factor.\765\
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\763\ U.S. Department of Energy (DOE). Carbon Capture
Opportunities for Natural Gas Fired Power Systems. https://www.energy.gov/fecm/articles/carbon-capture-opportunities-natural-gas-fired-power-systems.
\764\ https://boereport.com/2022/08/16/fluor/.
\765\ ``Technologies for CCS on Natural Gas Power Systems'' Dr.
Satish Reddy presentation to USEA, April 2014, https://usea.org/sites/default/files/event-/Reddy%20USEA%20Presentation%202014.pptx.
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The Fluor Econamine FG Plus\SM\ is a propriety carbon capture
solution with more than 30 licensed plants and more than 30 years of
operation. This technology uses a proprietary solvent to capture
CO2 from post-combustion sources. The process is well suited
to capture CO2 from large, single-point emission sources
such as power plants or refineries, including large facilities with
CO2 capture capacities greater than 10,000 tons per
day.\766\ On February 6, 2024, Fluor Corporation announced that Chevron
New Energies plans to use the Econamine FG Plus\SM\ carbon capture
technology to reduce CO2 emissions at Chevron's Eastridge
Cogeneration combustion turbine facility in Kern County, California.
When installed, Fluor's carbon capture solution is expected to reduce
the Eastridge Cogeneration facility's carbon emissions by approximately
95 percent.\767\
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\766\ https://www.fluor.com/market-reach/industries/energy-transition/carbon-capture.
\767\ https://newsroom.fluor.com/news-releases/news-details/2024/Fluors-Econamine-FG-PlusSM-Carbon-Capture-Technology-Selected-to-Reduce-CO2-Emissions-at-Chevron-Facility/default.aspx.
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Moreover, recently, CO2 capture technology has been
operated on NGCC post-combustion flue gas at the Technology Centre
Mongstad (TCM) in Norway.\768\ TCM can treat a 12 MWe flue gas stream
from a natural gas combined cycle cogeneration plant at Mongstad power
station. Many different solvents have been operated at TCM including
MHI's KS-21\TM\ solvent,\769\ achieving capture rates of over 98
percent.
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\768\ https://netl.doe.gov/carbon-capture/power-generation.
\769\ Mitsubishi Heavy Industries, ``Mitsubishi Heavy Industries
Engineering Successfully Completes Testing of New KS-21TM
Solvent for CO2 Capture,'' https://www.mhi.com/news/211019.html.
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Additionally, in Scotland, the proposed 900 MW Peterhead Power
Station combined cycle EGU with CCS is in the planning stages of
development. MHI is developing a FEED for the power plant and capture
facility.\770\ It is anticipated that the power plant will be
operational by the end of the 2020s and will have the potential to
capture 90 percent of the CO2 emitting from the combined
cycle facility and sequester up to 1.5 million metric tons of
CO2 annually. A storage site being developed 62 miles off
the Scottish North Sea coast will serve as a destination for the
captured CO2.771 772
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\770\ MHI and MHIENG Awarded FEED Contract. https://www.mhi.com/news/22083001.html.
\771\ Buli, N. (2021, May 10). SSE, Equinor plan new gas power
plant with carbon capture in Scotland. Reuters. https://www.reuters.com/business/sustainable-business/sse-equinor-plan-new-gas-power-plant-with-carbon-capture-scotland-2021-05-11/.
\772\ Acorn CCS granted North Sea storage licenses. September
18, 2023. https://www.ogj.com/energy-transition/article/14299094/acorn-granted-licenses-for-co2-storage.
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Furthermore, the Global CCS Centre is tracking other international
CCS on combustion turbine projects that are in on-going stages of
development.\773\
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\773\ https://status23.globalccsinstitute.com/.
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(b) NET Power Cycle
In addition, there are several planned projects using NET Power's
Allam-Fetvedt Cycle.\774\ The Allam-Fetvedt Cycle is a proprietary
process for producing electricity that combusts a fuel with purified
oxygen (diluted with recycled CO2 to control flame
temperature) and uses supercritical CO2 as the working fluid
instead of water/steam. This cycle is designed to achieve thermal
efficiencies of up to 59 percent.\775\ Potential advantages of this
cycle are that it emits no NOX and produces a stream of
high-purity CO2 \776\ that can be delivered by pipeline to a
storage or sequestration site without extensive processing. A 50 MW
(thermal) test facility in La Porte, Texas was completed in 2018 and
has since accumulated over 1,500 hours of runtime. There are several
announced NET Power commercial projects proposing to use the Allam-
Fetvedt Cycle. These include the 280 MW Broadwing Clean Energy Complex
in Illinois, and several international projects.
---------------------------------------------------------------------------
\774\ The NET Power Cycle was formerly referred to as the Allam-
Fetvedt cycle. https://netpower.com/technology/.
\775\ Yellen, D. (2020, May 25). Allam Cycle carbon capture gas
plants: 11 percent more efficient, all CO2 captured.
Energy Post. https://energypost.eu/allam-cycle-carbon-capture-gas-plants-11-more-efficient-all-co2-captured/.
\776\ This allows for capture of over 97 percent of the
CO2 emissions. www.netpower.com.
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In Scotland, the proposed 900 MW Peterhead Power Station combined
cycle EGU with CCS is in the planning stages of development. MHI is
developing a FEED for the power plant and capture facility.\777\ It is
anticipated that the power plant will be operational by the end of the
2020s and will have the potential to capture 90 percent of the
CO2 emitting from the combined cycle facility and sequester
up to 1.5 million metric tons of CO2 annually. A storage
site being developed 62 miles off the Scottish North Sea coast will
serve as a destination for the captured
CO2.778 779
(c) Coal-Fired Steam Generating Units
As detailed in section VII.C.1.a, CCS has been demonstrated on
coal-fired power plants, which provides further support that CCS on
base load combined cycle units is adequately demonstrated. Further, 90
percent capture is expected to be, in some ways, more straightforward
to achieve for natural gas-fired combined cycle combustion turbines
than for coal-fired steam generators. Many of the challenges faced by
Boundary Dam Unit 3--which proved to be solvable--were caused by the
impurities, including fly ash, SO2, and trace contaminants
in coal-fired post-combustion flue gas. Such impurities naturally occur
in coal (sulfur and trace contaminants) or are a natural result of
combusting coal (fly ash), but not in natural gas, and thus they do not
appear in the natural gas post-combustion flue gas. As a result, for
CO2 capture for natural gas combustion, flue gas handling is
simpler, solvent degradation is easier to prevent, and fewer
redundancies may be necessary for various components (e.g., heat
exchangers).
(d) Other Industry
As discussed in section VII.C.1.a.i.(A)(1) of this preamble, CCS
installations in other industries support that capture equipment can
achieve 90 percent capture of CO2 from natural gas-fired
base load combined cycle combustion turbines.
(e) EPAct05-Assisted CO2 Capture Projects at Stationary
Combustion Turbines
As for steam generating units, EPAct05-assisted CO2
capture projects on stationary combustion turbines corroborate that
CO2 capture on gas combustion turbines is adequately
demonstrated. Several CCS projects with at least 90 percent capture at
commercial-scale combined cycle turbines are in the planning stages.
These projects support that CCS with at least 90 percent capture for
these units is the industry standard and support the EPA's
determination that CCS is adequately demonstrated.
CCS is planned for the existing 550 MW natural gas-fired combined
cycle (two combustion turbines) at the Sutter Energy Center in Yuba
City, California.\780\ The Sutter
[[Page 39928]]
Decarbonization project will use ION Clean Energy's amine-based solvent
technology at a capture rate of 95 percent or more. The project expects
to complete a FEED study in 2024 and, prior to being selected by DOE
for funding award negotiation, planned commercial operation in 2027.
Sutter Decarbonization is one of the projects selected by DOE for
funding as part of OCED's Carbon Capture Demonstration Projects
program.\781\
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\780\ Calpine Sutter Decarbonization Project, May 17, 2023.
https://www.smud.org/en/Corporate/Environmental-Leadership/2030-Clean-Energy-Vision/CEV-Landing-Pages/Calpine-presentation.
\781\ Carbon Capture Demonstration Projects Selections for Award
Negotiations. https://www.energy.gov/oced/carbon-capture-demonstration-projects-selections-award-negotiations.
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The CO2 capture project at the Deer Park Energy Center
in Deer Park, Texas will be designed to capture 95 percent or more of
the flue gas from the five combustion turbines at the 1,200 MW natural
gas-fired combined cycle power plant, using technology from Shell
CANSOLV.\782\ The CO2 capture project already has an air
permit issued for the project, which includes a reduction in the
allowable emission limits for NOX from four of the
combustion turbines.\783\ The CO2 capture facility will
include two quencher columns, two absorber columns, and one stripping
column.
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\782\ Calpine Carbon Capture. https://calpinecarboncapture.com/wp-content/uploads/2023/05/Calpine-Deer-Park-English.pdf.
\783\ Deer Park Energy Center TCEQ Records Online Primary ID
171713.
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The Baytown Energy Center in Baytown, Texas is an existing natural
gas-fired combined cycle cogeneration facility providing heat and power
to a nearby industrial facility, while distributing additional
electricity to the grid. CCS using Shell's CANSOLV solvent is planned
for the equivalent of two of the three combustion turbines at the 896
MW natural gas-fired combined cycle power plant, with a capture rate of
95 percent. The CO2 capture facility at Baytown Energy
Center also has an air permit in place, and the permit application
provides some details on the process design.\784\ The CO2
capture facility will include two quencher columns, two absorber
columns, and one stripping column. To mitigate NOX
emissions, the operation of the SCR systems for the combustion turbines
will be adjusted to meet lower NOX allowable limits--
adjustments may include increasing ammonia flow, more frequent SCR
repacking and head cleaning, and, possibly, optimization of the ammonia
distribution system. The Baytown CO2 capture project is one
of the projects selected by DOE for funding as part of OCED's Carbon
Capture Demonstration Projects program.\785\ Captured CO2
will be transported and stored at sites along the U.S. Gulf Coast.
---------------------------------------------------------------------------
\784\ Baytown Energy Center Air Permit TCEQ Records Online
Primary ID 172517.
\785\ Carbon Capture Demonstration Projects Selections for Award
Negotiations. https://www.energy.gov/oced/carbon-capture-demonstration-projects-selections-award-negotiations.
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An 1,800 MW natural gas-fired combustion turbine that will be
constructed in West Virginia and will utilize CCS has been announced.
The project is planned to begin operation later this decade.\786\
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\786\ Competitive Power Ventures (2022). Multi-Billion Dollar
Combined Cycle Natural Gas Power Station with Carbon Capture
Announced in West Virginia. Press Release. September 16, 2022.
https://www.cpv.com/2022/09/16/multi-billion-dollar-combined-cycle-natural-gas-power-station-with-carbon-capture-announced-in-west-virginia/.
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There are numerous other EPAct05-assisted projects related to
natural gas-fired combined cycle turbines including the
following.787 788 789 790 791 These projects provide
corroborating evidence that capture of at least 90 percent is accepted
within the industry.
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\787\ General Electric (GE) (2022). U.S. Department of Energy
Awards $5.7 Million for GE-Led Carbon Capture Technology Integration
Project Targeting to Achieve 95% Reduction of Carbon Emissions.
Press Release. February 15, 2022. https://www.ge.com/news/press-releases/us-department-of-energy-awards-57-million-for-ge-led-carbon-capture-technology.
\788\ Larson, A. (2022). GE-Led Carbon Capture Project at
Southern Company Site Gets DOE Funding. Power. https://www.powermag.com/ge-led-carbon-capture-project-at-southern-company-site-gets-doe-funding/.
\789\ U.S. Department of Energy (DOE) (2021). DOE Invests $45
Million to Decarbonize the Natural Gas Power and Industrial Sectors
Using Carbon Capture and Storage. October 6, 2021. https://www.energy.gov/articles/doe-invests-45-million-decarbonize-natural-gas-power-and-industrial-sectors-using-carbon.
\790\ DOE (2022). Additional Selections for Funding Opportunity
Announcement 2515. Office of Fossil Energy and Carbon Management.
https://www.energy.gov/fecm/additional-selections-funding-opportunity-announcement-2515.
\791\ DOE (2019). FOA 2058: Front-End Engineering Design (FEED)
Studies for Carbon Capture Systems on Coal and Natural Gas Power
Plants. Office of Fossil Energy and Carbon Management. https://www.energy.gov/fecm/foa-2058-front-end-engineering-design-feed-studies-carbon-capture-systems-coal-and-natural-gas.
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General Electric (GE) (Bucks, Alabama) was awarded
$5,771,670 to retrofit a combined cycle turbine with CCS technology to
capture 95 percent of CO2 and is targeting commercial
deployment by 2030.
Wood Environmental & Infrastructure Solutions (Blue Bell,
Pennsylvania) was awarded $4,000,000 to complete an engineering design
study for CO2 capture at the Shell Chemicals Complex. The
aim is to reduce CO2 emissions by 95 percent using post-
combustion technology to capture CO2 from several plants,
including an onsite natural gas CHP plant.
General Electric Company, GE Research (Niskayuna, New
York) was awarded $1,499,992 to develop a design to capture 95 percent
of CO2 from combined cycle turbine flue gas with the
potential to reduce electricity costs by at least 15 percent.
SRI International (Menlo Park, California) was awarded
$1,499,759 to design, build, and test a technology that can capture at
least 95 percent of CO2 while demonstrating a 20 percent
cost reduction compared to existing combined cycle turbine carbon
capture.
CORMETECH, Inc. (Charlotte, North Carolina) was awarded
$2,500,000 to further develop, optimize, and test a new, lower-cost
technology to capture CO2 from combined cycle turbine flue
gas and improve scalability to large, combined cycle turbines.
TDA Research, Inc. (Wheat Ridge, Colorado) was awarded
$2,500,000 to build and test a post-combustion capture process to
improve the performance of combined cycle turbine flue gas
CO2 capture.
GE Gas Power (Schenectady, New York) was awarded
$5,771,670 to perform an engineering design study to incorporate a 95
percent CO2 capture solution for an existing combined cycle
turbine site while providing lower costs and scalability to other
sites.
Electric Power Research Institute (EPRI) (Palo Alto,
California) was awarded $5,842,517 to complete a study to retrofit a
700 MWe combined cycle turbine with a carbon capture system to capture
95 percent of CO2.
Gas Technology Institute (Des Plaines, Illinois) was
awarded $1,000,000 to develop membrane technology capable of capturing
more than 97 percent of combined cycle turbine CO2 flue gas
and demonstrate upwards of 40 percent reduction in costs.
RTI International (Research Triangle Park, North Carolina)
was awarded $1,000,000 to test a novel non-aqueous solvent technology
aimed at demonstrating 97 percent capture efficiency from simulated
combined cycle turbine flue gas.
Tampa Electric Company (Tampa, Florida) was awarded
$5,588,173 to conduct a study retrofitting Polk Power Station with
post-combustion CO2 capture technology aiming to achieve a
95 percent capture rate.
There are also several announced NET Power Allam-Fetvedt Cycle
based CO2 capture projects that are EPAct05-assisted. These
include the 280 MW Coyote Clean Power Project on the Southern Ute
Indian Reservation in
[[Page 39929]]
Colorado and a 300 MW project located near Occidental's Permian Basin
operations close to Odessa, Texas. Commercial operation of the facility
near Odessa, Texas is expected in 2028.
(f) Range of Conditions
The composition of natural gas combined cycle post-combustion flue
gas is relatively uniform as the level of impurities is, in general,
low. There may be some difference in NOX emissions, but
considering the sources are new, it is likely that they will be
installed with SCR, resulting in uniform NOX concentrations
in the flue gas. The EPA notes that some natural gas combined cycle
units applying CO2 capture may use exhaust gas recirculation
to increase the concentration of CO2 in the flue gas--this
produces a higher concentration of CO2 in the flue gas. For
those sources that apply that approach, the CO2 capture
system can be scaled smaller, reducing overall costs. Considering these
factors, the EPA concludes that there are not substantial differences
in flue gas conditions for natural gas combined cycle units, and the
small differences that could exist would not adversely impact the
operation of the CO2 capture equipment.
As detailed in section VII.C.1.a.i(B)(7), single trains of
CO2 capture facilities have turndown capabilities of 50
percent. Effective turndown to 25 percent of throughputs can be
achieved by using 2 trains of capture equipment. CO2 capture
rates have also been shown to be higher at lower throughputs. Moreover,
during off-peak hours when electricity prices are lower, additional
lean solvent can be produced and held in reserve, so that during high-
demand hours, the auxiliary demands to the capture plant stripping
column reboiler be reduced. Considering these factors, the capture rate
would not be affected by load following operation, and the operation of
the combustion turbine would not be limited by turndown capabilities of
the capture equipment. As detailed in preceding sections, simple cycle
combustion turbines cycle frequently, and have a number of startups and
shutdowns per year. However, combined cycle units cycle less frequently
and have fewer startups and shutdowns per year. Startups of combined
cycle units are faster than coal-fired steam generating units described
in section VII.C.1.a.i(B)(7) of the preamble. Cold startups of combined
cycle units typically take not more than 3 hours (hot startups are
faster), and shutdown takes less than 1 hour. During startup, heat
input to the unit is lower to slowly raise the temperature of the HRSG.
Importantly, natural gas post-combustion flue gas does not require
the same pretreatment as coal post-combustion flue gas. Therefore,
amine solvents are able to capture CO2 as soon as the flue
gas contacts the lean solvent, and startup does not have to wait for
operation of other emission controls. Furthermore, there are several
different process strategies that can be employed to enable capture
during cold startup.792 793 These include using an
additional reserve of lean solvent (solvent without absorbed
CO2), dedicated heat storage for reboiler preheating, and
fast starting steam cycle technologies or high-pressure bypass
extraction. Each of these three options has been modeled to show that
95 percent capture rates can be achieved during startup. The first
option simply uses a reserve of lean solvent during startup so that
capture can occur without needing to wait for the stripping column
reboiler to heat up. For hot starts, the startup time of the NGCC is
faster, and since the reboiler is already warm, the capture plant can
begin operating faster. Shutdowns are short, and high capture
efficiencies can be maintained.
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\792\ https://ieaghg.org/ccs-resources/blog/new-ieaghg-report-2022-08-start-up-and-shutdown-protocol-for-power-stations-with-co2-capture.
\793\ https://assets.publishing.service.gov.uk/media/5f95432ad3bf7f35f26127d2/start-up-shut-down-times-power-ccus-main-report.pdf.
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Considering that startup and shutdown for natural gas combined
cycle units is fast, startups are relatively few, and simple process
strategies can be employed so that high capture efficiencies can be
achieved during startup, the EPA has concluded that startup and
shutdown do not adversely impact the achievable CO2 capture
rate.
Considering the preceding information, the EPA has determined that
90 percent capture is achievable over long periods (i.e., 12-month
rolling averages) for base load combustion turbines for all relevant
flue gas conditions, variable load, and startup and shutdown.
(g) Summary of Evidence Supporting BSER Determination Without EPAct05-
Aassisted Projects
As noted above, under the EPA's interpretation of the EPAct05
provisions, the EPA may not rely on capture projects that received
assistance under EPAct05 as the sole basis for a determination of
adequate demonstration, but the EPA may rely on those projects to
support or corroborate other information that supports such a
determination. The information described above that supports the EPA's
determination that 90 percent CO2 capture from natural gas-
fired combustion turbines is adequately demonstrated, without
consideration of the EPAct05-assisted projects, includes (i) the
information concerning coal-fired steam generating units listed in
VII.C.1.a.i.(B)(9) \794\ (other than the information concerning
EPAct05-assisted coal-fired unit projects and the information
concerning natural gas-fired combustion turbines); (ii) the information
that a 90 percent capture standard is achievable at coal-fired steam
generating units, also applies to natural gas-fired combined cycle EGUs
(i.e., all the information in VIII.F.4.c.iv.(B) (before (1)) and (1)
(before (a)); (iii) the information concerning CCS on combined cycle
EGUs (i.e., all the information in VIII.F.4.c.iv.(B)(1)(a)); and (iv)
the information concerning Net Power (i.e., all the information in
VIII.F.4.c.iv.(B)(1)(b)). All this information by itself is sufficient
to support the EPA's determination that 90 percent CO2
capture from coal-fired steam generating units is adequately
demonstrated. Substantial additional information from EPAct05-assisted
projects, as described in section VIII.F.4.c.iv.(B)(1)(e), provides
additional support and confirms that 90 percent CO2 capture
from natural gas-fired combustion turbines is adequately demonstrated.
---------------------------------------------------------------------------
\794\ Specifically, this includes the information concerning
Boundary Dam, coupled with engineering analysis concerning key
improvements that can be implemented in future CCS deployments
during initial design and construction (i.e., all the information in
section VII.C.1.a.i.(B)(1)(a) and the information concerning
Boundary Dam in section VII.C.1.a.i.(B)(1)(b)); (ii) the information
concerning other coal-fired demonstrations, including the Argus
Cogeneration Plant and AES's Warrior Run (i.e., all the information
concerning those sources in section VII.C.1.a.i.(B)(1)(a)); (iii)
the information concerning industrial applications of CCS (i.e., all
the information in section VII.C.1.a.i.(A)(1); and (iv) the
information concerning CO2 capture technology vendor
statements (i.e., all the information in VII.C.1.a.i.(B)(3)).
---------------------------------------------------------------------------
(2) Transport of CO2
In section VII.C.1.a.i.(C) of this document, the EPA described its
rationale for finalizing a determination that CO2 transport
by pipelines as a component of CCS is adequately demonstrated for use
of CCS with existing steam generating EGUs. The Agency's rationale for
finalizing the same determination--that CO2 transport by
pipelines as a component of CCS is adequately demonstrated for CCS use
with new combustion turbine EGUs--is much the same as that described in
section VII.C.1.a.i.(C). As discussed in
[[Page 39930]]
section VII.C.1.a.i.(C) of this preamble, CO2 pipelines are
available and their network is expanding in the U.S., and the safety of
existing and new supercritical CO2 pipelines is
comprehensively regulated by PHMSA.\795\ A new combustion turbine may
also be co-located with a storage site, so that minimal transport of
the CO2 is required.
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\795\ PHMSA additionally initiated a rulemaking in 2022 to
develop and implement new measures to strengthen its safety
oversight of CO2 pipelines following investigation into a
CO2 pipeline failure in Satartia, Mississippi in 2020.
For more information, see: https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
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Pipeline transport of CO2 captured from newly
constructed or reconstructed natural gas-fired combustion turbine EGUs
meets the BSER requirements based on the same evidence, and for the
same reasons, as does pipeline transport of CO2 captured
from existing coal-fired steam generating EGUs, as described in section
VII.C.1.a.i.(C) of this preamble. This is because the CO2
that is captured from a natural gas-fired turbine, compressed, and
delivered into a pipeline is indistinguishable from the CO2
that is captured from an existing coal-fired steam generating unit.
Accordingly, all the evidence and explanation in section
VII.C.1.a.i.(C) of this preamble that it is adequately demonstrated,
cost-effective, and consistent with the other BSER factors for an
existing coal-fired steam generating unit to construct a lateral
pipeline from its facility to a sequestration site applies to new
natural gas-fired turbines. This includes the history of CO2
pipeline build-out (VII.C.1.a.i.(C)(1)), the recent examples of new
pipelines (VII.C.1.a.i.(C)(1)(b)), EPAct05-assisted CO2
pipelines for CCS (VII.C.1.a.i.(C)(1)(c)), the network of existing and
planned CO2 trunklines (VII.C.1.a.i.(C)(1)(d)), permitting
and rights of way considerations (VII.C.1.a.i.(C)(2)), and
considerations of the security of CO2 transport, including
PHMSA requirements (VII.C.1.a.i.(C)(3)).
The only difference between pipeline transport for the coal-fired
steam generation and the gas-fired turbines is that the coal-fired
units are already in existence and, as a result, the location and
length of their pipelines, as needed to transport their CO2
to nearby sequestration, is already known, whereas new gas-fired
turbines are not yet sited. We discuss the implications for new gas-
fired turbines in the next section.
(3) Geologic Sequestration of CO2
In section VII.C.1.a.i.(D) of this document, the EPA described its
rationale for finalizing a determination that geologic sequestration
(i.e., the long-term containment of a CO2 stream in
subsurface geologic formations) is adequately demonstrated as a
component of the use of CCS with existing coal-fired steam generating
EGUs. Similar to the previous discussion regarding CO2
transport, the Agency's rationale for finalizing a determination that
geologic sequestration is adequately demonstrated as a component of the
use of CCS with new combustion turbine EGUs is the same as described in
VII.C.1.a.i.(D) for existing coal-fired steam generating EGUs. The
storage/sequestration sites used to store captured CO2 from
existing coal-fired EGUs could also be used to store captured
CO2 from newly constructed or reconstructed combustion
turbine EGUs. All of the considerations and challenges associated with
developing geologic storage sites for existing sources are also
considerations and challenges associated with developing such sites for
newly constructed or reconstructed sources.
(a) In General
Geologic sequestration (i.e., the long-term containment of a
CO2 stream in subsurface geologic formations) is well
proven. Deep saline formations, which may be evaluated and developed
for CO2 sequestration are broadly available throughout the
U.S. Geologic sequestration requires a demonstrated understanding of
the processes that affect the fate of CO2 in the subsurface.
As discussed in section VII.C.1.a.i.(D) of this preamble, there have
been numerous instances of geologic sequestration in the U.S. and
overseas, and the U.S. has developed a detailed set of regulatory
requirements to ensure the security of sequestered CO2. This
regulatory framework includes the UIC well regulations, which are under
the authority of the SDWA, and the GHGRP, under the authority of the
CAA.
Geologic settings which may be suitable for geologic sequestration
of CO2 are widespread and available throughout the U.S.
Through an availability analysis of sequestration potential in the U.S.
based on resources from the DOE, the USGS, and the EPA, the EPA found
that there are 43 states with access to, or are within 100 km from,
onshore or offshore storage in deep saline formations, unmineable coal
seams, and depleted oil and gas reservoirs.
All of the evidence and explanation that geological sequestration
of CO2 is adequately demonstrated and meets the other BSER
factors that the EPA described with respect to sequestration of
CO2 from existing coal-fired steam generating units in
section VII.C.1.a.i.(D) of this preamble apply with respect to
CO2 from new natural gas-fired combustion turbines.
Sequestration is broadly available (VII.C.1.a.i.(D)(1)(a)). It is
adequately demonstrated, with many examples of projects successfully
injecting and containing CO2 in the subsurface
(VII.C.1.a.i.(D)(2)). It provides secure storage, with a detailed set
of regulatory requirements to ensure the security of sequestered
CO2, including the UIC well regulations pursuant to SDWA
authority, and the GHGRP pursuant to CAA authority
(VII.C.1.a.i.(D)(4)). The EPA has the experience to properly regulate
and review permits for UIC Class VI injection wells, has made
considerable improvements to its permitting process to expedite
permitting decisions, and has granted several states primacy to issue
permits, and is supporting that state permitting (VII.C.1.a.i.(D)(5)).
(b) New Natural Gas-Fired Combustion Turbines
As discussed in section VII.C.1.a.i.(D)(1), deep saline formations
that may be considered for use in geologic sequestration (or storage)
are common in the continental United States. In addition, there are
numerous unmineable coal seams and depleted oil and gas reserves
throughout the country that could potentially be utilized as
sequestration sites. The DOE estimates that areas of the U.S. with
appropriate geology have a sequestration potential of at least 2,400
billion to over 21,000 billion metric tons of CO2 in deep
saline formations, unmineable coal seams, and oil and gas reservoirs.
The EPA's scoping assessment found that at least 37 states have
geologic characteristics that are amenable to deep saline sequestration
and identified an additional 6 states are within 100 kilometers of
potentially amenable deep saline formations in either onshore or
offshore locations. In terms of land area, 80 percent of the
continental U.S. is within 100 km of deep saline formations.\796\ While
the EPA's geographic availability analyses focus on deep saline
formations, other geologic formations such as unmineable coal seams or
depleted oil and gas
[[Page 39931]]
reservoirs represent potential additional CO2 storage
options. Therefore, we expect that the vast majority of new base load
combustion turbine EGUs could be sited within 100 km of a sequestration
site.
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\796\ For additional information on CO2
transportation and geologic sequestration availability, please see
EPA's final TSD, GHG Mitigation Measures for Steam Generating Units.
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While the potential for some type of sequestration exists in large
swaths of the continental U.S., we recognize that there are a few
states that do not have geologic conditions suitable for geologic
sequestration within or near their borders. If an area does not have a
suitable geologic sequestration site, then a utility or project
developer seeking to build a new combustion turbine EGU for base load
generation has two options--either (1) the new EGU may be located near
the electricity demand and the CO2 transported via a
CO2 pipeline to a geologic sequestration site, or (2) the
new EGU may be located closer to a geologic sequestration site and the
electricity delivered to customers through transmission lines.
Regarding option 1, as discussed in VII.C.1.a.i(C), the EPA believes
that both new and existing EGUs are capable of constructing
CO2 pipelines as needed. With regard to option 2, we expect
that this option may be preferred for projects where a CO2
pipeline of substantial length would be required to reach the
sequestration site. However, we note that for new base load combustion
turbine EGUs, project developers have flexibility with regard to siting
such that they can balance whether to site a new unit closer to a
potential geologic sequestration site or closer to a load area
depending on their specific needs.
Electricity demand in areas that may not have geologic
sequestration sites may be served by gas-fired EGUs that are built in
areas with geologic sequestration, and the generated electricity can be
delivered through transmission lines to the load areas through ``gas-
by-wire.'' An analogous approach, known as ``coal-by-wire'' has long
been used in the electricity sector for coal-fired EGUs because siting
a coal-fired EGU near a coal mine and transmitting the generated
electricity long distances to the load area is sometimes less expensive
than siting the coal EGU near the load area and shipping the coal long
distances. The same principle may apply to new base load combustion
turbine EGUs such that it may be more practicable for an project
developer to site a new base load combustion turbine EGU in a location
in close proximity to a geologic sequestration site and to deliver the
electricity generated through transmission lines to the load area
rather than siting the new gas-fired combustion turbine EGU near the
load area and building a lengthy pipeline to the geologic sequestration
site.
Gas-by-wire and coal-by-wire are possible due to the electricity
grid's extensive high voltage transmission networks that enable
electricity to be transmitted over long distances. See the memorandum,
Geographic Availability of CCS for New Base Load NGCC Units, which is
available in the rulemaking docket for this action. In many of the
areas without reasonable access to geologic sequestration, utilities,
electric cooperatives, and municipalities have a history of joint
ownership of electricity generation outside the region or contracting
with electricity generation in outside areas to meet demand. Some of
the areas are in Regional Transmission Organizations (RTOs),\797\ which
engage in planning as well as balancing supply and demand in real time
throughout the RTO's territory. Accordingly, generating resources in
one part of the RTO can serve load in other parts of the RTO, as well
as load outside of the RTO.
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\797\ In this discussion, the term RTO indicates both ISOs and
RTOs.
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In the coal context, there are many examples of where coal-fired
power generation in one state has been used to supply electricity in
other states. For example, the Prairie State Generating Plant, a 2-unit
1,600 MW coal-fired power plant in Illinois that is currently
considering retrofitting with CCS, serves load in eight different
states from the Midwest to the mid-Atlantic.\798\ The Intermountain
Power Project, a coal-fired plant located in Delta, Utah, that is
converting to co-fire hydrogen and natural gas, serves customers in
both Utah and California.\799\ Additionally, historically nearly 40
percent of the power for the City of Los Angeles was provided from two
coal-fired power plants located in Arizona and Utah. Further, Idaho
Power, which serves customers in Idaho and eastern Oregon has met
demand in part from power generating at coal-fired power plants located
in Wyoming and Nevada. This same concept of siting generation in one
location to serve demand in another area and using existing
transmission infrastructure to do so could similarly be applied to gas-
fired combustion turbine power plants, and, in fact, there are examples
of gas-fired combustion turbine EGUs serving demand more than 100 km
away from where they are sited. For example, Portland General
Electric's Carty Generating Station, a 436-MW NGCC unit located in
Boardman, Oregon \800\ serves demand in Portland, Oregon,\801\ which is
approximately 270 km away from the source.
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\798\ https://prairiestateenergycampus.com/about/ownership/.
\799\ https://www.ipautah.com/participants-services-area/.
\800\ Portland General Electric, ``Our Power Plants,'' https://portlandgeneral.com/about/who-we-are/how-we-generate-energy/our-power-plants.
\801\ See George Plaven, ``PGE power plant rising in E.
Oregon,'' The Columbian (October 10, 2015, 5:55 a.m.), https://www.columbian.com/news/2015/oct/10/pge-power-plant-rising-in-e-oregon/. See also Portland General Electric, ``PGE Service Area,''
https://portlandgeneral.com/about/info/service-area.
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In the memorandum, Geographic Availability of CCS for New Base Load
NGCC Units, we explore in detail the potential for gas-by-wire and the
ability of demand in areas without geologic sequestration potential to
be served by gas generation located in areas that have access to
geologic sequestration. As discussed in the memorandum, the vast
majority of the United States is within 100 km of an area with geologic
sequestration potential. A review of our scoping assessment indicates
that there are limited areas of the country that are not within 100 km
of a potential deep saline sequestration formation (although some of
these areas may be within 100 km of an unmineable coal seam or depleted
oil and gas reservoir that could potentially serve as a sequestration
site). In many instances, these areas include areas with low population
density, areas that are already served by transmission lines that could
deliver gas-by-wire, and/or include areas that have made policy or
other decisions not to pursue a resource mix that includes new NGCC due
to state renewable portfolio standards or for other reasons.
In many of these areas, utilities, electric cooperatives, and
municipalities have a history of obtaining electricity from generation
in outside areas to meet demand. Some of the relevant areas are in an
RTO or ISO, which operate the transmission system and dispatch
generation to balance supply and demand regionwide, as well as engage
in regionwide planning and cost allocation to facilitate needed
transmission development. Accordingly, generating resources in one part
of an RTO/ISO, such as through an NGCC plant, can serve loads in other
parts of the RTO/ISO, as well as serving load areas outside of the RTO/
ISO. As we consider each of these geographic areas in the memorandum,
Geographic Availability of CCS for New Base Load NGCC Units, we make
key points as to why this final rule does not negatively impact the
ability of these regions to access new NGCC generation to the extent
that NGCC generation is needed to supply demand and/or those regions
[[Page 39932]]
want to include new NGCC generation in their resource mixes.
(C) Costs
The EPA has evaluated the costs of CCS for new combined cycle
units, including the cost of installing and operating CO2
capture equipment as well as the costs of transport and storage. The
EPA has also compared the costs of CCS for new combined cycle units to
other control costs, in part derived from other rulemakings that the
EPA has determined to be cost-reasonable, and the costs are comparable.
Based on these analyses, the EPA considers the costs of CCS for new
combined cycle units to be reasonable. Certain elements of the
transport and storage costs are similar for new combustion turbines and
existing steam generating units. In this section, the EPA outlines
these costs and identifies the considerations specific to new
combustion turbines. These costs are significantly reduced by the IRC
section 45Q tax credit.
(1) Capture Costs
According to the NETL Fossil Energy Baseline Report (October 2022
revision), before accounting for the IRC section 45Q tax credit for
sequestered CO2, using a 90 percent capture amine-based
post-combustion CO2 capture system increases the capital
costs of a new combined cycle EGU by 115 percent on a $/kW basis,
increases the heat rate by 13 percent, increases incremental operating
costs by 35 percent, and derates the unit (i.e., decreases the capacity
available to generate useful output) by 11 percent.\802\ For a base
load combustion turbine, carbon capture increases the LCOE by 62
percent (an increase of 27 $/MWh) and has an estimated cost of $81/ton
($89/metric ton) of onsite CO2 reduction.\803\ The NETL
costs are based on the use of a second-generation amine-based capture
system without exhaust gas recirculation (EGR) and, as discussed below,
do not take into account further cost reductions that can be expected
to occur from efficiency improvements as post-combustion capture
systems are more widely deployed, as well as potential technological
developments.\804\
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\802\ CCS reduced the net output of the NETL F class combined
cycle EGU from 726 MW to 645 MW.
\803\ Although not our primary approach to assessing costs in
this final rule, for consistency with the proposal's assumption
capacity factor, these calculations use a service life of 30 years,
an interest rate of 7.0 percent, a natural gas price of $3.61/MMBtu,
and a capacity factor of 65 percent. These costs do not include
CO2 transport, storage, or monitoring costs.
\804\ Recent DOE analysis has compared the NETL costs with more
recent FEED study costs and expert interviews and determined they
are consistent after accounting for differences in inflation,
economic assumptions, and other technology details. Portfolio
Insights: Carbon Capture in the Power Sector, DOE. https://www.energy.gov/oced/portfolio-strategy.
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The flue gas from natural gas-fired combined cycle turbine differs
from that of coal-fired EGUs in several ways that impact the cost of
CO2 capture. These include that the CO2
concentration in the flue gas is approximately one-third of that
observed at coal-fired EGUs, the volumetric flow rate on a per MW basis
is larger, and the oxygen concentration is approximately 3 times that
of a coal-fired EGU. While the higher amount of excess oxygen has the
potential to reduce the efficiency of amine-based solvents that are
susceptible to oxidation, natural gas post-combustion flue gas does not
have other impurities (SO2, PM, trace metals) that are
present and must be managed in coal flue gas. Other important factors
include that the lower concentrations of CO2 reduce the
efficiency of the capture process and that the larger volumetric flow
rates require a larger CO2 absorber, which increases the
capital cost of the capture process. Exhaust gas recirculation (EGR),
also referred to as flue gas recirculation (FGR), is a process that
addresses all these issues. EGR diverts some of the combustion turbine
exhaust gas back into the inlet stream for the combustion turbine.
Doing so increases the CO2 concentration and decreases the
O2 concentration in the exhaust stream and decreases the
flow rate, producing more favorable conditions for CCS. One study found
that EGR can decrease the capital costs of a combined cycle EGU with
CCS by 6.4 percent, decrease the heat rate by 2.5 percent, decrease the
LCOE by 3.4 percent, and decrease the overall CO2 capture
costs by 11 percent relative to a combined cycle EGU without EGR.\805\
The EPA notes that the NETL costs on which the EPA bases its cost
calculations for combined cycle CCS do not assume the use of EGR, but
as discussed below, EGR use is plausible and would reduce those costs.
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\805\ Energy Procedia. (2014). Impact of exhaust gas
recirculation on combustion turbines. Energy and economic analysis
of the CO2 capture from flue gas of combined cycle power plants.
https://www.sciencedirect.com/science/article/pii/S1876610214001234.
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While the costs considered in the preceding are based on the
current costs of CCS, the EPA notes that the costs of capture systems
can be expected to decrease over the rest of this decade and continue
to decrease afterwards.\806\ As part of the plan to reduce the costs of
CO2 capture, the DOE is funding multiple projects to further
advance CCS technology from various point sources, including combined
cycle turbines, cement manufacturing plants, and iron and steel
plants.\807\ It should be noted that some of these projects may be
EPAct05-assisted. The general aim is to lower the costs of the
technologies, and to increase investor confidence in the commercial
scale applications, particularly for newer technologies or proven
technologies applied under unique circumstances. In particular, OCED's
Carbon Capture Demonstration Projects are targeted to accelerate
continued power sector carbon capture commercialization through
reducing costs and reducing uncertainties to project development. These
cost and uncertainty reductions arise from reductions in cost of
capital, increases in system scale, standardization and reduction in
non-recurring engineering costs, maturation of supply chain ecosystem,
and improvements in engineering design and materials over time.\808\
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\806\ For example, see the article CCUS Market Outlook 2023:
Announced Capacity Soars by 50%, which states, ``New gas power
plants with carbon capture, for example, could be cheaper than
unabated power in Germany as early as next year when coupled with
the carbon price.'' https://about.bnef.com/blog/ccus-market-outlook-2023-announced-capacity-soars-by-50/.
\807\ The DOE has also previously funded FEED studies for
natural gas-fired combined cycle turbine facilities. These include
FEED studies at existing combined cycle turbine facilities at Panda
Energy Fund in Texas, Elk Hills Power Plant in Kern County,
California, Deer Park Energy Center in Texas, Delta Energy Center in
Pittsburg, California, and utilization of a Piperazine Advanced
Stripper (PZAS) process for CO2 capture conducted by The
University of Texas at Austin.
\808\ Portfolio Insights: Carbon Capture in the Power Sector
report. DOE. https://www.energy.gov/oced/portfolio-strategy.
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Although current post-combustion CO2 capture projects
have primarily been based on amine capture systems, there are multiple
alternate capture technologies in development--many of which are funded
through industry research programs--that could yield reductions in
capital, operating, and auxiliary power requirements and could reduce
the cost of capture significantly or improve performance. More
specifically, post combustion carbon capture systems generally fall
into one of several categories: solvents, sorbents, membranes,
cryogenic, and molten carbonate fuel cells \809\ systems. It is
[[Page 39933]]
expected that as CCS infrastructure increases, technologies from each
of these categories will become more economically competitive. For
example, advancements in solvents that are potentially direct
substitutes for current amine-solvents will reduce auxiliary energy
requirements and reduce both operating and capital costs, and thereby,
increase the economic competitiveness of CCS.\810\ Planned large-scale
projects, pilot plants, and research initiatives will also decrease the
capital and operating costs of future CCS technologies.
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\809\ Molten carbonate fuel cells are configured for emissions
capture through a process where the flue gas from an EGU is routed
through the molten carbonate fuel cell that concentrates the
CO2 as a side reaction during the electric generation
process in the fuel cell. FuelCell Energy, Inc. (2018). SureSource
Capture. https://www.fuelcellenergy.com/recovery-2/suresource-capture/.
\810\ DOE. Carbon Capture, Transport, & Storage. Supply Chain
Deep Dive Assessment. February 24, 2022. https://www.energy.gov/sites/default/files/2022-02/Carbon%20Capture%20Supply%20Chain%20Report%20-%20Final.pdf.
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In general, CCS costs have been declining as carbon capture
technology advances.\811\ While the cost of capture has been largely
dependent on the concentration of CO2 in the gas stream,
advancements in varying individual CCS technologies tend to drive down
the cost of capture for other CCS technologies. The increase in CCS
investment is already driving down the costs of near-future CCS
technologies. The Global CCS Institute has tracked publicly available
information on previously studied, executed, and proposed
CO2 capture projects.\812\ The cost of CO2
capture from low-to-medium partial pressure sources such as coal-fired
power generation has been trending downward over the past decade, and
is projected to fall by 50 percent by 2025 compared to 2010. This is
driven by the familiar learning-processes that accompany the deployment
of any industrial technology. A review of learning rates (the reduction
in cost for a doubling of production or capacity) for various energy
related technologies similar to carbon capture (flue gas
desulfurization, selective catalytic reduction, combined cycle
turbines, pulverized coal boilers, LNG production, oxygen production,
and hydrogen production via steam methane reforming) demonstrated
learning rates of 5 percent to 27 percent for both capital expenditures
and operations and maintenance costs.813 814 Studies of the
cost of capture and compression of CO2 from power stations
completed 10 years ago averaged around $95/metric ton ($2020).
Comparable studies completed in 2018/2019 estimated capture and
compression costs could fall to approximately $50/metric ton
CO2 by 2025. Current target pricing for announced projects
at coal-fired steam generating units is approximately $40/metric ton on
average, compared to Boundary Dam whose actual costs were reported to
be $105/metric ton, noting that these estimates do not include the
impact of the 45Q tax credit as enhanced by the IRA. Additionally, IEA
suggests this trend will continue in the future as technology
advancements ``spill over'' into other projects to reduce costs.\815\
Similarly, EIA incorporates a minimum 20 percent reduction in carbon
capture and sequestration costs by 2035 in their Annual Energy Outlook
2023 modeling in part to account for the impact of spillover and
international learning.\816\ The Annual Technology Baseline published
by NREL with input from NETL projects a 10 percent reduction in capital
expenditures from 2021 through 2032 in the ``Conservative Technology
Innovation Scenario'' for natural gas carbon capture retrofit projects,
under the assumption that only learning processes lead to future cost
reductions and that there are no additional improvements from
investments in targeted technology research and development.\817\ In a
recent case study of the cost and performance of carbon capture
retrofits on existing natural gas combined cycle units, based on
discussions with external technology providers, engineering
consultants, asset developers, and applicants for DOE awards, DOE used
a 25 percent capital cost reduction estimate to illustrate the
potential future capital costs of an Nth-of-a-Kind facility, as well as
``conservatively model[ing]'' operating expense reductions at 1
percent, for a combined overall decrease in the levelized cost of
energy of about 10 percent for the Nth-of-a-Kind facility compared to a
First-of-a-Kind facility.\818\ DOE further found this illustrative cost
reduction estimate from learning through doing to be consistent with
other studies that use hybrid engineering-economic and experience-curve
approaches to estimate potential decreases in the levelized cost of
energy of 10-11 percent for Nth-of-a-Kind plants compared with First-
of-a-Kind plants.819 820 Policies in the IIJA and IRA are
further increasing investment in CCS technology that can accelerate the
pace of innovation and deployment.
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\811\ International Energy Agency (IEA) (2020). CCUS in Clean
Energy Transitions--A new era for CCUS. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus. The same is
true for CCS on coal-fired EGUs.
\812\ Technology Readiness and Costs of CCS (2021). Global CCS
Institute. https://www.globalccsinstitute.com/wp-content/uploads/2021/03/Technology-Readiness-and-Costs-for-CCS-2021-1.pdf.
\813\ https://www.sciencedirect.com/science/article/pii/S1750583607000163.
\814\ As an additional example for cost reductions from learning
processes via deployment achieved in other complex power generation
projects, the most recent sustained deployment of 19 nuclear
reactors in South Korea from 1989 through 2008 resulted in a 13
percent reduction in capital costs. https://www.sciencedirect.com/science/article/pii/S0301421516300106.
\815\ International Energy Agency (IEA) (2020). CCUS in Clean
Energy Transitions--CCUS technology innovation. https://www.iea.org/reports/ccus-in-clean-energy-transitions/a-new-era-for-ccus.
\816\ Energy Information Administration (EIA) (2023).
Assumptions to the Annual Energy Outlook 2023: Electricity Market
Module. https://www.eia.gov/outlooks/aeo/assumptions/pdf/EMM_Assumptions.pdf.
\817\ National Renewable Energy Laboratory (NREL) (2023). Annual
Technology Baseline 2023. https://atb.nrel.gov/electricity/2023/fossil_energy_technologies.
\818\ Portfolio Insights: Carbon Capture in the Power Sector.
DOE. 2024. https://www.energy.gov/oced/portfolio-strategy.
\819\ https://www.frontiersin.org/articles/10.3389/fenrg.2022.987166/full.
\820\ https://www.sciencedirect.com/science/article/pii/S1750583607000163.
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(2) CO2 Transport and Sequestration Costs
NETL's ``Quality Guidelines for Energy System Studies; Carbon
Dioxide Transport and Sequestration Costs in NETL Studies'' provides an
estimation of transport costs based on the CO2 Transport
Cost Model.\821\ The CO2 Transport Cost Model estimates
costs for a single point-to-point pipeline. Estimated costs reflect
pipeline capital costs, related capital expenditures, and operations
and maintenance costs.
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\821\ Grant, T., et al. ``Quality Guidelines for Energy System
Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
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NETL's Quality Guidelines also provide an estimate of sequestration
costs. These costs reflect the cost of site screening and evaluation,
permitting and construction costs, the cost of injection wells, the
cost of injection equipment, operation and maintenance costs, pore
volume acquisition expense, and long-term liability protection.
Permitting and construction costs also reflect the regulatory
requirements of the UIC Class VI program and GHGRP subpart RR for
geologic sequestration of CO2 in deep saline formations.
NETL calculates these sequestration costs on the basis of generic plant
locations in the Midwest, Texas, North Dakota, and Montana, as
described in the NETL energy system studies.\822\
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\822\ National Energy Technology Laboratory (NETL), ``FE/NETL
CO2 Saline Storage Cost Model (2017),'' U.S. Department of Energy,
DOE/NETL-2018-1871, 30 September 2017. https://netl.doe.gov/energy-analysis/details?id=2403.
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[[Page 39934]]
There are two primary cost drivers for a CO2
sequestration project: the rate of injection of the CO2 into
the reservoir and the areal extent of the CO2 plume in the
reservoir. The rate of injection depends, in part, on the thickness of
the reservoir and its permeability. Thick, permeable reservoirs provide
for better injection and fewer injection wells. The areal extent of the
CO2 plume depends on the sequestration capacity of the
reservoir. Thick, porous reservoirs with a good sequestration
coefficient will present a small areal extent for the CO2
plume and have lower testing and monitoring costs. NETL's Quality
Guidelines model costs for a given cumulative storage potential.\823\
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\823\ Department of Energy. Regional Direct Air Capture Hubs.
(2022). https://www.energy.gov/oced/regional-direct-air-capture-hubs.
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In addition, provisions in the IIJA and IRA are expected to
significantly increase the CO2 pipeline infrastructure and
development of sequestration sites, which, in turn, are expected to
result in further cost reductions for the application of CCS at a new
combined cycle EGUs. The IIJA establishes a new Carbon Dioxide
Transportation Infrastructure Finance and Innovation program to provide
direct loans, loan guarantees, and grants to CO2
infrastructure projects, such as pipelines, rail transport, ships and
barges.\824\ The IIJA also establishes a new Regional Direct Air
Capture Hubs program which includes funds to support four large-scale,
regional direct air capture hubs and more broadly support projects that
could be developed into a regional or inter-regional network to
facilitate sequestration or utilization.\825\ DOE is additionally
implementing IIJA section 40305 (Carbon Storage Validation and Testing)
through its CarbonSAFE initiative, which aims to further development of
geographically widespread, commercial-scale, safe storage.\826\ The IRA
increases and extends the IRC section 45Q tax credit, discussed next.
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\824\ DOE. Carbon Dioxide Transportation Infrastructure. https://www.energy.gov/lpo/carbon-dioxide-transportation-infrastructure.
\825\ Department of Energy. ``Regional Direct Air Capture
Hubs.'' (2022). https://www.energy.gov/oced/regional-direct-air-capture-hubs.
\826\ For more information, see the NETL announcement. https://www.netl.doe.gov/node/12405.
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(3) IRC Section 45Q Tax Credit
For the reasons explained in section VII.C.1.a.ii of this preamble,
in determining the cost of CCS, the EPA is taking into account the tax
credit provided under IRC section 45Q, as revised by the IRA. The tax
credit is available at $85/metric ton ($77/ton) and offsets a
significant portion of the capture, transport, and sequestration costs
noted above.
(4) Total Costs of CCS
In a typical NSPS analysis, the EPA amortizes costs over the
expected operating life of the affected facility and assumes constant
revenue and expenses over that period of time. For a new combustion
turbine, the expected operating life is 30 years. The EPA has adjusted
that analysis in this rule to account for the fact that the IRC section
45Q tax credit is available for only the 12 years after operation is
commenced. Since the duration of the tax credit is less than the
expected life of a new base load combustion turbine, the EPA conducted
the costing analysis by recognizing that the substantial revenue
available for sequestering CO2 during the first 12 years of
operation is expected to result in higher capacity factors for that
period, and the potential higher operating costs during the subsequent
18 years when the 45Q tax credit is not available is likely to result
in lower capacity factors (see final TSD, Greenhouse Gas Mitigation
Measures, Carbon Capture and Storage for Combustion Turbines for more
discussion).827 828
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\827\ In the proposal, the EPA used a constant 65 percent
capacity factor, representative of the initial capacity factor of
recently constructed combined cycle turbines, and effective 30-year
45Q tax credit of $41/ton. For this final rule, the EPA considers
the approach of using a higher capacity factor for the first 12
years and a lower one for the last 18 years to reflect more
accurately actual operating conditions, and therefore to be a more
realistic basis for calculating CCS costs.
\828\ The EPA's cost approach for CCS for existing coal-fired
units also assumed that those units would increase their capacity
during the 12-year period when the 45Q tax credit was available. See
preamble section VII.C.1.a.ii, and Greenhouse Gas Mitigation
Measures for Steam Generating Units TSD section 4.7.5. Because coal-
fired power plants are existing plants, the EPA calculated CCS costs
by assuming a 12-year amortization period for the CCS equipment, and
the EPA did not need to make any assumptions about the operation of
the coal-fired unit after the 12-year period.
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Specifically, the EPA's cost analysis assumes that the combined
cycle turbine operates at a capacity of 80 percent over the initial 12-
year period. This capacity level is generally consistent with the IPM
model projections of 87 percent (and, in fact, somewhat more
conservative). The 80 percent capacity factor assumption is also less
than the 85 percent capacity factor assumption in the NETL
analysis.\829\ But notably, the higher capacity factors in the IPM
analysis and in the NETL analysis suggest that higher capacity factors
may be reasonable and as figure 8 in the final TSD, Greenhouse Gas
Mitigation Measures, Carbon Capture and Storage for Combustion Turbines
demonstrates, would result in even lower costs. The analysis further
assumes that the turbine operates at a capacity of 31 percent during
the remaining 18-year period. As explained in the final TSD, Greenhouse
Gas Mitigation Measures Carbon Capture and Storage for Combustion
Turbines, to avoid impacting the compliance costs due to changes in the
overall capacity factors with the base case, the EPA kept the overall
30-year capacity factor at the historical average of 51 percent. The
EPA evaluated several operational scenarios (as described in the TSD).
The scenario with an initial 12-year capacity factor of 80 percent and
a subsequent 18-year capacity factor of 31 percent (for a 30-year
capacity factor of 51 percent) represents the primary policy case. It
should be noted that at a 31 percent capacity factor, the combustion
turbine would be subcategorized as an intermediate load combustion
turbine, and therefore would be subject to a less stringent standard of
performance that is based on efficient operation, not on the use of
CCS.
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\829\ Compliance costs would be lower if higher capacity factors
were used during the first 12 years of operation.
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This costing approach results in lower compliance costs than
assuming a constant capacity factor for the 30-year useful life of the
turbine because of increased revenue from generation during the initial
12-year period, increased revenue from the IRC section 45Q tax credits
during that period, and lower costs during the last 18 years when the
tax credit is not available. As noted, this is a reasonable approach
because the economic incentive provided by the tax credit is so
significant on a $/ton basis that the EPA expects sources to dispatch
at higher levels while the tax credit is in effect.
The EPA calculated two sets of CCS costs: the first assumes that
the turbine continues to operate the capture system during the last 18
years, and the second assumes that the turbine does not operate the
capture system during the last 18 years.\830\ Assuming continued
operation of the capture equipment, the compliance costs are $15/MWh
and $46/ton ($51/metric ton) for a 6,100 MMBtu/h H-Class turbine, which
has a net output of approximately 990 MW; and $19/MWh and $57/ton ($63/
metric ton) for a 4,600 MMBtu/h F-Class turbine, which has a net output
of
[[Page 39935]]
approximately 700 MW.831 832 If the capture system is not
operated while the combustion turbine is subcategorized as an
intermediate load combustion turbine, the compliance costs are reduced
to $8/MWh and $43/ton ($47/metric ton) for a 6,100 MMBtu/h H-Class
combustion turbine, and $12/MWh and $60/ton ($66/metric ton) for a
4,600 MMBtu/h F-Class combustion turbine. All of these costs are
comparable to the cost metrics that, based on prior rules, the EPA
finds to be reasonable in this rulemaking.\833\ For a more detailed
discussion of costs, see the TSD--GHG Mitigation Measures--Carbon
Capture and Storage for Combustion Turbines, section 2.3, Figure 12a.
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\830\ The CCS and CO2 TS&M costs are amortized over
the period the equipment is operated--30 years or 12 years.
\831\ The output of the H-Class model combined cycle EGU without
CCS is 992 MW. The auxiliary load of CCS reduces the net out to 883
MW. The output of the F-Class model combined cycle EGU without CCS
is 726 MW. The auxiliary load of CCS reduces the net out to 645 MW.
\832\ As we explain in the final TSD, GHG Mitigation Measures--
Carbon Capture and Storage for Combustion Turbines, sections 2.3-
2.5, the 6,100 MMBtu/h H-Class combustion turbine is the median size
of recently constructed combined cycle facilities and the 4,600
MMBtu/h F-Class combustion turbine approximates the size of a number
of recently constructed combined cycle facilities as well. CCS costs
for smaller sources are higher but are not prohibitive. GHG
Mitigation Measures--Carbon Capture and Storage for Combustion
Turbines TSD, section 2.3, Figures 12a and 13. As noted in RTC
section 3.1, we expect costs to decrease due to learning by doing
and technological development. In addition, since the incremental
generating costs of larger more efficient combined cycle turbines
are lower relative to smaller combined cycle turbines, it is more
likely that larger more efficient combined cycle turbine will
operate as base load combustion turbines.
\833\ A DOE analysis of a representative NGCC plant using CCS in
the ERCOT market indicates that operating at high operating capacity
could be profitable today with the IRC 45Q tax credits. Portfolio
Insights: Carbon Capture in the Power Sector. DOE. https://www.energy.gov/oced/portfolio-strategy.
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The EPA considers these CCS cost estimates to be conservatively
high because they do not take into account cost improvements from the
potential use of exhaust gas recirculation, which, according to one
study, could lower LCOE by 3.4 percent, as described in preamble
section VIII.F.4.c.iv.(C)(1). Nor do they consider the potential for
additional efficiency improvements for combined cycle units \834\ or
CCS technological advances, as discussed in preamble section
VIII.F.4.c.iv.(B)(1)(b), VIII.F.4.c.iv.(C)(1), and RTC section 3.1. The
EPA considers that at least some of these cost improvements are likely.
Accordingly, the EPA also calculated the CCS costs based on an assumed
5 percent reduction in costs, in order to approximate these likely
improvements, as follows: Assuming continued operation of the capture
equipment, the compliance costs are $13/MWh and $40/ton ($44/metric
ton) for a 6,100 MMBtu/h H-Class combustion turbine, and $18/MWh and
$54/ton ($59/metric ton) for a 4,600 MMBtu/h F-Class combustion
turbine. If the capture system is not operated while the combustion
turbine is subcategorized as in intermediate load combustion turbine,
the compliance costs are reduced to $8/MWh and $39/ton ($43/metric ton)
for a 6,100 MMBtu/h H-Class combustion turbine, and $11/MWh and $56/ton
($61/metric ton) for a 4,600 MMBtu/h F-Class combustion turbine.
---------------------------------------------------------------------------
\834\ These additional efficiency improvements are noted in the
final TSD, Efficient Generation: Combustion Turbine Electric
Generating Units.
---------------------------------------------------------------------------
In addition, the EPA considers all those costs to be conservative
(in favor of higher costs) because they assume that the combustion
turbine operator will not receive any revenues from captured
CO2 after the 12-year period for the tax credit. In fact, it
is plausible that there will be sources of revenue, potentially
including from the sale of the CO2 for utilization and
credits to meet state or corporate clean energy goals, as discussed in
RTC section 2.2.4.3.
It should be noted that natural gas-fired combustion turbines with
CCS may well generate at higher capacity factors after the expiration
of the 45Q tax credit than the EPA's above-described BSER cost analysis
assumes. In fact, the EPA's IPM model projects that the natural gas
combined cycle generation that is projected to install CCS in the
illustrative final rule scenario operates at an average 73 percent
capacity factor, due to existing state regulatory requirements, during
the 2045 model year, which is after the expiration of the 45Q tax
credit. In addition, as discussed in RTC section 2.2.4.3, it is
plausible that following the 12-year period of the tax credit, by the
2040s, cost improvements in CCS operations, more widespread adoption of
CO2 emission limitation requirements in the electricity
sector, and greater demand for CO2 for beneficial uses will
support continued operation of fossil fuel-fired generation with CCS.
Accordingly, the EPA also calculated CCS costs assuming that new F-
Class and H-Class combustion turbines with CCS generate at a constant
capacity factor of at least 60 percent, and up to 80 percent, during
their 30-year useful life. In this calculation, the EPA amortized the
costs of CCS over the 30-year useful life of the turbine. The EPA
includes these costs in the final TSD, GHG Mitigation Measures--Carbon
Capture and Storage for Combustion Turbines, section 2.3, Figure
8.\835\ At the lower levels of capacity, costs are higher than
described above (which assumed 80 percent capacity during the first 12
years), but even at those lower levels, the costs are broadly
consistent with the cost-reasonable metrics based on prior rules,
particularly when those costs are reduced by an additional 5 percent to
account for improved efficiency and other factors, as noted above.
Nonetheless, consistent with the EPA's commitment to review, and if
appropriate, revise the emission guidelines for coal-fired steam
generating units as discussed in section VII.F, the EPA also intends to
evaluate, by 2041, the continued cost-reasonableness of CCS for natural
gas-fired combustion turbines in light of these potential significant
developments, and will consider at that time whether a future
regulatory action may be appropriate.
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\835\ The compliance costs assume the same capacity factors in
the base and policy case, that is, without CCS and with CCS. If
combined cycle turbine with CCS were to operate at higher capacity
factors in the policy case, compliance costs would be reduced.
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(5) Comparison to Other Costs of Controls
The costs for CCS applied to a representative new base load
stationary combustion turbine EGU are generally lower than the costs of
other controls in EPA rules for fossil fuel-fired electric generating
units, as well as the costs of other controls for greenhouse gases, as
described in section VII.C.1.a.ii(D), which supports the EPA's view
that the CCS costs are reasonable.
(D) Non-Air Quality Health and Environmental Impact and Energy
Requirements
In this section of the preamble, the EPA considers the non-air
quality health and environmental impacts of CCS for new combined cycle
turbines and concludes there are limited consequences related to non-
air quality health and environmental impact and energy requirements.
The EPA first discusses energy requirements, and then considers non-GHG
emissions impacts and water use impacts, resulting from the capture,
transport, and sequestration of CO2.
With respect to energy requirements, including a 90 percent or
greater carbon capture system in the design of a new combined cycle
turbine will increase the unit's parasitic/auxiliary energy demand and
reduce its net power output. A utility that wants to construct a
combined cycle turbine to provide 500 MWe-net of power could build a
[[Page 39936]]
500 MWe-net plant knowing that it will be de-rated by 11 percent (to a
444 MWe-net plant) with the installation and operation of CCS. In the
alternative, the project developer could build a larger 563 MWe-net
combined cycle turbine knowing that, with the installation of the
carbon capture system, the unit will still be able to provide 500 MWe-
net of power to the grid. Although the use of CCS imposes additional
energy demands on the affected units, those units are able to
accommodate those demands by scaling larger, as needed.
Regardless of whether a unit is scaled larger, the installation and
operation of CCS itself does not impact the unit's potential-to-emit
any criteria air pollutants. In other words, a new base load stationary
combustion turbine EGU constructed using highly efficient generation
(the first component of the BSER) would not see an increase in
emissions of criteria air pollutants as a direct result of installing
and using 90 percent or greater CO2 capture CCS to meet the
second phase standard of performance.\836\
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\836\ While the absolute onsite mass emissions would not
increase from the second component of the BSER, the emissions rate
on a lb/MWh-net basis would increase by 13 percent.
---------------------------------------------------------------------------
Scaling a unit larger to provide heat and power to the
CO2 capture equipment would have the potential to increase
non-GHG air emissions. However, most pollutants would be mitigated or
controlled by equipment needed to meet other CAA requirements. In
general, the emission rates and flue gas concentrations of most non-GHG
pollutants from the combustion of natural gas in stationary combustion
turbines are relatively low compared to the combustion of oil or coal
in boilers. As such, it is not necessary to use an FGD to pretreat the
flue gas prior to CO2 removal in the CO2 scrubber
column. The sulfur content of natural gas is low relative to oil or
coal and resulting SO2 emissions are therefore also
relatively low. Similarly, PM emissions from combustion of natural gas
in a combustion turbine are relatively low. Furthermore, the high
combustion efficiency of combustion turbines results in relatively low
HAP emissions. Additionally, combustion turbines at major sources of
HAP are subject to the stationary combustion turbine NESHAP, which
includes limits for formaldehyde emissions for new sources that may
require installation of an oxidation catalyst (87 FR 13183; March 9,
2022). Regarding NOX emissions, in most cases, the
combustion turbines in new combined cycle units will be equipped with
low-NOX burners to control flame temperature and reduce
NOX formation. Additionally, new combined cycle units are
typically subject to major NSR requirements for NOX
emissions, which may require the installation of SCR to comply with a
control technology determination by the permitting authority. See
section XI.A of this preamble for additional details regarding the NSR
program. Although NOX concentrations may be controlled by
SCR, for some amine solvents NOX in the post-combustion flue
gas can react in the CO2 absorber to form nitrosamines. A
conventional multistage water wash or acid wash and a mist eliminator
at the exit of the CO2 scrubber is effective at removal of
gaseous amine and amine degradation products (e.g., nitrosamine)
emissions.837 838 Acetaldehyde and formaldehyde can form
through oxidation of the solvent, however, this can be mitigated by
selecting compatible materials to limit catalytic oxidation and
interstage cooling in the absorber to limit thermal oxidation.
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\837\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
\838\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
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The use of water for cooling presents an additional issue. Due to
their relatively high efficiency, combined cycle EGUs have relatively
small cooling requirements compared to other base load EGUs. According
to NETL, a combined cycle EGU without CCS requires 190 gallons of
cooling water per MWh of electricity. CCS increases the cooling water
requirements due both to the decreased efficiency and the cooling
requirements for the CCS process to 290 gallons per MWh, an increase of
about 50 percent. However, because combined cycle turbines require
limited amounts of cooling water, the absolute amount of increase in
cooling water required due to use of CCS is relatively small compared
to the amount of water used by a coal-fired EGU. A coal-fired EGU
without CCS requires 450 gallons or more per MWh and the industry has
demonstrated an ability to secure these quantities of water and the EPA
has determined that the increased water requirements for CCS can be
addressed. In addition, many combined cycle EGUs currently use dry
cooling technologies and the use of dry or hybrid cooling technologies
for the CO2 capture process would reduce the need for
additional cooling water. Therefore, the EPA is finalizing a
determination that the challenges of additional cooling requirements
from CCS are limited and do not disqualify CCS from being the BSER.
Stakeholders have shared with the EPA concerns about the safety of
CCS projects and that historically disadvantaged and overburdened
communities may bear a disproportionate environmental burden associated
with CCS projects.\839\ The EPA takes these concerns seriously, agrees
that any impacts to historically disadvantaged and overburdened
communities are important to consider, and has done so as part of its
analysis discussed at section XII.E. For the reasons noted above, the
EPA does not expect CCS projects to result in uncontrolled or
substantial increases in emissions of non-GHG air pollutants from new
combustion turbines. Additionally, 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. These
projects will likely be subject to major NSR requirements for their
emissions of criteria pollutants, and therefore the sources would be
required to (1) control their emissions of attainment pollutants by
applying BACT and demonstrate the emissions will not cause or
contribute to a NAAQS violation, and (2) control their emissions of
nonattainment pollutants by applying LAER and fully offset the
emissions by securing emission reductions from other sources in the
area. Also, as mentioned in section VII.C.1, carbon capture systems
that are themselves a major source of HAP should evaluate the
applicability of CAA section 112(g) and conduct a case-by-case MACT
analysis if required, to establish MACT for any listed HAP, including
listed nitrosamines, formaldehyde, and acetaldehyde. But, as also
discussed in section VII.C.1, a conventional multistage water or acid
wash and mist eliminator (demister) at the exit of the CO2
scrubber is effective at removal of gaseous amine and amine degradation
products (e.g., nitrosamine) emissions. Additionally, as noted in
[[Page 39937]]
section VII.C.1.a.i.(C) of this preamble, PHMSA oversight of
supercritical CO2 pipeline safety protects against
environmental release during transport and UIC Class VI regulations
under the SDWA, in tandem with GHGRP requirements, ensure the
protection of USDWs and the security of geologic sequestration.
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\839\ In outreach with potentially vulnerable communities,
residents have voiced two primary concerns. First, there is the
concern that their communities have experienced historically
disproportionate burdens from the environmental impacts of energy
production, and second, that as the sector evolves to use new
technologies such as CCS, they may continue to face disproportionate
burden. This is discussed further in section XII.E of this preamble.
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The EPA is committed to working with its fellow agencies to foster
meaningful engagement with communities and protect communities from
pollution. This can be facilitated through the existing detailed
regulatory framework for CCS projects and further supported through
robust and meaningful public engagement early in the technological
deployment process.
The EPA also expects that the meaningful engagement requirements
discussed in section X.E.1.b.i of this preamble will ensure that all
interested stakeholders, including community members who might be
adversely impacted by non-GHG pollutants, will have an opportunity to
raise this concern with states and permitting authorities.
Additionally, state permitting authorities, and project developers are,
in general, required to provide public notice and comment on permits
for such projects. This provides additional opportunities for affected
stakeholders to engage in that process, and it is the EPA's expectation
that the responsible entities consider these concerns and take full
advantage of existing protections. Moreover, the EPA through its
regional offices is committed to thoroughly review permits associated
with CO2 capture.
(E) Impacts on the Energy Sector
The EPA does not believe that determining CCS to be BSER for base
load combustion turbines will cause reliability concerns, for several
independent reasons. First, the EPA is finalizing a determination that
the costs of CCS are reasonable and comparable to other control
requirements the EPA has required the electric power industry to adopt
without significant effects on reliability. Second, base load combined
cycle turbines are only one of many options that companies have to
build new generation. The EPA expects there to be considerable interest
in building intermediate load and low load combustion turbines to meet
demand for dispatchable generation. Indeed, the portion of the
combustion turbine fleet that is operating at base load is declining as
shown in the EPA's reference case modeling (Power Sector Platform 2023
using IPM reference case, see section IV.F of the preamble). In 2023,
combined cycle turbines are only expected to represent 14 percent of
all new generating capacity built in the U.S. and only a portion of
that is natural gas combined cycle capacity.\840\ Several companies
have recently announced plans to move away from new combined cycle
turbine projects in favor of more non-base load combustion turbines,
renewables, and battery storage. For example, Xcel recently announced
plans to build new renewable power generation instead of the combined
cycle turbine it had initially proposed to replace the retiring Sherco
coal-fired plant.\841\ Finally, while CCS is adequately demonstrated
and cost-reasonable, this final rulemaking allows companies that want
to build a base load combined cycle turbine another compliance option
to meet its requirements: building a unit that co-fires low-GHG
hydrogen in the appropriate amount to meet the standard of performance.
In fact, companies are currently pursuing both of these options--units
with CCS as well as units that will co-fire low-GHG hydrogen are both
in various stages of development. For these reasons, determining CCS to
be the BSER for base load units will not cause reliability concerns.
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\840\ https://www.eia.gov/todayinenergy/detail.php?id=55419.
\841\ https://cubminnesota.org/xcel-is-no-longer-pursuing-gas-power-plant-proposes-more-renewable-power/.
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(F) Extent of Reductions in CO2 Emissions
Designating CCS as a component of the BSER for certain base load
combustion turbine EGUs prevents large amounts of CO2
emissions. For example, a new base load combined cycle EGU without CCS
could be expected to emit 45 million tons of CO2 over its
30-year operating life, or 1.5 million tons of CO2 per year.
Use of CCS would avoid the release of nearly 41 million tons of
CO2 over the operating life of the combined cycle EGU, or
1.37 million tons per year. However, due to the auxiliary/parasitic
energy requirements of the carbon capture system, capturing 90 percent
of the CO2 does not result in a corresponding 90 percent
reduction in CO2 emissions. According to the NETL baseline
report, adding a 90 percent CO2 capture system increases the
EGU's gross heat rate by 7 percent and the unit's net heat rate by 13
percent. Since more fuel would be consumed in the CCS case, the gross
and net emissions rates are reduced by 89.3 percent and 88.7 percent
respectively. These amounts of CO2 emissions and reductions
are larger than for any other industrial source, except for coal-fired
steam generating units.
(G) Promotion of the Development and Implementation of Technology
The EPA also considered whether determining CCS to be a component
of the BSER for new base load combustion turbines will advance the
technological development of CCS and concluded that this factor further
corroborates our BSER determination. A standard of performance based on
highly efficient generation in combination with the use of CCS--
combined with the availability of IRC section 45Q tax credits and
investments in supporting CCS infrastructure from the IIJA--should
result in more widespread adoption of CCS. In addition, while solvent-
based CO2 capture has been adequately demonstrated at the
commercial scale, a CCS-based standard of performance may incentivize
the development and use of better-performing solvents or other
components of the capture equipment.
Furthermore, the experience gained by utilizing CCS with stationary
combustion turbine EGUs, with their lower CO2 flue gas
concentration relative to other industrial sources such as coal-fired
EGUs, will advance capture technology with other lower CO2
concentration sources. The EIA 2023 Annual Energy Outlook projects that
almost 862 billion kWh of electricity will be generated from natural
gas-fired sources in 2040.\842\ Much of that generation is projected to
come from existing combined cycle EGUs and further development of
carbon capture technologies could facilitate increased retrofitting of
those EGUs.
---------------------------------------------------------------------------
\842\ Does not include 114 billion kilowatt hours from natural
gas-fired CHP projected in AEO 2023.
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(H) Summary of BSER Determination
As discussed, the EPA is finalizing a determination that the second
component of the BSER for base load stationary combustion turbines is
the utilization of CCS at 90 percent capture. The EPA has determined
that 90 percent CCS meets the criteria for BSER for new base load
combustion turbines. It is an adequately demonstrated technology that
can be implemented a reasonable cost. Importantly, use of CCS at 90
percent capture results in significant reductions of CO2 as
compared to a base load combustion turbine without CCS. In addition,
the EPA has considered non-air quality and energy impacts. Considering
all these factors together, with particular emphasis on the importance
of significantly reducing carbon pollution from these heavily utilized
sources, the EPA concludes that
[[Page 39938]]
CCS at 90 percent capture is BSER for new base load combustion
turbines. In addition, selecting CCS at 90 percent capture further
promotes the development and implementation of this critical carbon
pollution reduction technology, which confirms the appropriateness of
determining it to be the BSER.
The BSER for base load combustion turbines contains two components
and the EPA is promulgating standards of performance to be implemented
in two phases with each phase reflecting the degree of emission
reduction achievable through the application of each component of the
BSER. The first component of the BSER is most efficient generation--an
affected new base load combustion turbine must be constructed (or
reconstructed) to meet a phase 1 emission standard that reflects the
emission rate of the best performing combustion turbine systems. The
phase 1 standard of performance for base load combustion turbines is in
effect immediately once the source begins operation. The second
component of the BSER, as just discussed, is use of CCS at a 90 percent
capture rate. The phase 2 standard of performance for base load
combustion turbines reflects the implementation of 90 capture CCS on a
highly efficient combined cycle combustion turbine system. The
compliance date begins January 1, 2032.
(I) January 2032 Compliance Date
The EPA proposed a compliance date beginning January 1, 2035, for
new and reconstructed base load stationary combustion turbines subject
to the phase 2 standard of performance based on CCS as the BSER. Some
commenters were supportive of the proposed compliance date and some
urged the EPA to set an earlier compliance date; the EPA also received
comments on the proposed rule that stated that the proposed compliance
date was not achievable and referenced longer project timelines for
CO2 capture. The EPA has considered the comments and
information available and is finalizing a compliance date of January 1,
2032, for the phase 2 standard of performance for base-load stationary
combustion turbines. The EPA is also finalizing a mechanism for a
compliance date extension of up to 1 year in cases where a source faces
a delay in the installation and startup of controls that are beyond the
control of the EGU owner or operator, as detailed in section VIII.N of
this preamble.
In total, the January 1, 2032, compliance date allows for more than
7 years for installation of CCS after issuance of this rule for sources
that have recently commenced construction. This is consistent with the
extended project schedule in the Sargent & Lundy report. This is also
greater than the approximately 6 years from start to finish for
Boundary Dam Unit 3 and Petra Nova.
As discussed in section VII.C.1.a.i(E), the timing for installation
of CCS on existing coal-fired steam generating units is based on the
baseline project schedule for the capture plant developed by Sargent
and Lundy (S&L) \843\ and a review of the available information for
installation of CO2 pipelines and sequestration sites.\844\
The representative timeline for CCS for coal-fired steam generating
units is detailed in the final TSD, GHG Mitigation Measures for Steam
Generating Units, available in the docket, and the anticipated timeline
for development of a CCS project for application at a new or
reconstructed base load stationary combustion turbine would be similar.
The explanations the EPA provided in section VII.C.1.a.i(E) regarding
the timeline for long-term coal-fired steam generating units generally
apply to new combustion turbines as well. The EPA expects that the
owners or operators of affected combustion turbines will be able to
complete the design, planning, permitting, engineering, and
construction steps for the carbon capture and transport and storage
systems in a similar amount of time as projects for coal-fired EGUs.
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\843\ CO2 Capture Project Schedule and Operations
Memo, Sargent & Lundy (2024).
\844\ Transport and Storage Timeline Summary, ICF (2024).
---------------------------------------------------------------------------
While those considerations apply in general, the EPA notes that the
timeline for the installation of CCS on coal-fired steam generating
units accounted for the state plan development process. Because there
are not state plans required for new combustion turbines, new sources
can commit to beginning substantial work earlier (e.g., FEED studies,
right-of-way acquisition), immediately after the completion of
feasibility work. However, the EPA also recognizes that other elements
of a state plan (e.g., RULOF), by which a source under specific
circumstances could have a later compliance date, are not available to
new sources. Therefore, while the timeline for CCS on coal-fired steam
generating units is based on the baseline S&L capture plant schedule
(about 6.25 years), the EPA bases the timeline for CCS on new
combustion turbines on the extended S&L capture plant schedule (7
years).
As discussed, base load stationary combustion turbines that
commence construction or reconstruction on or after May 23, 2023, are
subject to standards of performance that are implemented initially in
two phases. New stationary combustion turbines that are designed and
constructed for the purpose of operating in the base load subcategory
(i.e., at a 12-operating month capacity factor of greater than 40
percent) that hypothetically commenced construction on May 23, 2023,
could, according to the schedule allowing, conservatively, up to 7
years to develop a CCS project, have a system constructed and on-line
by May 23, 2030. However, the EPA is finalizing a compliance date of
January 1, 2032, because some base load combined cycle stationary
combustion projects that commenced construction between May 23, 2023,
and the date of this final rule, may not have included CCS in the
original design and planning for the new EGU and, therefore, would be
unlikely to be able to have an operational CCS system available by May
23, 2030.
Further, the EPA notes that a delayed compliance date (of January
1, 2035) was proposed for the phase 2 standards of performance due to
overlapping demands on the capacity to design, construct, and operate
carbon capture systems as well as pipeline systems that would
potentially be needed to support CCS projects for existing steam
generating units and other industrial sources. As discussed in section
VII.C.1.a.i(E), in this action the EPA is finalizing a compliance date
of January 1, 2032 for long term coal-fired steam generating EGUs to
meet a standard of performance based on 90 percent capture CCS. This
compliance date for long-term coal-fired steam generating EGUs places
fewer demands on the capacity to design, construct, and operate carbon
capture systems and the associated infrastructure for those sources.
Therefore, the EPA does not believe that there is a need to extend the
compliance date for phase 2 standards for base load combustion turbine
EGUs by 5 years beyond that for existing coal-fired steam generating
EGUs, as proposed.
Considering these factors, the EPA is therefore finalizing the
compliance date of January 1, 2032 for base load combustion turbine
EGUs to meet the phase 2 standard of performance. This is the same
compliance date applicable to existing long term coal-fired steam
generating EGUs that are subject to a standard of performance based on
90 percent capture CCS. The EPA assumes the timelines for development
of the various components of CCS for an existing coal-fired steam
generating
[[Page 39939]]
EGU, as discussed in section VII.C.1.a.i(E), are very similar for those
components for a CCS system serving a new or reconstructed base load
combustion turbine EGU.
Some commenters argued that because the power sector will require
some amount of time before CCS and associated infrastructure may be
installed on a widespread basis, CCS cannot be considered adequately
demonstrated. This argument is similar to the argument, discussed in
section V.C.2.b, that in order to be adequately demonstrated, a
technology must be in widespread commercial use. Both arguments are
incorrect. Under CAA section 111, for a control technology to qualify
as the BSER, the EPA must demonstrate that it is adequately
demonstrated for affected sources. The EPA must also show that the
industry can deploy the technology at scale in the compliance
timeframe. That the EPA has provided lead time in order to ensure
adequate time for industry to deploy the technology at scale shows that
the EPA is meeting its statutory obligation, not the inverse. Indeed,
it is not at all unusual for the EPA to provide lead time for industry
to deploy new technology. The EPA's approach is in line with the
statutory text and caselaw encouraging technology-forcing standard-
setting cabined by the EPA's obligation to ensure that its standards
are reasonable and achievable.
CCS is clearly adequately demonstrated, and ripe for wider
implementation. Nevertheless, the EPA acknowledged in the proposed
rule, and reaffirms now, that the power sector will require some amount
of lead time before individual plants can install CCS as necessary.
Deploying CCS requires the building of capture facilities, pipelines to
transport captured CO2 to sequestration sites, and the
development of sequestration sites. This is true for both existing
coal-fired steam generating EGUs, some of which would be required to
retrofit with CCS under the emission guidelines included in this final
rulemaking, and new gas-fired combustion turbine EGUs, which must
incorporate CCS into their construction planning.
In this final rulemaking, the EPA is setting a compliance deadline
of January 1, 2032 for the CCS-based standard for new base load
combustion turbines. The EPA determined, examining the evidence and
exercising its appropriate discretion to do so, that this is a
reasonable amount of time to allow for CCS buildout at the plant level.
As the EPA explained at proposal, D.C. Circuit caselaw supports this
approach. There, the EPA cited Portland Cement v. Ruckelshaus, for the
proposition that ``D.C. Circuit caselaw supports the proposition that
CAA section 111 authorizes the EPA to determine that controls qualify
as the BSER--including meeting the `adequately demonstrated'
criterion--even if the controls require some amount of `lead time,'
which the court has defined as `the time in which the technology will
have to be available.' '' (footnote omitted). Nothing in the comments
alters the EPA's view of the relevant legal requirements related to
adequate demonstration or lead time.
d. BSER for Base Load Subcategory--Third Component
The EPA proposed a third component of the BSER of 96 percent (by
volume) hydrogen co-firing in 2038 for owners/operators of base load
combustion turbines that elected to comply with the low-GHG hydrogen
co-firing pathway. As discussed in the next section, the EPA is not
finalizing the proposed BSER pathway of low-GHG hydrogen co-firing at
this time. Therefore, the Agency is not finalizing a third component of
the BSER for base load combustion turbines.
5. Technologies Proposed by the EPA But Ultimately Not Determined To Be
the BSER
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 as part of this action. In light of public
comments and additional analysis, uncertainties regarding projected
costs prevent the EPA from determining that low-GHG hydrogen is a
component of the BSER at this time.
The next section provides a summary of the proposed requirements
for low-GHG hydrogen followed by, in section VIII.F.5.b, an explanation
for why the Agency is not finalizing its proposed determination that
low-GHG hydrogen co-firing is BSER. In section VIII.F.6, the EPA
discusses considerations for the potential use of hydrogen. In section
VIII.F.6.a, the Agency explains why it is not limiting the hydrogen
that may be co-fired in a new or reconstructed combustion turbine to
only low-GHG hydrogen. In section VIII.F.6.b, the Agency discusses its
decision to not include a definition of low-GHG hydrogen.
a. Proposed Low-GHG Hydrogen Co-Firing BSER
The EPA proposed that new and reconstructed intermediate load
combustion turbines were subject to a second component of the BSER that
consisted of co-firing 30 percent (by volume) low-GHG hydrogen by 2032.
The EPA also proposed that new and reconstructed base load combustion
turbines could elect either (i) a second component of BSER that
consisted of installing CCS by 2035, or (ii) a second and third
component of BSER that consisted of co-firing 30 percent (by volume)
low-GHG hydrogen by 2032 and co-firing 96 percent (by volume) low-GHG
hydrogen by 2038.
The EPA solicited comment on whether the Agency should finalize
both the CCS and low-GHG hydrogen co-firing pathways as separate
subcategories with separate standards of performance and on whether the
EPA should finalize one pathway with the option of meeting the standard
of performance using either system of emission reduction (88 FR 33277,
May 23, 2023). The EPA also solicited comment on the option of
finalizing a single standard of performance based on the application of
CCS for the base load subcategory (88 FR 33283, May 23, 2023).
b. Explanation for Not Finalizing Low-GHG Hydrogen Co-Firing as a BSER
The EPA is not finalizing a low-GHG hydrogen co-firing component of
the BSER at this time. The EPA proposed that co-firing low-GHG hydrogen
qualified as a BSER pathway because the components of the system met
specific criteria, namely that the capability of combustion turbines to
co-fire hydrogen was adequately demonstrated and there was a reasonable
expectation that the necessary quantities of low-GHG hydrogen would be
nationally available by 2032 and 2038 at reasonable cost. Due to
concerns raised by commenters, the EPA conducted additional analysis of
key components of the low-GHG hydrogen best system and the Agency's
proposed determination that low-GHG hydrogen co-firing qualified as the
BSER. This additional analysis, discussed further below, indicated that
the currently estimated cost of low-GHG hydrogen in 2030 is higher than
anticipated at proposal. These higher cost estimates were key factors
in the EPA's decision to revise its 2030 cost estimate for delivered
low-GHG hydrogen.
While the EPA is not finalizing a BSER determination with regard to
co-firing with low-GHG hydrogen as part of this rulemaking and is
therefore not making any determination about whether such a practice is
adequately demonstrated, the Agency notes that there are multiple
models of combustion turbines available from major manufacturers that
have successfully
[[Page 39940]]
demonstrated the ability to combust hydrogen. Manufacturers have stated
that they expect to have additional models of combustion turbines
available that will be capable of firing 100 percent hydrogen while
limiting emissions of other pollutants (e.g., NOX). The EPA
further discusses considerations around the technical feasibility of
hydrogen co-firing in new and reconstructed combustion turbines, and
what they mean for the potential use of hydrogen co-firing as a
compliance strategy, in section VIII.F.6 of this preamble.
While the EPA believes that hydrogen co-firing is technically
feasible based on combustion turbine technology, information about how
the low-GHG hydrogen production industry will develop in the future is
not sufficiently certain for the EPA to be able to determine that
adequate quantities will be available. That is, there remain, at the
time of this final rulemaking, uncertainties pertaining to how the
future nationwide availability of low-GHG hydrogen will develop.
Relatedly, estimates of its future costs are more uncertain than
anticipated at proposal. For low-GHG hydrogen to meet the BSER criteria
as proposed, the EPA would have to be able to determine that
significant quantities of low-GHG hydrogen will be available at
reasonable costs such that affected sources in the power sector
nationwide could rely on it for use by 2032 and 2038. While some
analyses \845\ show that this will likely be the case, the full set of
information necessary to support such a determination is not available
at this time. However, the EPA believes this may change as the low-GHG
hydrogen industry continues to develop. The Agency plans to monitor the
development of the industry; if appropriate, the EPA will reevaluate
its findings and establish standards of performance that achieve
additional emission reductions. Furthermore, as noted above, the EPA
considers the co-firing of hydrogen to be technically feasible in
multiple models of available combustion turbines.
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\845\ Electric Power Research Institute (EPRI). (November 3,
2023). Impact of IRA's 45V Clean Hydrogen Production Tax Credit.
White paper. https://www.epri.com/research/products/000000003002028407.
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As noted above, the EPA has revised its cost analysis of low-GHG
hydrogen and determined that, due to the present uncertainty, estimated
future hydrogen costs are higher than at proposal. The higher estimated
cost of low-GHG hydrogen relative to proposal is the key factor in the
EPA's decision to not finalize low-GHG hydrogen co-firing as a BSER
pathway for new and reconstructed base load and intermediate load
combustion turbines at this time.
In the proposal, the EPA modeled low-GHG hydrogen as a fuel
available at a fixed delivered \846\ price of $1/kg (or $7.40/MMBtu) in
the baseline. This cost decreased to $0.50/kg (or $3.70/MMBtu) in the
Integrated Proposal case when the second phase of the new combustion
turbine standard began in 2032. This fuel was assumed to be ``clean''
and eligible for the highest subsidy under the IRC section 45V hydrogen
production tax credit and would comply with the proposed requirement to
use low-GHG hydrogen (88 FR 33314, May 23, 2023). The EPA's revised
modeling of the power sector for the final rule used a price of $1.15/
kg for delivered low-GHG hydrogen in both the final baseline and policy
cases. For additional discussion of the EPA's revised modeling of the
power sector and increased cost estimate for low-GHG hydrogen, see the
final RIA included in the docket for this rulemaking.
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\846\ The delivered price includes the cost to produce,
transport, and store hydrogen.
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The U.S. Department of Energy's 2022 report, Pathways to Commercial
Liftoff: Clean Hydrogen, informed the EPA's revised low-GHG hydrogen
cost analysis. According to the DOE report, the cost to produce,
transport, store, and deliver low-GHG or ``clean'' hydrogen is expected
to be between $0.70/kg and $1.15/kg by 2030 with the IRA's $3/kg
maximum IRC section 45V production tax credit included.\847\ The report
also points out that the power sector is competing with other
industrial sectors--such as transportation, ammonia and chemical
production, oil refining, and steel manufacturing--in terms of
potential downstream applications of clean hydrogen for the purpose of
reducing GHG emissions. The DOE report also estimates that $0.40/kg to
$0.50/kg is the price the power sector would be willing to pay for
clean hydrogen.
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\847\ U.S. Department of Energy (DOE) (March 2023). Pathways to
Commercial Liftoff: Clean Hydrogen. https://liftoff.energy.gov/wp-content/uploads/2023/05/20230523-Pathways-to-Commercial-Liftoff-Clean-Hydrogen.pdf.
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Some analyses of future hydrogen costs provide estimates that are
higher than those of the DOE. For example, public commenters estimated
the cost of delivered ``clean'' hydrogen to be less than $3/kg by 2030
before declining to $2/kg by 2035. These estimates of delivered
hydrogen costs include the IRC section 45V hydrogen production tax
credits contained in the IRA, but they do not reflect regulations
proposed by the U.S. Department of the Treasury pertaining to clean
hydrogen production tax and energy credits, which proposed certain
eligibility parameters (88 FR 89220, December 26, 2023). Until
Treasury's regulations on the IRC section 45V hydrogen production tax
credit are final, some analysts only estimate future production costs
of hydrogen, not delivered costs, and do not include any projected
potential impacts of the IRA incentives. For example, both McKinsey and
BloombergNEF project the unsubsidized production cost of clean hydrogen
to be approximately $2/kg by 2030, which could lead to negative to zero
prices for some subsidized hydrogen after considering transportation
and storage.848 849 One of the highest estimates for the
unsubsidized production cost of clean hydrogen is from the Rhodium
Group, which estimates the price to be from $3.39/kg to $4.92/kg in
2030.\850\ Again, it should be noted these estimates do not include
additional costs for transportation and storage. The increased cost
projections for low-GHG hydrogen production are partly due to higher
costs for capital equipment, such as electrolyzers. The DOE published a
Program Record \851\ detailing higher costs than previously estimated
by levering data from the regional clean hydrogen hubs and other
literature. Costs increases are predominantly driven by inflation,
supply chain cost increases, and higher estimated installation costs.
However, there is a significant range in electrolyzer costs; some
companies cite costs that are significantly lower ($750-$900/kW
installed cost) \852\ than that published in the Program Record.
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\848\ Heid, B.; Sator, A.; Waardenburg, M.; and Wilthaner, M.
(25 Oct 2022). Five charts on hydrogen's role in a net-zero future.
McKinsey & Company. https://www.mckinsey.com/capabilities/sustainability/our-insights/five-charts-on-hydrogens-role-in-a-net-zero-future.
\849\ Schelling, K. (9 Aug 2023). Green Hydrogen to Undercut
Gray Sibling by End of Decade. BloombergNEF. https://about.bnef.com/blog/green-hydrogen-to-undercut-gray-sibling-by-end-of-decade/.
\850\ Larsen, J.; King, B.; Kolus, H.; Dasari, N.; Bower, G.;
and Jones, W. (12 Aug 2022). A Turning Point for US Climate
Progress: Assessing the Climate and Clean Energy Provisions in the
Inflation Reduction Act. Rhodium Group. https://rhg.com/research/climate-clean-energy-inflation-reduction-act/.
\851\ U.S. Department of Energy (DOE). (February 22, 2024).
Summary of Electrolyzer Cost Data Synthesized from Applications to
the DOE Clean Hydrogen Hubs Program. DOE Hydrogen Program, Office of
Clean Energy Demonstrations Program Record. https://www.hydrogen.energy.gov/docs/hydrogenprogramlibraries/pdfs/24002-summary-electrolyzer-cost-data.pdf.
\852\ Martin, P. (December 18, 2023). What gives Bill Gates-
backed start-up Electric Hydrogen the edge over other electrolyzer
makers? Hydrogen Insight. https://www.hydrogeninsight.com/electrolysers/what-gives-bill-gates-backed-start-up-electric-hydrogen-the-edge-over-other-electrolyser-makers-/2-1-1572694.
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[[Page 39941]]
6. Considerations for the Potential Use of Hydrogen
The ability of combustion turbines to co-fire hydrogen can
effectively reduce stack GHG emissions. Hydrogen also offers unique
solutions for decarbonization because of its potential to provide
dispatchable, clean energy with long-term storage and seasonal
capabilities. For example, hydrogen is an energy carrier that can
provide long-term storage of low-GHG energy that can be co-fired in
combustion turbines and used to balance load with the increasing
volumes of variable generation. These services support the reliability
of the power system while facilitating the integration of variable
zero-emitting energy resources and supporting decarbonization of the
electric grid. One technology with the potential to reduce curtailment
is energy storage, and some power producers envision a role for
hydrogen to supplement natural gas as a fuel to support the balancing
and reliability of an increasingly decarbonized electric grid.
Hydrogen is a zero-GHG emitting fuel when combusted, so that co-
firing it in a combustion turbine in place of natural gas reduces GHG
emissions at the stack. For this reason, certain owners/operators of
combustion turbines in the power sector may elect to co-fire hydrogen
in the coming years to reduce onsite GHG emissions.\853\ Co-firing low-
emitting fuels--sometimes referred to as clean fuels--is a traditional
type of emissions control. However, the EPA recognizes 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
method. These differences in GHG emissions from the different methods
of hydrogen production are well-recognized in the energy sector (88 FR
33306, May 23, 2023), and, in fact, hydrogen is generally characterized
by its production method and the attendant level of GHG emissions.
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\853\ In June 2022, the U.S. Department of Energy (DOE) Loans
Program Office issued a $504.4 million loan guarantee to finance the
Advanced Clean Energy Storage (ACES) project in Delta, Utah. ACES
expects to utilize a 220 MW bank of electrolyzers and curtailed
renewable energy to produce clean hydrogen that will be stored in
salt caverns. The hydrogen will fuel an 840 MW combined cycle
combustion turbine at the Intermountain Power Project facility.
https://www.energy.gov/lpo/advanced-clean-energy-storage.
---------------------------------------------------------------------------
While the focus of this rule is the reduction of stack GHG
emissions from combustion turbines, the EPA also recognizes that, to
ensure overall GHG benefits, it is important any hydrogen used in the
power sector be low-GHG hydrogen. Thus, even though the EPA is not
finalizing the use of low-GHG hydrogen as a component of the BSER for
base load or intermediate load combustion turbines, it maintains that
the type of hydrogen used (i.e., the method by which the hydrogen was
produced) should be a primary consideration for any source that decides
to co-fire hydrogen. Again, the Agency reiterates its concern that
sources in the power sector that choose to co-fire hydrogen to reduce
their GHG emission rate should co-fire only low-GHG hydrogen to achieve
overall GHG reductions and important climate benefits.
In the proposal, the EPA solicited comment on whether it is
necessary to require low-GHG hydrogen. Similarly, the EPA also
solicited comment as to whether the low-GHG hydrogen requirement could
be treated as severable from the remainder of the standard such that
the standard could function without this requirement. The EPA also
solicited comment on a host of recordkeeping and reporting topics.
These pertained to the complexities of tracking the sources of
quantities of produced low-GHG hydrogen and the public interest in such
data.
a. Explanation for Not Requiring Hydrogen Used for Compliance To Be
Low-GHG Hydrogen
The EPA proposed that the type of hydrogen co-fired must be limited
to low-GHG hydrogen, and not include other types of hydrogen.\854\ This
requirement was proposed to prevent the anomalous outcome of a GHG
control strategy contributing to an increase in overall GHG emissions;
the provision that only low-GHG hydrogen could be used for compliance
mirrored the EPA's proposal that low-GHG hydrogen, in particular, could
qualify as a component of the BSER. For the reasons explained below,
the EPA is not finalizing a requirement that any hydrogen that sources
choose to co-fire must be low-GHG hydrogen. However, the Agency
continues to stress, notwithstanding the lack of requirement under this
rule, the importance of ensuring that any hydrogen used in combustion
turbines is low-GHG hydrogen. The EPA's choice to not finalize a low-
GHG requirement at this time is based in large part on knowledge of
current and future efforts that will reinforce the availability and
role of low-GHG hydrogen in the national economy and, more
specifically, in the power sector. As discussed further below, this
decision is against the backdrop of ongoing developments in the public
and private sectors, Treasury's regulations implementing a tax credit
for the production of clean hydrogen, multiple Federal government grant
and assistance programs, and the EPA's investigation into methods to
control emissions of air pollutants from hydrogen production.
---------------------------------------------------------------------------
\854\ 88 FR 33240, 33315 (May 23, 2023).
---------------------------------------------------------------------------
The EPA's decision to not require that any hydrogen used for
compliance be low-GHG hydrogen was based primarily on the current
market and policy developments regarding hydrogen production at this
particular point in time, including the clean hydrogen production tax
credits. There are currently multiple private and public efforts to
develop, inter alia, greenhouse gas accounting practices, verification
protocols, reporting conventions, and other elements that will help
determine how low-GHG hydrogen is measured, tracked, and verified over
the next several years. For example, Treasury is expected to finalize
parameters for evaluating overall emissions associated with hydrogen
production pathways as it prepares to implement IRC section 45V.\855\
The overall objective of Treasury's parameters is to recognize that
different methods of hydrogen production generate different amounts of
GHG emissions while encouraging lower-emitting production methods
through the multi-tier hydrogen production tax credit (IRC section 45V)
(see 88 FR 89220, December 26, 2023). In light of these nascent but
fast-moving efforts, the EPA does not believe it is reasonable or
helpful to prescribe its own definitions, protocols, and requirements
for low-GHG hydrogen at this point in time.
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\855\ U.S. Department of the Treasury. (October 5, 2022).
Treasury Seeks Public Input on Implementing the Inflation Reduction
Act's Clean Energy Tax Incentives. Press release. https://home.treasury.gov/news/press-releases/jy0993.
---------------------------------------------------------------------------
Furthermore, the Agency anticipates that combustion turbines will,
despite not being required to do so, use low-GHG hydrogen (to the
extent they are co-firing hydrogen as a compliance strategy). Depending
on market development in the coming decade, it is reasonable to expect
that any hydrogen used in the power sector would generally be low-GHG
hydrogen, even without a specific BSER pathway or low-GHG-only
requirement included in this final NSPS. For example, several utilities
with dedicated access to affordable low-GHG hydrogen are actively
developing co-firing projects with the goal of reducing their GHG
[[Page 39942]]
emissions. The infrastructure funding and tax incentives included in
the IIJA and the IRA are also driving the development of the low-GHG
hydrogen supply chain. These rapid changes in the hydrogen marketplace
not only counsel against the EPA's locking in its own requirements at
this time; they also provide confidence that greater quantities of low-
GHG hydrogen will be available moving forward, even if the precise
timing and quantity cannot currently be accurately forecast. The EPA
also provides information further below about its intentions to open a
non-regulatory docket to engage stakeholders on potential future
rulemakings for thermochemical-based hydrogen production facilities to
address issues pertaining to GHG, criteria, and HAP emissions.
i. Hydrogen Production and Associated GHGs
Hydrogen is used in industrial processes; in recent years,
applications of hydrogen co-firing have also expanded to include
stationary combustion turbines used to generate electricity. Several
commenters responded to the proposal by stating that to fully evaluate
the potential GHG emission reductions from co-firing low-GHG hydrogen
in a combustion turbine EGU, it is important to consider the different
processes for producing hydrogen and the GHG emissions associated with
each process. The EPA agrees that the method of hydrogen production is
critical to consider when assessing whether hydrogen co-firing actually
reduces overall GHG emissions. As stated previously, the varying levels
of CO2 emissions associated with different hydrogen
production processes are well-recognized, and stakeholders routinely
refer to hydrogen on the basis of the different production processes
and their different GHG profiles.
ii. Technological and Market Transformation of Low-GHG Hydrogen
Resources
In the proposal, the EPA highlighted ongoing efforts--independent
of any BSER pathway, requirement, or performance standard--of
combustion turbine manufacturers and industry stakeholders to research,
develop, and deploy hydrogen co-firing technologies (88 FR 33307, May
23, 2023). Their co-firing demonstrations are producing results, such
as increasing the percentages (by volume) of hydrogen that a turbine
can combust while answering questions regarding safety, performance,
reliability, durability, and the emission of other pollutants (e.g.,
NOX). Such efforts by industry to invest in the development
of hydrogen co-firing, and specifically in projects designed to co-fire
low-GHG hydrogen, in particular, give the EPA confidence that any
hydrogen that sources do choose to co-fire for compliance under this
rule will be low-GHG hydrogen. As these efforts progress, a sharper
understanding of costs will come into focus while significant Federal
funding--through grants, financial assistance programs, and tax
incentives included in the IIJA and the IRA discussed below--is
intended to support the continued development of a nationwide clean
hydrogen supply chain.
For the most part, companies that have announced that they are
exploring the use of hydrogen co-firing have stated that they intend to
use low-GHG hydrogen in the future as greater quantities of the fuel
become available at lower, stabilized prices. Many utilities and
merchant generators own and are developing low-GHG electricity
generating sources as well as combustion turbines, with the intent to
produce low-GHG hydrogen for sale and to use a portion of it to fuel
their stationary combustion turbines.856 857 This emerging
trend lends support to the view that, while acknowledging the
uncertainty of the ultimate timing of implementation, there is growing
interest in hydrogen co-firing in the power sector and stakeholders are
developing these resources with the intent to increase access to low-
GHG hydrogen as they increase hydrogen utilization in their co-firing
applications. Additional information provided by commenters and
analysis by the EPA identified several new combustion turbine projects
planning to co-fire low-GHG hydrogen, even though these low-GHG methods
of hydrogen production are not currently readily available on a
nationwide basis.858 859 860
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\856\ Mitsubishi Power. (2020). Intermountain Power Agency
Orders MHPS JAC Gas Turbine Technology for Renewable-Hydrogen Energy
Hub. https://power.mhi.com/regions/amer/news/200310.html.
\857\ Intermountain Power Agency (2022). https://www.ipautah.com/ipp-renewed/.
\858\ Los Angeles Department of Water & Power (2023). Initial
Study: Scattergood Generating Station Units 1 and 2 Green Hydrogen-
Ready Modernization Project. https://ceqanet.opr.ca.gov/2023050366.
\859\ https://clkrep.lacity.org/onlinedocs/2023/23-0039_rpt_DWP_02-03-2023.pdf.
\860\ Hering, G. (2021). First major US hydrogen-burning power
plant nears completion in Ohio. S&P Global Market Intelligence.
https://www.spglobal.com/platts/en/market-insights/latest-news/electric-power/081221-first-major-us-hydrogen-burning-power-plant-nears-completion-in-ohio.
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iii. Infrastructure Funding and Tax Incentives Included in the IIJA and
IRA
In both the IIJA and the IRA, Congress provided extensive support
for the development of hydrogen produced through low-GHG methods. This
support includes investment in infrastructure through the IIJA, and the
provision of tax credits in the IRA to incentivize the manufacture of
hydrogen through low GHG-emitting methods over the coming decades. For
example, the IIJA included the H2Hubs program, the Clean Hydrogen
Manufacturing and Recycling Program, the Clean Hydrogen Electrolysis
Program, and a non-regulatory Clean Hydrogen Production Standard
(CHPS).\861\ In the IRA, Congress enacted or expanded tax credits to
encourage the production and use of low-GHG hydrogen.\862\ In addition,
as discussed in the proposal, IRA section 60107 added new CAA section
135, or the Low Emission Electricity Program (LEEP). This provision
provides $1 million for the EPA to assess the GHG emissions reductions
from changes in domestic electricity generation and use anticipated to
occur annually through fiscal year 2031; and further provides $18
million for the EPA to promulgate additional CAA rules to ensure GHG
emissions reductions that go beyond the reductions expected in that
assessment. CAA section 135(a)(5)-(6).
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\861\ U.S. Department of Energy (DOE). (September 22, 2022).
Clean Hydrogen Production Standard. Hydrogen and Fuel Cell
Technologies Office. https://www.energy.gov/eere/fuelcells/articles/clean-hydrogen-production-standard.
\862\ These tax credits include IRC section 45V (tax credit for
production of hydrogen through low- or zero-emitting processes), IRC
section 48 (tax credit for investment in energy storage property,
including hydrogen production), IRC section 45Q (tax credit for
CO2 sequestration from industrial processes, including
hydrogen production); and the use of hydrogen in transportation
applications, IRC section 45Z (clean fuel production tax credit),
IRC section 40B (sustainable aviation fuel credit).
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Given the incentives provided in both the IRA and IIJA for low-GHG
hydrogen production and the current trajectory of hydrogen use in the
power sector, by 2032, the start date for compliance with the proposed
second phase of the NSPS, low-GHG hydrogen may be more widely available
and possibly the most common source of hydrogen available for
electricity production. It is also possible that the cost of delivered
low-GHG hydrogen will continue to decline toward the DOE's Hydrogen
Shot target. These expectations are based on a combination of economies
of scale as low-GHG production methods expand, the increasing
availability of low-cost input electricity--largely powered by zero- or
low-emitting energy sources--
[[Page 39943]]
and learning by doing as more combustion turbine projects are
developed. The EPA recognizes that the pace and scale of government
programs and private research suggest that the Agency will gain
significant experience and knowledge on this topic in the future.
iv. EPA Non-Regulatory Docket and Stakeholder Engagement on Potential
Regulatory Approaches for Emissions From Thermochemical Hydrogen
Production
In addition to the ongoing industry development of and
Congressional support for low-GHG hydrogen, the EPA is also taking
steps consistent with the importance of mitigating GHG emissions
associated with hydrogen production. On September 15, 2023, the EPA
received a petition from the Environmental Defense Fund (EDF) along
with 13 other health, environmental, and community groups, to regulate
fossil and other thermochemical methods of hydrogen production given
the current emissions from these facilities and the anticipated growth
in the sector spurred by IRA incentives. The petition notes that
facilities producing hydrogen for sale produced about 10 MMT of
hydrogen and emitted more than 40 MMT of CO2e in 2020.\863\
Regulatory safeguards are advocated by petitioners to help ensure that
the anticipated growth in this sector does not result in an unbounded
increase in emissions of GHGs, criteria, and hazardous air pollutants
(HAP). The petition requests that the EPA list hydrogen production
facilities as significant sources of pollution under CAA sections 111
and 112, and that the EPA develop both standards of performance for new
and modified hydrogen production facilities as well as emission
guidelines for existing facilities. The development of emission
standards for HAP, including but not limited to methanol, was also
requested by petitioners. Petitioners assert that emissions of
CO2, NOX, and PM should be addressed under the
EPA's section 111 authorities, and HAP should be addressed by EPA
regulations under section 112.\864\ The EPA is reviewing the petition.
As a predicate to potential future rulemakings, the Agency is
developing a set of framing questions and opening a non-regulatory
docket to solicit public comment on potential approaches for regulation
of GHGs and criteria pollutants under CAA section 111 and an
exploration of the appropriateness of regulating HAP emissions under
CAA section 112 and on potential section 114 reporting requirements to
address this growing industry.
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\863\ Petition for Rulemaking to List and Establish National
Emission Standards for Hydrogen Production Facilities under the
Clean Air Act Sections 111 and 112. The petition can be accessed at
https://www.edf.org/sites/default/files/2023-09/Petition%20for%20Rulemaking%20-%20Hydrogen%20Production%20Facilities%20-%20CAA%20111%20and%20112%20-%20EDF%20et%20al.pdf.
\864\ Id.
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b. Definition of Low-GHG Hydrogen
The EPA proposed to define low-GHG hydrogen as hydrogen produced
with emissions of less than 0.45 kg CO2e/kg H2,
from well-to-gate, which aligned with the highest of the four tiers of
tax credits available for hydrogen production, IRC section
45V(b)(2)(D). At that GHG emission rate or less, hydrogen producers are
eligible for a tax credit of $3/kg. With these provisions, Congress
indicated its judgement as to what GHG levels could be attained by the
lowest-GHG hydrogen production, and its intention to incentivize
production of that type of hydrogen. Congress's views informed the
EPA's proposal to define low-GHG hydrogen for purposes of making the
BSER for this CAA section 111 rulemaking consistent with IRC section
45V(b)(2)(D).
The EPA solicited comment broadly on its proposed definition for
low-GHG hydrogen, and on alternative approaches, to help develop
reporting and recordkeeping requirements that would have ensured that
co-firing low-GHG hydrogen minimized GHG emissions, and that combustion
turbines subject to this standard utilized only low-GHG hydrogen. The
EPA also solicited comment on whether it was necessary to provide a
definition of low-GHG hydrogen in this final rule.
The EPA is not finalizing a definition of low-GHG hydrogen in this
action. Because the Agency is not finalizing co-firing with low-GHG
hydrogen as a component of the BSER for certain combustion turbines and
is not finalizing a requirement that any hydrogen co-fired for
compliance by low-GHG hydrogen, there is no reason to finalize a
definition of low-GHG hydrogen at this time.
7. Other Options for BSER
The EPA considered several other systems of emission reduction as
candidates for the BSER for combustion turbines but is not determining
them to be the BSER. They include partial capture CCS, CHP and the
hybrid power plant, as discussed below.
a. Partial Capture CCS
Partial capture for CCS was not determined to be BSER because the
emission reductions are lower and the costs would, in general, be
higher. As discussed in section IV, individual natural gas-fired
combined cycle combustion turbines are the second highest-emitting
individual plants in the nation, and the natural gas-fired power plant
sector is higher-emitting than all other sectors. CCS at 90 percent
capture removes very high absolute amounts of emissions. Partial
capture CCS would fail to capture large quantities of emissions. With
respect to costs, designs for 90 percent capture in general take
greater advantage of economy of scale. Eligibility for the IRC section
45Q tax credit for existing EGUs requires design capture rates
equivalent to 75 percent of a baseline emission rate by mass. Sources
with partial capture rates that do not meet that requirement would not
be eligible for the tax credit and as a result, for them, the CCS
requirement would be too expensive to qualify for as the BSER. Even
assuming partial capture rates meet that definition, lower capture
rates would receive fewer returns from the IRC section 45Q tax credit
(since these are tied to the amount of carbon sequestered, and all else
equal lower capture rates would result in lower amounts of sequestered
carbon) and costs would thereby be higher.
b. Combined Heat and Power (CHP)
CHP, also known as cogeneration, is the simultaneous production of
electricity and/or mechanical energy and useful thermal output from a
single fuel. CHP requires less fuel to produce a given energy output,
and because less fuel is burned to produce each unit of energy output,
CHP has lower-emission rates and can be more economic than separate
electric and thermal generation. However, a critical requirement for a
CHP facility is that it primarily generates thermal output and
generates electricity as a byproduct and must therefore be physically
close to a thermal host that can consistently accept the useful thermal
output. It can be particularly difficult to locate a thermal host with
sufficiently large thermal demands such that the useful thermal output
would impact the emissions rate. The refining, chemical manufacturing,
pulp and paper, food processing, and district energy systems tend to
have large thermal demands. However, the thermal demand at these
facilities is generally only sufficient to support a smaller EGU,
approximately a maximum of several hundred MW. This
[[Page 39944]]
would limit the geographically available locations where new generation
could be constructed in addition to limiting its size. Furthermore,
even if a sufficiently large thermal host were in close proximity, the
owner/operator of the EGU would be required to rely on the continued
operation of the thermal host for the life of the EGU. If the thermal
host were to shut down, the EGU could be unable to comply with the
standard of performance. This reality would likely result in difficulty
in securing funding for the construction of the EGU and could also lead
the thermal host to demand discount pricing for the delivered useful
thermal output. For these reasons, the EPA did not propose CHP as the
BSER.
c. Hybrid Power Plant
Hybrid power plants combine two or more forms of energy input into
a single facility with an integrated mix of complementary generation
methods. While there are multiple types of hybrid power plants, the
most relevant type for this proposal is the integration of solar energy
(e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both
coal-fired and combined cycle turbine EGUs have operated using the
integration of concentrating solar thermal energy for use in boiler
feed water heating, preheating makeup water, and/or producing steam for
use in the steam turbine or to power the boiler feed pumps.
One of the benefits of integrating solar thermal with a fossil
fuel-fired EGU is the lower capital and operation and maintenance (O&M)
costs of the solar thermal technology. This is due to the ability to
use equipment (e.g., HRSG, steam turbine, condenser, etc.) already
included at the fossil fuel-fired EGU. Another advantage is the
improved electrical generation efficiency of the non-emitting
generation. For example, solar thermal often produces steam at
relatively low temperatures and pressures, and the conversion of the
thermal energy in the steam to electricity is relatively low
efficiency. In a hybrid power plant, the lower quality steam is heated
to higher temperatures and pressures in the boiler (or HRSG) prior to
expansion in the steam turbine, where it produces electricity.
Upgrading the relatively low-grade steam produced by the solar thermal
facility in the boiler improves the relative conversion efficiencies of
the solar thermal to electricity process. The primary incremental costs
of the non-emitting generation in a hybrid power plant are the costs of
the mirrors, additional piping, and a steam turbine that is 10 to 20
percent larger than that in a comparable fossil-only EGU to accommodate
the additional steam load during sunny hours. A drawback of integrating
solar thermal is that the larger steam turbine will operate at part
loads and reduced efficiency when no steam is provided from the solar
thermal panels (i.e., the night and cloudy weather). This limits the
amount of solar thermal that can be integrated into the steam cycle at
a fossil fuel-fired EGU.
In the 2018 Annual Energy Outlook,\865\ the levelized cost of
concentrated solar power (CSP) without transmission costs or tax
credits is $161/MWh. Integrating solar thermal into a fossil fuel-fired
EGU reduces the capital cost and O&M expenses of the CSP portion by 25
and 67 percent compared to a stand-alone CSP EGU respectively.\866\
This results in an effective LCOE for the integrated CSP of $104/MWh.
Assuming the integrated CSP is sized to provide 10 percent of the
maximum steam turbine output and the relative capacity factors of a
combined cycle turbine and the CSP (those capacity factors are 65 and
25 percent, respectively) the overall annual generation due to the
concentrating solar thermal would be 3 percent of the hybrid EGU
output. This would result in a 3 percent reduction in the overall
CO2 emissions and a 1 percent increase in the LCOE, without
accounting for any reduction in the steam turbine efficiency. However,
these costs do not account for potential reductions in the steam
turbine efficiency due to being oversized relative to a non-hybrid EGU.
A 2011 technical report by the National Renewable Energy Laboratory
(NREL) cited analyses indicating that solar augmentation of fossil
power stations is not cost-effective, although likely less expensive
and containing less project risk than a stand-alone solar thermal
plant. Similarly, while commenters stated that solar augmentation has
been successfully integrated at coal-fired plants to improve overall
unit efficiency, commenters did not provide any new information on
costs or indicate that such augmentation is cost-effective.
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\865\ EIA, Annual Energy Outlook 2018, February 6, 2018. https://www.eia.gov/outlooks/aeo/.
\866\ B. Alqahtani and D. Pati[ntilde]o-Echeverri, Duke
University, Nicholas School of the Environment, ``Integrated Solar
Combined Cycle Power Plants: Paving the Way for Thermal Solar,''
Applied Energy 169:927-936 (2016).
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In addition, solar thermal facilities require locations with
abundant sunshine and significant land area in order to collect the
thermal energy. Existing concentrated solar power projects in the U.S.
are primarily located in California, Arizona, and Nevada with smaller
projects in Florida, Hawaii, Utah, and Colorado. NREL's 2011 technical
report on the solar-augment potential of fossil-fired power plants
examined regions of the U.S. with ``good solar resource as defined by
their direct normal insolation (DNI)'' and identified sixteen states as
meeting that criterion: Alabama, Arizona, California, Colorado,
Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North
Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The
technical report explained that annual average DNI has a significant
effect on the performance of a solar-augmented fossil plant, with
higher average DNI translating into the ability of a hybrid power plant
to produce more steam for augmenting the plant. The technical report
used a points-based system and assigned the most points for high solar
resource values. An examination of a NREL-generated DNI map of the U.S.
reveals that states with the highest DNI values are located in the
southwestern U.S., with only portions of Arizona, California, Nevada,
New Mexico, and Texas (plus Hawaii) having solar resources that would
have been assigned the highest points by the NREL technical report (7
kWh/m2/day or greater).
Commenters supported not incorporating hybrid power plants as part
of the BSER, and the EPA is not including hybrid power plants as part
of the BSER because of gaps in the EPA's knowledge about costs, and
concerns about the cost-effectiveness of the technology, as noted
above.
G. Standards of Performance
Once the EPA has determined that a particular system or technology
represents BSER, the CAA authorizes the Administrator to establish
standards of performance for new units that reflect the degree of
emission limitation achievable through the application of that BSER. As
noted above, the EPA is finalizing a two-phase set of standards of
performance, which reflect a two-component BSER, for base load
combustion turbines. Under this approach, for the first phase of the
standards, which applies as of the effective date the final rule, the
BSER is highly efficient generation and best operating and maintenance
practices. During this phase, owners/operators of EGUs will be subject
to a numeric standard of performance that is representative of the
performance of the best performing EGUs in the subcategory. For the
second phase of the standards, beginning in 2035, the BSER for base
load turbines includes 90
[[Page 39945]]
percent capture CCS. The affected EGUs will be subject to an emissions
rate that reflects continued use of highly efficient generation and
best operating and maintenance practices, coupled with CCS. In
addition, the EPA is finalizing a single component BSER, applicable
from May 23, 2023, for low and intermediate load combustion turbines.
1. Phase-1 Standards
The first component of the BSER is the use of highly efficient
combined cycle technology for base load EGUs in combination with the
best operating and maintenance practices, the use of highly efficient
simple cycle technology in combination with the best operating and
maintenance practices for intermediate load EGUs, and the use of lower-
emitting fuels for low load EGUs.
The EPA proposed that for base load combustion turbines, the first-
component BSER supports a standard of 770 lb CO2/MWh-gross
for large natural gas-fired EGUs, i.e., those with a base load rating
heat input greater than 2,000 MMBtu/h; 900 lb CO2/MWh-gross
for small natural gas-fired EGUs, i.e., those with a base load rating
of 250 MMBtu/h; and between 900 and 770 lb CO2/MWh-gross,
based on the base load rating of the EGU, for natural gas-fired EGUs
with base load ratings between 250 MMBtu/h and 2,000 MMBtu/h.\867\ The
EPA proposed that the most efficient available simple cycle
technology--which qualifies as the BSER for intermediate load
combustion turbines--supports a standard of 1,150 lb CO2/
MWh-gross for natural gas-fired EGUs. For new and reconstructed low
load combustion turbines, the EPA proposed to find that the use of
lower-emitting fuels--which qualifies as the BSER--supports a standard
that ranges from 120 lb CO2/MMBtu to 160 lb CO2/
MMBtu depending on the fuel burned. The EPA proposed these standards to
apply at all times and compliance to be determined on a 12-operating
month rolling average basis.
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\867\ As proposed, a new small natural gas-fired base load EGU
would determine the facility emissions rate by taking the difference
in the base load rating and 250 MMBtu/h, multiplying that number by
0.0743 lb CO2/(MW * MMBtu), and subtracting that number
from 900 lb CO2/MWh-gross. The emissions rate for a
natural gas-fired base load combustion turbine with a base load
rating of 1,000 MMBtu/h is 900 lb CO2/MWh-gross minus 750
MMBtu/h (1,000 MMBtu/h-250 MMBtu/h) times 0.0743 lb CO2/
(MW * MMBtu), which results in an emissions rate of 844 lb
CO2/MWh-gross.
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The EPA proposed that these standards of performance are achievable
specifically for natural gas-fired base load and intermediate load
combustion turbine EGUs. However, combustion turbine EGUs burn a
variety of fuels, including fuel oil during natural gas curtailments.
Owners/operators of combustion turbines burning fuels other than
natural gas would not necessarily be able to comply with the proposed
standards for base load and intermediate load natural gas-fired
combustion turbines using highly efficient generation. Therefore, the
Agency proposed that owners/operators of combustion turbines burning
fuels other than natural gas may elect to use the ratio of the heat
input-based emissions rate of the specific fuel(s) burned to the heat
input-based emissions rate of natural gas to determine a source-
specific standard of performance for the operating period. For example,
the NSPS emissions rate for a large base load combustion turbine
burning 100 percent distillate oil during the 12-operating month period
would be 1,070 lb CO2/MWh-gross.\868\
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\868\ The heat input-based emission rates of natural gas and
distillate oil are 117 and 163 lb CO2/MMBtu,
respectively. The ratio of the heat input-based emission rates
(1.39) is multiplied by the natural gas-fired standard of
performance (770 lb CO2/MWh) to get the applicable
emissions rate (1,070 lb CO2/MWh).
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Some commenters stated that the proposed base load emissions
standard based on highly efficient generation is not adequately
demonstrated, and that site conditions and certain operating parameters
are outside of the control of the owner/operator. These commenters
explained that the emissions rate of a combustion turbine is dependent
on external and site-specific factors, rather than the design
efficiency. Factors such as warmer climates, elevation, water
conservation measures (e.g., the use of dry cooling), and automatic
generation control negatively impacted efficiency. They emphasized that
operating units at partial loads would be necessary for maintaining
grid reliability, especially as more renewables are incorporated, and
the proposed limit is only achievable under ideal operating conditions.
Commenters noted that the emission standards should account for start
and stop cycles, back-up fuel use, degradation, and compliance
tolerance. Commenters stated that the lack of flexibility would force
units to operate at nameplate capacity, even when it was unnecessary
and could result in increased emissions. In addition, some commenters
stated that duct burners could be an alternative to simple cycle
turbines for peaking generation, even though they were less efficient
than combined cycle turbines without duct burners. They recommended the
Agency consider excluding emissions and heat input from duct burners
from the emissions standard. Furthermore, commenters noted multiple
units that the EPA used in the analysis to support the proposed base
load standards were permitted near or above 800 lb CO2/MWh.
Commenters stated that the original equipment manufacturer would not be
able to provide a warranty that the proposed 12-month rolling emissions
rate is achievable due to the varying operating conditions. Commenters
recommended the EPA raise the emissions standard to 850 or 900 lb
CO2/MWh-gross for large base load combustion turbines. In
addition, commenters suggested that the EPA incorporate scaling for
smaller units to 1,100 lb CO2/MWh-gross, and the beginning
of the sliding scale should be at least 2,500 MMBtu/h.
a. Base Load Phase-1 Emission Standards
Considering the public comments, the EPA re-evaluated the phase-1
standard of performance for base load combustion turbines. To determine
the impact of duty cycle and temperature, the EPA binned hourly data by
load and season. This allowed the Agency to isolate the impact of
ambient temperature and duty cycle separately. The EPA evaluated the
impact of ambient temperature by comparing the average emissions for
all hours between 70 to 80 percent load during different seasons. For
the combined cycle turbines evaluated, the difference between the
summer and winter average emission rates was minimal, typically in the
single digits and less than a 1 percent difference in emission rates.
Since the seasonal temperature differences are much larger than
regional variations, the EPA determined that regional ambient
temperature has minimal impact on the emissions rate of combined cycle
EGUs. Owners/operators of combined cycle EGUs are either using inlet
cooling effectively to manage the efficiency losses of the combustion
turbine engine or increased generation from the Rankine cycle portion
(i.e., HRSG and steam turbine) of the combined cycle turbine is
offsetting efficiency losses in the combustion turbine engine.\869\ In
addition, the variation in emissions rate by load (described below) is
much larger than temperature and therefore the operating load is a more
important factor than ambient temperature impacting CO2
emission rates.
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\869\ As the efficiency of the combustion turbine engine is
reduced at higher ambient temperatures relatively more heat is in
the exhaust entering the HRSG. This can increase the output from the
steam turbine.
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Based on the emissions data submitted to the EPA, combined cycle
[[Page 39946]]
CO2 emission are lowest at between approximately 80 to 90
percent load. Emission rates are relatively stable at higher loads and
down to approximately 70 percent load--typically 1 or 2 percent higher
than the lowest emissions rate. Emissions can increase dramatically at
lower loads and could impact the ability of an owner/operator to comply
with the base load standard. The EPA considered two approaches to
address potential compliance issues for owners/operators of base load
combustion turbines operating at lower duty cycles. The first approach
was to calculate emission rates using only hourly data when the
combined cycle turbine was operating at an hourly load of 70 percent or
higher. However, this has minimal impact on the calculated base load
emissions rate. This is because of 2 reasons. First, the majority of
operating hours for base load combustion turbines are at 70 percent
load or higher. In addition, the 12-operating month averages are
determined by the overall sum of the CO2 emissions divided
by the overall output during the 12-operating month period and not the
average of the individual hourly rates. The impact of this approach is
that low load hours have smaller impacts on the 12-operating month
average relative to high load hours. Therefore, the EPA determined that
using only higher load hours to determine the base load emission rates
would not address potential issues for owners/operators of base load
combustion turbines operating at relative low duty cycles (i.e., low
hourly capacity factors).
The second approach the EPA considered, and is finalizing, is
estimating the emissions rate of combined cycle turbines at the lower
end of the base load threshold--where more hours of low load operation
could potentially be included in the 12-operating month average--and
establishing a standard of performance that is achievable at lower
percent of potential electric sales for the base load subcategory. To
determine what emission rates are currently achieved by existing high-
efficiency combined cycle EGUs, the EPA reviewed 12-operating month
generation and CO2 emissions data from 2015 through 2023 for
all combined cycle turbines that submitted continuous emissions
monitoring system (CEMS) data to the EPA's emissions collection and
monitoring plan system (ECMPS). The data were sorted by the lowest
maximum 12-operating month emissions rate for each unit to identify
long-term emission rates on a lb CO2/MWh-gross basis that
have been demonstrated by the existing combined cycle EGU fleets. Since
an NSPS is a never-to-exceed standard, the EPA proposed and is
finalizing a conclusion that use of long-term data are more appropriate
than shorter term data in determining an achievable standard. These
long-term averages account for degradation and variable operating
conditions, and the EGUs should be able to maintain their current
emission rates, as long as the units are properly maintained. While
annual emission rates indicate a particular standard is achievable for
certain EGUs in the short term, they are not necessarily representative
of emission rates that can be maintained over an extended period using
highly efficient generating technology in combination with best
operating and maintenance practices.
To determine the 12-operating month average emissions rate that is
achievable by application of the BSER, the EPA proposed and is
finalizing an approach to calculating 12-month CO2 emission
rates by dividing the sum of the CO2 emissions by the sum of
the gross electrical energy output over the same period. The EPA did
this separately for combined cycle EGUs and simple cycle EGUs to
determine the emissions rate for the base load and intermediate load
subcategories, respectively. Commenters generally supported the 12-
month rolling average for emission standard compliance.
The average maximum 12-operating month base load emissions rate for
large combined cycle turbines that began operation since 2015 is 810 lb
CO2/MWh-gross. The range of the maximum 12-operating month
emissions rate for individual units is 720 to 920 lb CO2/
MWh-gross. The lowest emissions rate was achieved by an individual unit
at the Okeechobee Clean Energy Center. This facility is a large 3-on-1
combined cycle EGU that commenced operation in 2019 and uses a
recirculating cooling tower for the steam cycle. Each turbine is rated
at 380 MW and the three HRSGs feed a single steam turbine of 550 MW.
The EPA did not propose to use the emissions rate of this EGU to
determine the standard of performance for multiple reasons. The
Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft configuration
but, many combined cycle EGUs use a 1-on-1 configuration. Combined
cycle EGUs using a 1-on-1 configuration can be designed such that both
the combustion turbine and steam turbine are arranged on one shaft and
drive the same generator. This configuration has potential capital cost
and maintenance costs savings and a smaller plant footprint that can be
particularly important for combustion turbines enclosed in a building.
In addition, a single shaft configuration has higher net efficiencies
when operated at part load than a multi-shaft configuration. Basing the
standard of performance strictly on the performance of multi-shaft
combined cycle EGUs could limit the ability of owners/operators to
construct new combined cycle EGUs in space-constrained areas (typically
urban areas \870\) and combined cycle EGUs with the best performance
when operated as intermediate load EGUs.\871\ Either of these outcomes
could result in greater overall emissions from the power sector. An
advantage of multi-shaft configurations is that the turbine engine can
be installed initially and run as a simple cycle EGU, with the HRSG and
steam turbines added at a later date, all of which allows for more
flexibility for the regulated community. In addition, a single large
steam turbine in a 2-1 or 3-1 configuration can generate electricity
more efficiently than multiple smaller steam turbines, increasing the
overall efficiency of comparably sized combined cycle EGUs. According
to Gas Turbine World 2021, multi-shaft combined cycle EGUs have design
efficiencies that are 0.7 percent higher than single shaft combined
cycle EGUs using the same turbine engine.\872\
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\870\ Generating electricity closer to electricity demand can
reduce stress on the electric grid, reducing line losses and freeing
up transmission capacity to support additional generation from
variable renewable sources. Further, combined cycle EGUs located in
urban areas could be designed as CHP EGUs, which have potential
environmental and economic benefits.
\871\ Power sector modeling projects that combined cycle EGUs
will operate at lower capacity factors in the future. Combined cycle
EGUs with lower base load efficiencies but higher part load
efficiencies could have lower overall emission rates.
\872\ According to the data in Gas Turbine World 2021, while
there is a design efficiency advantage of going from a 1-on-1
configuration to a 2-on-1 configuration (assuming the same turbine
engine), there is no efficiency advantage of 3-on-1 configurations
compared to 2-on-1 configurations.
---------------------------------------------------------------------------
The efficiency of the Rankine cycle (i.e., HRSG plus the steam
turbine) is determined in part by the ability to cool the working fluid
(e.g., steam) after it has been expanded through the turbine. All else
equal, the lower the temperature that can be achieved, the more
efficient the Rankine cycle. The Okeechobee Clean Energy Center used a
recirculating cooling system, which can achieve lower temperatures than
EGUs using dry cooling systems and therefore would be more efficient
and have a lower emissions rate. However dry cooling systems have lower
water requirements and therefore could be the preferred technology in
arid regions or
[[Page 39947]]
in areas where water requirements could have significant ecological
impacts. Therefore, the EPA proposed and is finalizing that the
efficient generation standard for base load EGUs should account for the
use of cooling technologies with reduced water requirements.
Finally, the Okeechobee Clean Energy Center operates primarily at
high duty cycles where efficiency is the highest and since it is a
relatively new facility efficiency degradation might not be accounted
for in the emissions analysis. Therefore, the EPA is not determining
that the performance of the Okeechobee Clean Energy Facility is
appropriate for a nationwide standard.
The proposed emissions rate of 770 lb CO2/MWh-gross has
been demonstrated by approximately 15 percent of recently constructed
large combined cycle EGUs. As noted in the proposal, these combustion
turbines include combined cycle EGUs using 1-on-1 configurations, dry
cooling, and combustion turbines on the lower end of the large base
load subcategory. In addition, this emissions rate has been
demonstrated by using combustion turbines from multiple manufacturers
and from one facility that commenced operation in 2011--demonstrating
the long-term achievability of the proposed emissions standard.
However, as noted by commenters the majority of recently constructed
combined cycle turbines are not achieving an emissions rate of 770 lb
CO2/MWh-gross and combustion turbine manufacturers might not
be willing to guarantee this emissions level in operating making it
challenging to build a new combined cycle EGU.
To account for differences in the performance of the best
performing combustion turbines and design options that result in less
efficient operation, the EPA normalized the reported emission rates for
combined cycle EGUs.\873\ Specifically, for the reported emissions
rates of combined cycle turbines with cooling towers was increased by
1.0 percent to account for potential new units using dry cooling.
Similarly, the emissions rate of 2-1 and 3-1 combined cycle turbines
were increased by 1.4 percent to account for potential new units using
a 1-1 configuration. In addition, for the best performing combined
cycle turbines, the EPA plotted the 12-operating month emissions rate
against the 12-operating month heat input-based capacity factor. Based
on this data, the EPA used the trend in increasing emission rates at
lower 12-operating month capacity factors to estimate the emissions
rate at capacity factors at which an individual facility has never
operated. This approach allowed the EPA to estimate the emissions rate
at a 40 percent 12-operating month capacity factor for the best
performing combined cycle turbines. This allows the estimation of the
emissions rate at the lower end of the base load subcategory using
higher capacity factor data.\874\ The EPA did not correct the
achievable emissions rate for combined cycle turbines where the
relationship indicated emission rates declined at lower 12-operating
month capacity factors.
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\873\ A similar normalization approach was used by the EPA in
previous EGU GHG NSPS rulemakings to benchmark the performance of
coal-fired EGUs when determining an achievable efficiency-based
standard of performance.
\874\ The most efficient combined cycle turbines tend to operate
strictly as base load combustion turbines, well above the base load
subcategorization threshold.
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As noted in the proposal, one of the best performing large combined
cycle EGUs that has maintained a 12-operating-month base load emissions
rate of 770 lb CO2/MWh-gross is the Dresden plant, located
in Ohio.\875\ This 2-on-1 combined cycle facility uses a recirculating
cooling tower. The turbine engines are rated at 2,250 MMBtu/h, which
demonstrates that the standard of performance for large base load
combustion turbines is achievable at a heat input rating of 2,000
MMBtu/h. As noted, a 2-on-1 configuration and a cooling tower are more
efficient than a 1-on-1 configuration and dry cooling. Normalizing for
these factors and accounting for operation at a 12-operating month
capacity factor of 40 percent increases the achievable demonstrated
emissions rate to 800 lb CO2/MWh-gross. However, the Dresden
Energy Facility does not use the most efficient combined cycle design
currently available. Multiple more efficient designs have been
developed since the Dresden Energy Facility commenced operation a
decade ago that more than offset these efficiency losses. Therefore,
the EPA has determined that the Dresden combined cycle EGU demonstrates
that an emissions rate of 800 lb CO2/MWh-gross is achievable
for all new large combined cycle EGUs with an acceptable compliance
margin. Therefore, the EPA is finalizing a phase 1 standard of
performance of 800 lb CO2/MWh-gross for large base load
combustion turbines (i.e., those with a base load rating heat input
greater than 2,000 MMBtu/h) based on the BSER of highly efficient
combined cycle technology.
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\875\ The Dresden Energy Facility is listed as being located in
Muskingum County, Ohio, as being owned by the Appalachian Power
Company, as having commenced commercial operation in late 2011. The
facility ID (ORISPL) is 55350 1A and 1B.
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With respect to small combined cycle combustion turbines, the best
performing unit identified by the EPA is the Holland Energy Park
facility in Holland, Michigan, which commenced operation in 2017 and
uses a 2-on-1 configuration and a cooling tower.\876\ The 50 MW turbine
engines have individual heat input ratings of 590 MMBtu/h and serve a
single 45 MW steam turbine. The facility has maintained a 12-operating
month, 99 percent confidence emissions rate of 870 lb CO2/
MWh-gross. The emissions standard for a base load combustion turbine of
this size is 880 lb CO2/MWh-gross. The normalized emissions
rate accounting for the use of recirculating cooling towers, a 2-1
configuration, and operation at a 40 percent capacity factor is 900 lb
CO2/MWh-gross. While this is higher than the final emissions
standard in this rule, there are efficient generation technologies that
are not being used at the Holland Energy Park. For example, a
commercially available HRSG that uses supercritical CO2
instead of steam as the working fluid is available. This HRSG would be
significantly more efficient than the HRSG that uses dual pressure
steam, which is common for small combined cycle EGUs.\877\ When these
efficiency improvements are accounted for, a similar combined cycle EGU
would be able to maintain an emissions rate of 880 lb CO2/
MWh-gross. In addition, the normalization approach assumes a worst-case
scenario. Hybrid cooling technologies are available and offer
performance similar to that of wet cooling towers. This long-term data
accounts for degradation and variable operating conditions and
demonstrates that a base load combustion turbine EGU with a turbine
rated at 590 MMBtu/h should be able to maintain an emissions rate of
880 lb CO2/MWh-gross.\878\ Therefore, estimating that
[[Page 39948]]
emission rates will be slightly higher for smaller combustion turbines,
the EPA is finalizing a phase 1 standard of performance of 900 lb
CO2/MWh-gross for small base load combustion turbines (i.e.,
those with a base load rating of 250 MMBtu/h) based on the BSER of
highly efficient combined cycle technology.
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\876\ The Holland Park Energy Center is a CHP system that uses
hot water in the cooling system for a snow melt system that uses a
warm water piping system to heat the downtown sidewalks to clear the
snow during the winter. Since this useful thermal output is low
temperature, it likely only results in a small reduction of the
electrical efficiency of the EGU. If the useful thermal output were
accounted for, the emissions rate of the Holland Energy Park would
be lower. The facility ID (ORISPL) is 59093 10 and 11.
\877\ If the combustion turbine engine exhaust temperature is
500 [deg]C or greater, a HRSG using 3 pressure steam without a
reheat cycle could potentially provide an even greater increase in
efficiency (relative to a HRSG using 2 pressure steam without a
reheat cycle).
\878\ To estimate an achievable emissions rate for an efficient
combined cycle EGU at 250 MMBtu/h the EPA assumed a linear
relationship for combined cycle efficiency with turbine engines with
base load ratings of less than 2,000 MMBtu/h.
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b. Intermediate Load Emission Standards
For the intermediate load standards of performance, some commenters
stated that an emissions standard of 1,150 lb CO2/MWh-gross
is only achievable for simple cycle except under ideal operating
conditions. Since the emissions standard is not achievable in practice,
these commenters stated that the majority of new simple cycle turbines
would be prevented from operating as variable or intermediate load
units. Similar to comments on the base load emissions standard,
commenters stated the standard of performance should account for
ambient conditions, operation at part load, automatic generation
control, and variable loads. If the intermediate load standard is not
achievable in practice, it could result in the operation of less
efficient generation in other operating modes and an increase in
overall GHG emissions. They also explained this could force simple
cycle turbines to always operate at nameplate capacity, even when it
was not necessary, which would also lead to increased emissions. These
commenters requested that the EPA raise the variable and intermediate
load emissions standard to 1,250 to 1,300 lb CO2/MWh-gross.
Considering the public comments, the EPA re-evaluated the standard
of performance for intermediate load combustion turbines using the same
approach as for combined cycle turbines, except using the performance
of simple cycle EGUs. The average maximum 12-operating operating month
intermediate load emissions rate for simple cycle turbines that began
operation since 2015 is 1,210 lb CO2/MWh-gross. The range of
the maximum 12-operating month emissions rate for individual units is
1,080 to 1,470 lb CO2/MWh-gross. The lowest emissions rate
was achieved by an individual unit at the Scattergood Generating
Station. This facility includes 2 large aeroderivative simple cycle
turbines (General Electric LMS 100) that commenced operation in 2015.
Each turbine is rated at approximately 100 MW and use water injection
to reduce NOX emissions. The EPA did not propose and is not
finalizing to use the emissions rate of this EGU to determine the
standard of performance for multiple reasons. Simple cycle turbine
efficiency tends to increase with size and the simple cycle turbines at
the Scattergood Facility are the largest aeroderivative turbines
available. Establishing a standard of performance based on emission
rates that only large aeroderivative turbines could achieve would limit
the ability to develop new firm combustion turbine based generating
capacity in smaller than 100 MW increments. This could result in the
local electric grid operating in a less overall efficient manner,
increasing overall GHG emissions. In addition, the largest available
aeroderivative simple cycle turbines can use either water injection or
dry low NOX combustion to reduce emissions of
NOX. For this particular design, the use of water injection
has higher design efficiencies than the dry low NOX option.
Water injection has similar ecological impacts as water used for
cooling towers, the EPA has determined in this case it is important to
preserve the option for new intermediate load combustion turbines to
use dry low NOX combustion.
The proposed emissions rate of 1,150 lb CO2/MWh-gross
was achieved by 20 percent of recently constructed intermediate load
simple cycle turbines. However, only two-thirds of LMS 100 simple cycle
turbines installed to date have maintained an intermediate load
emissions rate of 1,150 lb CO2/MWh-gross. In addition, only
one-third of the Siemens STG-A65 simple cycle turbines and only 10
percent of General Electric LM6000 simple cycle combustion turbine have
maintained this emissions rate. Both of these are common aeroderivative
turbines and since they do require an intercooler have potential space
consideration advantages compared to the LMS100. Finalizing the
proposed emissions standard could restrict new intermediate load simple
cycle turbine to the use of intercooling, limiting application to
locations that can support a cooling tower. An intermediate load
emissions rate of 1,170 lb CO2/MWh-gross has been achieved
by three-quarters of both the LMS100 and STG-A65 installations and 20
percent of LM6000 installations. In addition, this emissions rate has
been demonstrated by a frame simple turbine. The EPA notes that the
more efficient versions of the combustion turbines--water injection in
the case of the LMS 100 and DLN in the case of the STG-A65--have higher
design efficiencies and higher compliance levels than the version with
the alternate NOX control technology. This standard of
performance has been demonstrated by 40 percent of recently installed
intermediate load simple cycle turbines and the Agency has determined
that with proper maintenance is achievable with combustion turbines
from multiple manufacturers, with and without intercooling, and is
finalizing a standard of 1,170 lb CO2/MWh-gross for
intermediate load combustion turbines. The EPA considered, but
rejected, finalizing an emissions standard of 1,190 lb CO2/
MWh-gross. This standard of performance has been achieved by
essentially all LMS 100 and SGT-A65 intermediate load simple cycle
turbines and 70 percent of recently installed intermediate load simple
cycle turbines but would not require the most efficient available
versions of new intermediate load simple cycle turbines and does not
represent the BSER.
2. Phase-2 Standards
The EPA proposed that 90 percent CCS (as part of the CCS pathway)
qualifies as the second component of the BSER for base load combustion
turbines. For the base load combustion turbines, the EPA reduced the
emissions rate by 89 percent to determine the CCS based phase-2
standards.\879\ The CCS percent reduction is based on a CCS system
capturing 90 percent of the emitting CO2 being operational
anytime the combustion turbine is operating. Similar to the phase-1
emission standards, the EPA proposed and is finalizing a decision that
standard of performance for base load combustion turbines be adjusted
based on the uncontrolled emission rates of the fuels relative to
natural gas. For 100 percent distillate oil-fired combustion turbines,
the emission rates would be 120 lb CO2/MWh-gross.
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\879\ The 89 percent reduction from CCS accounts for the
increased auxiliary load of a 90 percent post combustion amine-based
capture system. Due to rounding, the proposed numeric standards of
performance do not necessarily match the standards that would be
determined by applying the percent reduction to the phase-1
standards.
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The EPA solicited comment on the range of reduction in emission
rate of 75 to 90 percent. In addition, the EPA solicited comment on
whether carbon capture equipment has lower availability/reliability
than the combustion turbine or the CCS equipment takes longer to
startup than the combustion turbine itself there would be periods of
operation where the CO2 emissions would not be controlled by
the carbon capture equipment. For the same reasons as for coal-fired
EGUs, the EPA has determined 90 percent CCS
[[Page 39949]]
has been demonstrated and appropriate for base load combustion
turbines, see section VII.C.
H. Reconstructed Stationary Combustion Turbines
All the major manufacturers of combustion turbines sell upgrade
packages that increase both the output and efficiency of existing
combustion turbines. An owner/operator of a reconstructed combustion
turbine would be able to use one of these upgrade packages to comply
with the intermediate load emission standards in this final rule. Some
examples of these upgrades include GE's Advanced Gas Path, Siemens' Hot
Start on the Fly, and Solar Turbines' Gas Compressor Restaging. The
Advanced Gas Path option includes retrofitting existing turbine
components with improved materials to increase durability, air sealing,
and overall efficiency.\880\ Hot Start on the Fly upgrades include
implementing new software to allow for the gas and steam turbine to
start-up simultaneously, which greatly improves start times, and in
some cases could do so by up to 20 minutes.\881\ Compressor restaging
involves analyzing the current operation of an existing combustion
turbine and adjusting its gas compressor characteristics including
transmission, injection, and gathering, to operate in the most
efficient manner given the other operating conditions of the
turbine.\882\ In addition, steam injection is a retrofittable
technology that is estimated to be available for a total cost of all
the equipment needed for steam injection of $250/kW.\883\ Due to the
differences in materials used and necessary additional infrastructure,
a steam injection system can be up to 60 percent smaller than a similar
HRSG, which is valuable for retrofit purposes.\884\
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\880\ https://www.gevernova.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/resources/advanced-gas-path-brochure.pdf.
\881\ https://www.siemens-energy.com/global/en/home/stories/trianel-power-plant-upgrades.html.
\882\ https://s7d2.scene7.com/is/content/Caterpillar/CM20191213-93d46-8e41d.
\883\ ``GTI'' (2019). Innovative Steam Technologies. https://otsg.com/industries/powergen/gti/.
\884\ Ibid.
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For owners/operators of base load combustion turbines, however,
HRSG have been added to multiple existing simple cycle turbines to
convert to combined cycle technology. There have been multiple examples
of this kind of conversion from simple cycle to combined cycle. One
such example is Unit 12 at Riverton Power Plant in Riverton, Kansas,
which was originally built in 2007 as a 143 MW simple cycle combustion
turbine. In 2013, an HRSG and additional equipment was added to convert
Unit 12 to a combined cycle combustion turbine.\885\ Another is Energy
Center Dover, located in Dover, Delaware, which in addition to a coal-
fired steam turbine, originally had two 44 MW simple cycle combustion
turbines. Also in 2013, the unit added an HRSG to one of the existing
simple cycle combustion turbines, connected the existing steam
generator to it, and retired the remaining coal-related equipment to
convert that combustion turbine to a combined cycle one.\886\ Some
other examples include the Los Esteros Critical Energy Facility in San
Jose, California, which converted from a four-turbine simple cycle
peaking facility to a combined-cycle one in 2013, and the Tracy
Combined Cycle Power Plant.\887\ The Tracy facility, located in Tracy,
California, was built in 2003 with two simple cycle combustion turbines
and in 2012 was converted to combined cycle with the addition of a
steam turbine.\888\
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\885\ https://www.nsenergybusiness.com/news/newsempire-district-starts-riverton-plants-combined-cycle-expansion-231013/.
\886\ https://news.delaware.gov/2013/07/26/repowered-nrg-energy-center-dover-unveiled-gov-markell-congressional-delegation-dnrec-sec-omara-other-officials-join-with-nrg-to-announce-cleaner-natural-gas-facility/.
\887\ https://www.calpine.com/los-esteros-critical-energy-facility.
\888\ https://www.middleriverpower.com/#portfolio.
---------------------------------------------------------------------------
In the previous sections, the EPA explained the background of and
requirements for new and reconstructed stationary combustion turbines
and evaluated various control technology configurations to determine
the BSER. Because the BSER is the same for new and reconstructed
stationary combustion turbines, the Agency used the same emissions
analysis for both new and reconstructed stationary combustion turbines.
For each of the subcategories, the EPA proposed and is finalizing a
conclusion that the BSER results in the same standard of performance
for new stationary combustion turbines and reconstructed stationary
combustion turbines. For CCS, consistent with the NETL Combined Cycle
CCS Retrofit Report, the EPA approximated the cost to add CCS to a
reconstructed combustion turbine by increasing the capital costs of the
carbon capture equipment by 9 percent relative to the costs of adding
CCS to a newly constructed combustion turbine and decreasing the net
efficiency by 0.3 percent.\889\ Using the same costing assumptions for
newly constructed combined cycle turbines, the compliance costs for
reconstructed combined cycle turbines are approximately 10 percent
higher than for comparable newly constructed combined cycle turbine.
Assuming continued operation of the capture equipment, the compliance
costs are $17/MWh and $51/ton ($56/metric ton) for a 6,100 MMBtu/h H-
Class combustion turbine, and $21/MWh and $63/ton ($69/metric ton) for
a 4,600 MMBtu/h F-Class combustion turbine. If the capture system is
not operated while the combustion turbine is subcategorized as in
intermediate load combustion turbine, the compliance costs are reduced
to $10/MWh and $50/ton ($55/metric ton) for a 6,100 MMBtu/h H-Class
combustion turbine, and $13/MWh and $67/ton ($73/metric ton) for a
4,600 MMBtu/h F-Class combustion turbine.
---------------------------------------------------------------------------
\889\ ``Cost and Performance of Retrofitting NGCC Units for
Caron Capture--Revision 3.'' DOE/NETL-2023/3845. March 17, 2023.
---------------------------------------------------------------------------
A reconstructed stationary combustion turbine is not required to
meet the standards if doing so is deemed to be ``technologically and
economically'' infeasible.\890\ This provision requires a case-by-case
reconstruction determination in the light of considerations of economic
and technological feasibility. However, this case-by-case determination
considers the identified BSER, as well as technologies the EPA
considered, but rejected, as BSER for a nationwide rule. One or more of
these technologies could be technically feasible and of reasonable
cost, depending on site-specific considerations and if so, would likely
result in sufficient GHG reductions to comply with the applicable
reconstructed standards. Finally, in some cases, equipment upgrades,
and best operating practices would result in sufficient reductions to
achieve the reconstructed standards.
---------------------------------------------------------------------------
\890\ 40 CFR 60.15(b)(2).
---------------------------------------------------------------------------
I. Modified Stationary Combustion Turbines
CAA section 111(a)(4) defines a ``modification'' as ``any physical
change in, or change in the method of operation of, a stationary
source'' that either ``increases the amount of any air pollutant
emitted by such source or . . . results in the emission of any air
pollutant not previously emitted.'' Certain types of physical or
operational changes are exempt from consideration as a modification.
Those are described in 40 CFR 60.2, 60.14(e).
In the 2015 NSPS, the EPA did not finalize standards of performance
for stationary combustion turbines that conduct modifications; instead,
the EPA concluded that it was prudent to delay
[[Page 39950]]
issuing standards until the Agency could gather more information (80 FR
64515; October 23, 2015). There were several reasons for this
determination: few sources had undertaken NSPS modifications in the
past, the EPA had little information concerning them, and available
information indicated that few owners/operators of existing combustion
turbines would undertake NSPS modifications in the future; and since
the Agency eliminated proposed subcategories for small EGUs in the 2015
NSPS, questions were raised as to whether smaller existing combustion
turbines that undertake a modification could meet the final performance
standard of 1,000 lb CO2/MWh-gross.
It continues to be the case that the EPA is aware of no evidence
indicating that owners/operators of combustion turbines intend to
undertake actions that could qualify as NSPS modifications in the
future. The EPA did not propose or solicit comment on standards of
performance for modifications of combustion turbines and is not
establishing any in this final rule.
J. Startup, Shutdown, and Malfunction
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the D.C. Circuit vacated portions of two provisions in the
EPA's CAA section 112 regulations governing the emissions of HAP during
periods of SSM. Specifically, the court vacated the SSM exemption
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that the
SSM exemption violates the requirement under section 302(k) of the CAA
that some CAA section 112 standard apply continuously. The EPA has
determined the reasoning in the court's decision in Sierra Club v. EPA
applies equally to CAA section 111 because the definition of emission
or standard in CAA section 302(k), and the embedded requirement for
continuous standards, also applies to the NSPS. Consistent with Sierra
Club v. EPA, the EPA is finalizing standards in this rule that apply at
all times. The NSPS general provisions in 40 CFR 60.11(c) currently
exclude opacity requirements during periods of startup, shutdown, and
malfunction and the provision in 40 CFR 60.8(c) contains an exemption
from non-opacity standards. These general provision requirements would
automatically apply to the standards set in an NSPS, unless the
regulation specifically overrides these general provisions. The NSPS
subpart TTTT (40 CFR part 60, subpart TTTT) does not contain an opacity
standard, thus, the requirements at 40 CFR 60.11(c) are not applicable.
The NSPS subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and
requires that sources comply with the standard(s) at all times. In
reviewing NSPS subpart TTTT and proposing the new NSPS subpart TTTTa,
the EPA proposed to retain in subpart TTTTa the requirements that
sources comply with the standard(s) at all times in table 3 of the new
subpart TTTTa to override the general provisions for SSM exemption
related provisions. The EPA proposed and is finalizing that all
standards in subpart TTTTa apply at all times.
In developing the standards in this rule, the EPA has taken into
account startup and shutdown periods and, for the reasons explained in
this section of the preamble, is not establishing alternate standards
for those periods. The EPA analysis of achievable standards of
performance used CEMS data that includes all period of operation. Since
periods of startup, shutdown, and malfunction were not excluded from
the analysis, the EPA is not establishing alternate standard for those
periods of operation.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead, they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
CAA section 111 standards. Nothing in CAA section 111 or in caselaw
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting standards of performance,
nothing in CAA section 111 requires the Agency to consider malfunctions
as part of that analysis. The EPA is not required to treat a
malfunction in the same manner as the type of variation in performance
that occurs during routine operations of a source. A malfunction is a
failure of the source to perform in a ``normal or usual manner'' and no
statutory language compels the EPA to consider such events in setting
CAA section 111 standards of performance. The EPA's approach to
malfunctions in the analogous circumstances (setting ``achievable''
standards under CAA section 112) has been upheld as reasonable by the
D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606-610 (2016).
K. Testing and Monitoring Requirements
Because the NSPS reflects the application of the best system of
emission reduction under conditions of proper operation and
maintenance, in doing the NSPS review, the EPA also evaluates and
determines the proper testing, monitoring, recordkeeping and reporting
requirements needed to ensure compliance with the NSPS. This section
includes a discussion on the current testing and monitoring
requirements of the NSPS and any additions the EPA is including in 40
CFR part 60, subpart TTTTa.
1. General Requirements
The EPA proposed to allow three approaches for determining
CO2 emissions: a CO2 CEMS and stack gas flow
monitor; hourly heat input, fuel characteristics, and F factors \891\
for EGUs firing oil or gas; or Tier 3 calculations using fuel use and
carbon content. The first two approaches are in use for measuring
CO2 by units affected by the Acid Rain program (40 CFR part
75), to which most, if not all, of the EGUs affected by NSPS subpart
TTTT are already subject, while the last approach is in use for
stationary fuel combustion sources reporting to the GHGRP (40 CFR part
98, subpart C).
---------------------------------------------------------------------------
\891\ An F factor is the ratio of the gas volume of the products
of combustion to the heat content of the fuel.
---------------------------------------------------------------------------
The EPA believes continuing the use of approaches already in use by
other programs represents a cost-effective means of obtaining quality
assured data requisite for determining carbon dioxide mass emissions.
MPS reporting software required by this subpart for reporting emissions
to the EPA expects hourly or daily CO2 emission values and
has thousands of electronic checks to validate data using the Acid Rain
program requirements (40 CFR part 75). ECMPS does not currently
accommodate or validate data under GHGRP's Tier 3 approach. Because
most, if not all, of the EGUs that will be affected by this final rule
are already affected by Acid Rain program monitoring requirements, the
cost and burden for EGU owners or operators are already accounted for
by other rulemakings. Therefore, this aspect of the final rule is
designed to have minimal, if any, cost or burden associated with
CO2 testing and monitoring. In addition, there are no
changes to measurement and testing requirements for determining
electrical output, both gross and net, as well as
[[Page 39951]]
thermal output, to existing requirements.
However, the EPA requested comment on whether continuous
CO2 CEMS and stack gas flow measurements should be the sole
means of compliance for this rule. Such a switch would increase costs
for those EGU owners or operators who are currently relying on the oil-
or gas-fired calculation-based approaches. By way of reference, the
annualized cost associated with adoption and use of continuous
CO2 and flow measurements where none now exist is estimated
to be about $52,000. To the extent that the rule were to mandate
continuous CO2 and stack gas flow measurements in accordance
with what is currently allowed as one option and that an EGU lacked
this instrumentation, its owner or operator would need to incur this
annual cost to obtain such information and to keep the instrumentation
calibrated. Commenters encouraged the EPA to maintain the flexibility
for EGUs to use hourly heat input measurements, fuel characteristics,
and F factors as is allowed under the Acid Rain program. Commenters
argued that in addition to the incremental costs, some facilities have
space constraints that could make the addition of stack gas flow
monitors difficult or impractical. In this final rule, the EPA allows
the use of hourly heat input, fuel characteristics, and F factors as an
alternative to CO2 CEMS and stack gas flow monitors for EGUs
that burn oil or gas.
One commenter argued that the part 75 data requirements, which are
required for several emission trading programs including the Acid Rain
program, are punitive and that the data are biased high. Other
commenters argued that the part 75 CO2 data are biased low.
EPA disagrees that the data requirements are punitive. Most, if not
all, of the EGUs subject to this subpart are already reporting the data
under the Acid Rain program. Oil- and gas-fired EGUs that are not
subject to the Acid Rain program but are subject to a Cross-State Air
Pollution Rule program are already reporting most of the necessary data
elements (e.g., hourly heat input and F factors) for SO2
and/or NOX emissions. The additional data and effort
necessary to calculate CO2 emissions is minor. The EPA also
disagrees that the data are biased significantly high or low. Each
CO2 CEMS and stack gas flow monitor must undergo regular
quality assurance and quality control activities including periodic
relative accuracy test audits where the EGU's monitoring system is
compared to an independent monitoring system. In a May 2022 study
conducted by the EPA, the average difference between the EGU's
monitoring system and the independent monitoring system was
approximately 2 percent for CO2 concentration and slightly
greater than 2 percent for stack gas flow.
2. Requirements for Sources Implementing CCS
The CCS process is also subject to monitoring and reporting
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires
reporting of facility-level GHG data and other relevant information
from large sources and suppliers in the U.S. The ``suppliers of carbon
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires
those affected facilities with production process units that capture a
CO2 stream for purposes of supplying CO2 for
commercial applications or that capture and maintain custody of a
CO2 stream in order to sequester or otherwise inject it
underground to report the mass of CO2 captured and supplied.
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of
CO2 sequestered under the ``geologic sequestration of carbon
dioxide'' source category of the GHGRP (GHGRP subpart RR). In April
2024, to complement GHGRP subpart RR, the EPA finalized the ``geologic
sequestration of carbon dioxide with enhanced oil recovery (EOR) using
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide
an alternative method of reporting geologic sequestration in
association with EOR.892 893 894
---------------------------------------------------------------------------
\892\ EPA. (2024). Rulemaking Notices for GHG Reporting. https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
\893\ International Standards Organization (ISO) standard
designated as CSA Group (CSA)/American National Standards Institute
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil
Recovery (CO2-EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
\894\ As described in 87 FR 36920 (June 21, 2022), both subpart
RR and subpart VV (CSA/ANSI ISO 27916:2019) require an assessment
and monitoring of potential leakage pathways; quantification of
inputs, losses, and storage through a mass balance approach; and
documentation of steps and approaches used to establish these
quantities. Primary differences relate to the terms in their
respective mass balance equations, how each defines leakage, and
when facilities may discontinue reporting.
---------------------------------------------------------------------------
CCS as the BSER, as detailed in section VIII.F.4.c.iv of this
preamble, is determined to be adequately demonstrated based solely on
geologic sequestration that is not associated with EOR. However, EGUs
also have the compliance option to send CO2 to EOR
facilities that report under GHGRP subpart RR or GHGRP subpart VV. The
EPA is requiring that any affected unit that employs CCS technology
that captures enough CO2 to meet the proposed standard and
injects the captured CO2 underground must report under GHGRP
subpart RR or GHGRP subpart VV. If the emitting EGU sends the captured
CO2 offsite, it must transfer the CO2 to a
facility that reports in accordance with GHGRP subpart RR or GHGRP
subpart VV. This does not change any of the requirements to obtain or
comply with a UIC permit for facilities that are subject to the EPA's
UIC program under the Safe Drinking Water Act.
The EPA also notes that compliance with the standard is determined
exclusively by the tons of CO2 captured by the emitting EGU.
The tons of CO2 sequestered by the geologic sequestration
site are not part of that calculation, though the EPA anticipates that
the quantity of CO2 sequestered will be substantially
similar to the quantity captured. However, to verify that the
CO2 captured at the emitting EGU is sent to a geologic
sequestration site, the Agency is leveraging regulatory reporting
requirements under the GHGRP. The EPA also emphasizes that this final
rule does not involve regulation of downstream recipients of captured
CO2. That is, the regulatory standard applies exclusively to
the emitting EGU, not to any downstream user or recipient of the
captured CO2. The requirement that the emitting EGU transfer
the captured CO2 to an entity subject to the GHGRP
requirements is thus exclusively an element of enforcement of the EGU
standard. This avoids duplicative monitoring, reporting, and
verification requirements between this rule and the GHGRP, while also
ensuring that the facility injecting and sequestering the
CO2 (which may not necessarily be the EGU) maintains
responsibility for these requirements. Similarly, the existing
regulatory requirements applicable to geologic sequestration are not
part of this final rule.
L. Recordkeeping and Reporting Requirements
The current rule (subpart TTTT of 40 CFR part 60) requires EGU
owners or operators to prepare reports in accordance with the Acid Rain
Program's ECMPS. Such reports are to be submitted quarterly. The EPA
believes all EGU owners and operators have extensive experience in
using the ECMPS and use of a familiar system ensures quick and
effective rollout of the program in this final rule. Because all EGUs
are expected to be covered by and included in the ECMPS, minimal, if
any, costs for reporting are expected for
[[Page 39952]]
this final rule. In the unlikely event that a specific EGU is not
already covered by and included in the ECMPS, the estimated annual per
unit cost would be about $8,500.
The current rule's recordkeeping requirements at 40 CFR part
60.5560 rely on a combination of general provision requirements (see 40
CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and
an explicit list of items, including data and calculations; the EPA is
retaining those existing subpart TTTT of 40 CFR part 60 requirements in
the new NSPS subpart TTTTa of 40 CFR part 60. The annual cost of those
recordkeeping requirements will be the same amount as is required for
subpart TTTT of 40 CFR part 60 recordkeeping. As the recordkeeping in
subpart TTTT of 40 CFR part 60 will be replaced by similar
recordkeeping in subpart TTTTa of 40 CFR part 60, this annual cost for
recordkeeping will be maintained.
M. Compliance Dates
Owners/operators of affected sources that commenced construction or
reconstruction after May 23, 2023, must meet the requirements of 40 CFR
part 60, subpart TTTTa, upon startup of the new or reconstructed
affected facility or the effective date of the final rule, whichever is
later. This compliance schedule is consistent with the requirements in
section 111 of the CAA.
N. Compliance Date Extension
Several industry commenters noted the potential for delay in
installation and utilization of emission controls--especially CCS--due
to supply chain constraints, permitting challenges, environmental
assessments, or delays in development of necessary infrastructure,
among other reasons. Commenters requested that the EPA include a
mechanism to extend the compliance date for affected EGUs that are
installing emission controls. These commenters explained that an
extension mechanism could provide greater regulatory certainty for
owners and operators.
After considering these comments, the EPA believes that it is
reasonable to provide a consistent and transparent means of allowing a
limited extension of the Phase 2 compliance deadline where an affected
new or reconstructed base load stationary combustion EGU has
demonstrated such an extension is needed for installation and
utilization of controls. This mechanism is intended to address
unavoidable delays in implementation--not to provide more time to
assess the NSPS compliance strategy for the affected EGU.
As indicated, the EPA is finalizing a provision that will allow the
owner/operators of new or reconstructed base load stationary combustion
turbine EGUs to request a limited Phase 2 compliance extension based on
a case-by-case demonstration of necessity. Under these provisions, the
owner or operator of an affected source may apply for a Phase 2
compliance date extension of up to 1 year to comply with the applicable
emissions control requirements, which if approved by the EPA, would
require compliance with Phase 2 standards of performance no later than
January 1, 2033. This mechanism is only available for situations in
which an affected source encounters a delay in installation or startup
of a control technology that makes it impossible to commence compliance
with Phase 2 standards of performance by January 1, 2032 (i.e., the
Phase 2 compliance date specified in section VIII.F.4 of this
preamble).
The EPA will grant a request for a Phase 2 compliance extension of
up to 1 year only where a source demonstrates that it has taken all
steps possible to install and start up the necessary controls and still
cannot comply with the Phase 2 standards of performance by the January
1, 2032 compliance date due to circumstances entirely beyond its
control. Any request for a Phase 2 compliance extension must be
received by the EPA at least 180 days before the January 1, 2032 Phase
2 compliance date. The owner/operator of the requesting source must
provide documentation of the circumstances that precipitated the delay
(or an anticipated delay) and demonstrate that those circumstances are
entirely beyond the control of the owner/operator and that the owner/
operator has no ability to remedy the delay. These circumstances may
include, but are not limited to, delays related to permitting, delays
in delivery or construction of parts necessary for installation or
implementation of the control technology, or development of necessary
infrastructure (e.g., CO2 pipelines).
The request must include documentation that demonstrates that the
necessary controls cannot be installed or started up by the January 1,
2032 Phase 2 compliance date. This may include information and
documentation obtained from a control technology vendor or engineering
firm demonstrating that the necessary controls cannot be installed or
started up by the applicable Phase 2 compliance date, documentation of
any permit delays, or documentation of delays in construction or
permitting of infrastructure (e.g., CO2 pipelines) that is
necessary for implementation of the control technology. The owner/
operator of an affected new stationary combustion turbine EGU remains
subject to the January 1, 2032 Phase 2 compliance date unless and until
the Administrator grants a compliance extension.
As discussed in sections VII.C.1.a.i.(E) and VII.C.2.b.i(C), the
EPA has determined compliance timelines for these new sources that are
consistent with achieving emission reductions as expeditiously as
practicable given the time it takes to install and startup the BSER
technologies for compliance with the Phase 2 standards of performance.
The Phase 2 compliance dates are designed to accommodate the process
steps and timeframes that the EPA reasonably anticipates will apply to
affected EGUs. This extension mechanism acknowledges that circumstances
entirely outside the control of the owners or operators of affected
EGUs may extend the timeframe for installation or startup of control
technologies beyond the timeframe that the EPA has determined is
reasonable as a general matter. Thus, so long as this extension
mechanism is limited to circumstances that cannot be reasonably
controlled or remedied by the owners or operators of the affected EGUs
and that make it impossible to achieve compliance with Phase 2
standards of performance by the January 1, 2032 compliance date, its
use is consistent with achieving compliance as expeditiously as
practicable.
The EPA believes that a 1-year extension on top of the lead time
already provided by the 2032 compliance date should be sufficient to
address any compliance delays and to allow all base load units to
timely install CSS. New or reconstructed base load stationary
combustion turbines that are granted a 1-year Phase 2 compliance date
extension and still are not able to install or startup the control
technologies necessary to meet the Phase 2 standard of performance by
the extended Phase 2 compliance date of January 1, 2033 may adjust
their operation to the intermediate load subcategory (i.e., 12-
operating-month capacity factor between 20-40 percent). Such sources
must then comply with applicable standards of performance for the
intermediate load stationary combustion turbine subcategory until the
necessary controls are installed and operational such that the source
can comply with the Phase 2 standard of performance.
[[Page 39953]]
IX. Requirements for New, Modified, and Reconstructed Fossil Fuel-Fired
Steam Generating Units
A. 2018 NSPS Proposal Withdrawal
1. Background
As discussed in section V.B, the EPA promulgated NSPS for GHG
emissions from fossil fuel-fired steam generating units in 2015 (``2015
NSPS'').\895\ The 2015 NSPS finalized partial CCS as the BSER and
finalized standards of performance to limit emissions of GHG manifested
as CO2 from newly constructed, modified, and reconstructed
fossil fuel-fired EGUs (i.e., utility boilers and integrated
gasification combined cycle (IGCC) units). In the same document, the
Agency also finalized CO2 emission standards for newly
constructed and reconstructed stationary combustion turbine EGUs. 80 FR
64510 (October 23, 2015). These final standards were codified in 40 CFR
part 60, subpart TTTT.
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\895\ 80 FR 64510 (October 23, 2015).
---------------------------------------------------------------------------
On December 20, 2018, the EPA published a proposal to revise
certain parts of the 2015 Rule, titled ``Review of Standards of
Performance for Greenhouse Gas Emissions From New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units.''
83 FR 65424 (December 20, 2018) (``2018 Proposal''). In Fall 2020,
after reviewing comments on the 2018 Proposal, the EPA developed a
draft final rule and sent that package to the Office of Management and
Budget (OMB) for interagency review under Executive Order 12866 (``2020
OMB Review Package''). The 2020 OMB Review Package, if finalized, would
have amended the BSER for new coal-fired EGUs and required a pollutant-
specific significant contribution finding (SCF) prior to regulating a
source category. The review of the BSER portion of the package was
delayed \896\ and the pollutant-specific SCF portion of the 2020 OMB
Review Package was finalized on January 13, 2021 in a final rule,
titled ``Pollutant-Specific Contribution Finding for Greenhouse Gas
Emissions from New, Modified, and Reconstructed Stationary Sources:
Electric Utility Generating Units, and Process for Determining
Significance of Other New Source Performance Standards Source
Categories.'' 86 FR 2542 (January 13, 2021) (``SCF Rule''). However,
the D.C. Circuit vacated the SCF Rule on April 5, 2021.\897\ The BSER
analysis and that portion of the 2018 Proposal have not been finalized
and are being withdrawn in this final action. The 2018 Proposal stated
that the Agency was proposing to find that partial CCS is not the BSER
on grounds that it is too costly and that the 2015 Rule did not show
that the technology had sufficient geographic scope to qualify as the
BSER for newly constructed coal-fired EGUs. The EPA instead proposed
that the BSER for newly constructed coal-fired EGUs would be the most
efficient available steam cycle (i.e., supercritical steam conditions
for large units and subcritical steam conditions for small units) in
combination with the best operating practices instead of partial CCS.
In addition, for newly constructed coal-fired EGUs firing moisture-rich
fuels (i.e., lignite), the BSER would also include pre-combustion fuel
drying using waste heat from the process. The 2018 Proposal also would
have revised the standards of performance for reconstructed EGUs, the
maximally stringent standards for coal-fired EGUs undergoing large
modifications (i.e., modifications resulting in an increase in hourly
CO2 emissions of more than 10 percent), and for base load
and non-base load operating conditions that reflected the Agency's
revised BSER determination. The 2018 Proposal did not revise the BSER
for any other sources as determined in the 2015 Rule. It also included
minor amendments to the applicability criteria for combined heat and
power (CHP) and non-fossil EGUs and other miscellaneous technical
changes in the regulatory requirements.
---------------------------------------------------------------------------
\896\ As part of the interagency review process, an error in the
partial CCS costing report that the EPA used to update the costs of
partial CCS between the 2018 Proposal and 2020 OMB Review Package
was identified. The error included in the original 2020 OMB Review
Package had the impact of increasing the cost of partial CCS. The
corrected report resulted in partial CCS costs that were similar to
those included in the 2018 Proposal.
\897\ State of California v. EPA (D.C. Cir. 21-1035), Document
No. 1893155 (April 5, 2021).
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2. Withdrawal of the 2018 Proposal
In this action, under CAA section 111(b), the Agency is withdrawing
the 2018 Proposal and the proposed determination that the BSER for
coal-fired steam generating units should be highly efficient generation
technology combined with best operating practices. The EPA no longer
believes there is a basis for finding that highly efficient generation
technology combined with best operating practices are the BSER for
coal-fired steam generating units. As described at length in this
preamble, CCS technology is adequately demonstrated for coal-fired
steam generating units and so it is not appropriate to impose the less
effective emission control of highly efficient generation combined with
best operating practices for new sources in this source category.
Moreover, the EPA is presently considering whether to revise the 2015
Rule to take into account improvements in CCS technology and the
existing tax credits under the IRA. For a more in-depth, technical
discussion of the rationale underlying this action, please refer to the
technical memorandum in the docket titled, 2018 Proposal Withdrawal.
B. Additional Amendments
The EPA proposed and is finalizing multiple less significant
amendments. These amendments are either strictly editorial and will not
change any of the requirements of 40 CFR part 60, subpart TTTT, or will
add additional compliance flexibility. The amendments are also
incorporated into the final subpart TTTTa. For additional information
on these amendments, see the redline strikeout version of the rule
showing the amendments in the docket for this action.
First, the EPA proposed and is finalizing editorial amendments to
define acronyms the first time they are used in the regulatory text.
Second, the EPA proposed and is finalizing adding International System
of Units (SI) equivalent for owners/operators of stationary combustion
turbines complying with a heat input-based standard. Third, the EPA
proposed and is finalizing correcting errors in the current 40 CFR part
60, subpart TTTT, regulatory text referring to part 63 instead of part
60. Fourth, as a practical matter owners/operators of stationary
combustion turbines subject to the heat input-based standard of
performance need to maintain records of electric sales to demonstrate
that they are not subject to the output-based standard of performance.
Therefore, the EPA proposed and is finalizing adding a specific
requirement that owner/operators maintain records of electric sales to
demonstrate they did not sell electricity above the threshold that
would trigger the output-based standard. Next, the EPA proposed and is
finalizing updating the ANSI, ASME, and ASTM International (ASTM) test
methods to include more recent versions of the test methods. Finally,
the EPA proposed and is finalizing adding additional compliance
flexibilities for EGUs either serving a common electric generator or
using a common stack.
C. Eight-year Review of NSPS for Fossil Fuel-Fired Steam Generating
Units
1. Modifications
In the 2015 NSPS, the EPA issued final standards for a steam
generating
[[Page 39954]]
unit that implements a ``large modification,'' defined as a physical
change, or change in the method of operation, that results in an
increase in hourly CO2 emissions of more than 10 percent
when compared to the source's highest hourly emissions in the previous
5 years. Such a modified steam generating unit is required to meet a
unit-specific CO2 emission limit determined by that unit's
best demonstrated historical performance (in the years from 2002 to the
time of the modification). The 2015 NSPS did not include standards for
a steam generating unit that implements a ``small modification,''
defined as a change that results in an increase in hourly
CO2 emissions of less than or equal to 10 percent when
compared to the source's highest hourly emissions in the previous 5
years.\898\
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\898\ 80 FR 64514 (October 23, 2015).
---------------------------------------------------------------------------
In the 2015 NSPS, the EPA explained its basis for promulgating this
rule as follows. The EPA has historically been notified of only a
limited number of NSPS modifications involving fossil fuel-fired steam
generating units and therefore predicted that very few of these units
would trigger the modification provisions and be subject to the
proposed standards. Given the limited information that we have about
past modifications, the Agency has concluded that it lacks sufficient
information to establish standards of performance for all types of
modifications at steam generating units at this time. Instead, the EPA
has determined that it is appropriate to establish standards of
performance at this time for larger modifications, such as major
facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that result
in substantial increases in a unit's hourly CO2 emissions
rate. The Agency has determined, based on its review of public comments
and other publicly available information, that it has adequate
information regarding the types of modifications that could result in
large increases in hourly CO2 emissions, as well as on the
types of measures available to control emissions from sources that
undergo such modifications, and on the costs and effectiveness of such
control measures, upon which to establish standards of performance for
modifications with large emissions increases at this time.\899\ The EPA
did not reopen any aspect of these determinations concerning
modifications in the 2015 NSPS, except, as noted below, for the BSER
and associated requirements for large modifications.
---------------------------------------------------------------------------
\899\ Id. at 64597-98.
---------------------------------------------------------------------------
Because the EPA has not promulgated a NSPS for small modifications,
any existing steam generating unit that undertakes a change that
increases its hourly CO2 emissions rate by 10 percent or
less will continue to be treated as an existing source that is subject
to the CAA section 111(d) requirements being finalized today.
With respect to large modifications, the EPA explained in the 2015
NSPS that they are rare, but there is record evidence indicating that
they may occur.\900\ Because the EPA is finalizing requirements for
existing coal-fired steam generating units that are, on their face,
more stringent than the requirements for large modifications, the EPA
believes it is appropriate to review and revise the latter requirements
to minimize the anomalous incentive that an existing source could have
to undertake a large modification for the purpose of avoiding the more
stringent requirements that it would be subject to if it remained an
existing source. Accordingly, the EPA proposed and is finalizing
amending the BSER for large modifications for coal-fired steam
generating units to mirror the BSER for the subcategory of long-term
coal-fired steam generating units that is, the use of CCS with 90
percent capture of CO2. The EPA believes that it is
reasonable to assume that any existing source that invests in a
physical change or change in the method of operation that would qualify
as a large modification expects to continue to operate past 2039.
Accordingly, the EPA has determined that CCS with 90 percent capture
qualifies as the BSER for such a source for the same reasons that it
qualifies as the BSER for existing sources that plan to operate past
December 31, 2039. The EPA discusses these reasons in section VII.C.1.a
of this preamble. The EPA has determined that CCS with 90 percent
capture qualifies as the BSER for large modifications, and not the
controls determined to be the BSER in the 2015 NSPS, due to the recent
reductions in the cost of CCS.
---------------------------------------------------------------------------
\900\ Id. at 64598.
---------------------------------------------------------------------------
By the same token, the EPA is finalizing that the degree of
emission limitation associated with CCS with 90 percent capture is an
88.4 percent reduction in emission rate (lb CO2/MWh-gross
basis), the same as finalized for existing sources with CCS with 90
percent capture. See section VII.C.3.a of this preamble. Based on this
degree of emission limitation, the EPA proposed and is finalizing that
the standard of performance for steam generating units that undertake
large modifications after May 23, 2023, is a unit-specific emission
limit determined by an 88.4 percent reduction in the unit's best
historical annual CO2 emission rate (from 2002 to the date
of the modification). The EPA proposed and is finalizing that an owner/
operator of a modified steam generating unit comply with the emissions
rate upon startup of the modified affected facility or the effective
date of the final rule, whichever is later. The EPA proposed and is
finalizing the same testing, monitoring, and reporting requirements as
are currently in 40 CFR part 60, subpart TTTT.
The EPA did not propose, and is not finalizing, any review or
revision of the 2015 standard for large modifications of oil- or gas-
fired steam generating units because the 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.
2. New Construction and Reconstruction
The EPA promulgated NSPS for GHG emissions from fossil fuel-fired
steam generating units in 2015. In the proposal, the EPA proposed that
it did not need to review the 2015 NSPS because at that time, the EPA
did not have information indicating that any such units will be
constructed or reconstructed. However, the EPA has recently become
aware that a new coal-fired power plant is under consideration in
Alaska. In November 2023, DOE announced a $9 million cooperative
agreement for the Alaska Railbelt Carbon Capture and Storage (ARCCS)
project, to be led by researchers at the University of Alaska
Fairbanks. The ARCCS project would study the viability of a carbon
storage complex in Southcentral Alaska, likely at the mostly-depleted
Beluga River gas field west of Anchorage'' in the Cook Inlet Basin,
which could store captured CO2. According to reports, the
privately owned Flatlands Energy Corp. is considering constructing a
400 MW coal- and biomass-fired power plant in the Susitna River valley
region, which, if built, would be one of the sources of captured
CO2.\901\
---------------------------------------------------------------------------
\901\ DOE Funding Opportunity Announcement, ``DOE Invests More
Than $444 Million for CarbonSAFE Project,'' (November 15, 2023),
https://netl.doe.gov/node/13090; University of Alaska Fairbanks,
Institute of Northern Engineering, ``Cook Inlet Region Low Carbon
Power Generation With Carbon Capture, Transport, and Storage
Feasibility Study,'' https://ine.uaf.edu/media/391133/cook-inlet-low-carbon-power-feasibility-study-uaf-pcorfinal.pdf; Herz,
Nathaniel, ``Could a new Alaska coal power plant be climate
friendly? An $11 million study aims to find out,'' Northern Journal
(December 29, 2923), republished in Anchorage Daily News, https://www.adn.com/business-economy/energy/2023/12/29/could-a-new-alaska-coal-power-plant-be-climate-friendly-an-11-million-study-aims-to-find-out/.
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[[Page 39955]]
In light of this development, the EPA is not finalizing its
proposal not to review the 2015 NSPS. Instead, the EPA will continue to
consider whether to review the 2015 NSPS and will monitor the
development of this potential new construction project in Alaska as
well as any other potential projects to newly construct or reconstruct
a coal-fired power plant. If the EPA does decide to review the 2015
NSPS, it would propose to revise them for coal-fired steam generating
units.
D. Projects Under Development
During the 2015 NSPS rulemaking, the EPA identified the Plant
Washington project in Georgia and the Holcomb 2 project in Kansas as
EGU ``projects under development'' based on representations by
developers that the projects had commenced construction prior to the
proposal of the 2015 NSPS and, thus, would not be new sources subject
to the final NSPS (80 FR 64542-43; October 23, 2015). The EPA did not
set a performance standard at the time but committed to doing so if new
information about the projects became available. These projects were
never constructed and are no longer expected to be constructed.
The Plant Washington project was to be an 850 MW supercritical
coal-fired EGU. The Environmental Protection Division (EPD) of the
Georgia Department of Natural Resources issued air and water permits
for the project in 2010 and issued amended permits in
2014.902 903 904 In 2016, developers filed a request with
the EPD to extend the construction commencement deadline specified in
the amended permit, but the director of the EPD denied the request,
effectively canceling the approval of the construction permit and
revoking the plant's amended air quality permit.\905\
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\902\ https://www.gpb.org/news/2010/07/26/judge-rejects-coal-plant-permits.
\903\ https://www.southernenvironment.org/press-release/court-rules-ga-failed-to-set-safe-limits-on-pollutants-from-coal-plant/.
\904\ https://permitsearch.gaepd.org/permit.aspx?id=PDF-OP-22139.
\905\ https://www.southernenvironment.org/wp-content/uploads/legacy/words_docs/EPD_Plant_Washington_Denial_Letter.pdf.
---------------------------------------------------------------------------
The Holcomb 2 project was intended to be a single 895 MW coal-fired
EGU and received permits in 2009 (after earlier proposals sought
approval for development of more than one unit). In 2020, after
developers announced they would no longer pursue the Holcomb 2
expansion project, the air permits were allowed to expire, effectively
canceling the project.
For these reasons, the EPA proposed and is finalizing a decision to
remove these projects under the applicability exclusions in subpart
TTTT.
X. State Plans for Emission Guidelines for Existing Fossil Fuel-Fired
EGUs
A. Overview
This section provides information related to state plan
development, including methodologies for establishing presumptively
approvable standards of performance for affected EGUs, flexibilities
for complying with standards of performance, and components that must
be included in state plans as well as the process for submission. This
section also addresses significant comments on and any changes to the
proposed emission guidelines regarding state plans that the EPA is
finalizing in this action.
State plan submissions under these emission guidelines are governed
by the requirements of 40 CFR part 60, subpart Ba (subpart Ba).\906\
The EPA finalized revisions to certain aspects of 40 CFR part 60,
subpart Ba, in November 2023, Adoption and Submittal of State Plans for
Designated Facilities: Implementing Regulations Under Clean Air Act
Section 111(d) (final subpart Ba).\907\ Unless expressly amended or
superseded in these emission guidelines, the provisions of subpart Ba
apply. This section explicitly addresses any instances where the EPA is
adding to, superseding, or otherwise varying the requirements of
subpart Ba for the purposes of these particular emission guidelines.
---------------------------------------------------------------------------
\906\ 40 CFR 60.20a-60.29a.
\907\ 88 FR 80480 (November 17, 2023). At the time of
promulgation of these emission guidelines, the November 2023 updates
to the CAA section 111(d) implementing regulations are subject to
litigation in the D.C. Circuit Court of Appeals. West Virginia v.
EPA, D.C. Circuit No. 24-1009. The outcome of that litigation will
not affect any of the distinct requirements being finalized in these
emission guidelines, which are not directly dependent on those
procedural requirements. Moreover, regardless of the outcome of that
litigation, the necessary regulatory framework will exist for states
to develop and submit state plans that include standards of
performance for affected EGUs pursuant to these emission guidelines
and prior implementing regulations.
---------------------------------------------------------------------------
As noted in the preamble of the proposed action, under the Tribal
Authority Rule (TAR) adopted by the EPA, Tribes may seek authority to
implement a plan under CAA section 111(d) in a manner similar to that
of a state. See 40 CFR part 49, subpart A. Tribes may, but are not
required to, seek approval for treatment in a manner similar to that of
a state for purposes of developing a Tribal Implementation Plan (TIP)
implementing the emission guidelines. If a Tribe obtains approval and
submits a TIP, the EPA will generally use similar criteria and follow
similar procedures as those described for state plans when evaluating
the TIP submission and will approve the TIP if appropriate. The EPA is
committed to working with eligible Tribes to help them seek
authorization and develop plans if they choose. Tribes that choose to
develop plans will generally have the same flexibilities available to
states in this process.
In section X.B of this document, the EPA describes the foundational
requirement that state plans achieve an equivalent level of emission
reduction to the degree of emission limitation achievable through
application of the BSER as determined by the EPA. Section X.C describes
the presumptive methodology for calculating the standards of
performance for affected EGUs based on subcategory assignment, as well
as requirements related to invoking RULOF to apply a less stringent
standard of performance than results from the EPA's presumptive
methodology. Section X.C also describes requirements for increments of
progress for affected EGUs in certain subcategories and for
establishing milestones and reporting obligations for affected EGUs
that plan to permanently cease operations, as well as testing and
monitoring requirements. In section X.D, the EPA describes how states
are permitted to include flexibilities such as emission trading and
averaging as compliance measures for affected EGUs in their state
plans. Finally, section X.E describes what must be included in state
plans, including plan components specific to these emission guidelines
and requirements for conducting meaningful engagement, as well as the
timing of state plan submission and EPA review of state plans and plan
revisions.
In this section of the preamble, the term ``affected EGU'' means
any existing fossil fuel-fired steam generating unit that meets the
applicability criteria described in section VII.B of this preamble.
Affected EGUs are covered by the emission guidelines being finalized in
this action under 40 CFR part 60 subpart UUUUb.
[[Page 39956]]
B. Requirement for State Plans To Maintain Stringency of the EPA's BSER
Determination
As explained in section V.C of this preamble, CAA section 111(d)(1)
requires the EPA to establish requirements for state plans that, in
turn, must include standards of performance for existing sources. Under
CAA section 111(a)(1), a standard of performance is ``a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the best system of
emission reduction which . . . the Administrator determines has been
adequately demonstrated.'' That is, the EPA has the responsibility to
determine the BSER for a given category or subcategory of sources and
to determine the degree of emission limitation achievable through
application of the BSER to affected sources.\908\ The level of emission
reductions required of existing sources under CAA section 111 is
reflected in the EPA's presumptive standards of performance,\909\ which
achieve emission reductions under these emission guidelines through
requiring cleaner performance by affected sources.
---------------------------------------------------------------------------
\908\ See, e.g., West Virginia v. EPA, 597 U.S. 697, 720 (2022)
(``In devising emissions limits for power plants, EPA first
`determines' the `best system of emission reduction' that--taking
into account cost, health, and other factors--it finds `has been
adequately demonstrated.' The Agency then quantifies `the degree of
emission limitation achievable' if that best system were applied to
the covered source.'') (internal citations omitted).
\909\ See 40 CFR 60.22a(b)(5).
---------------------------------------------------------------------------
States use the EPA's presumptive standards of performance to
establish requirements for affected sources in their state plans. In
general, the standards of performance that states establish for
affected sources must be no less stringent than the presumptive
standards of performance in the applicable emission guidelines.\910\
Thus, in order for the EPA to find a state plan ``satisfactory,'' that
plan must address each affected EGU within the state and must achieve
at least the level of emission reduction that would result if each
affected EGU was achieving its presumptive standard of performance,
after accounting for any application of RULOF.\911\ That is, while
states have the discretion to establish the applicable standards of
performance for affected EGUs in their state plans, the structure and
purpose of CAA section 111 and the EPA's regulations require that those
plans achieve an equivalent level of emission reductions as applying
the EPA's presumptive standards of performance to each of those sources
(again, after accounting for any application of RULOF). Section X.C of
this preamble addresses how states maintain the level of emission
reduction when establishing standards of performance, and section X.D
of this preamble addresses how states maintain the level of emission
reduction when incorporating compliance flexibilities.
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\910\ 40 CFR 60.24a(c).
\911\ As explained in section X.C.2 of this preamble, states may
invoke RULOF to apply a less stringent standard of performance to a
particular affected EGU when the state demonstrates that the EGU
cannot reasonably achieve the degree of emission limitation
determined by the EPA. In this case, the state plan may not
necessarily achieve the same stringency as each source achieving the
EPA's presumptive standards of performance because affected EGUs for
which RULOF has been invoked would have standards of performance
less stringent than the EPA's presumptive standards.
---------------------------------------------------------------------------
Additionally, consistent with the understanding that the purpose of
CAA section 111 is for affected sources to reduce their emissions
through cleaner operation, the Agency is also clarifying that emissions
reductions from sources not affected by the final emission guidelines
may not be counted towards compliance with either a source-specific or
aggregate standard of performance. In other words, state plans may not
account for emission reductions at non-affected fossil fuel-fired EGUs,
emission reductions due to the operation or installation of other
electricity-generating resources not subject to these emission
guidelines for the purposes of demonstrating compliance with affected
EGUs' standards of performance.
C. Establishing Standards of Performance
This section addresses several topics related to standards of
performance in state plans. First, this section describes affected
EGUs' eligibility for the subcategories in the final emission
guidelines and how to calculate presumptive standards of performance,
including calculating unit-specific baseline emission performance.
Second, it summarizes compliance date information as well as how states
can provide for a compliance date extension mechanism in their state
plans. Third, this section describes how states may consider RULOF to
apply a less stringent standard of performance or a longer compliance
schedule to a particular affected EGU. Fourth, it explains how states
must establish certain increments of progress for affected EGUs
installing control technology to comply with standards of performance,
as well as milestones and reporting obligations for affected EGUs
demonstrating that they plan to permanently cease operations. And,
finally, this section describes emission testing and monitoring
requirements.
Affected EGUs that meet the applicability requirements discussed in
section VII.B must be addressed in the state plan. For each affected
EGU within the state, the state plan must include a standard of
performance and compliance schedule. That is, each individual unit must
have its own, source-specific standard of performance and compliance
schedule. Coal-fired affected EGUs must have increments of progress in
the state plan and, if they plan to permanently cease operation and to
rely on such cessation of operation for purposes of these emission
guidelines, an enforceable commitment and reporting obligations and
milestones. State plans must also specify the test methods and
procedure for determining compliance with the standards of performance.
While a presumptive methodology for standards of performance and
other requirements were proposed for existing combustion turbine EGUs,
the EPA is not finalizing emission guidelines for such EGUs at this
time; therefore, the following discussion will not address the proposed
combustion turbine EGU requirements or comments pertaining to these
proposed requirements. In addition, the EPA is not finalizing the
imminent- and near-term coal-fired subcategories for coal-fired steam
generating units; therefore, the following discussion will not address
these proposed subcategories or comments pertaining to these proposed
subcategories. Similarly, the EPA is not finalizing emission guidelines
for states and territories in non-contiguous areas, and is therefore
not finalizing the proposed subcategories for non-continental oil-fired
steam generating units or associated requirements nor addressing
comments pertaining to these subcategories in this section.
1. Application of Presumptive Standards
This section of the preamble describes the EPA's approach to
providing presumptive standards of performance for each of the
subcategories of affected EGUs under these emission guidelines,
including establishing baseline emission performance. As explained in
section X.B of this preamble, CAA section 111(a)(1) requires that
standards of performance reflect the degree of emission limitation
achievable through application of the BSER, as determined by the EPA.
For each subcategory of affected EGUs, the EPA has determined a BSER
and degree of emission limitation and is providing, in these emission
guidelines, a methodology for
[[Page 39957]]
establishing presumptively approvable standards of performance (also
referred to as ``presumptive standards of performance'' or
``presumptive standards''). Appropriate use of these methodologies will
result in standards of performance that achieve the requisite degree of
emission limitation and therefore meet the statutory requirements of
section 111(a)(1) and the corresponding regulatory requirement that
standards of performance must generally be no less stringent that the
corresponding emission guidelines.\912\ 40 CFR 60.24a(c).
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\912\ Should a state decide to establish a standard of
performance for an affected EGU using a methodology other than that
provided by the EPA in these emission guidelines, the state would
have to demonstrate that the resulting standard of performance
achieves equivalent emission reductions as application of the EPA's
presumptive standard of performance.
---------------------------------------------------------------------------
Thus, a state, when establishing standards of performance for
affected EGUs in its plan, must identify each affected EGU in the state
and specify into which subcategory each affected EGU falls. The state
would then use the corresponding methodology for the given subcategory
to establish the presumptively approvable standard of performance for
each affected EGU.
As discussed in section X.C.2 of this preamble, states may apply
less stringent standards of performance to particular affected EGUs in
certain circumstances based on consideration of RULOF. States also have
the authority to deviate from the methodology provided in these
emission guidelines for presumptively approvable standards in order to
apply a more stringent standard of performance (e.g., a state decides
that an affected EGU in the medium-term coal-fired subcategory should
comply with a standard of performance corresponding to co-firing 50
percent natural gas instead of 40 percent). Application of a standard
of performance that is more stringent than provided by the EPA's
presumptive methodology does not require application of the RULOF
provisions.\913\
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\913\ 88 FR 80529-31 (November 17, 2023).
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a. Establishing Baseline Emission Performance for Presumptive Standards
For each subcategory, the methodology to calculate a standard of
performance entails establishing a baseline of CO2 emissions
and corresponding electricity generation or heat input for an affected
EGU and then applying the degree of emission limitation achievable
through the application of the BSER (as established in section VII.C of
this preamble). The methodology for establishing baseline emission
performance for an affected EGU will result in a value that is unique
to each affected EGU. To establish baseline emission performance for an
affected EGU in all the subcategories except the low load natural gas-
and oil-fired subcategories, the EPA is finalizing a determination that
a state will use the CO2 mass emissions and corresponding
electricity generation data for a given affected EGU from any
continuous 8-quarter period from 40 CFR part 75 reporting within the 5-
year period immediately prior to the date the final rule is published
in the Federal Register. For affected EGUs in either the low load
natural gas-fired subcategory or the low load oil-fired subcategory,
the EPA is finalizing a determination that a state will use the
CO2 mass emissions and corresponding heat input for a given
affected EGU from any continuous 8-quarter period from 40 CFR part 75
reporting within the 5-year period immediately prior to the date the
final rule is published in the Federal Register. This period is based
on the NSR program's definition of ``baseline actual emissions'' for
existing electric steam generating units. See 40 CFR 52.21(b)(48)(i).
Eight quarters of 40 CFR part 75 data corresponds to a 2-year period,
but the EPA is finalizing this continuous 8-quarter period as it
corresponds to quarterly reporting according to 40 CFR part 75.
Functionally, the EPA expects states to utilize the most representative
continuous 8-quarter period of data from the 5-year period immediately
preceding the date the final rule is published in the Federal Register.
For the 8 quarters of data, a state would divide the total
CO2 emissions (in the form of pounds) over that continuous
time period by either the total gross electricity generation (in the
form of MWh) or, for affected EGUs in either the low load natural gas-
fired subcategory or the low load oil-fired subcategory, the total heat
input (in the form of MMBtu) over that same time period to calculate
baseline CO2 emission performance in either lb of
CO2 per MWh or lb of CO2 per MMBtu. As an
example, a state establishing baseline emission performance for an
affected EGU in the medium-term coal-fired subcategory in the year 2023
would start by evaluating the CO2 emissions and electricity
generation data for the affected EGU for 2018 through 2022 and choose a
continuous 8-quarter period that it deems to be the most appropriate
representation of the operation of that affected EGU. While the EPA
will evaluate the choice of baseline periods chosen by states when
reviewing state plan submissions, the EPA intends to defer to a state's
reasonable exercise of discretion as to which 8-quarter period is
representative.
The EPA is finalizing the use of 8 quarters during the 5-year
period prior to the date the final rule is published in the Federal
Register as the relevant period for the baseline methodology for
several reasons. First, each affected EGU has unique operational
characteristics that affect the emission performance of the EGU (load,
geographic location, hours of operation, coal rank, unit size, etc.),
and the EPA believes each affected EGU's emission performance baseline
should be representative of the source-specific conditions of the
affected EGU and how it has typically operated. Additionally, allowing
a state to choose (likely in consultation with the owners or operators
of affected EGUs) the 8-quarter period for assessing baseline
performance can avoid situations in which a prolonged period of
atypical operating conditions would otherwise skew the emissions
baseline. Relatedly, the EPA believes that, by using total mass
CO2 emissions and total electric generation or heat input
for an affected EGU over an 8-quarter period, any relatively short-term
variability of data due to seasonal operations or periods of startup
and shutdown, or other anomalous conditions, will be averaged into the
calculated level of baseline emission performance. The baseline-setting
approach also aligns with the reporting and compliance requirements in
the final emission guidelines. Using total mass CO2
emissions and total electric generation or heat input provides a simple
and streamlined approach for calculating baseline emission performance
without the need to sort and filter non-representative data; any minor
amount of non-representative data will be subsumed and accounted for
through implicit averaging over the course of the 8-quarter period.
Moreover, by not sorting or filtering the data, this approach reduces
the need for discretion in assessing whether the data is appropriate to
use. Commenters generally supported the proposed methodology for
setting a baseline, particularly saying that they prefer not to have to
sort or filter any data.
The EPA believes that using this baseline-setting approach as the
basis for establishing presumptively approvable standards of
performance will provide certainty for states, as well as transparency
and a streamlined process for state plan development. While this
approach is specifically designed to be flexible enough to
[[Page 39958]]
accommodate unit-specific circumstances, states retain the ability to
deviate from this methodology. The EPA believes that the instances in
which a state may need to use an alternate baseline-setting methodology
will be limited to anticipated changes in operation, (i.e.,
circumstances in which historical emission performance is not
representative of future emission performance). States that wish to
vary the baseline calculation for an affected EGU based on anticipated
changes in operation of that EGU, when those changes result in a less
stringent standard of performance, must use the RULOF mechanism, which
is designed to address such contingencies.
Comment: Commenters sought clarification as to whether the
methodology referred to the previous 5 calendar years or the 5-year
period ending on the most recent quarter reported under 40 CFR part 75
prior to publication of the final emission guidelines.
Response: The EPA clarifies that the methodology refers to the 5-
year period ending on the most recent quarter reported under 40 CFR
part 75 prior to publication of the final emission guidelines in the
Federal Register.
b. Presumptive Standards for Fossil Fuel-Fired Steam Generating Units
As described in section VII of this preamble, the EPA is finalizing
separate subcategories of existing fossil fuel-fired steam generating
units based on fuel type (i.e., coal-fired, natural gas-fired, or oil-
fired). Fuel type is based on the status of the source on January 1,
2030, and annual fuel use reporting is required after that date as a
part of compliance. The EPA is further creating a subcategory for coal-
fired steam generating units operating in the medium term, and further
subcategorizing natural gas- and oil-fired steam generating units by
load level.
Consistent with CAA section 111(d)(1)'s requirement that state
plans provide for the implementation and enforcement of standards of
performance, for affected EGUs in the medium-term subcategory, states
must include sources' enforceable commitments to cease operating before
January 1, 2039, in their plans. The state plan must specify the
calendar date by which the affected EGU plans to cease operation; to be
included in a state plan, a commitment to cease operations by such a
date must be enforceable by the state, whether through state rule,
agreed order, permit, or other legal instrument.\914\ Upon EPA approval
of the state plan, that commitment will become federally- and citizen-
enforceable.
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\914\ 40 CFR 60.26a.
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For affected oil- and natural gas-fired steam generating units,
subcategories are defined by load level and the type of fuel fired.
There are three subcategories for natural gas- and oil-fired steam
generating units (base load, intermediate load, and low load). Because
subcategory applicability is determined retrospectively, as opposed to
prospectively, and because the standards of performance for oil- and
natural gas-fired affected EGUs are based on BSERs that do not require
add-on controls, it is not necessary to require these sources to take
enforceable utilization commitments limiting them to just one
subcategory in order to implement and enforce their standards. For
steam generating units that meet the definition of natural gas- or oil-
fired, and that either retain the capability to fire coal after the
date this final rule is published in the Federal Register, that fired
any coal during the 5-year period prior to that date, or that will fire
any coal after that date and before January 1, 2030, the plan must
include a requirement to remove the capability to fire coal before
January 1, 2030.
The EPA is finalizing a requirement that compliance be demonstrated
annually. For affected EGUs in all subcategories except the low load
natural gas- and oil-fired subcategory, an affected EGU must
demonstrate compliance based on the lb CO2/MWh emission rate
derived by dividing the total reported CO2 mass emissions by
the total reported electric generation during the compliance period
(corresponding to 1 calendar year), which is consistent with the
expression of the degree of emission limitation for each subcategory in
sections VII.C.3 and VII.D.3. For affected EGUs in the low load natural
gas- and oil-fired subcategory, an affected EGU must demonstrate
compliance based on the lb CO2/MMBtu emission rate derived
by dividing the total reported CO2 mass emissions by the
total reported heat input during the compliance period (again,
corresponding to 1 calendar year), consistent with the expression of
the degree of emission limitation for the subcategory in section
VII.D.3.\915\ In other words, for units with a compliance date of
January 1, 2030, the first compliance period will be January 1, 2030,
through December 31, 2030. For units with a compliance date of January
1, 2032, the first compliance period will be January 1, 2032, through
December 31, 2032. The compliance demonstration must occur by March 1
of the following year (i.e., for the 2030 compliance period, by March
1, 2031).
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\915\ If the state plan incorporates compliance flexibilities
like emission averaging and trading, an affected EGU must
demonstrate compliance consistent with the expression of the
respective flexibility. See section X.D of this preamble for more
information.
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In addition, the EPA is finalizing a requirement that standards of
performance must be established as either a rate or, for affected EGUs
in certain subcategories, a mass of emissions. If a state chooses to
allow mass-based compliance for certain affected EGUs it must first
calculate the rate-based emission limitation that corresponds to the
presumptive standard of performance, and then explain how it translated
that rate-based emission limitation into the mass that constitutes an
affected EGU's standard of performance. See section X.D of this
preamble for more information on demonstrating compliance where states
are incorporating compliance flexibilities.
i. Long-Term Coal-Fired Steam Generating Units
This section describes the EPA's methodology for establishing
presumptively approvable standards of performance for long-term coal-
fired steam generating units. Affected coal-fired steam generating
units that do not meet the specifications of the medium-term coal-fired
EGU subcategory are necessarily long-term units, and have a BSER of CCS
with 90 percent capture and a degree of emission limitation of 90
percent capture of the mass of CO2 in the flue gas (i.e.,
the mass of CO2 after the boiler but before the capture
equipment) over an extended period of time and an 88.4 percent
reduction in emission rate on a lb CO2/MWh-gross basis over
an extended period of time (i.e., an annual calendar-year basis). The
EPA is finalizing a determination that where states use the methodology
described here to establish standards of performance for affected EGUs
in this subcategory, those established standards will be presumptively
approvable when included in a state plan submission.
Establishing a standard of performance for an affected coal-fired
EGU in this subcategory consists of two steps: establishing a source-
specific level of baseline emission performance (as described in
section X.C.1.a of this preamble); and applying the degree of emission
limitation, based on the application of the BSER, to that level of
baseline emission performance. Implementation of CCS with a capture
rate of 90 precent translates to a degree
[[Page 39959]]
of emission limitation comprising of an 88.4 percent reduction in
CO2 emission rate compared to the baseline level of emission
performance. Using the complement of 88.4 percent (i.e., 11.6 percent)
and multiplying it by the baseline level of emission performance
results in the presumptively approvable standard of performance. For
example, if a long-term coal-fired EGU's level of baseline emission
performance is 2,000 lbs CO2 per MWh, it will have a
presumptively approvable standard of performance of 232 lbs
CO2 per MWh (2,000 lbs CO2 per MWh multiplied by
0.116).
The EPA is also finalizing a requirement that affected coal-fired
EGUs in the long-term subcategory comply with federally enforceable
increments of progress, which are described in section X.C.3 of this
preamble.
ii. Medium-Term Coal-Fired Steam Generating Units
This section describes the EPA's methodology for establishing
presumptively approvable standards of performance for medium-term coal-
fired steam generating units. Affected coal-fired steam generating
units that plan to commit to permanently cease operations before
January 1, 2039, have a BSER of 40 percent natural gas co-firing on a
heat input basis. The EPA is finalizing a determination that where
states use the methodology described here to establish standards of
performance for an affected EGU in this subcategory, those established
standards of performance would be presumptively approvable when
included in a state plan submission.
Establishing a standard of performance for an affected EGU in this
subcategory consists of two steps: establishing a source-specific level
of baseline emission performance (as described in section X.C.1.a); and
applying the degree of emission limitation, based on the application of
the BSER, to that level of baseline emission performance.
Implementation of natural gas co-firing at a level of 40 percent of
total annual heat input translates to a level of stringency of a 16
percent reduction in emission rate on a lb CO2/MWh-gross
basis over an extended period of time (i.e., an annual calendar-year
basis) compared to the baseline level of emission performance. Using
the complement of 16 percent (i.e., 84 percent) and multiplying it by
the baseline level of emission performance results in the presumptively
approvable standard of performance for the affected EGU. For example,
if a medium-term coal-fired EGU's level of baseline emission
performance is 2,000 lbs CO2 per MWh, it will have a
presumptively approvable standard of performance of 1,680
CO2 lbs per MWh (2,000 lbs CO2 per MWh multiplied
by 0.84).
For medium-term coal-fired steam generating units that have an
amount of co-firing that is reflected in the baseline operation, the
EPA is finalizing a requirement that states account for such
preexisting co-firing in adjusting the degree of emission limitation.
If, for example, an EGU co-fires natural gas at a level of 10 percent
of the total annual heat input during the applicable 8-quarter baseline
period, the corresponding degree of emission limitation would be
adjusted to a 12 percent reduction in CO2 emission rate on a
lb CO2/MWh-gross basis compared to the baseline level of
emission performance (i.e., an additional 30 percent of natural gas by
heat input) to reflect the preexisting level of natural gas co-firing.
This results in a standard of performance based on the degree of
emission limitation achieving an additional 30 percent co-firing beyond
the 10 percent that is accounted for in the baseline. The EPA believes
this approach is a more straightforward mathematical adjustment than
adjusting the baseline to appropriately reflect a preexisting level of
co-firing.
The standard of performance for the medium-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, the BSER determination for this subcategory is
predicated on the assumption that affected EGUs within it will
permanently cease operations prior to January 1, 2039. If a state
decides to place an affected EGU in the medium-term coal-fired
subcategory, the state plan must include that EGU's commitment to
permanently cease operating as an enforceable requirement. The state
plan must also include provisions that provide for the implementation
and enforcement of this commitment, including requirements for
monitoring, reporting, and recordkeeping.
Affected coal-fired EGUs that are relying on commitments to cease
operating must comply with the milestones and reporting requirements as
specified under these emission guidelines. The EPA intends these
milestones to assist affected EGUs in ensuring they are completing the
necessary steps to comply with their state plan requirements and to
help ensure that any issues with implementation are identified in a
timely and efficient manner. These milestones are described in detail
in section X.C.4 of this preamble. Affected EGUs in this subcategory
would also be required to comply with the federally enforceable
increments of progress described in section X.C.3 of this preamble.
iii. Natural Gas-Fired Steam Generating Units and Oil-Fired Steam
Generating Units
This section describes the EPA's final methodology for
presumptively approvable standards of performance for the following
subcategories of affected natural gas-fired and oil-fired steam
generating units: low load natural gas-fired steam generating units,
intermediate load natural gas-fired steam generating units, base load
natural gas-fired steam generating units, low load oil-fired steam
generating units, intermediate load oil-fired steam generating units,
and base load oil-fired steam generating units. The final definitions
of these subcategories are discussed in section VII.D.1 of this
preamble. The final presumptive standards of performance are based on
degrees of emission limitation that units are currently achieving,
consistent with the proposed BSER of routine methods of operation and
maintenance, which amounts to a proposed degree of emission limitation
of no increase in emission rate.
For natural gas-fired steam generating units, the EPA proposed
fixed presumptive standards of 1,500 lb CO2/MWh-gross for
intermediate load units (solicited comment on values between 1,400 and
1,600 lb/MWh-gross) and 1,300 lb CO2/MWh-gross for base load
units (solicited comment on values between 1,250 and 1,400 lb
CO2/MWh-gross). For oil-fired steam generating units, the
EPA proposed fixed presumptive standards of 1,500 lb CO2/
MWh-gross for intermediate load units (solicited comment on values
between 1,400 and 2,000 lb/MWh-gross) and 1,300 lb CO2/MWh-
gross for base load units (solicited comment on values between 1,250
and 1,800 lb CO2/MWh-gross).
The EPA is finalizing presumptive standards of performance for
affected natural gas-fired and oil-fired steam generating units in lieu
of methodologies that states would use to establish presumptive
standards of performance. This is largely because of the low
variability in emissions data at intermediate and base load for these
units and relatively consistent performance between these units at
[[Page 39960]]
those load levels, as discussed in section VII.D of this preamble and
detailed in the final TSD, Natural Gas- and Oil-fired Steam Generating
Units, which supports the establishment of a generally applicable
standard of performance.
For intermediate load natural gas-fired units (annual capacity
factors greater than or equal to 8 percent and less than 45 percent),
annual emission rates are less than 1,600 lb CO2/MWh-gross
for more than 95 percent of units. Therefore, the EPA is finalizing the
presumptive standard of performance of an annual calendar-year emission
rate of 1,600 lb CO2/MWh-gross for these units.
For base load natural gas-fired units (annual capacity factors
greater than or equal to 45 percent), annual emission rates are less
than 1,400 lb CO2/MWh-gross for more than 95 percent of
units. Therefore, the EPA is finalizing the presumptive standard of
performance of an annual calendar-year emission rate of 1,400 lb
CO2/MWh-gross for these units.
In the continental U.S., there are few if any oil-fired steam
generating units that operate with intermediate or high utilization.
Liquid-oil-fired steam generating units with 24-month capacity factors
less than 8 percent do qualify for a work practice standard in lieu of
emission requirements under the MATS (40 CFR part 63, subpart UUUUU).
If oil-fired units operated at higher annual capacity factors, it is
likely they would do so with substantial amounts of natural gas-firing
and have emission rates that are similar to steam generating units that
fire only natural gas at those levels of utilization. There are a few
natural gas-fired steam generating units that are near the threshold
for qualifying as oil-fired units (i.e., firing more than 15 percent
oil in a given year) but that on average fire more than 90 percent of
their heat input from natural gas. Therefore, the EPA is finalizing the
same presumptive standards of performance for oil-fired steam
generating units as for natural gas-fired units (1,400 lb
CO2/MWh-gross for base load units and 1,600 lb
CO2/MWh-gross for intermediate load units).
Lastly, the EPA is finalizing uniform fuels as the BSER for low
load natural gas and oil-fired steam generating units. The EPA is
finalizing degrees of emission limitation defined by 130 lb
CO2/MMBtu for low load natural gas-fired steam generating
units and 170 lb CO2/MMBtu for low load oil-fired steam
generating units, and presumptively approvable standards consistent
with those values.
Comment: One commenter stated that the EPA should instead allow
states to define standards using a source's baseline emission rate,
with some additional flexibilities to account for changes in load.\916\
The commenter also requested that, if the EPA were to finalize
presumptive standards, then the higher values that the EPA solicited
comment on for natural gas-fired units should be finalized. The
commenter similarly requested that, if the EPA were to finalize
presumptive standards, then the higher values that the EPA solicited
comment on for oil-fired units should be finalized--however, the
commenter also noted that its two sources that are currently oil-firing
operate below an 8 percent annual capacity factor and would therefore
not be subject to the intermediate load or base load presumptive
standard.
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\916\ See Document ID No. EPA-HQ-OAR-2023-0072-0806.
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Response: The EPA is finalizing presumptive standards for natural
gas-fired steam generating units of 1,400 lb CO2/MWh-gross
for base load units and 1,600 lb CO2/MWh-gross for
intermediate load units. The EPA is finalizing the same standards for
oil-fired steam generating units for the reasons discussed in the
preceding text. Few, if any, oil-fired units operate as intermediate
load or base load units, as acknowledged by the commenter. Those oil-
fired units that have operated near the threshold for intermediate load
have typically fired a large proportion of natural gas and operated at
emission rates consistent with the final presumptive standards.
c. Compliance Dates
This section summarizes information on the compliance dates, or the
first date on which the standard of performance applies, that the EPA
is finalizing for each subcategory. As discussed in section X.C.1.b,
compliance is required to be demonstrated on an annual (i.e., calendar
year) basis.
The EPA proposed a compliance date of January 1, 2030, for all
affected steam generating units. As discussed in section VII.C.1.a.i(E)
of this preamble, the EPA received comments that this compliance date
was not achievable for sources in the long-term coal-fired EGU
subcategory that would be installing CCS. In response to those
comments, the EPA reevaluated the information and timeline for CCS
installation and is finalizing a compliance date of January 1, 2032,
for the long-term coal-fired subcategory. The Agency is finalizing a
compliance date of January 1, 2030, for units in the medium-term coal-
fired subcategory as well as for natural gas- and oil-fired steaming
generating units.
The EPA refers to January 1, 2030, and January 1, 2032, as
``compliance dates,'' ``final compliance dates,'' and ``initial
compliance dates'' in various parts of this preamble. In each case, the
EPA means that this is the date on which affected EGUs must start
monitoring and reporting their emissions and other relevant data for
purposes of demonstrating compliance with their standards of
performance under these emission guidelines. Affected EGUs demonstrate
compliance on a calendar year basis, i.e., the compliance period for
affected EGUs is 1 calendar year. Therefore, affected EGUs will not
have to demonstrate that they are achieving their standards of
performance on January 1, 2030, or January 1, 2032, as that
demonstration is made only at the end of the compliance period, i.e.,
at the end of the calendar year. But, again, these are the dates on
which affected EGUs in the relevant subcategories must start monitoring
and reporting for purposes of their future compliance demonstrations
with their standards of performance.
d. Compliance Date Extension Mechanism
The EPA is finalizing provisions that allow states to include a
mechanism to extend the compliance date for certain affected EGUs in
their state plans. This mechanism is only available for situations in
which an affected EGU encounters a delay in installation of a control
technology that makes it impossible to commence compliance by the date
specified in section X.C.1.c of this preamble. The owner or operator
must provide documentation of the circumstances that precipitated the
delay (or the anticipated delay) and demonstrate that those
circumstances were or are entirely beyond the owner or operator's
control and that the owner or operator has no ability to remedy the
delay. These circumstances may include, but are not limited to,
permitting-related delays or delays in delivery or construction of
parts necessary for installation or implementation of the control
technology.
The EPA received extensive comment requesting a mechanism to extend
the compliance date for affected EGUs installing a control technology
to address situations in which the owner or operator of the affected
EGU encounters a delay outside of their control. Several industry
commenters noted the potential for such delays due to, among other
reasons, supply chain constraints, permitting processes, and/or
environmental assessments as well as
[[Page 39961]]
delays in deployment of supporting infrastructure like pipelines. These
commenters explained that an extension mechanism could provide greater
regulatory certainty for owners and operators. In light of this
feedback and acknowledgment that there may be circumstances outside of
owners/operators' control that impact their ability to meet the
compliance dates in these emission guidelines, the EPA believes that it
is reasonable to provide a consistent and transparent means of allowing
a limited extension of the compliance deadline where an affected EGU
has demonstrated such an extension is needed for installation of
controls. This mechanism is intended to address delays in
implementation--not to provide more time to assess the compliance
strategy (i.e., the type of technology or subcategory assignment) for
the affected EGU, as some commenters suggested; those decisions are to
be made at the time of state plan approval.
The compliance date extension mechanism is consistent with both CAA
section 111 and these emission guidelines. Consistent with the
statutory purpose of remedying dangerous air pollution, state plans
must generally provide for compliance with standards of performance as
expeditiously as practicable but no later than specified in the
emission guidelines. 40 CFR 60.24a(c). As discussed in sections
VII.C.1.a.i.(E) and VII.C.2.b.i(C), the EPA has determined compliance
timelines in these emission guidelines consistent with achieving
emission reductions as expeditiously as practicable given the time it
takes to install the BSER technologies for the respective
subcategories. The compliance dates are designed to accommodate the
process steps and timeframes that the EPA reasonably anticipates will
apply to affected EGUs. This extension mechanism acknowledges that
circumstances entirely outside the control of the owners or operators
of affected EGUs may extend the timeframe for installation of control
technologies beyond what the EPA reasonably expects for the
subcategories as a general matter. Thus, so long as this extension
mechanism is limited to circumstances that cannot be reasonably
controlled or remedied by states or affected EGUs and that make it
impossible to achieve compliance by the dates specified in these
emission guidelines, its use is consistent with achieving compliance as
expeditiously as practicable.
The EPA is establishing parameters, described in this subsection,
for the features of this mechanism (e.g., documentation, time
limitation). Within these parameters, states should consider state-
specific circumstances related to the implementation and enforcement of
this mechanism in their state plans. Importantly, in order to provide
compliance date extensions that do not require a state plan revision
available to affected EGUs, states must include the mechanism in their
proposed state plans that are provided for public comment and
meaningful engagement (as well as in the final state plan submitted to
the EPA), and the circumstances for and consequences of using this
mechanism must be clearly spelled out and bounded. States are not
required to include this mechanism in their state plans; absent its
inclusion, states must submit a state plan revision in order to extend
a compliance schedule that has been approved into a plan.
First, state plans must provide that a compliance date extension
through this mechanism is available only for affected EGUs that are
installing add-on controls. Affected EGUs that intend to comply without
installing additional control technologies--including, but not limited
to, oil and gas-fired steam generating EGUs--should not experience the
types of installation or implementation delays that this mechanism is
intended to address. Second, state plan mechanisms must provide that to
receive a compliance date extension, the owner or operator of an
affected EGU is required to demonstrate to the state air pollution
control agency, and provide supporting documentation to establish, the
basis for and plans to address the delay. For each affected EGU, this
demonstration must include (1) confirmation that the affected EGU has
met the relevant increments of progress up to the point of the delay,
including any permits obtained and/or contracts entered into for the
installation of control technology, (2) documentation, such as invoices
or correspondence with permitting authorities, vendors, etc., of the
circumstances of the delay and that the delay is due to the action, or
lack thereof, of a third party (e.g., supplier or permitting
authority), and that the owner or operator of the affected EGU has
itself acted consistent with achieving timely compliance (e.g., in
applying for permits with all necessary information or contracting in
sufficient time to perform in accordance with required schedules), and
(3) plans for addressing the circumstances and remedying the delay as
expeditiously as practicable, including updated dates for the final
increment of progress corresponding to the compliance date as well as
any other increments that are outstanding at the time of the
demonstration. These requirements for documentation are intended to
ensure, inter alia, that the owner or operator has made all reasonable
efforts to achieve timely compliance and that the circumstances for
granting an extension are not speculative but are rather based on
delays the affected EGU is currently experiencing or is reasonably
certain to experience.
The extended compliance date must be as expeditiously as
practicable and the maximum time allowed for this extension is 1 year
beyond the compliance date specified for the affected EGU by the state
plan. Several commenters suggested that a 1-year extension was
appropriate. If the delay is anticipated to be longer than 1 year,
states can provide for the use of this mechanism for up to 1 year but
should also initiate a state plan revision if necessary to provide an
updated compliance date through consideration of RULOF, subject to EPA
approval of the plan revision.
The state air pollution control agency is charged with approving or
disapproving a compliance date extension request based on its written
determination that the affected EGU has or has not made each of the
necessary demonstrations and provided all of the necessary
documentation. All documentation for the extension request must be
submitted by the owner or operator of the affected EGU to the state air
pollution control agency no later than 6 months prior to the compliance
date provided in these emission guidelines. The owner or operator of
the affected EGU must also notify the relevant EPA Regional
Administrator of their compliance date extension request at the time of
the submission of the request. The owner or operator of the affected
EGU must also post their application for the compliance date extension
request to the Carbon Pollution Standards for EGUs website, as
discussed in section X.E.1.b.ii of this preamble, when they submit the
request to the state air pollution control agency. The state air
pollution control agency must notify the relevant EPA Regional
Administrator of any determination on an extension request and the new
compliance date for any affected EGU(s) with an approved extension at
the time of the determination on the extension request. The owner or
operator of the affected EGU must also post the state's determination
on the compliance extension request to the Carbon Pollution Standards
for EGUs website, as discussed in section X.E.1.b.ii of this preamble,
upon receipt of the determination, and, if the request is
[[Page 39962]]
approved, update information on the website related to the compliance
date and increments of progress dates within 30 days of the receipt of
the state's approval.
2. Remaining Useful Life and Other Factors
Under CAA section 111(d), the EPA is required to promulgate
regulations under which states submit plans that ``establish[]
standards of performance for any existing source'' and ``provide for
the implementation and enforcement of such standards of performance.''
While states establish the standards of performance, there is a
fundamental obligation under CAA section 111(d) that such standards
reflect the degree of emission limitation achievable through the
application of the BSER, as determined by the EPA.\917\ The EPA
identifies this degree of emission limitation as part of its emission
guideline. 40 CFR 60.22a(b)(5). Thus, as described in section X.C.2 of
this preamble, the EPA is providing methodologies for states to follow
in determining and applying presumptively approvable standards of
performance to affected EGUs in each of the subcategories covered by
these emission guidelines. In general, the standards of performance
that states establish for designated facilities must be no less
stringent than the presumptively approvable standards of performance
specified in these emission guidelines. 40 CFR 60.24a(c).
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\917\ West Virginia v. EPA, 597 U.S. 697, 720 (2022) (``In
devising emissions limits for power plants, EPA first `determines'
the `best system of emission reduction' that--taking into account
cost, health, and other factors--it finds `has been adequately
demonstrated.' The Agency then quantifies `the degree of emission
limitation achievable' if that best system were applied to the
covered source.'') (internal citations omitted).
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However, CAA section 111(d)(1) also requires that the EPA's
regulations permit the states, in applying a standard of performance to
any particular designated facility, to ``take into consideration, among
other factors, the remaining useful life of the existing source to
which the standard applies.'' The EPA's implementing regulations under
40 CFR 60.24a allow a state to consider a particular designated
facility's remaining useful life and other factors (``RULOF'') in
applying to that facility a standard of performance that is less
stringent than the presumptive level of stringency in the applicable
emission guideline, or a compliance schedule that is longer than
prescribed by that emission guideline.
In the proposal, the EPA indicated that it had recently proposed,
in a separate rulemaking, to clarify the general implementing
regulations governing the application of RULOF. The Agency further
explained that the revised RULOF regulations, as finalized in that
separate rulemaking, would apply to these emission guidelines. The
revisions to the implementing regulations' RULOF provisions were
finalized in November 2023, with some changes in response to public
comments relative to proposal. As provided by 40 CFR 60.20a(a) and
(a)(1) and indicated in the proposal, the RULOF provisions in 40 CFR
60.24a, as revised in the November 2023 final rule, will govern the use
of RULOF to provide less stringent standards of performance or longer
compliance schedules under these emission guidelines. The EPA is not
superseding any provision of the RULOF regulations at 40 CFR 60.24a in
these emission guidelines.
As explained in the preamble to the final rule, Adoption and
Submittal of State Plans for Designated Facilities: Implementing
Regulations Under Clear Air Act Section 111(d), the EPA has interpreted
the RULOF provision of CAA section 111(d)(1) as allowing states to
apply a standard of performance that is less stringent than the degree
of emission limitation in the applicable emission guideline, or a
longer compliance schedule, to a particular facility based on that
facility's remaining useful life and other factors. The use of RULOF to
deviate from an emission guideline is available only when there are
fundamental differences between the circumstances of a particular
facility and the information the EPA considered in determining the
degree of emission limitation or the compliance schedule, and those
fundamental differences make it unreasonable for the facility to
achieve the degree of emission limitation or meet the compliance
schedule in the emission guideline. This ``fundamentally different''
standard is consistent with the statutory purpose of reducing dangerous
air pollution under CAA section 111; the statutory framework under
which, to achieve that purpose, the EPA is directed to determine the
degree of emission under CAA section 111(a)(1); and the understanding
that RULOF is intended as a limited variance from the EPA's
determination to address unusual circumstances at particular
facilities.\918\
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\918\ See, e.g., 88 FR 80512 (November 17, 2023).
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The relevant consideration for states contemplating the use of
RULOF to apply a less stringent standard of performance is whether a
designated facility can reasonably achieve the degree of emission
limitation in the applicable emission guideline, not whether it can
implement the system of emission reduction the EPA determined is the
BSER. That is, if a designated facility cannot implement the BSER but
can reasonably achieve the specified degree of emission limitation
using a different system of emission reduction, the state cannot use
RULOF to apply a less stringent standard of performance to that
facility.
If a state has demonstrated, pursuant to 40 CFR 60.24a(e), that a
particular facility cannot reasonably achieve the degree of emission
limitation or compliance schedule determined by the EPA in these
emission guidelines, the state may then apply a less stringent standard
of performance or longer compliance schedule. The process for doing so
is laid out in 40 CFR 60.24a(f). Critically, standards of performance
and compliance schedules pursuant to RULOF must be no less stringent,
or no longer, than is necessary to address the fundamental difference
between the information the EPA considered and the particular facility
that was the basis for invoking RULOF under 40 CFR 60.24a(e). In
determining a less stringent standard of performance, the state must,
to the extent necessary, evaluate the systems of emission reduction
identified in the emission guidelines using the factors and evaluation
metrics the EPA considered in assessing those systems, including
technical feasibility, the amount of emission reductions, the cost of
achieving such reductions, any non-air quality health and environmental
impacts, and energy requirements. States may also consider, as
justified, other factors specific to the facility that were the basis
for invoking RULOF under 40 CFR 60.24a(e), as well as additional
systems of emission reduction.
The RULOF provision at 40 CFR 60.24a(g) states that, where the
basis of a less stringent standard of performance is an operating
condition within the control of a designated facility, the state plan
must include such operating condition as an enforceable requirement.
The state plan must also include requirements, such as for monitoring,
reporting, and recordkeeping, for the implementation and enforcement of
the condition. This is relevant in the case of, for example, less
stringent standards of performance that are based on a particular
designated facility's remaining useful life or utilization.
Finally, the general implementing regulations provide that states
may always adopt and enforce, as part of their state plans, standards
of
[[Page 39963]]
performance that are more stringent than the degree of emission
limitation determined by the EPA and compliance schedules that require
final compliance more quickly than specified in the applicable emission
guidelines. 40 CFR 60.24a(i). States do not have to use the RULOF
provisions in 40 CFR 60.24a(e)-(h) to apply a more stringent standard
of performance or faster compliance schedule.
The EPA notes that there were a number of RULOF provisions proposed
as additions to the general implementation regulations in subpart Ba
and discussed in the proposed emission guidances that the EPA did not
finalize as part of that separate rulemaking. Any proposed RULOF
requirements that were not finalized in 40 CFR 60.24a are likewise not
being finalized in this action and do not apply as requirements under
these emission guidelines. However, two considerations in particular
remain relevant to states' development of plans despite not being
finalized as requirements: consideration of communities most impacted
by and vulnerable to the health and environmental impacts of an
affected EGU that is invoking RULOF, and the need to engage in reasoned
decision making that is supported by information and a rationale that
is included in the state plan.\919\
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\919\ The other RULOF provisions that the EPA proposed as
additions to 40 CFR 60.24a but did not finalize are related to
setting imminent and outermost dates for the consideration of
remaining useful life and consideration of RULOF to apply more
stringent standards of performance. See 88 FR 80480, 80525, 80529
(November 17, 2023).
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As explained in the preamble to the November 2023 final rule
revising subpart Ba, consideration of health and environmental impacts
is inherent in consideration of two factors, the non-air quality health
and environmental impacts and amount of emission reduction, that the
EPA considers under CAA section 111(a)(1). Therefore, a state
considering whether a variance from the EPA's degree of emission
limitation is appropriate will necessarily consider the potential
impacts and benefits of control to communities impacted by an affected
EGU that is potentially receiving a less stringent standard of
performance.\920\ Additionally, as discussed in section X.E.1.b.i of
this preamble, the general implementing regulations for CAA section
111(d) in subpart Ba require states to submit, with their state plans
or plan revisions, documentation that they have conducted meaningful
engagement with pertinent stakeholders and/or their representative in
the plan (or plan revision) development process. 40 CFR 60.23a(i). The
application of a less stringent standard of performance or longer
compliance schedule pursuant to RULOF can impact the effects a state
plan has on pertinent stakeholders, which include, but are not limited
to, industry, small businesses, and communities most affected by and/or
vulnerable to the impacts of a state plan or plan revision. See 40 CFR
60.21a(l). Therefore, the potential application of less stringent
standards of performance or longer compliance schedule should be part
of a state's meaningful engagement on a state plan or plan revision.
---------------------------------------------------------------------------
\920\ 88 FR 80528 (November 17, 2023).
---------------------------------------------------------------------------
Similarly, the EPA emphasized in the preamble to the November 2023
final rule revising subpart Ba that states carry the burden of making
any demonstrations in support of less-stringent standards of
performance pursuant to RULOF in developing their plans. As a general
matter, states always bear the responsibility of reasonably documenting
and justifying the standards of performance in their plans. In order to
find a standard of performance satisfactory, the EPA must be able to
ascertain, based on the information and analysis included in the state
plan submission, that the standard meets the statutory and regulatory
requirements.\921\
---------------------------------------------------------------------------
\921\ See id. at 80527.
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Comment: Multiple commenters expressed support for the EPA's
proposed approach to RULOF, including its framework for ensuring that
less stringent standards of performance and longer compliance schedules
are limited to unique circumstances that reflect fundamental
differences from the circumstances that the EPA considered, and that
such standards do not undermine the overall effectiveness of the
emission guidelines. These commenters also noted that the proposed
RULOF approach is consistent with CAA section 111(d). However, other
commenters argued that the EPA lacks authority to put restrictions on
how states consider RULOF to apply less stringent standards of
performance or longer compliance schedules. Some commenters stated that
the EPA's framework for the consideration of RULOF runs counter to
section 111's framework of cooperative federalism and that the EPA has
a limited role of determining BSER for the source category while the
statute reserves significant authority for the states to establish and
implement standards of performance. One commenter elaborated that the
broad discretion given to states to establish standards of performance
gives the EPA only a limited role in reviewing states' RULOF
demonstrations.
Response: The provisions that will govern states' use of RULOF
under these emission guidelines are contained in the part 40, subpart
Ba CAA section 111(d) implementing regulations. Following proposal of
these emission guidelines, the EPA finalized revisions to the subpart
Ba RULOF provisions in a separate rulemaking. Any comments on these
generally applicable provisions, including the EPA's authority to
promulgate and implement them and consistency with the cooperative
federalism framework of CAA section 111(d), are outside the scope of
this action. The EPA has, however, considered and responded to comments
that concern the application of these generally applicable RULOF
provisions under these particular emission guidelines.
Comment: Several commenters spoke to the role of RULOF given the
structure of the proposed subcategories for coal-fired steam generating
affected EGUs. Some commenters supported the EPA's statement that,
given the four proposed subcategories based on affected EGUs' intended
operating horizons, the Agency did not anticipate that states would be
likely to need to invoke RULOF based on a particular affected EGU's
remaining useful life. In contrast, other commenters stated that the
EPA was attempting to unlawfully preempt state consideration of RULOF.
Some noted that, regardless of the approach to subcategorization, a
particular source may still present source-specific considerations that
a state may consider relevant when applying a standard of performance.
One commenter referred to RULOF as a way for states to ``modify''
subcategories to address the circumstances of particular affected EGUs.
Response: As explained in section VII.C of this preamble, the
structure of the subcategories for coal-fired steam generating affected
EGUs under these final emission guidelines differs from the four
subcategories that the EPA proposed. The EPA is finalizing just two
subcategories for coal-fired EGUs: the long-term subcategory and the
medium-term subcategory. Under these circumstances, the justification
for the EPA's statement at proposal that it is unlikely that states
would need to invoke RULOF based on a coal-fired steam generating
affected EGU's remaining useful life no longer applies. Consistent with
40 CFR 60.24a(e) and the Agency's explanation in the proposal, states
have the ability to
[[Page 39964]]
consider, inter alia, a particular source's remaining useful life when
applying a standard of performance to that source.\922\
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\922\ See 88 FR 33383 (invoking RULOF based on a particular
coal-fired EGU's remaining useful life ``is not prohibited under
these emission guidelines'').
---------------------------------------------------------------------------
Moreover, the EPA is clarifying that RULOF may be used to
particularize the compliance obligations for an affected EGU when a
state demonstrates that it is unreasonable for that EGU to achieve the
applicable degree of emission limitation or compliance schedule
determined by the EPA. Invocation of RULOF does not have the effect of
modifying the subcategory structure or creating a new subcategory for a
particular affected EGU. That EGU remains in the applicable
subcategory. As explained elsewhere in this section of the preamble,
the particularized compliance obligations must differ as little as
possible from the presumptive standard of performance and compliance
schedule for the subcategory into which the affected EGU falls under
these emission guidelines.
Comment: One commenter requested that the EPA identify situations
in which it is reasonable to deviate from the presumptive standards of
performance in the emission guidelines and include presumptively
approvable approaches for states to use when invoking RULOF. The
commenter noted that this would reduce the regulatory burden on states
developing and submitting plans. Another commenter, however, stated
that the EPA should not provide any presumptively approvable standard,
criteria, or analytic approach for states seeking to use RULOF. This
commenter explained that the premise of source-specific variances under
RULOF is that they reflect circumstances that are unique to a
particular unit and fundamental differences from the general case, and
that it would be inappropriate to offer a generic rubric for approving
variances separate from the particularized facts of each case.
Response: The EPA is not identifying circumstances in which it
would be reasonable to deviate from its determinations or providing
presumptively approvable approaches to invoking RULOF in these emission
guidelines. For this source category--fossil-fuel fired steam
generating EGUs--in particular, the circumstances and characteristics
of affected EGUs and the control strategies the EPA has identified as
BSER are extremely context- and source-specific. In order to invoke
RULOF for a particular affected EGU, a state must demonstrate that it
is unreasonable for that EGU to reasonably achieve the applicable
degree of emission limitation or compliance schedule. Given the
diversity of sizes, ages, locations, process designs, operating
conditions, etc., of affected EGUs, it is highly unlikely that the
circumstances that result in one affected EGU being unable to
reasonably achieve the applicable presumptive standard or compliance
schedule would apply to any other affected EGU. Further, the RULOF
provisions of subpart Ba provide clarity for and guidance to states as
to what constitutes a satisfactory less-stringent standard of
performance under these emission guidelines.
While the EPA is not providing presumptively approvable
circumstances or analyses for RULOF in these emission guidelines, it is
providing information and analysis that states can leverage in making
any determinations pursuant to the RULOF provisions. As explained
elsewhere in this section of the preamble, the EPA expects that states
will be able to particularize the information it is providing in
section VII of this preamble and the final Technical Support Documents
for the circumstances of any affected EGUs for which they are
considering RULOF, thereby decreasing the analytical burdens.
Comment: Several commenters stated that the proposed emission
guidelines did not provide adequate time for RULOF analyses.
Response: As noted above, the EPA expects states to leverage the
information it is providing in section VII of this preamble and the
final Technical Support Documents in conducting any RULOF analyses
under these emission guidelines. In particular, the Agency believes
states will be able to use the information it is providing on available
control technologies for affected EGUs, technical considerations, and
costs given different amortization periods and particularize it for the
purpose of conducting any analyses pursuant to 40 CFR 60.24a(e) and
(f). Additionally, as discussed in section X.C.2.b of this preamble,
the regulatory provisions for RULOF under subpart Ba provide a
framework for determining less stringent standards of performance that
have the practical effect of minimizing states' analytical burdens.
Given the EPA's consideration of affected EGU's circumstances and
operational characteristics in designing these emission guidelines, the
Agency does not anticipate that states will be in the position of
conducting numerous RULOF analyses as part of their state planning
processes. The EPA therefore believes that states will have sufficient
time to consider RULOF and conduct any RULOF analyses under these
emission guidelines.
a. Threshold Requirements for Considering RULOF
The general implementing regulations of 40 CFR part 60, subpart Ba,
provide that a state may apply a less stringent standard of performance
or longer compliance schedule than otherwise required under the
applicable emission guidelines based on consideration of a particular
source's remaining useful life and other factors. To do so, the state
must demonstrate for each designated facility (or class of such
facilities) that the facility cannot reasonably achieve the degree of
emission limitation determined by the EPA (i.e., the presumptively
approvable standard of performance) based on: (1) Unreasonable cost
resulting from plant age, location, or basic process design, (2)
physical impossibility or technical infeasibility of installing the
necessary control equipment, or (3) other factors specific to the
facility. In order to determine that one or more of these circumstances
has been met, the state must demonstrate that there are fundamental
differences between the information specific to a facility (or class of
such facilities) and the information the EPA considered in the
applicable emission guidelines that make achieving the degree of
emission limitation or compliance schedule in those guidelines
unreasonable for the facility.
For each subcategory of affected EGUs in these emission guidelines,
the EPA determined the degree of emission limitation achievable through
application of the BSER by considering information relevant to each of
the factors in CAA section 111(a)(1): whether a system of emission
reduction is adequately demonstrated for the subcategory, the costs of
a system of emission reduction, the non-air quality health and
environmental impacts and energy requirements associated with a system
of emission reduction, and the extent of emission reductions from a
system.\923\ As noted above, the relevant consideration for invoking
RULOF is whether an affected EGU can reasonably achieve the presumptive
standard of
[[Page 39965]]
performance for the applicable subcategory, as opposed to whether it
can implement the BSER. In determining the BSER the EPA found that
certain costs, impacts, and energy requirements were, on balance,
reasonable for affected EGUs; it is therefore reasonable to assume that
the same costs, impacts, and energy requirements would be equally
reasonable in the context of other systems of reduction, as well.
Therefore, the information the EPA considered in relation to each of
these factors is the baseline for consideration of RULOF regardless of
the system of emission reduction being considered.
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\923\ The EPA also considered expanded use and development of
technology in determining the BSER for each subcategory. However, as
this consideration is not necessarily relevant at the scale of a
particular source for which a less stringent standard of performance
is being considered, it is not addressed here.
---------------------------------------------------------------------------
The EPA is providing presumptive standards of performance in these
emission guidelines in the form of rate-based emission limitations.
Thus, the focus for states considering whether a particular affected
EGU has met the threshold for a less stringent standard of performance
pursuant to RULOF is whether that affected EGU can reasonably achieve
the applicable rate-based presumptive standard of performance in these
emission guidelines.
Within each of the statutory factors it considered in determining
the BSER, the Agency considered information using one or more
evaluation metrics. For example, for both the long-term and medium-term
coal-fired steam generating EGUs the EPA considered cost in terms of
dollars/ton CO2 reduced and increases in levelized costs
expressed as dollars per MWh electricity generation. Under the non-air
quality health and environmental impacts and energy requirements
factor, the EPA considered non-greenhouse gas emissions and energy
requirements in terms of parasitic load and boiler efficiency, in
addition to evaluation metrics specific to the systems being evaluated
for each subcategory. For the full range of factors, evaluation
metrics, and information the EPA considered with regard to the long-
term and medium-term coal-fired steam generating EGU subcategories, see
section VII.D.1 and VII.D.2 of this preamble.
Although the considerations for invoking RULOF described in 40 CFR
60.24a(e) are broader than just unreasonable cost of control, much of
the information the EPA considered in determining the BSER, and
therefore many of the circumstances states might consider in
determining whether to invoke RULOF, are reflected in the cost
consideration. Where possible, states should reflect source-specific
considerations in terms of cost, as it is an objective and replicable
metric for comparison to both the EPA's information and across affected
EGUs and states.\924\ For example, consideration of pipeline length
needed for a particular affected EGU is best reflected through
consideration of the cost of that pipeline. In particular,
consideration of the remaining useful life of a particular affected EGU
should be considered with regard to its impact on costs. In determining
the BSER, the EPA considers costs and specifically annualized costs
associated with payment of the total capital investment associated with
the BSER. An affected EGU's remaining useful life and associated length
of the capital recovery period can have a significant impact on
annualized costs. States invoking RULOF based on an affected EGU's
remaining useful life should demonstrate that the annualized costs of
applying the degree of emission limitation achievable through
application of the BSER for a source with a short remaining useful life
are fundamentally different from the costs that the EPA found were
reasonable. For purposes of determining the annualized costs for an
affected EGU with a shorter remaining useful life, the EPA considers
the amortization period to begin at the compliance date for the
applicable subcategory.
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\924\ The EPA reiterates that states are not precluded from
considering information and factors other than costs under 40 CFR
60.24a(e)(ii) and (iii).
---------------------------------------------------------------------------
States considering the use of RULOF to provide a less stringent
standard of performance for a particular EGU must demonstrate that the
information relevant to that EGU is fundamentally different from the
information the EPA considered. For example, in determining the degree
of emission limitation achievable through the application of co-firing
for medium-term coal-fired steam generating EGUs, the EPA found that
costs of $71/ton CO2 reduced and $13/MWh are reasonable. A
state seeking to invoke RULOF for an affected coal-fired steam
generating EGU based on unreasonable cost of control resulting from
plant age, location, or basic process design would therefore, pursuant
to 40 CFR 60.24a(e), demonstrate that the costs of achieving the
applicable degree of emission limitation for that particular affected
EGU are fundamentally different from $71/ton CO2 reduced
and/or $13/MWh.
Any costs that the EPA has determined are reasonable for any BSER
for affected EGUs under these emission guidelines would not be an
appropriate basis for invoking RULOF. Additionally, costs that are not
fundamentally different from costs that the EPA has determined are or
could be reasonable for sources would also not be an appropriate basis
for invoking RULOF. Thus, costs that are not fundamentally different
from, e.g., $18.50/MWh (the cost for installation of wet-FGD on a 300
MW coal-fired steam generating unit, used for cost comparison in
section VIII.D.1.a.ii of this preamble) would not be an appropriate
basis for invoking RULOF under these emission guidelines. On the other
hand, costs that constitute outliers, e.g., that are greater than the
95th percentile of costs on a fleetwide basis (assuming a normal
distribution) would likely represent a valid demonstration of a
fundamental difference and could be the basis of invoking RULOF.
Importantly, the costs evaluated in BSER determinations are, in
general, based on average values across the fleet of steam generating
units. Those BSER cost analysis values represent the average of a
distribution of costs including costs that are above or below the
average representative value. On that basis, implicit in the
determination that those average representative values are reasonable
is the determination that a significant portion of the unit-specific
costs around those average representative values are also reasonable,
including some portion of those unit-specific costs that are above but
not significantly different than the average representative values.
That is, the cost values the EPA considered in determining the BSER
should not be considered bright-line upper thresholds between
reasonable and unreasonable costs. Moreover, the examples in this
discussion are provided merely for illustrative purposes; because each
RULOF demonstration must be evaluated based on the facts and
circumstances relevant to a particular affected EGU, the EPA is not
setting any generally applicable thresholds or providing presumptively
approvable approaches for determining what constitutes a fundamental
difference in cost or any other consideration under these emission
guidelines. The Agency will assess each use of RULOF in a state plan
against the applicable regulatory requirements; however, the EPA is
providing examples in this preamble in response to comments requesting
that it provide further clarity and guidance on what constitutes a
satisfactory use of RULOF.
Under 40 CFR 60.24a(e)(1)(iii), states may also consider ``other
factors specific to the facility.'' Such ``other factors'' may include
both factors (categories of information) that the EPA did not consider
in determining the degree of emission limitation achievable through
[[Page 39966]]
application of the BSER and additional evaluation metrics (ways of
considering a category of information) that the EPA did not consider in
its analysis. To invoke RULOF based on consideration of ``other
factors,'' a state must demonstrate that a factor makes it unreasonable
for the affected EGU to achieve the applicable degree of emission
limitation in these emission guidelines.
The general implementing regulations of subpart Ba provide that
states may invoke RULOF for a class of facilities. In the preamble to
the subpart Ba final rule, the EPA explained that ``invoking RULOF and
providing a less-stringent standard [of] performance or longer
compliance schedule for a class of facilities is only appropriate where
all the facilities in that class are similarly situated in all
meaningful ways. That is, they must not only share the circumstance
that is the basis for invoking RULOF, they must also share all other
characteristics that are relevant to determining whether they can
reasonably achieve the degree of emission limitation determined by the
EPA in the applicable EG. For example, it would not be reasonable to
create a class of facilities for the purpose of RULOF on the basis that
the facilities do not have space to install the EPA's BSER control
technology if some of them are able to install a different control
technology to achieve the degree of emission limitation in the EG.''
\925\ Given that individual fossil fuel-fired steam generating EGUs are
very unlikely to be similarly situated with regard to all of the
characteristics relevant to determining the reasonableness of meeting a
degree of emission limitation, the EPA believes it would not likely be
reasonable for a state to invoke RULOF for a class of facilities under
these emission guidelines. That is, because there are relatively few
affected EGUs in each subcategory and because each EGU is likely to
have a distinct combination of size, operating process, footprint,
geographic location, etc., it is highly unlikely that the same
threshold analysis would apply to two or more units.
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\925\ 88 FR 80517 (November 17, 2023).
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i. Invoking RULOF for Long-Term Coal-Fired Steam Generating EGUs
In determining the BSER for the long-term coal-fired steam
generating EGUs, the EPA considered several evaluation metrics specific
to CCS. However, affected EGUs are not required to implement CCS to
comply with their standards of performance. To the extent a state is
considering whether it is reasonable for a particular affected EGU in
this subcategory to achieve the degree of emission limitation using CCS
as the control strategy, the state would consider whether that affected
EGU's circumstances are fundamentally different from the evaluation
metrics and information the EPA considered in these emission
guidelines. If a state is considering whether it is reasonable for an
affected EGU to achieve the degree of emission limitation for long-term
coal-fired steam generating EGUs through some other control strategy,
certain of the evaluation metrics and information the EPA considered,
such as overall costs and energy requirements, would be relevant while
other metrics or information may or may not be.
As discussed above, the EPA considered costs in terms of $/ton
CO2 reduced and $/MWh. The Agency broke down its cost
consideration for CCS into capture costs and CO2 transport
and sequestration costs, as discussed in sections VIII.D.1.a.ii.(A) and
(B) of this preamble. The EPA also considered the availability of the
IRC section 45Q tax credit in evaluating the cost of CCS for affected
EGUs, and finally, evaluated the impacts of two different capacity
factor assumptions on costs. Similarly, the Agency considered a number
of evaluation metrics specific to CCS under the non-air quality health
and environmental impacts and energy requirements factors, in addition
to considering non-greenhouse gas emissions and parasitic/auxiliary
energy demand increases and the net power output decreases. In
particular, the EPA considered water use, CO2 capture plant
siting, transport and geologic sequestration, and impacts on the energy
sector in terms of long-term structure and reliability of the power
sector. A state may also consider other factors and circumstances that
the EPA did not consider in its evaluation of CCS, to the extent such
factors or circumstances are relevant to the reasonableness of
achieving the associated degree of emission limitation.
As detailed in section VII.D.1.a.i of this preamble, the EPA has
determined that CCS is adequately demonstrated for long-term coal-fired
steam generating EGUs. The Agency evaluated the components of CCS both
individually and in concurrent, simultaneous operation. If a state
believes a particular affected EGU cannot reasonably implement CCS
based on physical impossibility or technical infeasibility, the state
must demonstrate that the circumstances of that individual EGU are
fundamentally different from the information on CCS that the EPA
considered in these emission guidelines.
ii. Invoking RULOF for Medium-Term Coal-Fired Steam Generating EGUs
As for the long-term coal-fired steam generating EGU subcategory,
the EPA also considered evaluation metrics and information specific to
the BSER, natural gas co-firing, for the medium-term subcategory.
Again, similar to the long-term subcategory, certain generally
applicable metrics and information that the EPA considered, e.g.,
overall costs and energy requirements, will be relevant regardless of
the control strategy a state is considering for an affected EGU in the
medium-term subcategory. To the extent a state is considering whether
it is reasonable for a particular affected EGU to reasonably achieve
the presumptive standard of performance using natural gas co-firing as
a control, the state should evaluate whether there is a fundamental
difference between the circumstances of that EGU and the information
the EPA considered. In considering costs for natural gas co-firing, the
Agency took into account costs associated with adding new gas burners
and other boiler modifications, fuel cost, and new natural gas
pipelines. In considering non-air quality health and environmental
impacts and energy requirements, the EPA addressed losses in boiler
efficiency due to co-firing, as well as non-greenhouse gas emissions
and impact on the structure of the energy sector. States may also
consider other factors and circumstances that are relevant to
determining the reasonableness of achieving the applicable degree of
emission limitation.
iii. Invoking RULOF To Apply a Longer Compliance Schedule
Under 40 CFR 60.24a(c), ``final compliance,'' i.e., compliance with
the applicable standard of performance, ``shall be required as
expeditiously as practicable but no later than the compliance times
specified'' in the applicable emission guidelines, unless a state has
demonstrated that a particular designated facility cannot reasonably
comply with the specific compliance time per the RULOF provision at 40
CFR 60.24a(e). The EPA, in these emission guidelines, has detailed the
amount of time needed for states and affected EGUs in the long-term and
medium-term coal-fired steam generating EGU subcategories to comply
with standards of performance using CCS and natural gas co-firing,
respectively, in sections VII.C.1 and VII.C.2 of this preamble. These
compliance times are based on information available for and applicable
to the subcategories as a whole. The
[[Page 39967]]
Agency anticipates that some affected EGUs will be able to comply more
expeditiously than on these generally applicable timelines. Similarly,
there may be circumstances in which a particular EGU cannot reasonably
comply with its standard of performance by the compliance date
specified in these emission guidelines. In order to provide a longer
compliance schedule, the state must demonstrate that there is a
fundamental difference between the information the EPA considered for
the subcategory as a whole and the circumstances of a particular EGU.
These circumstances should not be speculative; the state must
substantiate the need for a longer compliance schedule with
documentation supporting that need and justifying why a certain
component or components of implementation will take longer than the EPA
considered in these emission guidelines. If a state anticipates that a
process or activity will take longer than is typical for similarly
situated EGUs within and outside the state or longer than it has
historically, the state should provide an explanation of why it expects
this to be the case as well as evidence corroborating the reasons and
need for additional time. Consistent with 40 CFR 60.24a(c) and (e),
states should not use the RULOF provision to provide a longer
compliance schedule unless there is a demonstrated, documented reason
at the time of state plan submission that a particular source will not
be able to achieve compliance by the date specified in these emission
guidelines. The EPA notes that it is providing a number of
flexibilities in these final emission guidelines for states and sources
if they find, subsequent to state plan submission, that additional time
is necessary for compliance; states should consider these flexibilities
in conjunction with the potential use of RULOF to provide a longer
compliance schedule. A source-specific compliance date pursuant to
RULOF must be no later than necessary to address the fundamental
difference; that is, it must be as close to the compliance schedule
provided in these emission guidelines as reasonably possible.
Considerations specific to providing a longer compliance schedule to
address reliability are addressed in section X.C.2.e.i of this
preamble.
Comment: Several commenters stated that the EPA must respect the
broad authority granted to states under the CAA and that while the
EPA's information on various factors is helpful to states, states may
readily deviate from the emission guidelines in order to account for
source- and state-specific characteristics. The commenters argued that
the EPA's general implementing regulations at 40 CFR 60.24a(c)
recognize that states may consider factors that make application of a
less stringent standard of performance or longer compliance time
significantly more reasonable, and commenters stated that those factors
should include, inter alia, cost, feasibility, infrastructure
development, NSR implications, fluctuations in performance depending on
load, state energy policy, and potential reliability issues. The
commenters stated that states have the authority to account for
consideration of other factors in various ways and that the EPA must
defer to state choices, provided those choices are reasonable and
consistent with the statute.
Response: Comments on states' use of RULOF vis-[agrave]-vis the
EPA's determinations pursuant to CAA section 111(a)(1) in the
applicable emission guidelines are outside the scope of this
rulemaking.\926\ Similarly, comments on the EPA's authority to review
states' use of RULOF in state plans and the scope of that review are
outside the scope of this rulemaking.\927\ The EPA is also clarifying
that, while the commenters are correct that the general implementing
regulations at 40 CFR 60.24a(c) recognize that states may invoke RULOF
to provide a less stringent standard of performance or longer
compliance schedule, they also provide that, unless the threshold for
the use of RULOF in 40 CFR 60.24a(e) has been met, ``standards of
performance shall be no less stringent than the corresponding emission
guideline(s) . . . and final compliance shall be required as
expeditiously as practicable but no later than the compliance times
specified'' in the emission guidelines. The threshold for invoking
RULOF is when a state demonstrates that a particular affected EGU
cannot reasonably achieve the degree of emission limitation determined
by the EPA, based on one or more of the circumstances at 40 CFR
60.24a(e)(i)-(iii), because there are fundamental differences between
the information the EPA considered in the emission guidelines and the
information specific to the affected EGU. The ``significantly more
reasonable'' standard does not apply to RULOF determinations under
these emission guidelines.\928\
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\926\ See 88 FR 80509-17 (November 17, 2023).
\927\ See id. at 80526-27.
\928\ 40 CFR 60.20a(a).
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The EPA agrees that states have authority to consider ``other
circumstances specific to the facility.'' States are uniquely situated
to have knowledge about unit-specific considerations. If a unit-
specific factor or circumstance is fundamentally different from the
information the EPA considered and that difference makes it
unreasonable for the affected EGU to achieve that degree of emission
limitation or compliance schedule,\929\ it is grounds for applying a
less stringent standard of performance or longer compliance schedule.
The EPA will review states' RULOF analyses and determinations for
consistency with the applicable regulatory requirements at 40 CFR
60.24a(e)-(h).
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\929\ ``Other factors'' may include facility-specific
circumstances and factors that the EPA did not anticipate and
consider in the applicable emission guideline that make achieving
the EPA's degree of emission limitation unreasonable for that
facility. 88 FR 80480, 80521 (November 17, 2023).
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Comment: Multiple commenters weighed in on the subject of cost
metrics. Two commenters stated that the EPA should not require states
to consider costs using the same metrics that it considered in the
emission guidelines. These commenters explained that the unique
circumstances of each unit mean that different metrics may be
appropriate and should be allowed as long as the state plan provides a
justification. Other commenters, however, supported the proposed
requirement for states to consider costs using the same metrics as the
EPA. Similarly, commenters differed on the example in the proposed rule
preamble that costs that are greater than the 95th percentile of costs
on a fleetwide basis would likely be fundamentally different from the
fleetwide costs that the EPA considered in these emission guidelines.
While one commenter believed that the 95th percentile may not be an
appropriate threshold in all circumstances and should not be treated as
an absolute, another commenter argued that the EPA should formalize the
95th percentile threshold as a requirement for states seeking to invoke
RULOF based on unreasonable cost.
Response: The EPA believes that, in order to evaluate whether there
is a fundamental difference between the cost information the EPA
considered in these emission guidelines and the cost information for a
particular affected EGU, it is necessary for states to evaluate costs
using the same metrics that the EPA considered. However, states are not
precluded from considering additional cost metrics alongside the two
metrics used in these emission guidelines: $/ton of CO2
reduced and $/MWh of electricity
[[Page 39968]]
generated. States should justify why any additional cost metrics are
relevant to determining whether a particular affected EGU can
reasonably achieve the applicable degree of emission limitation.
The EPA did not state that a cost that is greater than the 95th
percentile of fleetwide costs would necessarily justify invocation of
RULOF. Nor did the EPA intend to suggest that such costs are the only
way states can demonstrate that the costs for a particular affected EGU
are fundamentally different. While it may be an appropriate benchmark
in some cases, there are other ways for states to demonstrate that the
cost for a particular affected EGU is an outlier. That is, the EPA is
not requiring that the unit-specific costs be above the 95th percentile
in order to demonstrate that they are fundamentally different from the
costs the Agency considered in these emission guidelines. As discussed
elsewhere in this section of the preamble, the diversity in
circumstances of individual affected EGUs under these emission
guidelines makes it infeasible for the EPA to a priori define a bright
line for what constitutes reasonable versus unreasonable costs for
individual units in these emission guidelines.
Comment: One commenter noted that the EPA should only approve the
use of RULOF to provide a longer compliance schedule where there is
clearly documented evidence (e.g., receipts, invoices, actual site
work) that a source is making best endeavors to achieve compliance as
expeditiously as possible.
Response: The EPA believes this kind of evidence is strong support
for providing a longer compliance schedule. The Agency further believes
that states should show that the need to provide a longer compliance
schedule is notwithstanding best efforts on the parts of all relevant
parties to achieve timely compliance. The EPA is not, however,
precluding the possibility that states could reasonably justify a
longer compliance schedule based on other types of information or
evidence.
b. Calculation of a Standard of Performance That Accounts for RULOF
If a state has demonstrated that a particular affected EGU is
unable to reasonably achieve the applicable degree of emission
limitation or compliance schedule under these emission guidelines per
40 CFR 60.24a(e), it may then apply a less stringent standard of
performance or longer compliance schedule according to the process laid
out in 40 CFR 60.24a(f). Pursuant to that process, the state must
determine the standard of performance or compliance schedule that,
respectively, is no less stringent or no longer than necessary to
address the fundamental difference that was the basis for invoking
RULOF. That is, the standard of performance or compliance schedule must
be as close to the EPA's degree of emission limitation or compliance
schedule as reasonably possible for that particular EGU.
The EPA notes that the proposed emission guidelines would have
included requirements for how states determine less stringent standards
of performance, including what systems of emission reduction states
must evaluate and the order in which they must be evaluated. These
proposed requirements were intended to ensure that states reasonably
consider the controls that may qualify as a source-specific BSER.\930\
However, the final RULOF provisions in subpart Ba for determining less
stringent standards of performance differ from the proposed subpart Ba
provisions in a way that obviates the need for the separate
requirements proposed in these emission guidelines. First, as opposed
to determining a source-specific BSER for sources that have met the
threshold requirements for RULOF, states determine the standard of
performance that is no less stringent than the EPA's degree of emission
limitation than necessary to address the fundamental difference.
Second, the process for determining such a standard of performance that
the EPA finalized at 40 CFR 60.24a(f)(1) involves evaluating, to the
extent necessary, the systems of emission reduction that the EPA
identified in the applicable emission guidelines using the factors and
evaluation metrics that the Agency considered in assessing those
systems. Because the final RULOF provisions of subpart Ba create
essentially the same process as the provisions the EPA proposed for
determining a less stringent standard of performance under these
emission guidelines, the EPA has determined it is not necessary to
finalize those provisions here.
---------------------------------------------------------------------------
\930\ See 88 FR 33384 (May 23, 2023).
---------------------------------------------------------------------------
The EPA anticipates that states invoking RULOF for affected EGUs
will do so because an EGU is in one of two circumstances: it is
implementing the control strategy the EPA determined is the BSER but
cannot achieve the degree of emission limitation in the emission
guideline using that control (or any other system of emission
reduction); or it is not implementing the BSER and cannot reasonably
achieve the degree of emission limitation using any system of emission
reduction.
If an affected EGU will be implementing the BSER but cannot meet
the degree of emission limitation due to fundamental differences
between the circumstances of that particular EGU and the circumstances
the EPA considered in the emission guidelines, it may not be necessary
for the state to evaluate other systems of emission reduction to
determine the less stringent standard of performance. In this instance,
the state and affected EGU would determine the degree of emission
limitation the EGU can reasonably achieve, consistent with the
requirement that it be no less stringent than necessary. That degree of
emission limitation would be the basis for the less stringent standard
of performance. For example, assume an affected EGU in the long-term
coal-fired steam generating EGU subcategory is intending to install CCS
and the state has demonstrated that it is not reasonably possible for
the capture equipment at that particular EGU to achieve 90 percent
capture of the mass of CO2 in the flue gas (corresponding to
an 88.4 percent reduction in emission rate), but it can reasonably
achieve 85 percent capture. If the source cannot reasonably achieve an
88.4 percent reduction in emission rate using any other system of
emission reduction, the state may apply a less stringent standard of
performance that corresponds to 85 percent capture without needing to
evaluate further systems of emission reduction.
In other cases, however, an affected EGU may not be implementing
the BSER and may not be able to reasonably achieve the applicable
degree of emission limitation (i.e., the presumptive standard of
performance) using any control strategy. In such situations, the state
must determine the standard of performance that is no less stringent
than necessary by evaluating the systems of emission reduction the EPA
considered in these emission guidelines, using the factors and
evaluation metrics the EPA considered in assessing those systems.
States may also consider additional systems of emission reduction that
the EPA did not identify but that the state believes are available and
may be reasonable for a particular affected EGU.
The requirement at 40 CFR 60.24a(f)(1) provides that a state must
evaluate these systems of emission reduction to the extent necessary to
determine the standard of performance that is as close as reasonably
possible to the presumptive standard of performance under these
emission guidelines. It will most likely not be necessary for a state
to consider all of the systems that the EPA identified for a given
affected EGU. For example, if the state has already determined it is
not
[[Page 39969]]
reasonably possible for an affected EGU to implement one of these
control strategies, at any stringency, as part of its demonstration
under 40 CFR 60.24a(e) that a less stringent standard of performance is
warranted, the state does not need to evaluate that system again.
Similarly, if a state starts by evaluating the system that achieves the
greatest emission reductions and determines the affected EGU can
implement that system, it is most likely not necessary for the state to
consider the other systems on the list in order to determine that the
resulting standard of performance is no less stringent than necessary.
The Agency anticipates that states will leverage the information the
EPA has provided regarding systems of emission reduction in these
emission guidelines, as well as the wealth of other technical, cost,
and related information on various control systems in the record for
this final action, in conducting their evaluations under 40 CFR
60.24a(f). In many cases, it will be possible for states to use
information the EPA has provided as a starting point and particularize
it for the circumstances of an individual affected EGU.\931\
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\931\ See, e.g., sections VII.C.1-4 of this preamble, the final
TSD, GHG Mitigation Measures for Steam Generation Units, the
CO2 Capture Project Schedule and Operations Memo,
Documentation for the Lateral Cost Estimation, Transport and Storage
Timeline Summary, and the Heat Rate Improvement Method Costs and
Limitations Memo.
---------------------------------------------------------------------------
For systems of emission reduction that have a range of potential
stringencies, states should start by evaluating the most stringent
iteration that is potentially feasible for the particular affected EGU.
If that level of stringency is not reasonable, the state should also
evaluate other stringencies as may be needed to determine the standard
of performance that is no less stringent than the applicable degree of
emission limitation in these emission guidelines than necessary.
In evaluating the systems of emission reduction identified in these
emissions guidelines, states must also consider the factors and
evaluation metrics that the EPA considered in assessing those systems,
including technical feasibility, the amount of emission reductions, any
non-air quality health and environmental impacts, and energy
requirements. 40 CFR 60.24a(f)(1). They may also consider, in
evaluating systems of emission reduction, other factors specific to the
facility that constitute a fundamental difference between the
information the EPA considered and the circumstances of the particular
affected EGU and that were the basis of invoking RULOF for that
particular EGU. For example, if a state determined that it is
physically impossible or technically infeasible and/or unreasonably
costly for a long-term coal-fired affected EGU to construct a
CO2 pipeline because the EGU is located on a remote island,
the state could consider that information in evaluating additional
systems of emission reduction, as well.
The general implementing regulations at 40 CFR 60.24a(f)(2) provide
that any less stringent standards of performance that a state applies
pursuant to RULOF must be in the form required by the applicable
emission guideline. The presumptive standards of performance the EPA is
providing in these emission guidelines are rate-based emission
limitations. In order to ensure that a source-specific standard of
performance is no less stringent than the EPA's presumptive standard
than necessary, the source-specific standard pursuant to RULOF must be
determined and expressed in the form of a rate-based emission
limitation. That is, the systems of emission reduction that states
evaluate pursuant to 40 CFR 60.24a(f)(1) must be systems for reducing a
source's emission rate and the state must apply a standard of
performance expressed as an emission rate, in lb CO2/
MWh,\932\ that is no less stringent than necessary. As discussed in
section X.D.1.b of this preamble, the EPA is not providing that
affected EGUs with standards of performance pursuant to consideration
of RULOF can use mass-based or rate-based compliance flexibilities
under these emission guidelines.
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\932\ The presumptive standards of performance for coal-fired
steam-generating affected EGUs and base load and intermediate load
natural gas- and oil-fired steam generating affected EGUs are in
units of lb CO2/MWh; thus, any standards of performance
pursuant to consideration of RULOF must be determined in these
units, as well. The presumptive standard of performance for low-load
natural gas-fired and oil-fired affected EGUs are in units of lb
CO2/MMBtu. While the EPA does not expect that states will
use the RULOF provisions to provide less stringent standards of
performance for these sources because their BSER is based on uniform
fuels, should a state do so, the standard of performance would be
determined in units of lb CO2/MMBtu.
---------------------------------------------------------------------------
The general implementing regulations also provide that any
compliance schedule extending more than twenty months past the state
plan submission deadline must include legally enforceable increments of
progress. 40 CFR 60.24a(d). Due to the timelines the EPA is finalizing
under these emission guidelines, any affected EGU with compliance
obligations pursuant to consideration of RULOF will have a compliance
schedule that triggers the need for increments of progress in state
plans. Because compliance obligations pursuant to RULOF are, by their
nature, source-specific, the EPA is not providing particular increments
of progress for sources for which RULOF has been invoked in these
emission guidelines. Therefore, states must provide increments of
progress for RULOF sources in their state plans that comply with the
generally applicable requirements in 40 CFR 60.24a(d) and 40 CFR
60.21a(h).
Additionally, 40 CFR 60.24a(h) requires that a less stringent
standard of performance must meet all other applicable requirements of
both the general implementing regulations and these emission
guidelines.
i. Determining a Less-Stringent Standard of Performance for Long-Term
Coal Fired Steam Generating EGUs
The EPA identified four potential systems of emission reduction for
long-term coal-fired steam generating EGUs: CCS with 90 percent
CO2 capture, CCS with partial CO2 capture/lower
capture rates, natural gas co-firing, and HRI. If a state has
demonstrated, pursuant to 40 CFR 60.24a(e), that a particular affected
coal-fired EGU in the long-term subcategory can install and operate CCS
but cannot reasonably achieve an 88.4 percent degree of emission
limitation using CCS or any other systems of emission reduction, under
the process laid out in 60.24a(f)(1) the state would proceed to
evaluate CCS with lower rates of CO2 capture. The state
would identify the most stringent degree of emission limitation the
affected EGU can reasonably achieve using CCS and that degree of
emission limitation would become the basis for the source's less
stringent standard of performance.\933\
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\933\ 40 CFR 60.24a(f) requires that a standard of performance
pursuant to consideration of RULOF be no less stringent than
necessary to address the fundamental difference identified under 40
CFR 60.24a(e). If a particular affected EGU can install and operate
CCS but only at such a low CO2 capture rate that it could
reasonably achieve greater stringency based on natural gas co-
firing, the state would apply a standard of performance based on
natural gas co-firing.
---------------------------------------------------------------------------
If a state has demonstrated, pursuant to 40 CFR 60.24a(e), that a
particular affected coal-fired EGU cannot reasonably install and
operate CCS as a control strategy and cannot otherwise achieve the
presumptive standard of performance, the state would proceed to
evaluate natural gas co-firing and HRI as potential control strategies.
Because 40 CFR 60.24a(f)(1) requires that a standard of performance be
no less stringent than necessary to address the fundamental differences
that were the basis for invoking RULOF, states would start by
evaluating natural gas co-firing at 40 percent. If the affected EGU
cannot
[[Page 39970]]
reasonably co-fire at 40 percent, the state would proceed to evaluate
lower levels of natural gas co-firing unless it has demonstrated that
the EGU cannot reasonably co-fire any amount of natural gas. If that is
the case, the state would then evaluate HRI as a control strategy. The
EPA notes that states may also consider additional systems of emission
reduction that may be available and reasonable for particular EGUs.
ii. Determining a Less-Stringent Standard of Performance for Medium-
Term Coal Fired Steam Generating EGUs
The EPA identified three potential systems of emission reduction
for affected coal-fired steam generating EGUs in the medium-term
subcategory: CCS, natural gas co-firing, and HRI. The EPA explained in
section VII.D.2.b.i of this preamble that the cost effectiveness of CCS
is less favorable for medium-term steam generating EGUs based on the
short periods they have to amortize capital costs and utilize the IRC
section 45Q tax credit. The EPA therefore believes that it would be
reasonable for states determining a less stringent standard of
performance for an affected EGU in the medium-term subcategory to forgo
evaluating CCS as a potential control strategy. States would therefore
start by evaluating lower levels of natural gas co-firing, unless a
state has demonstrated pursuant to 40 CFR 60.24a(e) that the particular
EGU cannot reasonably install and implement natural gas co-firing as a
system of emission reduction. If that is the case, the state would
evaluate HRI as the basis for a standard of performance that is no less
stringent than necessary.
The EPA expects that any coal-fired steam generating EGU to which a
less stringent standard of performance is being applied will be able to
reasonably implement some system of emission reduction; at a minimum,
the Agency believes that all sources could institute approaches to
maintain their historical heat rates.
iii. Determining a Longer Compliance Schedule
Pursuant to 40 CFR 60.24a(f)(1), a longer compliance schedule
pursuant to consideration of RULOF must be no longer than necessary to
address the fundamental difference identified pursuant to 40 CFR
60.24a(e). For states that are providing extensions to the schedules in
the EPA's emission guidelines, implementation of this requirement is
straightforward. States should provide any information and analyses
discussed in other sections of this preamble as relevant to justifying
the need for, and length of, any compliance schedule extensions under
the RULOF provisions. For states that are applying less stringent
standards of performance that are based on a system of emission
reduction other than the BSER for that subcategory, states should apply
a compliance schedule consistent with installation and implementation
of that system that is as expeditious as practicable.\934\
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\934\ See 40 CFR 60.24a(c).
---------------------------------------------------------------------------
Comment: One commenter asserted that the 2023 proposed rule
indicated that states invoking RULOF would be required to evaluate
certain controls, in a certain order, as appropriate for subcategories
of affected EGUs. The commenter stated that the EPA must defer to
states' consideration of other systems of emission reduction that the
EPA has determined are not the BSER, including the manner in which the
states choose to consider those systems.
Response: The EPA is not finalizing the proposed requirements in
these emission guidelines that would have specified the systems of
emission reduction that states must consider when invoking RULOF and
the order in which they consider them. The EPA is instead providing
that states' analyses and determinations of less stringent standards of
performance pursuant to RULOF must be conducted in accordance with the
generally applicable requirements of the part 60, subpart Ba
implementing regulations; specifically, 40 CFR 60.24a(f). While the
requirements under this regulation for determining less stringent
standards of performance pursuant to RULOF are similar to the
requirements proposed under these emission guidelines, they are also,
as described above, more flexible because they provide (1) that states
must consider other systems of emission reduction to the extent
necessary to determine the standard of performance that is no less
stringent than the EPA's degree of emission limitation than necessary,
and (2) that states may consider other systems of emission reduction,
in addition to those the EPA identified in the applicable emission
guidelines.
c. Contingency Requirements
Per the general implementing regulations at 40 CFR 60.24a(g), if a
state invokes RULOF based on an operating condition within the control
of an affected EGU, such as remaining useful life or a specific level
of utilization, the state plan must include such operating condition or
conditions as an enforceable requirement. The state plan must also
include provisions that provide for the implementation and enforcement
of the operating conditions, including requirements for monitoring,
reporting, and recordkeeping. The EPA notes that there may be
circumstances in which an affected EGU's circumstances change after a
state has submitted its state plan; states may always submit plan
revisions if needed to alter an enforceable requirement therein.
Comment: One commenter stated that if a state does not accept the
presumptive standards of performance for a facility, it must establish
federally enforceable retirement dates and operating conditions for
that facility. The commenter asserted that the CAA does not authorize
the EPA to constrain states' discretion by requiring them to impose
such restrictions as the price for exercising the RULOF authority
granted by Congress. The commenter suggested that the EPA eliminate the
requirement to include enforceable retirement dates and restrictions on
operations in conjunction with a RULOF determination and stated that
states should retain discretion to decide whether and when, based on
RULOF, it is necessary to impose such restrictions on sources.
Response: The EPA clarifies that states are in no way required to
impose enforceable retirement dates or operating restrictions on
affected EGUs under these emission guidelines. It is entirely within a
state's control to decide whether such a requirement is appropriate for
a source. If a state determines that it is, in fact, appropriate to
codify an affected EGU's intention to cease operating or limit its
operations as an enforceable requirement, the state may use such
considerations as the basis for applying, as warranted, a less
stringent standard of performance to that source. This allowance is
provided under the subpart Ba general implementing regulations, 40 CFR
60.24a(g).
d. More Stringent Standards of Performance in State Plans
States always have the authority and ability to include more
stringent standards of performance and faster compliance schedules as
federally enforceable requirements in their state plans. They do not
need to use the RULOF provisions to do so. See 40 CFR 60.24a(i).
e. Interaction of RULOF and Other State Plan Flexibilities and
Mechanisms
The EPA discusses the ability of affected EGUs with standards of
performance determined pursuant to 40 CFR 60.24a(f) to use compliance
[[Page 39971]]
flexibilities under these emission guidelines in section X.D of this
preamble.
i. Use of RULOF To Address Reliability
The EPA, in determining the degree of emission limitation
achievable through application of the BSER for coal-fired steam
generating EGUs, analyzed potential impacts of the BSERs on resource
adequacy in addition to considering multiple studies on how reliability
could be impacted by these emission guidelines. In doing so, the Agency
considered potential large-scale (regional and national) and long-term
impacts on the reliability of the electricity system under CAA section
111(a)(1)'s ``energy requirements'' factor. In evaluating CCS as a
control strategy for long-term coal-fired steam generating EGUs, the
Agency determined that CCS as the BSER would have limited and non-
adverse impacts on the long-term structure of the power sector or on
reliability of the power sector. See section VII.C.1.a.iii.(F) and
final TSD, Resource Adequacy Analysis. Additionally, the EPA has made
several adjustments to the final emission guidelines relative to
proposal that should have the effect of alleviating any reliability
concerns, including changing the scope of units covered by these
actions and removing certain subcategories, including one that would
have included an annual capacity factor limitation. See section XII.F
of this preamble for further discussion.
While the EPA has determined that the structure and requirements of
these emission guidelines will not negatively impact large-scale and
long-term reliability, it also acknowledges the more locationally
specific, source-by-source decisions that go into maintaining grid
reliability. For example, there may be circumstances in which a
balancing authority may need to have a particular unit available at a
certain time in order to ensure reliability of the larger system. As
noted above, the structure and various mechanisms of these emission
guidelines allow states and reliability authorities to plan for
compliance in a manner that preserves grid operators' abilities to
maintain electric reliability. Specifically, coal-fired EGUs that are
planning to cease operation do not have control requirements under
these emission guidelines, the removal of the imminent-term and near-
term subcategories means that states and reliability authorities have
greater flexibility in the earlier years of implementation, and the EPA
is providing two dedicated reliability mechanisms. Given these
adjustments, the Agency believes there will remain very few, if any,
circumstances in which states will need to provide particularized
compliance obligations for an affected EGU based on a need to address
reliability. However, there may be isolated instances in which a
particular affected EGU cannot reasonably comply with the applicable
requirements due to a source-specific reliability issue. Such unit-
specific reliability considerations may constitute an ``[o]ther
circumstance[] specific to the facility'' that makes it unreasonable
for a particular EGU to achieve the degree of emission limitation or
compliance schedule the EPA has provided in these emission guidelines.
40 CFR 60.24a(e)(1)(iii). The EPA is therefore confirming that states
may use the RULOF provisions in 40 CFR 60.24a to apply a less stringent
standard of performance or longer compliance schedule to a particular
affected EGU based on reliability considerations. The EPA emphasizes
that the RULOF provisions should not be used to provide a less
stringent standard of performance if the applicable degree of emission
limitation for an affected EGU is reasonably achievable. To do so would
be inconsistent with CAA sections 111(d) and 111(a)(1). Thus, to the
extent states and affected EGUs find it necessary to use RULOF to
particularize these emission guidelines' requirements for a specific
unit based on reliability concerns, such adjustments should take the
form of longer compliance schedules.
In order to meet the threshold for applying a less stringent
standard of performance or longer compliance schedule based on unit-
specific reliability considerations under 40 CFR 60.24a(e), a state
must demonstrate a fundamental difference between the information the
EPA considered on reliability and the circumstances of the specific
unit. This demonstration would be made by showing that requiring a
particular affected EGU to comply with its presumptive standard of
performance under the specified compliance timeframe would compromise
reliability, e.g., by necessitating that the affected EGU be taken
offline for a specific period of time during which a resource adequacy
shortfall with adverse impacts would result. In order to make this
demonstration, states must provide an analysis of the reliability risk
if the particular affected EGU were required to comply with its
applicable presumptive standard of performance by the compliance date,
clearly demonstrating that the EGU is reliability critical such that
requiring it to comply would trigger non-compliance with at least one
of the mandatory reliability standards approved by FERC or cause the
loss of load expectation to increase beyond the level targeted by
regional system planners as part of their established procedures for
that particular region. Specifically, this requires a clear
demonstration that each unit for which use of RULOF is being considered
would be needed to maintain the targeted level of resource
adequacy.\935\ The analysis must also include a projection of the
period of time for which the particular affected EGU is expected to be
reliability critical. States must also provide an analysis by the
relevant reliability Planning Authority \936\ that corroborates the
asserted reliability risk and confirms that one or both of the
circumstances would result from requiring the particular affected EGU
to comply with its applicable requirements, and also confirms the
period of time for which the EGU is projected to be reliability
critical. The state plan must also include a certification from the
Planning Authority that the claims are accurate and that the identified
reliability problem both exists and requires the specific relief
requested.
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\935\ See, e.g., the North American Electric Reliability
Corporation's ``Probabilistic Assessment: Technical Guideline
Document,'' August 2016. https://www.nerc.com/comm/RSTC/PAWG/proba_technical_guideline_document_08082014.pdf.
\936\ The North American Electric Reliability Corporation
(NERC)'s currently enforceable definition of ``Planning Authority''
is, ``[t]he responsible entity that coordinates and integrates
transmission Facilities and service plans, resource plans, and
Protection Systems.'' Glossary of Terms Used in NERC Reliability
Standards, Updated April 1, 2024. https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.
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To substantiate a reliability risk that stems from resource
adequacy in particular, the analyses must also demonstrate that the
specific affected EGU has been designated by the relevant Planning
Authority as needed for resource adequacy and thus reliability, and
that requiring that affected EGU to comply with the requirements in
these emission guidelines would interfere with its ability to serve
this function as intended by the Planning Authority. However, the EPA
reiterates that the structure of the subcategories for coal-fired steam
generating affected EGUs in these final emission guidelines differs
from the proposal in ways that should provide states and affected EGUs
wider latitude to make the operational decisions needed to ensure
resource adequacy. Thus, again, the Agency expects that the
circumstances in which states need to rely on consideration of RULOF to
[[Page 39972]]
particularize an affected EGU's compliance obligation will be rare.
The EPA will review these analyses and documentation as part of its
evaluation of standards of performance and compliance schedules that
states apply based on consideration of reliability under the RULOF
provisions.
As described in sections X.C.1.d and XII.F.3.b of this preamble,
the EPA is providing two flexible mechanisms that states may
incorporate in their plans that, if utilized, would provide a temporary
delay of affected EGU's compliance obligations if there is a
demonstrated reliability need.\937\ The EPA anticipates that states
discovering, after a state plan has been submitted and approved, that a
particular affected EGU needs additional time to meet its compliance
obligation as a result of a reliability or resource adequacy issue will
avail themselves of these flexibilities. If a state anticipates that
the reliability or resource adequacy issue will persist beyond the 1-
year extension provided by these flexible mechanisms, the EPA expects
that states will also initiate a state plan revision. In such a state
plan revision, the state must make the demonstration and provides the
analysis described above in order to use to adjust an affected EGU's
compliance obligations to address the reliability or resource adequacy
issue at that time.
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\937\ The mechanism described in section X.C.1.d of this
preamble is not restricted to circumstances in which a state needs
to provide an affected EGU with additional time to comply with its
standard of performance specifically for reliability or resource
adequacy, but it can be used for this purpose. The reliability
mechanism described in section XII.F.3.b is specific to reliability
and can be used to extend the date by which a source plans to cease
operating by up to 1 year.
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The EPA intends to continue engagement on the topic of electric
system reliability, resource adequacy, and linkages to various EPA
regulatory efforts to ensure proper communication with key stakeholders
and Federal counterparts including DOE and FERC. Additionally, the
Agency intends to coordinate with its Federal partners with expertise
in reliability when evaluating RULOF demonstrations that invoke this
consideration. There are also opportunities to potentially provide
information and technical support on implementation of these emission
guidelines and critical reliability considerations that will benefit
states, affected sources, system planners, and reliability authorities.
Specifically, the DOE-EPA MOU on Electric System Reliability provides a
framework for ongoing engagement, and the EPA intends to work with DOE
to ensure that reliability stakeholders have additional and ongoing
opportunities to engage EPA on this important topic.
Comment: The EPA received multiple comments on the use of the RULOF
provisions to address reliability. Several commenters emphasized that
states need the ability to adjust affected EGUs' compliance obligations
for reasons linked to reliability. They elaborated that an independent
system operator/regional transmission organization determination that
an affected EGU is needed for reliability would be anchored in a RULOF
analysis that considers forces that may drive the unit's premature
retirement. Some commenters indicated that use of RULOF to address such
units would allow those units to continue to operate for the required
period of time, applying routine methods of operation, to address grid
reliability. They similarly noted that sources that have foreseeable
retirement glidepaths but are key resources could be offered a BSER
that promotes the EPA's carbon reduction goals but falls outside of the
Agency's one-size-fits-all BSER approach.
Another commenter suggested that states should be able to modify a
subcategory in their plans to address a reliability issue, and provided
the example of allowing a unit that is planning to retire at the end of
2032 but that is needed for reliability purposes at greater than 20
percent capacity factor to subcategorize as an imminent-term unit
despite operating past the end date for the imminent-term subcategory.
The commenter suggested that such a modification could be justified
under both the remaining useful life consideration and the energy
requirements consideration of RULOF. Other commenters similarly
requested that the EPA clarify that the RULOF provisions can be used to
accommodate the changes in the power sector, e.g., the build-out of
transmission and distribution infrastructure, that are ongoing and that
may impact the anticipated operating horizons of some affected EGUs.
Response: As explained above, the EPA has analyzed the potential
impacts of these emission guidelines and determined that they would
have limited and non-adverse impacts on large-scale and long-term
reliability and resource adequacy. However, the EPA acknowledges that
there may be reliability-related considerations that apply at the level
of a particular EGU that the Agency could not have known or foreseen
and did not consider in its broader assessment. As described above,
states may use the RULOF provision to address reliability or resource
adequacy if they demonstrate, based on the analysis and consultation
with planning authorities described in this section of this preamble,
that there is a fundamental difference between the information the EPA
considered in these emission guidelines and the circumstances and
information relevant to a particular affected EGU that makes it
unreasonable for that EGU to comply with its presumptive standard of
performance by the applicable compliance date.
The EPA stresses that a generic or unsubstantiated reliability or
resource adequacy concern is not sufficient to substantiate a
fundamental difference or unreasonableness of complying with applicable
requirements. Simply asserting that grid reliability or resource
adequacy is a concern for a state and thus an affected EGU needs a less
stringent standard of performance or longer compliance schedule would
not be sufficient. Rather, a state would have to demonstrate, via the
certification and analysis described above, that the relevant planning
authority has designated a particular affected EGU as reliability or
resource adequacy critical and that requiring that EGU to comply with
its standard of performance by the applicable compliance date would
interfere with the maintenance of reliability or resource adequacy as
intended by that planning authority.
A standard of performance or compliance schedule that has been
particularized for an affected EGU based on consideration of
reliability or resource adequacy must, pursuant to 40 CFR 60.24a(f), be
no less stringent than necessary to address the fundamental difference
identified pursuant to 40 CFR 60.24a(e), which in this case would be
unit-specific grid reliability or resource adequacy needs. A less
stringent standard of performance does not necessarily correspond to a
standard of performance based on routine methods of operation and
maintenance.
The EPA notes that states do not need to use the RULOF provisions
to justify the date on which a particular affected EGU plans to cease
operation. RULOF only comes into play if there is a fundamental
difference between the information the EPA considered and the
information specific to an affected EGU with a shorter remaining useful
life that makes achieving the EPA's presumptive standard of performance
unreasonable,, e.g., the amortized cost of control. If a state elects
to rely on an affected EGU's operating conditions, such as a plan to
permanently cease operation, as the basis for applying a less stringent
standard of performance, those conditions must be included as an
[[Page 39973]]
enforceable commitment in the state plan.
As explained elsewhere in this section of the preamble, the effect
of RULOF is not to modify subcategories under these emission guidelines
but rather to particularize the compliance obligations of an affected
EGU within a given subcategory. The EPA also notes that it is not
finalizing the proposed imminent-term or near-term subcategories for
affected coal-fired steam generating EGUs.
ii. Use of RULOF With Compliance Date Extension Mechanism
As discussed in section X.C.1.d of the preamble to this final rule,
the EPA is allowing states to include in their plans a mechanism to
provide a compliance deadline extension of up to 1 year for certain
affected EGUs. This mechanism would be available for affected EGUs with
standards of performance that require add-on control technologies and
that demonstrate the extension is needed for installation of controls
due to circumstances outside the control of the affected EGU. In the
event the state and affected EGU believe that 1 year will not be
sufficient to remedy those circumstances, i.e., that the affected EGU
will not be able to comply with its standard of performance even with a
1-year extension, the state may also start the process of revising its
plan to apply a longer compliance schedule based on consideration of
RULOF. In order to demonstrate that there is a fundamental difference
between the circumstances of the affected EGU and the information the
EPA considered in determining the compliance schedule in the emission
guidelines, the state should provide documentation to justify why it is
unreasonable for the affected EGU to meet that compliance schedule,
even with an additional year (providing that the state has allowed for
a 1-year extension), based on one or more of the considerations in 40
CFR 60.24a(e)(1). This documentation should demonstrate that the need
to provide a longer compliance schedule was due to circumstances
outside the affected EGU's control and that the affected EGU has met
all relevant increments of progress and other obligations in a timely
manner up to the point at which the delay occurred. That is, the state
must demonstrate that the need to invoke RULOF and to provide a longer
compliance schedule was not caused by self-created circumstances. As
discussed in sections X.C.1.d and X.C.2.a of this preamble,
documentation such as permits obtained and/or contracts entered into
for the installation of control technology, receipts, invoices, and
correspondence with vendors and regulators is helpful evidence for
demonstrating that states and affected EGUs have been making progress
towards compliance and that the need for a longer compliance schedule
is due to circumstances outside the affected EGU's control.
In establishing a longer compliance schedule pursuant to 40 CFR
60.24a(f)(1), a state must demonstrate that the revised schedule is no
longer than necessary to accommodate circumstances that have resulted
in the delay.
3. Increments of Progress for Medium-Term and Long-Term Coal-Fired
Steam Generating EGUs
The EPA's longstanding CAA section 111 implementing regulations
provide that state plans must include legally enforceable Increments of
Progress (IoPs) toward achieving compliance for each designated
facility when the compliance schedule extends more than a specified
length of time from the state plan submission date. Under the subpart
Ba revisions finalized in November 2023, IoPs are required when the
final compliance deadline (i.e., the date on which affected EGUs must
start monitoring and reporting emissions data and other information for
purposes of demonstrating compliance with standards of performance) is
more than 20 months after the plan submittal deadline. These emission
guidelines for steam EGUs finalize a 24-month state plan submission
deadline and compliance dates of January 1, 2032 (for long-term coal-
fired EGUs), and January 1, 2030 (for all other steam generating EGUs),
exceeding subpart Ba's 20-month threshold. Under these emission
guidelines, in particular, the lengthy planning and construction
processes associated with the CCS and natural gas co-firing BSERs make
IoPs an appropriate mechanism to assure steady progress toward
compliance and to provide transparency on that progress.
The EPA received support for the proposed approach to IoPs from
many commenters; others, however, offered adverse perspectives.
Supportive commenters generally emphasized the need for clear,
transparent, and enforceable implementation checkpoints between state
plan submittal and the compliance dates given the lengthy timelines
affected EGUs are being afforded to achieve their standards of
performance. These comments were broadly consistent with the proposed
rationale for the IoPs. Adverse comments are addressed at the end of
this subsection of the preamble.
The EPA is finalizing IoPs for affected EGUs based on BSERs that
involve installation of emissions controls: long-term coal-fired EGUs
and medium-term coal-fired EGUs. Units complying through the BSER
specified for each subcategory, either CCS for the long-term
subcategory or natural gas co-firing for the medium-term subcategory,
must use IoPs tailored to those BSERs. Units complying through a
different control technology must adopt increments that correspond to
each of the steps in 40 CFR 60.21a(h). As specified in the proposal,
each increment must be assigned a calendar date deadline, but states
have discretion to set those dates based on the unique circumstances of
each unit. The EPA is also finalizing its proposal to exempt the
natural gas- and oil-fired EGU subcategories from IoP requirements.
These subcategories have BSERs of routine operation and maintenance,
which does not require the installation of significant new emission
controls or operational changes.
The EPA is finalizing the proposed approach allowing states to
choose the calendar dates for all IoPs for long- and medium-term coal-
fired EGUs, subject to two constraints. The IoP corresponding to 40 CFR
60.21a(h)(1), submittal of a final control plan to the air pollution
control agency, must be assigned the earliest calendar date deadline
among the increments, and the IoP corresponding to 40 CFR 60.21a(h)(5),
final compliance, must be assigned a date aligned with the compliance
date for each subcategory, either January 1, 2032, for the long-term
subcategory or January 1, 2030, for the medium-term subcategory. The
EPA believes that this approach will provide states and EGUs with
flexibility to account for idiosyncrasies in planning processes, tailor
compliance timelines to individual facilities, allow simultaneous work
toward separate increments, and ensure full performance by the
compliance date.
For coal-fired EGUs assigned to the long-term and medium-term
subcategories and that adopt the corresponding BSER (CCS or natural gas
co-firing, respectively) as their compliance strategy, the EPA is
finalizing BSER-specific IoPs that correspond to the steps in 40 CFR
60.21a(h). Some increments have been adjusted to more closely align
with planning, engineering, and construction steps anticipated for
affected EGUs that will be complying with standards of performance with
natural gas co-firing or CCS, in particular; however, these technology-
specific increments retain the basic structure and substance of the
[[Page 39974]]
increments in the general implementing regulations under subpart Ba. In
addition, consistent with 40 CFR 60.24a(d), the EPA is finalizing
similar additional increments of progress for the long-term and medium-
term coal-fired subcategories that are specific to pipeline
construction in order to ensure timely progress on the planning,
permitting, and construction activities related to pipelines that may
be required to enable full compliance with the applicable standard of
performance. The EPA is also finalizing an additional increment of
progress related to the identification of an appropriate sequestration
site for the long-term coal-fired subcategory. Finally, the EPA is
finalizing a requirement that state plans must require affected EGUs
with increments of progress to post the activities or actions that
constitute the increments, the schedule required in the state plan for
achieving them, and, within 30 business days, any documentation
necessary to demonstrate that they have been achieved to the Carbon
Pollution Standards for EGUs website, as discussed in section
X.E.1.b.ii of this preamble, in a timely manner.
For coal-fired steam generating units in the long-term subcategory
adopting CCS as their compliance approach, the EPA is finalizing the
following seven IoPs as enforceable elements required to be included in
a state plan: (1) Submission of a final control plan for the affected
EGU to the appropriate air pollution control agency. The final control
plan must be consistent with the subcategory declaration in the state
plan and must include supporting analysis for the affected EGU's
control strategy, including a feasibility and/or FEED study, the
anticipated timeline to achieve full compliance, and the benchmarks
anticipated along the way. (2) Awarding of contracts for emission
control systems or for process modifications, or issuance of orders for
the purchase of component parts to accomplish emission control or
process modification. Affected EGUs can demonstrate compliance with
this increment by submitting sufficient evidence that the appropriate
contracts have been awarded. (3) Initiation of onsite construction or
installation of emission control equipment or process change required
to achieve 90 percent CO2 capture on an annual basis. (4)
Completion of onsite construction or installation of emission control
equipment or process change required to achieve 90 percent
CO2 capture on an annual basis. (5) Demonstration that all
permitting actions related to pipeline construction have commenced by a
date specified in the state plan. Evidence in support of the
demonstration must include pipeline planning and design documentation
that informed the permitting process(es), a complete list of pipeline-
related permitting applications, including the nature of the permit
sought and the authority to which each permit application was
submitted, an attestation that the list of pipeline-related permits is
complete with respect to the authorizations required to operate the
facility at full compliance with the standard of performance, and a
timeline to complete all pipeline permitting activities. (6) Submittal
of a report identifying the geographic location where CO2
will be injected underground, how the CO2 will be
transported from the capture location to the storage location, and the
regulatory requirements associated with the sequestration activities,
as well as an anticipated timeline for completing related permitting
activities. (7) Final compliance with the standard of performance.
States must assign calendar deadlines for each increment consistent
with the following requirements: the first increment, submission of a
final control plan, must be assigned the earliest calendar date among
the increments; the seventh increment, final compliance must be set for
January 1, 2032.
For coal-fired steam generating units in the long-term subcategory
adopting a compliance approach that differs from CCS, the EPA is
finalizing the requirement that states adopt IoPs for each affected EGU
that are consistent with the IoPs at 40 CFR 60.21a(h). As with long-
term units adopting CCS as their compliance strategy, states must
assign calendar deadlines for each increment consistent with the
following requirements: the first increment, corresponding to 40 CFR
60.21a(h)(1), must be assigned the earliest calendar date among the
increments; the final increment, corresponding to 40 CFR 60.21a(h)(5),
must be set for January 1, 2032.
For coal-fired steam generating units in the medium-term
subcategory adopting natural gas co-firing as their compliance
approach, the EPA is finalizing the following six IoPs as enforceable
elements required to be included in a state plan: (1) Submission of a
final control plan for the affected EGU to the appropriate air
pollution control agency. The final control plan must be consistent
with the subcategory declaration in the state plan and must include
supporting analysis for the affected EGU's control strategy, including
the design basis for modifications at the facility, the anticipated
timeline to achieve full compliance, and the benchmarks anticipated
along the way. (2) Awarding of contracts for boiler modifications, or
issuance of orders for the purchase of component parts to accomplish
such modifications. Affected EGUs can demonstrate compliance with this
increment by submitting sufficient evidence that the appropriate
contracts have been awarded. (3) Initiation of onsite construction or
installation of any boiler modifications necessary to enable natural
gas co-firing at a level of 40 percent on an annual average basis. (4)
Completion of onsite construction of any boiler modifications necessary
to enable natural gas co-firing at a level of 40 percent on an annual
average basis. (5) Demonstration that all permitting actions related to
pipeline construction have commenced by a date specified in the state
plan. Evidence in support of the demonstration must include pipeline
planning and design documentation that informed the permitting
application process, a complete list of pipeline-related permitting
applications, including the nature of the permit sought and the
authority to which each permit application was submitted, an
attestation that the list of pipeline-related permit applications is
complete with respect to the authorizations required to operate the
facility at full compliance with the standard of performance, and a
timeline to complete all pipeline permitting activities. (6) Final
compliance with the standard of performance. States must also assign
calendar deadlines for each increment consistent with the following
requirements: the first increment, submission of a final control plan,
must be assigned the earliest calendar date among the increments; the
sixth increment, final compliance, must be set for January 1, 2030.
For coal-fired steam generating units in the medium-term
subcategory adopting a compliance approach that differs from natural
gas co-firing, the EPA is finalizing the requirement that states adopt
IoPs for each affected EGU that are consistent with the increments in
40 CFR 60.21a(h).
[[Page 39975]]
As with medium-term units adopting natural gas co-firing as their
compliance strategy, states must assign calendar deadlines for each
increment consistent with the following requirements: the first
increment, corresponding to 40 CFR 60.21a(h)(1), must be assigned the
earliest calendar date among the increments; the final increment,
corresponding to 40 CFR 60.21a(h)(5), must be set for January 1, 2030.
The EPA notes that if an affected EGU receives approval for a
compliance date extension, the date for at least one, if not several,
IoPs must be adjusted to align with the revised compliance date. The
new dates for the relevant IoPs must be specified in the application
for the extension. The EPA notes that the last increment--final
compliance--should be no later than 1 year after the original
compliance date, pursuant to the requirements described in section
X.C.1.d.
Comment: The EPA received comments that the proposed IoPs are too
restrictive and may limit certain implementation flexibilities, namely
that the burden to adjust IoPs after state plan submittal will limit
sources' ability to switch subcategories or adjust implementation
timelines due to unforeseen circumstances.
Response: The EPA has considered these comments and notes that the
final rule includes planning flexibilities to address these situations.
The first of these flexibilities is embedded in the subpart Ba
regulations governing optional state plan revisions. Plan revisions,
including revisions to subcategory assignments and any corresponding
IoPs, may be used at a state's discretion to account for changes in
planned compliance approaches. 40 CFR 60.28a. Such revisions can also
include RULOF-based adjustments to approved standards of performance as
well as the timelines to meet those standards, including the IoPs.
Further, as mentioned above, the compliance date extension mechanism
described in section X.C.1.d allows for modification of the IoPs to
align with an approved compliance date extension. In addition, the
subcategory structure of these final emission guidelines differs from
that at proposal such that it is less likely that affected coal-fired
EGUs will switch subcategories. In the event that an affected EGU does
switch between the long-term and medium-term subcategories, the state
plan revision process is the most appropriate mechanism because a
different control strategy may be appropriate. Based on this
consideration and the availability of planning flexibilities to account
for changes in compliance plans and changed circumstances, the EPA is
finalizing the approach to IoPs as proposed.
Comment: Some commenters raised concerns related to length of time
between the state plan submittal deadline and the final compliance
dates, namely that some IoPs will take place too far into the future to
be reliably assigned calendar date deadlines.
Response: As noted above, the EPA has concluded that length of time
between the state plan submittal deadline and the compliance deadlines
for units in the medium-term and long-term subcategories as well as the
anticipated complexity for units to comply with the final standards of
performance necessitate the use of discrete interim checkpoints prior
to final compliance, formally established as increments of progress, to
ensure timely and transparent progress toward each unit's compliance
obligation. It would be inconsistent to determine that the same factors
necessitating the increments--the length of time between the state plan
submittal deadline and the compliance obligation as well as the complex
nature of the implementation process--also eliminate the IoPs' core
accountability function by prohibiting the assignment of calendar date
deadlines. Finally, as described above, the final emission guidelines
also allow states and affected EGUs significant flexibility to
determine when each increment applies.
Comment: Some commenters raised concerns that the IoPs could limit
affected EGUs from selecting compliance approaches that differ from the
BSER technology associated with each subcategory, namely averaging and
trading.
Response: Under the approach finalized in this rule, units assigned
to the long-term and medium-term subcategories that do not adopt the
associated BSER as part of their compliance strategy must establish
date-specified IoPs consistent with the subpart Ba IoPs codified at 40
CFR 60.21a(h). That is, states will particularize the generic IoPs in
subpart Ba as appropriate for affected EGUs that comply with their
standards of performance using control technologies other than CCS (for
long-term units) or natural gas co-firing (for medium-term units). The
EPA discusses considerations relevant to averaging and trading in
section X.D of this preamble.
4. Reporting Obligations and Milestones for Affected EGUs That Plan to
Permanently Cease Operations
The EPA proposed legally enforceable reporting obligations and
milestones for affected EGUs demonstrating that they plan to cease
operations and use that voluntary commitment for eligibility for the
imminent-term, near-term, or medium-term subcategory. No reporting
obligations and milestones were proposed for affected EGUs within the
long-term subcategory since a voluntary commitment to cease operations
was not part of the subcategory's applicability criteria. The proposed
rationale for the milestone requirements recognized that the proposed
subcategories were based on the operating horizons of units within each
subcategory, and that there were numerous steps that EGUs in these
subcategories need to take in order to effectuate their commitments to
cease operations. The proposed reporting obligations and milestones
were intended to provide transparency and assurance that affected EGUs
could complete the steps necessary to qualify for a subcategory with a
less stringent standard of performance.\938\
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\938\ 88 FR 33390 (May 23, 2023).
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Of the proposed subcategories for which the reporting obligations
and milestones were proposed to apply, the EPA's final emission
guidelines retain only the medium-term coal-fired subcategory. Though
the EPA is finalizing only one subcategory with an associated
operational time horizon, the Agency has determined that the original
rationale for the milestones is still valid. That is, the BSER
determination for EGUs assigned to the medium-term subcategory is
contingent on sources within this subcategory having limited operating
horizons relative to affected EGUs in the long-term subcategory, and
the integrity of the subcategory approach and the environmental
integrity of these emission guidelines depend on sources behaving
consistent with the operating horizon they have represented in the
state plan. The steps required for EGUs to cease operations are
numerous and vary across jurisdictions; giving states, the EPA, and
other stakeholders insight into these steps and affected EGUs' progress
along these steps provides assurance that they are on track to meeting
their state plan requirements. The reporting obligations and milestones
the EPA is finalizing under these emission guidelines are a reasonable
approach to assuring transparency and timely compliance; they can also
serve as an early indication that a state plan revision may be
necessary if it becomes apparent that an affected EGU is not meeting
its designated milestones. Further, the agency has determined that a
similar rationale for requiring reporting obligations and milestones
applies to
[[Page 39976]]
affected EGUs that invoke RULOF based on a unit's remaining useful
life. States may apply a less stringent standard of performance to a
particular affected EGU if its shorter remaining useful life results in
a fundamental difference between the circumstances of that EGU and the
information the EPA considered, and that difference makes it
unreasonable for the EGU to achieve the presumptive standard of
performance. However, if such a unit continues to operate past the date
by which it previously committed to cease operating, the basis for the
less stringent standard of performance is abrogated and the
environmental integrity of the emission guidelines compromised.
Therefore, as for affected EGUs in the medium-term subcategory, the
reporting obligations and milestones are an essential component of
assuring that affected EGUs that invoke RULOF based on a unit's
remaining useful life are actually able to satisfy the condition of
receiving the less stringent standard in the first instance.
The EPA is finalizing the following milestones and reporting
requirements, explained in more detail below, for both affected EGUs
assigned to the medium-term subcategory and affected EGUs that invoke
RULOF based on a unit's remaining useful life. These sources must
submit an Initial Milestone Report five years before the date by which
it will permanently cease operations, annual Milestone Status Reports
for each intervening year between the initial report and the date
operations will cease, and a Final Milestone Status Report no later
than six months from the date by which the affected EGU has committed
to cease operating.
Commenters expressed a range of views regarding the proposed
reporting obligations and milestones. Some were broadly supportive of
the reporting milestones and the EPA's stated rationale to provide a
mechanism to help ensure that affected EGUs progress steadily toward a
commitment to cease operations when that commitment affects the
stringency of their standard of performance. Summaries of and responses
to additional comments on the reporting obligations and milestones are
addressed at the end of this subsection.
The discussion below refers to reporting ``milestones.'' Owners/
operators of sources take a number of process steps in preparing a unit
to cease operating (i.e., preparing it to deactivate). The EPA is
requiring that states select certain of these steps to serve as
milestones for the purpose of reporting where a source is in the
process; the EPA is designating two milestones in particular and states
will select additional steps for reporting milestones. The requirements
being established under these emission guidelines do not require
milestone steps to be taken at any particular time--they merely require
reporting on when a source intends to reach each of its designated
milestones and whether and when it has actually done so. The reporting
obligations and milestone requirements count backward from the calendar
date by which an affected EGU has committed to permanently cease
operations, which must be included in the state plan, to monitor timely
progress toward that date. Five years before any planned date to
permanently cease operations or 60 days after state plan submission,
whichever is later, the owner or operator of affected EGUs must submit
an Initial Milestone Report to the applicable air pollution control
agency that includes the following: (1) A summary of the process steps
required for the affected EGU to permanently cease operation by the
date included in the state plan, including the approximate timing and
duration of each step and any notification requirements associated with
deactivation of the unit. (2) A list of key milestones that will be
used to assess whether each process step has been met, and calendar day
deadlines for each milestone. These milestones must include at least
the initial notice to the relevant reliability authority of an EGU's
deactivation date and submittal of an official retirement filing with
the EGU's reliability authority. (3) An analysis of how the process
steps, milestones, and associated timelines included in the Initial
Milestone Report compare to the timelines of similar EGUs within the
state that have permanently ceased operations within the 10 years prior
to the date of promulgation of these emission guidelines. (4)
Supporting regulatory documents, including correspondence and official
filings with the relevant regional transmission organization (RTO),
independent system operator (ISO), balancing authority, public utility
commission (PUC), or other applicable authority; any deactivation-
related reliability assessments conducted by the RTO or ISO; and any
filings pertaining to the EGU with the United States Securities and
Exchange Commission (SEC) or notices to investors, including but not
limited to references in forms 10-K and 10-Q, in which the plans for
the EGU are mentioned; any integrated resource plans and PUC orders
approving the EGU's deactivation; any reliability analyses developed by
the RTO, ISO, or relevant reliability authority in response to the
EGU's deactivation notification; any notification from a relevant
reliability authority that the EGU may be needed for reliability
purposes notwithstanding the EGU's intent to deactivate; and any
notification to or from an RTO, ISO, or balancing authority altering
the timing of deactivation for the EGU.
For each of the remaining years prior to the date by which an
affected EGU has committed to permanently cease operations that is
included in the state plan, it must submit an annual Milestone Status
Report that addresses the following: (1) Progress toward meeting all
milestones identified in the Initial Milestone Report; and (2)
supporting regulatory documents and relevant SEC filings, including
correspondence and official filings with the relevant regional
transmission organization, balancing authority, public utility
commission, or other applicable authority to demonstrate compliance
with or progress toward all milestones.
The EPA is also finalizing a provision that affected EGUs with
reporting milestones associated with commitments to permanently cease
operations would be required to submit a Final Milestone Status Report
no later than 6 months following its committed closure date. This
report would document any actions that the unit has taken subsequent to
ceasing operation to ensure that such cessation is permanent, including
any regulatory filings with applicable authorities or decommissioning
plans.
The EPA is finalizing a requirement that affected EGUs with
reporting milestones for commitments to permanently cease operations
must post their Initial Milestone Report, annual Milestone Status
Reports, and Final Milestone Status Report, including the schedule for
achieving milestones and any documentation necessary to demonstrate
that milestones have been achieved, on the Carbon Pollution Standards
for EGUs website, as described in section X.E.1.b, within 30 business
days of being filed. The EPA recognizes that applicable regulatory
authorities, retirement processes, and retirement approval criteria
will vary across states and affected EGUs. The proposed milestone
reporting requirements are intended to establish a general framework
flexible enough to account for significant differences across
jurisdictions while assuring timely planning toward the dates by which
affected EGUs permanently cease operations.
[[Page 39977]]
Comment: Some commentors questioned the need for the milestone
reports by pointing to existing closure enforcement mechanisms within
their jurisdictions.
Response: The existence of enforceable mechanisms in some
jurisdictions does not obviate the need for the reporting milestones
under these emission guidelines. First, the closure requirements, the
nature of the enforcement mechanisms, and process requirements to cease
operations will vary across different jurisdictions, and some
jurisdictions may lack mechanisms entirely. The reporting milestones
framework sets a uniform floor for reporting progress toward a
commitment to cease operations, reducing differences in the quality and
scope of information available to the EPA and public regarding
closures. Second, the reporting milestones under these emission
guidelines serve the additional purpose of transparency and allowing
all stakeholders to have access to information related to affected
EGUs' ongoing compliance.
Comment: Some commentors noted the unique EGU closure processes
within their own jurisdictions and expressed concern as to whether the
milestones requirements were too rigid to accommodate them.
Response: The reporting milestones are designed to create a
flexible reporting framework that can accommodate differences in state
closure processes. States can satisfy the required elements of the
milestone reports by explaining how the process steps for plant
closures within their jurisdiction work and establishing milestones
corresponding to the process steps required within individual
jurisdictions.
5. Testing and Monitoring Requirements
a. Emissions Monitoring and Reporting
The EPA proposed to require that state plans must include a
requirement that affected EGUs monitor and report hourly CO2
mass emissions emitted to the atmosphere, total heat input, and total
gross electricity output, including electricity generation and, where
applicable, useful thermal output converted to gross MWh, in accordance
with the 40 CFR part 75 monitoring, reporting, and recordkeeping
requirements. The EPA is finalizing a requirement that affected EGUs
must use a 40 CFR part 75 certified monitoring methodology and report
the hourly data on a quarterly basis, with each quarterly report due to
the Administrator 30 days after the last day in the calendar quarter.
The 40 CFR part 75 monitoring provisions require most coal-fired
boilers to use a CO2 continuous emissions monitoring system
(CEMS), including both a CO2 concentration monitor and a
stack gas flow monitor. Some oil- and gas-fired boilers may have
options to use alternative measurement methodologies (e.g., fuel flow
meters combined with fuel quality data).
The EPA received comments supporting and opposing the requirement
to use 40 CFR part 75 monitoring, reporting, and recordkeeping
requirements.
Comment: Commenters generally supported these requirements, noting
that the majority of EGUs affected by this rule already monitor and
submit emissions reports under 40 CFR part 75 under existing programs,
including the Acid Rain Program and/or Regional Greenhouse Gas
Initiative--a cooperative of several states formed to reduce
CO2 emissions from EGUs. In addition, EGUs that are not
required to monitor and report under one of those programs may have 40
CFR part 75 certified monitoring systems in place for the MATS or
CSAPR.
Response: The EPA agrees with these comments. Relying on the same
monitors that are certified and quality assured in accordance with 40
CFR part 75 reduces implementation costs and ensures consistent
emissions data across regulatory programs.
Comment: Some commenters focused on potential measurement bias of
40 CFR part 75 certified monitoring systems, with commenters split on
whether the data are biased high or low.
Response: The EPA disagrees that the data reported under 40 CFR
part 75 are biased significantly high or low. Each CO2 CEMS
must undergo regular quality assurance and quality control activities
including periodic relative accuracy test audits (RATAs) where a
monitoring system is compared to an independent monitoring system using
EPA reference methods and NIST-traceable calibration gases. In a May
2022 study conducted by the EPA, the absolute value of the median
difference between EGUs' monitoring systems and independent monitoring
systems using EPA reference methods was found to be approximately 2
percent for CO2 concentration monitors and stack gas flow
monitors in the years 2017 through 2021.\939\
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\939\ Zintgraff, Stacey. 2022. Monitoring Insights: Relative
Accuracy in EPA CAMD's Power Sector Emissions Data. www.epa.gov/system/files/documents/2022-05/Monitoring%20Insights-%20Relative%20Accuracy.pdf.
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b. CCS-Specific Technology Monitoring and Reporting
Affected EGUs employing CCS must comply with relevant monitoring
and reporting requirements specific to CCS. As described in the
proposal, the CCS process is subject to monitoring and reporting
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires
reporting of facility-level GHG data and other relevant information
from large sources and suppliers in the U.S. The ``suppliers of carbon
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires
those affected facilities with production process units that capture a
CO2 stream for purposes of supplying CO2 for
commercial applications or that capture and maintain custody of a
CO2 stream in order to sequester or otherwise inject it
underground to report the mass of CO2 captured and supplied.
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of
CO2 sequestered under the ``geologic sequestration of carbon
dioxide'' source category of the GHGRP (GHGRP subpart RR). In April
2024, to complement GHGRP subpart RR, the EPA finalized the ``geologic
sequestration of carbon dioxide with enhanced oil recovery (EOR) using
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide
an alternative method of reporting geologic sequestration in
association with EOR.940 941 942
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\940\ EPA. (2024). Rulemaking Notices for GHG Reporting. https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
\941\ International Standards Organization (ISO) standard
designated as CSA Group (CSA)/American National Standards Institute
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil
Recovery (CO2-EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
\942\ As described in 87 FR 36920 (June 21, 2022), both subpart
RR and subpart VV (CSA/ANSI ISO 27916:2019) require an assessment
and monitoring of potential leakage pathways; quantification of
inputs, losses, and storage through a mass balance approach; and
documentation of steps and approaches used to establish these
quantities. Primary differences relate to the terms in their
respective mass balance equations, how each defines leakage, and
when facilities may discontinue reporting.
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As discussed in section VII.C.1.a.vii, the EPA is finalizing a
requirement that any affected unit that employs CCS technology that
captures enough CO2 to meet the standard and injects the
captured CO2 underground must report under GHGRP subpart RR
or GHGRP subpart VV. If the emitting EGU sends the captured
CO2 offsite, it must transfer the CO2 to a
facility subject to the GHGRP requirements, and the facility injecting
the CO2 underground must
[[Page 39978]]
report under GHGRP subpart RR or GHGRP subpart VV. These emission
guidelines do not change any of the requirements to obtain or comply
with a UIC permit for facilities that are subject to the EPA's UIC
program under the Safe Drinking Water Act.
The EPA also notes that compliance with the standard is determined
exclusively by the tons of CO2 captured by the emitting EGU.
The tons of CO2 sequestered by the geologic sequestration
site are not part of that calculation, though the EPA anticipates that
the quantity of CO2 sequestered will be substantially
similar to the quantity captured. To verify that the CO2
captured at the emitting EGU is sent to a geologic sequestration site,
we are leveraging regulatory requirements under the GHGRP. The BSER is
determined to be adequately demonstrated based solely on geologic
sequestration that is not associated with EOR. However, EGUs also have
the compliance option to send CO2 to EOR facilities that
report under GHGRP subpart RR or GHGRP subpart VV. We also emphasize
that these emission guidelines do not involve regulation of downstream
recipients of captured CO2. That is, the regulatory standard
applies exclusively to the emitting EGU, not to any downstream user or
recipient of the captured CO2. The requirement that the
emitting EGU transfer the captured CO2 to an entity subject
to the GHGRP requirements is thus exclusively an element of enforcement
of the EGU standard. This will avoid duplicative monitoring, reporting,
and verification requirements between this proposal and the GHGRP,
while also ensuring that the facility injecting and sequestering the
CO2 (which may not necessarily be the EGU) maintains
responsibility for these requirements. Similarly, the existing
regulatory requirements applicable to geologic sequestration are not
part of the final emission guidelines.
D. Compliance Flexibilities
In the finalized subpart Ba revisions, Adoption and Submittal of
State Plans for Designated Facilities: Implementing Regulations Under
Clean Air Act Section 111(d), the EPA explained that, under its
interpretation of CAA section 111, each state is permitted to include
compliance flexibilities, including flexibilities that allow affected
EGUs to meet their emission limits in the aggregate, in their state
plans. The EPA also explained that, in particular emission guidelines,
the Agency may limit compliance flexibilities if necessary to protect
the environmental outcomes of the guidelines.\943\ Thus, in the subpart
Ba final rule the EPA returned to its longstanding position that CAA
section 111(d) authorizes the EPA to approve state plans that achieve
the requisite emission limitation through aggregate reductions from
their sources, including through trading or averaging, where
appropriate for a particular emission guideline and consistent with the
intended environmental outcomes under CAA section 111.\944\
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\943\ 88 FR 80533 (November 17, 2023).
\944\ The EPA has authorized trading or averaging as compliance
methods in several emission guidelines. See, e.g., 70 FR 28606,
28617 (May 18, 2005) (Clean Air Mercury Rule authorized trading)
(vacated on other grounds); 40 CFR 60.24(b)(1) (subpart B CAA
section 111 implementing regulations promulgated in 2005 allow
states' standards of performance to be based on an ``allowance
system''); 80 FR 64662, 64840 (October 23, 2015) (CPP authorizing
trading or averaging as a compliance strategy). In the recent final
emission guidelines for the oil and natural gas industry, the EPA
also finalized a determination that states are permitted sources to
demonstrate compliance in the aggregate. 89 FR 16820 (March 8,
2024).
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In developing both the proposed and final emission guidelines, the
EPA heard from stakeholders that flexibilities are important in
complying with standards of performance under these emission
guidelines. The EPA proposed to allow states to incorporate emission
trading and averaging into their plans under these emission guidelines,
provided that states ensure that the use of such flexibilities will
result in an aggregate level of emission reduction that is equivalent
to each source individually achieving its standard of performance.
Specifically, a variety of commenters from states, industry, RTO/
ISOs, and NGOs emphasized the importance of allowing states to
incorporate not only flexibilities that allow sources to demonstrate
compliance in the aggregate, such as emission trading and averaging,
but also unit-specific mass-based compliance into their plans. In
particular, commenters expressed a strong preference for mass-based
compliance mechanisms, whether unit-specific or emission trading, and
cited reliability as a key driver of their support for such mechanisms.
However, for the most part commenters did not provide detail on how
flexibilities could be designed under the unique circumstances of these
emission guidelines. In addition, many commenters did not specify as to
the usefulness of certain compliance flexibilities for steam generating
EGUs versus combustion turbine EGUs. Because these final emission
guidelines only apply to steam generating EGUs, there are fewer
affected EGUs that could partake in these flexibilities, which may
limit their usefulness. A description of and responses to general
comments on these compliance flexibilities can be found at the end of
this subsection.
The EPA notes that many other features of the final emission
guidelines provide the type of flexibility that the commenters stated
they wanted through the use of emission trading, averaging, and/or
unit-specific mass-based compliance. First, as noted in section X.C.1.b
of this preamble, compliance with presumptively approvable rate-based
standards of performance is demonstrated on an annual basis, which
already provides flexibility around mass emissions over an annual
period (i.e., it affords the affected EGU the ability over the course
of the year to vary its emission output, which may be useful if, for
example, it needs to temporarily turn off its control equipment or
otherwise increase its emission rate). Second, the EPA is finalizing
two mechanisms, described in section XII.F of this preamble, to address
reliability concerns raised by commenters: a short-term reliability
mechanism that allows affected EGUs to operate above their standard of
performance for a limited time in periods of emergency and a
reliability assurance mechanism to ensure sufficient capacity is
available. Finally, as described in section X.C.2 of this preamble,
states may invoke RULOF to provide for less stringent standards of
performance for affected EGUs under certain circumstances (states may
invoke RULOF both at the time of initial state plan development as well
as through state plan revision should the circumstances of an affected
EGU change following state plan submission).
The EPA believes that the use of compliance flexibilities, within
the parameters specified in these emission guidelines, may provide some
additional operational flexibility to states and affected EGUs in
achieving the required emission reductions which, under these emission
guidelines, are achieved specifically through cleaner performance. In
particular, for aggregate compliance flexibilities like emission
averaging and trading, affected EGUs may be able to capitalize on
heterogeneity in economic emission reduction opportunities based on
minor differences in marginal emission abatement costs and/or operating
parameters among EGUs. This heterogeneity may provide some incentive
among participating EGUs to overperform (i.e., operate even more
cleanly than required by the applicable standard of performance,
because of the opportunity to sell compliance
[[Page 39979]]
instruments to other units), while also providing some limited
opportunity for other sources to vary their emission output.
Therefore, the EPA is finalizing a determination that the use of
compliance flexibilities, including emission trading, averaging, and
unit-specific mass-based compliance, is permissible for affected EGUs
in certain subcategories and in certain circumstances under these
emission guidelines. Specifically, the EPA is allowing affected EGUs in
the medium- and long-term coal-fired subcategories to utilize these
compliance flexibilities. The scope of this allowance is tailored to
ensure consistency with the fundamental principle under CAA section 111
that state plans maintain the stringency of the EPA's BSER
determination and associated degree of emission limitation as applied
through the EPA's presumptive standards of performance in the context
of these emission guidelines. In addition, the EPA believes that the
scope of this allowance is consistent and appropriate for providing an
incentive for overperformance. Relatedly, the EPA is also providing
further elaboration on what it means for states to demonstrate that
implementation of a standard of performance using a rate- or mass-based
flexibility is at least as stringent as unit-specific implementation of
affected EGUs' standards of performance. States are not required to
allow their affected EGUs to use compliance flexibilities but can
provide for such flexibilities at their discretion. In order for the
EPA to find that a state plan that includes such flexibilities is
``satisfactory,'' the state plan must demonstrate how it will achieve
and maintain the requisite level of emission reduction.
The EPA stresses that any flexibilities involving aggregate
compliance would be used to demonstrate compliance with an already-
established standard of performance, rather than be used to establish a
standard of performance in the first instance. The presumptive
standards of performance that the EPA is providing in these emission
guidelines are based on control strategies that are applied at the
level of individual units. A compliance flexibility may change the way
an affected EGU demonstrates compliance with a standard of performance
(e.g., by allowing that EGU to surrender allowances from another unit
in lieu of reducing a portion of its own emissions), but does not alter
the benchmark of emission performance against which compliance is
evaluated. This is in contrast to the RULOF mechanism, which, as
described in section X.C.2 of this preamble, states may use to apply a
different standard of performance with a different degree of emission
limitation than the EPA's presumptive standard. States incorporating
trading or averaging would not need to undergo a RULOF demonstration
for sources participating in trading or averaging programs because they
are not altering those sources' underlying standards of performance--
just providing an additional way for sources to demonstrate compliance.
While the EPA acknowledges widespread interest in the use of mass-
based compliance, in the context of these particular emission
guidelines, the Agency has significant concerns about the ability to
demonstrate that mass-based compliance approaches achieve at least
equivalent emission reduction as the application of rate-based, source-
specific standards of performance. As explained in further detail in
sections X.D.4 and X.D.5, the EPA is requiring the use of a backstop
emission limitation, or backstop rate, in conjunction with mass-based
compliance approaches (i.e., for both unit-specific mass-based
compliance and mass-based emission trading) for both the long-term and
medium-term coal-fired subcategories. However, the EPA is finalizing a
presumptively approvable unit-specific mass-based compliance approach
only for affected EGUs in the long-term subcategory. The use of mass-
based compliance approaches--both unit-specific and trading--for
affected EGUs in the medium-term coal-fired subcategory in particular
poses a high risk of undermining the stringency of these emission
guidelines due to inherent uncertainty about the future utilization of
these sources. While the EPA is not precluding states from attempting
to design mass-based approaches for affected EGUs in the medium-term
coal-fired subcategory that satisfy the requirement of achieving at
least equivalent stringency as rate-based implementation, the Agency
was unable to devise an appropriate, implementable presumptively
approvable approach for affected EGUs in the medium-term coal-fired
subcategory and is therefore not providing one here. The EPA is also
not providing a presumptively approvable approach to emission trading
or averaging. Instead, the EPA intends to review emission trading or
averaging programs in state plans on a case-by-case basis against the
foundational principles for consistency with CAA section 111, as
discussed in this section of the preamble.
Section X.D.1 of this preamble discusses the fundamental
requirement that compliance flexibilities maintain the level of
emission reduction of unit-specific implementation, in order to inform
states' consideration of such flexibilities for any use in their state
plans. It also addresses why limitations on the use of compliance
flexibilities for certain subcategories are necessary to maintain the
intended environmental outcomes of these emission guidelines. Sections
X.D.2, X.D.3, X.D.4, and X.D.5 discuss each available type of
compliance flexibility and provide information on how they can be used
in state plans under these emission guidelines. Section X.D.6 provides
information on general implementation features of emission trading and
averaging programs that states must consider if they develop such a
program. Section X.D.7 discusses interstate emission trading. Finally,
section X.D.8 discusses considerations related to existing state
programs and the inclusion of compliance flexibilities in a state plan
under these emission guidelines.
Comment: Commenters cited a variety of reasons supporting the use
of compliance flexibilities, such as emission trading, averaging, and
unit-specific mass-based compliance, in these emission guidelines,
including the need for flexibility in meeting the degree of emission
limitation defined by the BSER, the potential for more cost-effective
compliance, and reliability purposes.
Response: The EPA believes that, in certain circumstances, these
flexibilities can provide some operational and cost flexibility to
states and affected EGUs in complying with these emission guidelines
and their standards of performance in state plans. However, as
described above, the EPA is addressing reliability-related concerns
primarily through other structural changes and mechanisms under these
emission guidelines (see section XII.F of this preamble) that may
obviate the need to use compliance flexibilities specifically to
address reliability concerns. As a general matter, the EPA believes
that compliance flexibilities such as emission trading and averaging
provide some incentive for overperformance that could be beneficial to
states and affected EGUs.
The EPA is finalizing a determination that emission trading,
averaging, and unit-specific mass-based compliance are permissible for
certain subcategories under these emission guidelines, subject to the
limitations described in section X.D.1 of this preamble. The EPA
believes these limitations are necessary
[[Page 39980]]
in the context of these emission guidelines in order to maintain the
level of emission reduction of the EPA's BSER determination and
corresponding degree of emission limitation.
Comment: Some commenters expressed opposition to the use of
emission trading and averaging, citing the potential for emission
trading and averaging programs to maintain or exacerbate existing
disparities in communities with environmental justice concerns.
Response: The EPA is cognizant of these concerns and believes that
emission trading and averaging are not necessarily incompatible with
environmental justice. The EPA is including limitations on the use of
compliance flexibilities in state plans that should help address these
EJ concerns. As discussed in more detail in section X.D.1, the EPA is
restricting certain subcategories from using trading or averaging as
well as, for mass-based compliance mechanisms, requiring the use of a
backstop rate, to ensure that the use of compliance flexibilities
maintains the level of emission reduction of the EPA's BSER
determination and corresponding degree of emission limitation as well
as achieves the statutory objective of these emission guidelines to
mitigate air pollution by requiring sources to operate more cleanly.
The EPA notes that trading programs can be designed to include measures
like unit-specific emission rates that assure that reductions and
corresponding benefits accrue proportionally to communities with
environmental justice concerns. The EPA also notes that states have the
ability to add further features and requirements to emission trading
and averaging programs than identified in these emission guidelines, or
to forgo their use entirely.
Pursuant to the requirements of subpart Ba, states are required to
conduct meaningful engagement on all aspects of their state plans with
pertinent stakeholders. This would necessarily include any potential
use of flexibilities for sources to demonstrate compliance with the
proposed standards of performance through emissions trading or
averaging. As discussed in greater detail in section X.E.1.b.i of this
preamble, meaningful engagement provides an opportunity for communities
most affected by and vulnerable to the impacts of a plan to provide
input, including input on any impacts resulting from the use of
compliance flexibilities.
Comment: Some commenters stated that allowing trading or averaging
is not consistent with the legal opinion in West Virginia v. EPA.
Response: This comment is outside the scope of this action. The EPA
finalized its interpretation that CAA section 111 does not preclude
states from including compliance flexibilities such as trading or
averaging in their state plans (although the EPA may limit those
flexibilities in particular emission guidelines if necessary to protect
the environmental outcomes of those guidelines) when it revised the CAA
section 111(d) implementing regulations in subpart Ba.\945\ As
described in the final subpart Ba revisions, ``in West Virginia v. EPA,
the Supreme Court did not directly address the state's authority to
determine their sources' control measures. Although the Court did hold
that constraints apply to the EPA's authority in determining the BSER,
the Court's discussion of CAA section 111 is consistent with the EPA's
interpretation that the provision does not preclude states from
granting sources compliance flexibility.'' \946\ The EPA further
explained in the preamble to the subpart Ba final rule that the West
Virginia Court was clear that the focus of the case was exclusively on
whether the EPA acted within the scope of its authority in establishing
the BSER: ``The Court did not identify any constraints on the states in
establishing standards of performance to their sources, and its holding
and reasoning cannot be extended to apply such constraints.'' \947\
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\945\ 88 FR 80480 80533-35 (November 17, 2023).
\946\ 88 FR 80534 (November 17, 2023).
\947\ 88 FR 80535 (November 17, 2023).
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The EPA reiterates that, under these emission guidelines, the BSER
determinations are emission reduction technologies or strategies that
apply to and reduce the emission rates of individual affected EGUs.
Furthermore, states have the option of including emission trading or
averaging in their states plans but are by no means required to do so.
States that choose to include trading or averaging programs in their
state plans are required to demonstrate that those programs are in the
aggregate as stringent as each affected EGU individually achieving its
rate-based standard of performance. Additionally, as explained
elsewhere in sections X.D.4 and X.D.5 of this preamble, the EPA is
requiring the use of a backstop emission rate in conjunction with mass-
based compliance flexibilities, one result of which is that units
cannot comply with their standards of performance merely by shifting
their generation to other electricity generators. Therefore, the EPA's
BSERs in these emission guidelines are not based on generation shifting
and, even if the EPA believed that West Virginia v. EPA implicated the
use of compliance flexibilities, the permissible use of trading and
averaging in this particular case does not implicate the Court's
concerns about generation shifting therein.
1. Demonstrating Equivalent Stringency
As stated in the section above, states are permitted to use
emission trading, averaging, and unit-specific mass-based compliance in
their plans for certain subcategories under these emission guidelines,
provided that the plan demonstrates that any such use will achieve a
level of emission reduction that is in the aggregate as environmentally
protective as each affected EGU achieving its rate-based standard of
performance. This requirement is rooted in the structure and purpose of
CAA section 111. Most commenters supported the use of compliance
flexibilities in these emission guidelines, and many explicitly
expressed support for the EPA's stringency criterion in this context.
Commenters also requested greater clarity on how to demonstrate
equivalent stringency in a state plan. In this section, the EPA
describes foundational parameters for a demonstration of equivalence in
the state plan as well as limitations on the availability of compliance
flexibilities for certain affected EGUs, which stem from the EPA's
stringency criterion. Additionally, the EPA offers further explanation
of how it will review state plan submissions to determine whether plans
that include compliance flexibilities achieve an equivalent (or
greater) level of emission reduction as each affected EGU individually
complying with its unit-specific rate-based standard of performance.
a. Requirements for Demonstrating Equivalent Stringency
In their plans, states incorporating compliance flexibilities must
first clearly demonstrate how they calculated the aggregate rate-based
emission limitation (for rate-based averaging), mass limit (for unit-
specific mass-based compliance), or mass budget (for mass-based
emission trading) from unit-specific, rate-based presumptive standards
of performance. (For rate-based trading, the standard of performance
coupled with, if necessary, an adjustment based on the acquisition of
compliance instruments, is used to demonstrate compliance.) In doing
so, states must identify the specific affected EGUs that will be using
compliance flexibilities; which flexibility each unit
[[Page 39981]]
will able to use; the unit-specific, rate-based presumptive standard of
performance; and the standard of performance established in the plan
for each unit (rate-based limit or mass limit) or set of units
(aggregate rate-based emission limitation or mass budget). The state
must document and justify the assumptions made in calculating an
aggregate rate-based emission limitation, mass limit, or mass budget,
such as how the calculation is weighted or, for mass-based mechanisms,
the level of utilization of participating affected EGUs used to
calculate the mass limit or budget. This requirement is discussed in
more detail in the context of each type of compliance flexibility in
the following subsections.
Next, states must demonstrate how the compliance flexibility will
maintain the requisite stringency, i.e., how the plan will maintain the
aggregate level of emission reduction that would be achieved if each
unit was individually complying with its rate-based standard of
performance. As discussed in section X.C.1 of this preamble, an
affected EGU's standard of performance must generally be no less
stringent than the corresponding presumptive standard of performance
under these emission guidelines. This is true regardless of whether a
standard of performance is expressed in terms of rate or mass. However,
under an aggregate compliance approach, a unit may demonstrate
compliance with that standard of performance by averaging its emission
performance or trading compliance instruments (e.g., allowances) with
other affected EGUs. Here, to ensure consistency with the level of
emission reductions Congress expected under CAA section 111(a)(1), the
state must also demonstrate that the plan overall achieves equivalent
stringency, i.e., the same or better environmental outcome, as applying
the EPA's presumptive standards of performance to each affected EGU
(after accounting for any application of RULOF). That is, in order for
the EPA to find a state plan ``satisfactory,'' that plan must achieve
at least the level of emission reduction that would result if each
affected EGU was achieving its presumptive standard of performance
(again, after accounting for any application of RULOF).
The requirement that state plans achieve equivalent stringency to
the EPA's degree of emission limitation flows from the structure and
purpose of CAA section 111, which is to mitigate air pollution that is
reasonably anticipated to endanger public health or welfare. It
achieves this outcome by requiring source categories that cause or
contribute to dangerous air pollution to operate more cleanly. Unlike
the CAA's NAAQS-based programs, section 111 is not designed to reach a
level of emissions that has been deemed ``safe'' or ``acceptable'';
there is no air-quality target that tells states and sources when
emissions have been reduced ``enough.'' Rather, CAA section 111
requires affected sources to reduce their emissions to the level that
the EPA has determined is achievable through application of the best
system of emission reduction, i.e., to achieve emission reductions
consistent with the applicable presumptive standard of performance.
Consistent with the statutory purpose of requiring affected sources to
operate more cleanly, the EPA typically expresses presumptive standards
of performance as rate-based emission limitations (i.e., limitations on
the amount of a regulated pollutant that can be emitted per unit of
output, per unit of energy or material input, or per unit of time).
In the course of complying with a rate-based standard of
performance under a state plan, an affected source takes actions that
may or may not affect its ongoing emission reduction obligations. For
example, a source may take certain actions that remove it from the
source category, e.g., by switching fuel type or permanently ceasing
operations. Upon doing so, the source is no longer subject to the
emission guidelines. Or an affected source may choose to change its
operating characteristics in a way that impacts its overall mass of
emissions, e.g., by changing its utilization, in which case the source
is still required to reduce its emission rate consistent with cleaner
performance. In either instance, the changes in operation to one
affected source do not implicate the obligations of other affected
sources. Although changes to certain sources' operation may reduce
emissions from the source category, they do not absolve the remaining
affected EGUs from the statutory obligation to reduce their emission
rates consistent with the level that the EPA has determined is
achievable through application of the BSER. While state plans may, when
permitted by the applicable emission guidelines, allow affected sources
to translate their rate-based presumptive standards of performance into
mass limits and/or comply with their standards of performance in the
aggregate through averaging or trading, the fundamental statutory
requirement remains: the state plan must demonstrate that, even if
individual affected sources are not necessarily achieving their
presumptive rate-based standards of performance, the plan as a whole
must provide for the same level of emission reduction for the affected
EGUs as though they were. While states may choose to allow individual
sources to emit more or less than the degree of emission limitation
determined by the EPA, any compliance flexibilities must be designed to
ensure that their use does not erode the emission reduction benefits
that would result if each source was individually achieving its
presumptive standard of performance (after accounting for any use of
RULOF).
For rate-based averaging and trading, discussed in more detail in
sections X.D.2 and X.D.3 of this preamble, demonstrating an equivalent
level of emission reduction is relatively straightforward, as a rate-
based program inherently provides relatively stronger assurance of
equivalence with individual rate-based standards of performance. This
is due to the fact that the aggregate rate-based emission limitation
(for rate-based averaging) or rate-based standard of performance with
adjustment for compliance instruments (for rate-based trading) is
calculated based on both the emission output and gross generation
output (utilization) of the participating affected EGUs. In other
words., a rate-based compliance flexibility, such as a rate-based unit-
specific standard of performance, inherently adjusts for changes in
utilization and preserves the imperative to operate more cleanly. For
unit-specific mass-based compliance and mass-based trading,
demonstrating equivalent stringency is more complicated, as the use of
a mass limit or mass budget on its own may not guarantee that sources
are achieving emission reductions commensurate with operating more
cleanly. Thus the EPA is requiring that, in order to ensure that the
emission outcome that would be achieved through unit-specific rate-
based standards of performance are preserved, states must also include
a backstop emission rate limitation, or backstop rate, for affected
EGUs using a mass-based compliance flexibility, as discussed in more
detail in sections X.D.4 and X.D.5 of this preamble. In addition,
states employing a mass-based mechanism in their plans must show why
assumptions underlying the calculation of utilization for the purposes
of establishing a mass limit or mass budget are appropriately
conservative to ensure an equivalent level of emission reduction, as
discussed more in sections X.D.4 and X.D.5 of this preamble.
In sum, states wishing to employ compliance flexibilities in their
state
[[Page 39982]]
plans must demonstrate that the plan achieves at least equivalent
stringency with each source individually achieving its standard of
performance, bearing in mind the discussion and requirements in this
section, as well as the discussion and requirements in the following
sections specific to each type of mechanism. The EPA will review state
plan submissions that include compliance flexibilities to ensure that
they are consistent with CAA section 111's purpose of reducing
dangerous air pollution by requiring sources to operate more cleanly.
In order for the EPA to find a state plan ``satisfactory,'' that plan
must address each affected EGU within the state and demonstrate that
the plan overall achieves at least the level of emission reduction that
would result if each affected EGU was achieving its presumptive
standard of performance, after accounting for any application of RULOF.
b. Exclusion of Certain Affected EGUs From Compliance Flexibilities
While the use of compliance flexibilities such as emission trading,
averaging, and unit-specific mass-based compliance is generally
permissible under these emission guidelines, the EPA indicated in the
proposal that it may be appropriate for certain groups of sources to be
excluded from using these flexibilities in order to ensure an
equivalent level of emission reduction with each source individually
achieving its standard of performance. In the proposed emission
guidelines, the EPA expressed concerns about the use of compliance
flexibilities for several subcategories that have BSER determinations
of routine methods of operation and maintenance as well as those
sources for which states have invoked RULOF to apply a less stringent
standard of performance, as their inclusion may undermine the intended
level of emission reduction of the BSER for other facilities. The EPA
also questioned whether trading and averaging across subcategories
should be limited in order to maintain the stringency of unit-specific
compliance. Finally, the EPA questioned whether affected EGUs that
receive the IRC section 45Q tax credit for permanent sequestration of
CO2 may have an overriding incentive to maximize both the
application of the CCS technology and total electric generation,
leading to source behavior that may be non-responsive to the economic
incentives of a trading program.
In response to the request for comment on these concerns related to
the appropriateness of emission trading and averaging for certain
subcategories and for sources with a standard based on RULOF, the EPA
received mixed feedback. Some commenters agreed with the EPA's concerns
about these subcategories participating in trading and averaging and
that affected EGUs in these subcategories should be prevented from
participating in an emission trading or averaging program. However,
several commenters said that it was indeed appropriate to allow all
subcategories as well as sources with a standard of performance based
on RULOF to participate in trading and averaging and that the program
would still achieve an equivalent level of emission reduction, even if
those subcategories are of limited stringency.
In response to the request for comment on whether emission trading
and averaging should be allowed across subcategories in light of
concerns over differing levels of stringency for different
subcategories impacting overall achievement of an equivalent level of
emission reduction, the EPA also received mixed feedback. Some
commenters supported restricting trading and averaging across
subcategories because of concerns that EGUs in a subcategory with a
relatively higher stringency could acquire allowances from EGUs in a
subcategory with a relatively lower stringency in order to comply
instead of operating a control technology. Several commenters stated
that trading across subcategories need not be limited because, as long
as state plans are of an equivalent level of emission reduction,
emission trading and averaging would still require the overall
aggregate limit to be met.
Taking into consideration the comments on the proposed emission
guidelines as well as changes made to the subcategories in the final
emission guidelines, the Agency is finalizing the following
restrictions on the use of compliance flexibilities by certain
subcategories.
First, emission trading or averaging programs must not include
affected EGUs for which states have invoked RULOF to apply less
stringent standards of performance. The Agency believes that, because
RULOF sources have a standard of performance tailored to individual
source circumstances that is required to be as stringent as reasonably
practicable, these sources should not need further operational
flexibility and are also unlikely to be able to overperform to any
significant or regular degree. This means that their participation in
an emission trading or averaging program is, at best, unlikely to add
any value to the program (in terms of opportunity for overperformance)
or, at worst, may provide an inappropriate opportunity for other
sources subject to a relatively more stringent presumptive standard of
performance to underperform by obtaining compliance instruments from or
averaging their emission performance with affected EGUs that are
subject to a relatively less stringent standard of performance based on
RULOF. This outcome undermines the ability of the state plan to
demonstrate an equivalent level of emission reduction, as non-RULOF
sources would face a reduced incentive to operate more cleanly. In
addition, affected EGUs with a standard of performance based on RULOF
are prohibited from using unit-specific mass-based compliance under
these emission guidelines. This is due to the compounding uncertainty
regarding how states will use RULOF to particularize the compliance
obligations for an affected EGU and the future utilization of affected
EGUs that may be subject to RULOF. The RULOF provisions are used where
a particular EGU is in unique circumstances and may result in a less
stringent standard of performance based on the BSER technology, a less
stringent standard of performance based on a different control
technology, a longer compliance schedule, or some combination of the
three. The bespoke nature of compliance obligations pursuant to RULOF
makes it difficult for the EPA to provide principles for and for states
to design mass-based compliance strategies that ensure an equivalent
level of emission reduction. Additionally, as previously discussed,
there is a significant amount of uncertainty in the future utilization
of certain affected EGUs, including those with standards of performance
pursuant to RULOF. While there is no risk of implicating the compliance
obligation of other sources in unit-specific mass-based compliance, the
EPA believes that allowing RULOF sources to use unit-specific mass
compliance would pose a significant risk in undermining the stringency
of the state plan such that these sources may not be achieving the
level of emission reduction commensurate with cleaner performance.
Second, emission trading or averaging programs may not include
affected EGUs in the natural gas- and oil-fired steam subcategories.
The BSER determination and associated degree of emission limitation for
affected EGUs in these subcategories do not require any improvement in
emission performance and already offer flexibility to sources to
account for varying efficiency at different operating levels. As a
result, these sources are unlikely to be
[[Page 39983]]
responsive to an incentive towards overperformance, which means that
their participation in an emission trading or averaging program is
unlikely to add any value to the program (in terms of opportunity for
overperformance). In addition, the EPA is concerned that the
participation of these sources may undermine the program's equivalence
with the presumptive standards of performance, because other steam
sources, which have a relatively more stringent degree of emission
limitation, may be inappropriately incentivized to underperform by
obtaining compliance instruments from or averaging their emission
performance with affected EGUs in the natural gas- and oil-fired steam
subcategories. This outcome undermines the ability of the state plan to
demonstrate equivalent stringency by reducing the incentive for sources
to operate more cleanly. In addition, affected EGUs in the natural gas-
and oil-fired steam subcategories are prohibited from using unit-
specific mass-based compliance. While there is no risk of implicating
the compliance obligation of other sources in unit-specific mass-based
compliance, the EPA believes, as previously stated, there is already
sufficient flexibility offered to sources in the natural gas- and oil-
fired steam subcategories, as the basis for subcategorizing these
sources takes into account their varying efficiency at different
operating levels.
The EPA is allowing both coal-fired subcategories (both the medium-
and long-term) to participate in all types of compliance flexibilities,
within the parameters set by the EPA described in the following
sections. The Agency believes, and many commenters agreed, that
affected EGUs taking advantage of the IRC section 45Q tax credit may
still benefit from the operational flexibility provided by emission
trading and averaging, as well as unit-specific mass-based compliance.
The Agency also believes that overperformance among these sources is
possible and worth incentivizing through the use of compliance
flexibilities. Incentivizing overperformance can lead to innovation in
control technologies that, in turn, can lead to lower costs for, and
greater emissions reductions from, control technologies.
The EPA is not finalizing a restriction on trading or averaging
across subcategories for the two subcategories that are permitted to
participate in these flexibilities. This means that affected EGUs in
the medium-term coal-fired subcategory may trade or average their
compliance with affected EGUs in the long-term coal-fired subcategory.
With the aforementioned restrictions on participation in trading and
averaging, the EPA does not see a need to further restrict the ability
of eligible sources to trade or average with other sources.
2. Rate-Based Emission Averaging
The EPA proposed to permit states to incorporate rate-based
averaging into their state plans under these emission guidelines. In
general, rate-based averaging allows multiple affected EGUs to jointly
meet a rate-based standard of performance. The scope of such averaging
could apply at the facility level (i.e., units located within a single
facility) or at the owner or operator level (i.e., units owned by the
same utility). A description of and responses to comments received on
rate-based averaging can be found at the end of this subsection.
As discussed in the proposed emission guidelines, averaging can
provide potential benefits to affected sources by allowing for more
cost effective and, in some cases, more straightforward compliance.
First, averaging offers some flexibility for owners or operators to
target cost effective reductions at certain affected EGUs. For example,
owners or operators of affected EGUs might target installation of
emission control approaches at units that operate more. Second,
averaging at the facility level provides greater ease of compliance
accounting for affected EGUs with a complex stack configuration (such
as a common- or multi-stack configuration). In such instances, unit-
level compliance involves apportioning reported emissions to individual
affected EGUs that share a stack based on electricity generation or
other parameters; this apportionment can be avoided by using facility-
level averaging.
The EPA is finalizing a determination that rate-based averaging is
permissible for affected EGUs in the medium- and long-term coal-fired
subcategories. The scope of rate-based averaging may be at the facility
level or at the owner/operator level within the state, as these are the
circumstances under which rate-based averaging can provide significant
benefits, as identified above, with minimal implementation complexity.
Above this level (i.e., across owner/operators or at the state or
interstate level), the EPA has determined that a rate-based compliance
flexibility must be implemented through rate-based trading, as
described in section X.D.3 of this preamble. The EPA is establishing
this limitation on the scope of averaging because it believes that the
level of complexity associated with utilities, independent power
producers, and states attempting to coordinate the real-time compliance
information needed to assure that either all affected EGUs are meeting
their individual standard of performance, or that a sufficient number
of affected EGUs are overperforming to allow operational flexibility
for other affected EGUs such that the aggregate standard of performance
is being achieved, would curtail transparency and limit states', the
EPA's, and stakeholders' abilities to track timely compliance. For
example, dozens of units trying to average their emission rates would
require owners or operators from different utilities and independent
power producers to share operating and emissions data in real time.
Thus, due to likely limitations on the timely availability of
compliance-related information across owners and operators and across
states, which is necessary to ensure aggregate compliance, the EPA
believes that it is appropriate to limit the scope of rate-based
averaging to the facility level or the owner/operator level within one
state in order to provide greater compliance certainty and thus better
demonstrate an equivalent level of emission reduction.
Demonstrating equivalence with unit-specific implementation of
rate-based standards of performance in a rate-based averaging program
is straightforward. A state would need to specify in its plan the group
of affected EGUs participating in the averaging program that will
demonstrate compliance on an aggregate basis, the unit-specific rate-
based presumptive standard of performance that would apply to each
participating affected EGU, and the aggregate compliance rate that must
be achieved for the group of participating affected EGUs and how that
aggregate rate is calculated, as described below. For states
incorporating owner/operator-level averaging, the state plan would also
need to include provisions that specify how the program will address
any changes in the owner/operator for one or more participating
affected EGUs during the course of program implementation to ensure
effective implementation and enforcement of the program. Such
provisions should be specified upfront in the plan and be self-
executing, such that a state plan revision is not required to address
such changes.
To ensure an equivalent level of emission reduction with
application of individual rate-based standards of performance, the EPA
is requiring that the weighting of the aggregate compliance rate is
done on an output basis; in other words, participating affected EGUs
must demonstrate
[[Page 39984]]
compliance through achievement of an aggregate CO2 emission
rate that is a gross generation-based weighted average of the required
standards of performance of each of the affected EGUs that participate
in averaging. Such an approach is necessary to ensure that the
aggregate compliance rate is representative of the unit-specific
standards of performance that apply to each of the participating
affected EGUs. Commenters were generally supportive of this method of
calculating an aggregate rate for a group of sources participating in
averaging. The Agency emphasizes that only affected EGUs are permitted
to be included in the calculation of an aggregate rate-based standard
of performance as well as in an aggregate compliance demonstration of a
rate-based standard of performance.
Comment: Commenters supported the use of rate-based averaging on
the grounds that it can provide operational flexibility to affected
EGUs as well as the opportunity for owners and operators to optimize
control technology investments. Many commenters supported averaging at
the facility- and owner/operator-level as well as on a statewide or
interstate basis.
Response: The EPA believes that rate-based trading can provide some
additional operational flexibility and is finalizing that rate-based
averaging is permissible at the facility- and owner/operator-level for
affected EGUs in the medium- and long-term coal-fired subcategories.
However, for reasons discussed above, the EPA believes that rate-based
trading, rather than rate-based averaging, should be implemented where
a state would like to implement a rate-based compliance flexibility at
a state or interstate basis.
3. Rate-Based Emission Trading
The EPA proposed to permit states to incorporate rate-based trading
into their state plans under these emission guidelines. In general, a
rate-based trading program allows affected EGUs to trade compliance
instruments that are generated based on their emission performance. A
description of and responses to comments on rate-based trading can be
found at the end of this subsection.
The EPA notes that, like rate-based averaging, rate-based trading
can provide some flexibility for owners or operators to target cost
effective reductions at specific affected EGUs, but can heighten the
flexibility relative to averaging by further increasing the number of
participating affected EGUs. In addition, emission trading can provide
incentive for overperformance.
The proposed emission guidelines described how rate-based trading
could work in this context. First, the EPA discussed how it expects
states to denote the tradable compliance instrument in a rate-based
trading programs as one ton of CO2. A tradable compliance
instrument denominated in another unit of measure, such as a MWh, is
not fungible in the context of a rate-based emission trading program. A
compliance instrument denominated in MWh that is awarded to one
affected EGU most likely does not represent an equivalent amount of
emissions credit when used by another affected EGU to demonstrate
compliance, as the CO2 emission rates (lb CO2/
MWh) of the two affected EGUs are likely to differ.
Each affected EGU is required under these emission guidelines to
have a particular standard of performance, based on the degree of
emission limitation achievable through application of the BSER, with
which it would have to demonstrate compliance. Under a rate-based
trading program, affected EGUs performing at a CO2 emission
rate below their standard of performance would be awarded compliance
instruments at the end of each calendar year denominated in tons of
CO2. The number of compliance instruments awarded would be
equal to the difference between their standard of performance
CO2 emission rate and their actual reported CO2
emission rate multiplied by their gross generation in MWh. Affected
EGUs demonstrating compliance through a rate-based averaging program
that are performing worse than their standard of performance would be
required to obtain and surrender an appropriate number of compliance
instruments when demonstrating compliance, such that their demonstrated
CO2 emission rate is equivalent to their rate-based standard
of performance. Transfer and use of these compliance instruments would
be accounted for in the numerator (sum of total annual CO2
emissions) of the CO2 emission rate as each affected EGU
performs its compliance demonstration. Compliance would be demonstrated
for an affected EGU based on its reported CO2 emission
performance (in lb CO2/MWh) and, if necessary, the surrender
of an appropriate number of tradable compliance instruments, such that
the demonstrated lb CO2/MWh emission performance is
equivalent to (or lower than) the rate-based standard of performance
for the affected EGU.
The EPA is finalizing a determination that rate-based trading is
permissible for affected EGUs in the medium- and long-term coal-fired
subcategories. The Agency notes, as previously discussed, that rate-
based trading (rather than averaging) must be utilized if the state
wishes to establish a statewide or interstate rate-based compliance
flexibility, in order to ensure compliance and equivalent stringency.
For similar reasons, rate-based trading should also be utilized in lieu
of owner/operator-level averaging when an owner/operator wishes to use
a rate-based compliance flexibility for a group of its units that are
located in more than one state.
Demonstrating equivalence with unit-specific implementation of
rate-based standards of performance in a rate-based trading program is
relatively straightforward. States would need to specify in their plans
the affected EGUs participating in the trading program and their
individual standards of performance. Under the method of rate-based
trading described in this section, a compliance demonstration would be
done for each participating affected EGU based on a combination of the
reported emission performance and, if relevant, the surrender of
compliance instruments. In addition, the EPA is requiring that the
compliance instrument be denominated as one ton of CO2
(rather than another unit such as MWh). The Agency believes this
requirement is necessary to ensure an equivalent level of emission
reduction as application of individual rate-based standards of
performance.
An additional aspect of demonstrating equivalence is ensuring that
the program achieves and maintains an equivalent level of emission
reduction with standards of performance over time, which is much more
certain in a rate-based trading program than in a mass-based program.
Unlike mass-based trading programs, under which states must make
assumptions about units' future utilization that may become inaccurate
as those units' operations shift over time, rate-based trading programs
do not rely on utilization assumptions. Utilization is already
accounted for by default in a rate-based trading program. Thus, while
mass-based compliance flexibilities require additional design features
to ensure the continued accuracy of assumptions about utilization and
thus emission limits or budgets over time, such features are not
necessary in a rate-based trading program.
Comment: While commenters broadly supported the use of rate-based
emission trading under these emission guidelines, as it provides
operational flexibility to affected EGUs, some commenters expressed
concern that
[[Page 39985]]
rate-based trading could lead to an absolute increase in emissions.
Response: The EPA notes that, as a general matter, CAA section 111
reduces emissions of dangerous air pollutants by requiring affected
sources to operate more cleanly. Under the construct of these emission
guidelines, so long as a rate-based trading program is appropriately
designed to maintain the level of emission reduction that would be
achieved through unit-specific, rate-based standards of performance, it
would be consistent with CAA section 111.
4. Unit-Specific Mass-Based Compliance
Although the EPA discussed mass-based trading in the proposed
emission guidelines, it did not specifically address whether states may
include a related flexibility, unit-specific mass-based compliance, in
their plans. Several commenters supported mass-based mechanisms,
including both unit-specific mass-based compliance and mass-based
trading. A description of and responses to comments on unit-specific
mass-based compliance can be found at the end of this subsection.
The EPA's CAA section 111 implementing regulations generally permit
states to include mass-based limits in their plans, see 40 CFR
60.21a(f), subject to the requirement that standards of performance
must be no less stringent than the presumptive standards of performance
in the corresponding emission guidelines. 40 CFR 60.24a(c). However,
the EPA has significant concerns about the use of unit-specific mass-
based compliance in the context of these emission guidelines and the
ability of states using this mechanism to ensure that such use will
result in the same level of emission reduction that would be achieved
by applying the rate-based standard of performance. These concerns
arise both from the particular focus of these emission guidelines on
emission reduction strategies that result in cleaner performance of
affected EGUs, and the inherent uncertainty in predicting the
utilization of affected EGUs during the compliance period, especially
given the long lead times provided.
Therefore, while the EPA is allowing states to include unit-
specific mass-based compliance in their plans for affected coal-fired
EGUs in the medium- and long-term subcategories, it is also requiring
states to use a backstop emission rate in conjunction with the mass-
based compliance demonstration. As discussed in section X.D.1 of this
preamble, the EPA believes the use of a backstop rate is consistent
with the focus on achieving cleaner performance. CAA section 111
requires the mitigation of dangerous air pollution, which is generally
achieved under this provision by requiring affected sources to operate
more cleanly. Thus, standards of performance are typically expressed as
a rate. In these emission guidelines, in particular, the BSERs for
affected EGUs are control technologies and other systems of emission
reduction that reduce the amount of CO2 emitted per unit of
electricity generation. The EPA is not precluding states from
translating those unit-specific rate-based standards of performance
into a mass-based limit (for unit-specific mass-based compliance) or
budget (for emission trading). However, in order to ensure that the
emission reductions required under CAA section 111 are achieved, mass-
based limits or budgets must be accompanied by a backstop rate for
purposes of demonstrating compliance. In addition, for coal-fired EGUs
in the medium-term coal-fired subcategory in particular, it is critical
that states' assumptions about future utilization do not result in
inaccurate mass-based limits or budgets that allow units to emit more
than they would be permitted to under unit-specific, rate-based
compliance.
The EPA is finalizing a presumptively approvable unit-specific
mass-based compliance approach for affected EGUs in the long-term coal-
fired subcategory, including a methodology for the applicable backstop
rate, but is not finalizing a presumptively approvable approach for
affected EGUs in the medium-term coal-fired subcategory. As explained
below, the EPA has not been able to determine a unit-specific mass-
based compliance mechanism for medium-term coal-fired EGUs that would
ensure that the mass limit is no less stringent than the presumptive
standard of performance under these emission guidelines.
In general, unit-specific mass-based compliance establishes a
budget of allowable mass emissions (a mass limit) for an individual
affected EGU based on the degree of emission limitation defined by its
subcategory and a specified level of anticipated utilization. Standards
of performance would be provided in the form of mass limits in tons of
CO2 for each individual affected EGU, and compliance would
be demonstrated through surrender of allowances, with each allowance
representing a permit to emit one ton of CO2. Unlike mass-
based emission trading, under a unit-specific mass compliance
mechanism, these allowances would not be tradable with other affected
EGUs. To demonstrate compliance, the affected EGU would be required to
surrender allowances in a number equal to its reported CO2
emissions during each compliance period.
As detailed in section VII.C.1.a.i(B)(7), for affected coal-fired
EGUs in the long-term subcategory that are installing CCS, considering
the potential impacts of variable load, startups, and shutdowns, 90
percent CO2 capture is, in general, achievable over the
course of a year. However, the EPA believes unit-specific mass-based
compliance could provide some benefit by affording long-term affected
coal-fired EGUs that adopt this mechanism even greater operational
flexibility.\948\ For example, if an affected EGU encounters challenges
related to the start-up of the CCS technology or needs to conduct
maintenance of the capture equipment, unit-specific mass-based
compliance would provide a path for the affected EGU to continue
operating. At the same time, unit-specific mass-based compliance
coupled with a backstop rate would generally ensure that units operate
more cleanly and that the required level of emission reduction is
achieved. As explained in more detail below, the EPA's confidence
regarding the equivalent stringency of this mass-based compliance
approach for units in the long-term subcategory depends on the Agency's
confidence in the likely utilization of a unit that has adopted
emissions controls--in this case, CCS.
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\948\ States may also elect to include the short-term
reliability mechanism described in section XII.F.3.a in their plans
to address grid emergency situations.
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For affected EGUs in the long-term coal-fired subcategory, the EPA
is providing a presumptively approvable approach to unit-specific mass-
based compliance. To establish the presumptively approvable mass limit,
the presumptively approvable rate (as described in section X.C.1.b.i of
this preamble) would be multiplied by a level of gross generation
(i.e., utilization level) corresponding to an annual capacity factor of
80 percent, which is the capacity factor used for the BSER analysis
(see section VII.C.1.a.ii of this preamble) and represents expected
utilization based on the incentive provided by the IRC section 45Q tax
credit. In addition, under this approach, affected EGUs would need to
meet a backstop emission rate, expressed in lb CO2 per MWh
on a gross basis, equivalent to a reduction relative to baseline
emission performance of 80 percent, on an annual calendar-year basis.
The EPA believes this backstop rate represents a reasonable level of
operational flexibility for affected EGUs
[[Page 39986]]
in the long-term subcategory, and it could provide flexibility for
sources to employ other technologies (e.g., membrane and chilled
ammonia capture technologies) that can achieve a similarly high degree
of emission limitation to CCS with amine-based capture. States may
deviate from this approach (however, as previously discussed, the
approach must include a backstop rate) and deviations will be reviewed
to ensure consistency with the statute and this rule when the EPA
reviews the state plan. For example, states may wish to use an assumed
utilization level of greater than 80 percent to establish a mass limit.
In reviewing such an approach for reasonableness, the EPA would
consider, among other things, whether an affected EGU's capacity factor
has historically been greater than 80 percent for any continuous 8
quarters of data. The EPA would review the supporting data and
resulting mass limit for consistency with the statute. The EPA has
confidence that the presumptively approvable approach achieves an
equivalent level of emission reduction as the implementation of the
individual presumptive standard of performance because of the high
degree of stringency associated with this subcategory as well as the
45Q tax credit, which incentivizes units to maximize capture of
CO2 as well as the utilization of the affected EGU.
On the other hand, the EPA does not have the same confidence in a
mass-based approach to unit-specific compliance for the medium-term
coal-fired subcategory for two reasons: the uncertainty in the
utilization of these affected EGUs and the relatively lower stringency
of the subcategory (i.e., 16 percent reduction relative to baseline
emission performance), particularly as compared to the long-term
subcategory. The EPA has not been able to develop a workable approach
to mass-based compliance for these units that both preserves the
stringency of the presumptive standard of performance and results in an
implementable program for affected EGUs.
First, there are significant challenges in selecting an appropriate
utilization assumption for the purposes of generating a mass limit for
affected EGUs in the medium-term subcategory. When setting the mass
limit for a future time period, as would occur in a state plan under
these emission guidelines, assumptions about the source's anticipated
level of utilization must be made. Estimating future utilization of
affected EGUs in the medium-term subcategory is subject to a
significant degree of uncertainty, driven by sector-wide factors
including changes in relative fuel prices, new incentives for
technology deployment provided by the IIJA and the IRA, and increasing
electrification, as well as EGU-specific factors related to its age
and/or operating characteristics. As described in the Power Sector
Trends TSD, coal-fired EGUs tend to become less efficient as they age,
which may impact utilities' investment decisions and the utilization of
these EGUs. In addition, affected EGUs in this subcategory are unlikely
to be earning the IRC section 45Q tax credit, meaning they lack an
incentive to maximize both utilization and control of emissions beyond
what is required by the subcategory.
The accuracy of this estimate of utilization is critical to
maintaining the environmental integrity established by unit-specific,
rate-based compliance under these emission guidelines. If a state
assumes a level of utilization that is higher than an affected EGU
actually operates during the compliance period, the resulting mass
limit will be non-binding, i.e., may not reflect any emission
reductions relative to what the unit would have emitted in the absence
of these emission guidelines. In this case a backstop emission rate
helps, but the unit would become subject to a de facto less-stringent
standard of performance. This result does not preserve environmental
integrity consistent with CAA section 111(a)(1). Conversely, assuming a
level of utilization for the purpose of setting a mass limit that is
lower than an affected EGU actually operates during the compliance
period maintains the level of emission reduction of unit-specific,
rate-based implementation but may have unintended effects on
operational flexibility. Thus, the EPA believes that in many, if not
most circumstances it will not be possible for states to accurately
predict the future utilization of medium-term affected EGUs.
Second, the EPA notes that the relatively lower stringency of the
subcategory further complicates the calculation of an appropriate mass
limit. Under mass-based compliance, the quantity of emission reductions
that corresponds to a 16 percent reduction in CO2 emission
rate is a relatively small reduction in terms of tons of
CO2. This relatively small reduction is likely to be
subsumed by the uncertainty inherent in predicting the utilization of
an affected EGU for purposes of determining its mass limit. That is, an
EGU in the medium-term subcategory that assumes future utilization
consistent with its historical baseline but reduces its emission rate
by 16 percent would achieve, on paper at least, an emission reduction
of 16 percent. However, if its utilization during the compliance period
is more than 16 percent lower than it was in the past, the EGU using a
mass-based compliance approach would face a reduced or completely
eliminated obligation to improve its emission performance. In this
case, mass-based compliance results in a lower level of emission
reduction than unit-specific rate-based compliance. While this
phenomenon is not likely to occur for long-term coal-fired affected
EGUs given the much higher degree of stringency of the rate-based
emission limitation and the greater certainty in future utilization,
the EPA believes it would be widespread amongst medium-term affected
EGUs.
Thus, the EPA is not providing a presumptively approvable approach
for unit-specific mass-based compliance for affected EGUs in the
medium-term coal-fired subcategory. However, it is also not prohibiting
states from, in their discretion, allowing the use of unit-specific
mass-based compliance. For such use to be approvable in state plans it
must meet two requirements. First, as previously noted in section X.D.1
of this preamble, the state must apply a backstop rate in conjunction
with a mass limit for the purposes of demonstrating compliance. As a
starting point, states could consider basing their backstop rate for
medium-term affected EGUs on the percentage reduction from the degree
of emission limitation used for the presumptively approvable backstop
rate for the long-term coal-fired subcategory, i.e., the 80 percent
reduction relative to baseline emission performance is approximately
90.5 percent of the 88.4 percent degree of emission limitation.
Applying that to the degree of emission limitation for the medium-term
coal-fired subcategory is 14.5 percent, so the backstop rate, expressed
in lb CO2 per MWh on a gross basis, could be set as a 14.5
percent reduction relative to baseline emission performance on an
annual calendar-year basis. Second, as described in section X.D.1 of
this preamble, states must demonstrate that their plan would achieve an
equivalent level of emission reduction as the application of unit-
specific, rate-based standards of performance, including showing how
the mass limit has been calculated and the basis for any assumptions
made (e.g., about utilization). As explained in this section, the EPA
believes it will be very difficult for states to accurately predict the
future utilization of these units, which substantially increases the
risk of establishing a mass limit that
[[Page 39987]]
does not ensure at least an equivalent level of emission reduction. The
EPA will therefore apply a high degree of scrutiny to assumptions made
about the utilization of affected EGUs employing this flexibility in
state plans. Only state plans that demonstrate that use of compliance
flexibilities will not erode the emission reductions required under
these emission guidelines are approvable.
Comment: Commenters were generally supportive of the use of mass-
based compliance mechanisms (both unit-specific and aggregate
mechanisms such as emission trading) for these emission guidelines.
Commenters said that mass-based compliance can help ensure
environmental outcomes while also allowing sources to cycle,
incorporate variable resources, and respond to grid conditions.
Response: The EPA is finalizing that mass-based compliance
mechanisms are permissible when they assure an equivalent level of
emission reduction with each source individually achieving its standard
of performance, subject to the parameters described by the EPA in this
preamble. For unit-specific mass-based compliance, affected EGUs in the
medium- and long-term coal-fired subcategories may demonstrate
compliance with their standards of performance through a mass limit.
The EPA believes unit-specific mass-based compliance may offer some
additional operational flexibility to states and affected EGUs, which
could include allowing for cycling and incorporating variable
resources. The EPA notes that sources must still be in compliance with
the requisite backstop rate.
Comment: Many commenters expressed support for mass-based
compliance mechanisms on the grounds that it facilitates calibration
with existing state programs affecting the same sources that are
affected under these emission guidelines.
Response: The EPA acknowledges that states may find it more
straightforward to compare emission reduction obligations under these
emission guidelines and existing state programs by using mass-based
compliance mechanisms for state plans under these emission guidelines.
However, the EPA notes that mass-based compliance mechanisms, including
unit-specific mass-based compliance, are only available to certain
sources affected by these emission guidelines, as described in this
section of the preamble, which may be a smaller universe of sources
than are affected by existing state programs. State plans must ensure
an equivalent level of emission reduction from the sources that are
affected sources under these emission guidelines. That is, states
cannot rely on or account for emission reductions occurring at non-
affected sources.
Section X.D.8 of this preamble discusses more considerations
related to the relationship between the inclusion of compliance
flexibilities in state plans under these emission guidelines and
existing state programs.
Comment: Many commenters requested presumptively approvable mass-
based standards of performance.
Response: As discussed above, the EPA is finalizing a presumptively
approvable unit-specific mass-based compliance approach for units in
the long-term coal-fired subcategory that includes a backstop rate to
ensure an equivalent level of emission reduction. The EPA emphasizes
that states should take into account the discussions of stringency in
section X.B and of demonstrating equivalence in section X.D.1 of this
document, as well as guidance in each subsection on particular
compliance flexibilities in considering mass-based compliance
approaches that deviate from the presumptively approvable method or for
sources for which the EPA is not providing a presumptively approvable
approach.
5. Mass-Based Emission Trading
The EPA proposed that states would be permitted to incorporate
mass-based trading into their state plans under these emission
guidelines. While several commenters supported the use of mass-based
emission trading, as with unit-specific mass-based compliance, the EPA
has significant concerns about states' ability using this mechanism to
maintain an equivalent level of emission reduction to unit-specific,
rate-based standards of performance. A description of and responses to
comments on mass-based trading can be found at the end of this
subsection.
Under these final emission guidelines, the EPA is allowing states
to include mass-based emission trading for affected coal-fired EGUs in
the medium- and long-term subcategories in their plans. The same
requirements and caveats discussed in section X.D.4 of this preamble
above apply to the respective subcategories as for unit-specific mass-
based compliance. Specifically, the EPA is requiring the use of a unit-
specific backstop rate in conjunction with the mass-based compliance
demonstration, which is necessary for consistency with the purpose of
these emission guidelines to achieve the emission reductions required
under CAA section 111(a)(1) through cleaner emission performance. The
Agency similarly believes it will be very difficult for states to
design mass-based trading programs that include affected EGUs in the
medium-term coal-fired subcategory and that maintain the level of
emission reduction that would be achieved under unit-specific
compliance with the presumptive standards of performance.
In general, a mass-based trading program establishes a budget of
allowable mass emissions for a group of affected EGUs, with tradable
instruments (typically referred to as ``allowances'') issued to
affected EGUs in the amount equivalent to the mass emission budget. To
establish a mass budget under these emission guidelines, states would
use the rate-based standard of performance and an assumed level of
utilization for each participating affected EGU, and sum the resulting
individual mass limits to an aggregate mass budget. Additionally,
states would need to specify in the plan how allowances would be
distributed to participating affected EGUs. Each allowance would
represent a tradable permit to emit one ton of CO2, with
affected EGUs required to surrender allowances at the end of the
compliance period in a number determined by their reported
CO2 emissions. Total emissions from all participating
affected EGUs should be no greater than the total mass budget. In
addition, each participating affected EGU would need to demonstrate
compliance with the unit-specific backstop rate.
The EPA sees similar potential benefits related to operational
flexibility of mass-based emission trading as with unit-specific mass-
based compliance, discussed in section X.D.4 of this preamble. These
benefits could be heightened by having a larger pool of allowances
available to affected EGUs. In addition, the EPA notes that emission
trading can provide incentive for overperformance.
While there is indeed the potential for heightened benefits from
mass-based emission trading due to a larger pool of allowances
resulting from the inclusion of multiple sources, the EPA believes that
there is also a heightened risk that the mass budget will not be
appropriately calculated due to the compounding uncertainty resulting
from multiple participating sources. As noted in section X.D.4 of this
preamble, projecting the utilization of affected EGUs has become
increasingly challenging, driven by changes in technology, fuel prices,
and electricity demand. In generating a mass budget, assumptions about
utilization must be made for each participating source, which magnifies
the risk, particularly
[[Page 39988]]
for affected EGUs in the medium-term coal-fired subcategory, that an
improper assumption about utilization for one affected EGU implicates
the compliance obligation of other affected EGUs. Based on the
understanding that a trading program that ensures the level of emission
reduction of unit-specific, rate-based compliance under these emission
guidelines would necessarily have to be designed with highly
conservative utilization assumptions, the EPA is not providing a
presumptively approvable approach for mass-based trading. The EPA
additionally does not believe a presumptively approvable mass-based
trading approach is warranted because, as noted in the introduction to
this section, there are fewer sources covered by the final emission
guidelines than the proposed emission guidelines, which may limit
interest in and the utility of the use of mass-based trading for these
emission guidelines.
The EPA is not prohibiting states from developing their own
approaches to mass-based trading under these emission guidelines;
however, they must apply a unit-specific backstop rate for all
participating affected EGUs (see section X.D.4 of this preamble for a
discussion of the backstop rate under unit-specific mass-based
compliance), and they must demonstrate, as described in section X.D.1
of this preamble, that their plan would achieve an equivalent level of
emission reduction as the application of individual rate-based
standards of performance, including showing how the mass limit has been
calculated and the basis for any assumptions made (e.g., about
utilization). As with unit-specific mass-based compliance, the EPA will
apply a high degree of scrutiny to assumptions made about the
utilization of affected EGUs participating in a mass-based trading
program in state plans. States must also specify the structure and
purpose of any other trading program design feature(s) (e.g., mass
budget adjustment mechanism) and how they impact the demonstration of
an equivalent level of emission reduction.
Comment: Many commenters supported the use of mass-based trading
under these emission guidelines. Commenters stated that because many
states are familiar with the mechanism, having used it for other
pollutants in this sector or, in the case of some existing state
programs, for CO2, it would be easy to employ in the context
of these emission guidelines and provide needed flexibility. In
addition, commenters cited ensuring reliability as a motivation for
using mass-based trading.
Response: While the EPA is finalizing that mass-based trading is
permissible under these emission guidelines for affected EGUs in the
medium- and long-term coal-fired subcategories, the EPA believes that
some of the flexibility desired by commenters is addressed by other
features of and changes made to the final emission guidelines, as
described in the beginning of section X.D of this preamble. Despite
familiarity on the part of states and sources with mass-based trading
programs, the EPA is concerned that the unique circumstances of the
EGUs affected by these final emission guidelines, including uncertainty
over their future utilization as well as the relatively lower
stringency of the medium-term coal-fired subcategory, pose a challenge
for states in demonstrating an equivalent level of emission reduction
of mass-based trading programs to the application of individual rate-
based standards.
Comment: Some commenters expressed concern with whether and how
mass-based trading would achieve and sustain the emission performance
identified in the determination of BSER.
Response: The EPA shares these concerns, and for that reason is
requiring the use of a unit-specific backstop rate in conjunction with
mass-based compliance flexibilities, including mass-based trading. The
EPA has also described its concerns over states' ability to estimate
future utilization and will thus apply a high degree of scrutiny to
assumptions made about the utilization of affected EGUs participating
in mass-based trading in state plans.
6. General Emission Trading and Averaging Program Implementation
Features
As noted in the proposed emission guidelines, states would need to
establish the procedures and systems necessary to implement and enforce
an emission averaging or trading program, whether it is rate-based or
mass-based, if they elect to incorporate such flexibilities into their
state plans. This would include, but is not limited to, establishing
the mechanics for demonstrating compliance under the program (e.g.,
surrender of compliance instruments as necessary based on monitoring
and reporting of CO2 emissions and generation); establishing
requirements for continuous monitoring and reporting of CO2
emissions and generation; and developing a tracking system for tradable
compliance instruments. The EPA requested comment on whether there was
interest in capitalizing on the existing trading program infrastructure
developed by the EPA for other trading programs, and some states and
one utility expressed support for states' ability to use EPA's
allowance management system for such programs. In addition to providing
such resources for regional and national emission trading and averaging
programs, the EPA has also provided technical support and resources to
various non-EPA state and regional emission trading programs. In the
event states choose to create emission averaging or trading programs
under these emission guidelines, the EPA can provide technical support
for such programs, including through the use of the Agency's existing
trading program infrastructure, and is available to consult with states
during the plan development process about the appropriateness of using
such resources, such as the EPA's allowance management system, based on
the design of state programs.
States may also need to consider how to handle differing compliance
dates for affected EGUs in an emission averaging or trading program,
given that under these emission guidelines the date when standards of
performance apply varies depending on the subcategory for the affected
EGU. The most straightforward way to address this, and which commenters
supported, is to initially only include those sources with a compliance
date of January 1, 2030, and then subsequently add sources into the
program (and thus factor them into the aggregate standard of
performance that must be achieved in the case of rate-based averaging
or mass-based budget in the case of mass-based compliance approaches)
at the start of the first year in which their standard of performance
applies.
Another topic that states incorporating emission averaging or
trading would need to consider is whether to provide for banking of
tradable compliance instruments (hereafter referred to as ``allowance
banking,'' although it is relevant for both mass-based and rate-based
trading programs). Allowance banking has potential implications for a
trading program's ability to maintain the requisite level of emission
reduction of the standards of performance. The EPA recognizes that
allowance banking--that is, permitting allowances that remain unused in
one control period to be carried over for use in future control
periods--may provide incentives for earlier emission reductions,
promote operational flexibility and planning, and facilitate market
liquidity. Many commenters supported allowing banking for these
reasons. However, the
[[Page 39989]]
EPA has observed that unrestricted allowance banking from one control
period to the next (absent provisions that adjust future control period
budgets to account for banked allowances) may result in a long-term
allowance surplus that has the potential to undermine a trading
program's ability to ensure that, at any point in time, the affected
sources are achieving the required level of emission performance. In
the Good Neighbor Plan's trading program provisions, for example, the
EPA implemented an annual allowance bank recalibration to prevent
allowance surpluses from accumulating and adversely impacting program
stringency.\949\ While the requirement to include a backstop rate for
mass-based compliance flexibilities can mitigate some concerns that
unrestricted allowance banking will undermine the program's calibration
towards achieving emission reductions through cleaner performance, the
EPA urges that states considering allowing trading also consider
restricting allowance banking (whether all or only a portion) in order
to ensure that a program continues to be calibrated towards equivalent
stringency with individual rate-based standards of performance, which
several commenters did support.
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\949\ Federal ``Good Neighbor Plan'' for the 2015 Ozone National
Ambient Air Quality Standards, 88 FR 36654 (June 5, 2023). Under the
allowance bank recalibration provisions, EPA will recalibrate the
``Group 3'' allowance bank for the 2024-2029 control periods to meet
the target bank level of 21 percent of the sum of the state emission
budgets for that control period. For control periods 2030 and later,
the target bank level is 10.5 percent of the sum of the state
emission budgets. If the overall bank is less than the target bank
level for a given control period, then no bank recalibration will
occur for that control period.
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Comment: Many commenters expressed the need for expanding the state
plan submission timeline beyond 24 months to allow more time to design
emission trading and averaging programs.
Response: As discussed in section X.E.2 of this preamble, the EPA
is finalizing a 24-month state plan development timeframe. Because
there are significantly fewer sources covered under the final emission
guidelines and because the EPA is restricting certain subcategories
from using compliance flexibilities such as emission averaging and
trading and unit-specific mass-based compliance, the EPA believes 24
months is a reasonable amount of time to develop state plans, including
time necessary to develop compliance flexibility approaches. Moreover,
the EPA is offering a presumptively approvable approach to unit-
specific mass-based compliance for affected EGUs in the long-term coal-
fired subcategory, which can further simplify the process for
developing compliance approaches in state plans.
7. Interstate Emission Trading
In the proposed emission guidelines, the EPA requested comment on
whether, and under what circumstances or conditions, to allow
interstate emission trading under these emission guidelines. Given the
interconnectedness of the power sector and given that many utilities
and power generators operate in multiple states, interstate emission
trading may increase compliance flexibility. The EPA also took comment
on whether the scope of rate-based averaging should be limited to a
certain level of geographic aggregation (i.e., intrastate but not
interstate).
Many commenters expressed support for interstate trading and
averaging, arguing that it further augments the flexibility offered by
these mechanisms. Because electricity markets are often operated on an
interstate basis, commenters stated that interstate trading and
averaging would facilitate better electricity market planning. In
particular, some commenters noted that interstate programs would also
allow for better grid reliability planning across areas with regional
planning entities.
While the EPA is finalizing a determination that states can
incorporate both rate- and mass-based interstate emission trading
programs into their state plans, the EPA has significant stringency-
related and logistical concerns about the use of interstate emission
trading for these particular emission guidelines. For mass-based
trading in particular, the EPA has concerns that further increasing the
number of sources participating in the program heightens the risk that
the mass budget will not be appropriately calculated due to the
uncertainty in estimating future utilization of affected EGUs, thus
inhibiting the ability of states to demonstrate that their program
achieves an equivalent level of emission reduction. This concern is
somewhat alleviated for rate-based compliance flexibilities, but the
EPA notes that states that wish to implement such flexibilities on an
interstate basis should do so through rate-based trading, as discussed
in section X.D.2. Interstate trading programs must adhere to the same
requirements described in section X.D.1 and must demonstrate
equivalence of the program for all participating affected EGUs.
For interstate emission trading programs to function successfully,
all participating states would need to, at a minimum, use the same form
of trading and have consistent design elements and identical trading
program requirements. Each state participating in an interstate trading
program would need to submit their own individual state plan, subject
to the state plan component and submission requirements described in
section X.E, but the states would coordinate their individual plan
provisions addressing the interstate trading program. Additionally,
each state plan would need provisions to ensure that affected EGUs
within their state are in compliance taking into account the actions of
affected EGUs participating in the interstate trading program in other
states. The EPA would need all state plan submissions that incorporate
interstate emission trading before evaluating any of the individual
state plans in order to ensure consistency among all participating
states. The EPA is willing to provide technical assistance to states
during the state plan development process about the use of interstate
emission trading, but notes that states may need to coordinate their
individual state plan submissions among different EPA regions.
8. Relationship to Existing State Programs
As described in the proposed emission guidelines, the EPA
recognizes that many states have adopted policies and programs (with
both a supply-side and demand-side focus) under their own authorities
that have significantly reduced CO2 emissions from EGUs,
that these policies will continue to achieve future emission
reductions, and that states may continue to adopt new power sector
policies addressing CO2 emissions. States have exercised
their power sector authorities for a variety of purposes, including
economic development, energy supply and resilience goals, conventional
and GHG pollution reduction, and generating allowance proceeds for
investments in communities disproportionately impacted by environmental
harms. The scope and approach of the EPA's final emission guidelines
differ significantly from the range of policies and programs employed
by states to reduce power sector CO2 emissions, and these
emission guidelines operate more narrowly to improve the CO2
emission performance of a subset of EGUs within the broader electric
power sector.
Several commenters requested guidance on how states can count
existing state programs, many of which include requirements to reduce
CO2 emissions at sources not affected by this
[[Page 39990]]
rule, in their state plans under these emission guidelines. The EPA is
not providing such guidance in this action but would be open to
consulting with states during the state plan development process about
the requirements of these emission guidelines in relation to existing
state programs. States may make determinations about whether and how to
design their plans, accounting for state-specific programs or
requirements that apply to the same affected EGUs included in a state
plan. However, as noted in section X.B, emission reductions from
sources not affected by this rule cannot be used to demonstrate
compliance with a standard of performance established to meet the
emission guidelines. Only emission reductions at affected EGUs may
count towards compliance with the state plan, including towards
demonstrating compliance with the equivalent stringency criterion
applied to compliance flexibilities. States may employ compliance
flexibilities (such as mass-based mechanisms) described in this section
in order to facilitate comparison between the requirements under
existing state programs and under these emission guidelines; however,
the EPA emphasizes that individual affected EGUs or groups of affected
EGUs must comply with the requirements established for such units in
the state plan, and that such compliance cannot incorporate measures
taken by EGUs not affected by these emission guidelines.
E. State Plan Components and Submission
This section describes the requirements for the contents of state
plans and the timing of state plan submissions as well as the EPA's
review of and action on state plan submissions. This section also
discusses issues related to the applicability of a Federal plan and
timing for the promulgation of any Federal Plan, if necessary.
As explained earlier in this preamble, the requirements of 40 CFR
part 60, subpart Ba, govern state plan submissions under these emission
guidelines. Where the EPA is finalizing requirements that add to,
supersede, or otherwise vary from the requirements of subpart Ba for
the purposes of state plan submissions under these particular emission
guidelines,\950\ those requirements are addressed explicitly in section
X.E.1.b on specific state plan requirements and in other parts of
section X of this preamble. Unless expressly amended or superseded in
these final emission guidelines, the provisions of subpart Ba apply.
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\950\ 40 CFR 60.20a(a)(1).
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1. Components of a State Plan Submission
A state plan must include a number of discrete components,
including but not limited to those that apply for all state plans
pursuant to 40 CFR part 60, subpart Ba. In this action, the EPA is also
finalizing additional plan components that are specific to state plans
submitted pursuant to these emission guidelines. For example, the EPA
is finalizing plan components that are necessary to implement and
enforce the specific types of standards of performance for affected
EGUs that would be adopted by a state and incorporated into its state
plan.
a. General Components
The CAA section 111 implementing regulations at 40 CFR part 60,
subpart Ba, provide separate lists of administrative and technical
criteria that must be met in order for a state plan submission to be
deemed complete.\951\ The complete list of applicable administrative
completeness criteria for state plan submissions is: (1) A formal
letter of submittal from the Governor or the Governor's designee
requesting EPA approval of the plan or revision thereof; (2) Evidence
that the state has adopted the plan in the state code or body of
regulations; or issued the permit, order, or consent agreement
(hereafter ``document'') in final form. That evidence must include the
date of adoption or final issuance as well as the effective date of the
plan, if different from the adoption/issuance date; (3) Evidence that
the state has the necessary legal authority under state law to adopt
and implement the plan; (4) A copy of the actual regulation, or
document submitted for approval and incorporation by reference into the
plan, including indication of the changes made (such as redline/
strikethrough) to the existing approved plan, where applicable. The
submittal must be a copy of the official state regulation or document
signed, stamped, and dated by the appropriate state official indicating
that it is fully enforceable by the state. The effective date of the
regulation or document must, whenever possible, be indicated in the
document itself. The state's electronic copy must be an exact duplicate
of the hard copy. If the regulation/document provided by the state for
approval and incorporation by reference into the plan is a copy of an
existing publication, the state submission should, whenever possible,
include a copy of the publication cover page and table of contents; (5)
Evidence that the state followed all applicable procedural requirements
of the state's regulations, laws, and constitution in conducting and
completing the adoption/issuance of the plan; (6) Evidence that public
notice was given of the plan or plan revisions with procedures
consistent with the requirements of 40 CFR 60.23a, including the date
of publication of such notice; (7) Certification that public hearing(s)
were held in accordance with the information provided in the public
notice and the state's laws and constitution, if applicable and
consistent with the public hearing requirements in 40 CFR 60.23a; (8)
Compilation of public comments and the state's response thereto; and
(9) Documentation of meaningful engagement, including a list of
pertinent stakeholders, a summary of the engagement conducted, a
summary of stakeholder input received, and a description of how
stakeholder input was considered in the development of the plan or plan
revisions.
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\951\ 40 CFR 60.27a(g)(2) and (3).
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Pursuant to subpart Ba, the technical criteria that all plans must
meet include the following: (1) Description of the plan approach and
geographic scope; (2) Identification of each designated facility (i.e.,
affected EGU); identification of standards of performance for each
affected EGU; and monitoring, recordkeeping, and reporting requirements
that will determine compliance by each designated facility; (3)
Identification of compliance schedules and/or increments of progress;
(4) Demonstration that the state plan submission is projected to
achieve emission performance under the applicable emission guidelines;
(5) Documentation of state recordkeeping and reporting requirements to
determine the performance of the plan as a whole; and (6) Demonstration
that each standard is quantifiable, permanent, verifiable, enforceable,
and nonduplicative.
b. Specific State Plan Requirements for These Emission Guidelines
To ensure that state plans submitted pursuant to these emission
guidelines are consistent with the statutory requirements and the
requirements of subpart Ba, the EPA is finalizing additional regulatory
requirements that state plans must meet for all affected EGUs subject
to a standard of performance, as well as certain subcategory-specific
requirements. The EPA reiterates that standards of performance for
affected EGUs included in a state plan must be quantifiable,
[[Page 39991]]
verifiable, permanent, enforceable, and non-duplicative. Additionally,
per CAA section 302(l), standards of performance must be continuous in
nature. Additional state plan requirements finalized as part of this
action include:
Identification of each affected EGU and the subcategory to
which each affected EGU is assigned;
A requirement that state plans include, in the regulatory
portion of the plan, a list of coal-fired steam-generating EGUs that
are existing sources at the time of state plan submission and that plan
to permanently cease operation before January 1, 2032, and the calendar
dates by which they have committed to do so. The state plan must
provide that an EGU operating past the date listed in the plan is no
longer exempt from these emission guidelines and is in violation of
that plan, except to the extent the existing coal-fired steam
generating EGU has received a time-limited extension of its date for
ceasing operation pursuant to the reliability assurance mechanism
described in section XII.F.3.b of this preamble;
Standards of performance for each affected EGU, including
provisions for implementation and enforcement of such standards as well
as identification of the control technology or other system of emission
reduction affected EGUs intend to implement to achieve the standards of
performance. Standards of performance must be expressed in lb
CO2/MWh gross basis or, for affected EGUs in the low load
natural gas- and oil-fired subcategory, lb CO2/MMBtu, or, if
a state is allowing the use of mass-based compliance, tons
CO2 per year;
For each affected EGU, identification of baseline emission
performance, including CO2 mass and electricity generation
data or, for affected EGUs in either the low load natural gas-fired
subcategory or the low load oil-fired subcategory, heat input data from
40 CFR part 75 reporting for the 5-year period immediately prior to the
date this final rule is published in the Federal Register and what
continuous 8-quarter period from the 5-year period was used to
calculate baseline emission performance;
Where a state plan provides for the use of a compliance
flexibility, such as an alternative form of the standard (e.g., mass
limit; aggregate emission rate limitation) and/or the use of emission
averaging or trading, identification of the presumptive unit-specific
rate-based standard of performance in lb CO2/MWh-gross that
would apply for each affected EGU in the absence of the compliance
flexibility mechanism; the standard of performance (aggregate emission
rate limitation, mass limit, or mass budget) that is actually applied
for affected EGUs under the compliance flexibility mechanism and how it
is calculated; provisions for the implementation and enforcement of the
compliance flexibility mechanism, which includes provisions that
address assurance of achievement of equivalent emission reduction,
including, for mass-based compliance flexibilities, identification of
the unit-specific backstop emission limitation; and a demonstration
that the state plan will achieve an equivalent level of emission
reduction with individual rate-based standards of performance through
incorporation of the compliance flexibility mechanism;
Increments of progress and reporting obligations and
milestones as required for affected EGUs within the applicable
subcategories or pursuant to consideration of RULOF, included as
enforceable elements of a state plan;
For affected EGUs in the medium-term coal-fired steam
generating EGU subcategory and affected EGUs relying on a plan to
permanently cease operation for application of a less stringent
standard of performance pursuant to RULOF, the state plan must include
an enforceable commitment to permanently cease operation by a date
certain. The state plan must clearly identify the calendar dates by
which such affected EGUs have committed to permanently cease operation;
\952\
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\952\ Consistent with CAA section 111(d)(1), state plans must
include commitments to cease operation as necessary for the
implementation and enforcement of standards of performance. When
such commitments are the predicate for receiving a particular
standard of performance, adherence to those commitments is necessary
to maintain the level of emission reduction Congress required under
CAA section 111(a)(1). See 40 CFR 60.24a(g) (operating conditions
within the control of a designated facility that are relied on for
purposes of RULOF must be included as enforceable requirements in
state plans); see also, e.g., ``Affordable Clean Energy Rule,'' 84
FR 32520, 32558 (July 8, 2019) (repealed on other grounds)
(requiring that retirement dates associated with standards of
performance be included in state plans and become federally
enforceable upon approval by the EPA); 76 FR 12651, 12660-63 (March
8, 2011) (best available retrofit technology requirements based on
enforceable retirements that were made federally enforceable in
state implementation plan); Guidance for Regional Haze State
Implementation Plans for the Second Implementation Period at 34,
EPA-457/B-19-003, August 2019 (to the extent a state replies on an
enforceable shutdown date for a reasonable progress determination,
that measure would need to be included in the SIP and/or be
federally enforceable).
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A requirement that state plans provide that any existing
coal-fired steam generating EGU shall operate only subject to a
standard of performance pursuant to these emission guidelines or under
an exemption from applicability provided under 40 CFR 60.5850b
(including any time-limited extension of the date by which an EGU has
committed to permanently cease operations pursuant to the reliability
assurance mechanism); and
Monitoring, reporting, and recordkeeping requirements for
affected EGUs.
These final emission guidelines include requirements pertaining to
the methodologies for establishing a presumptively approvable standard
of performance for an affected EGU within a given subcategory. These
presumptive methodologies are specified for each of the subcategories
of affected EGUs in section X.C.1 of this preamble.
As discussed in sections X.C and X.D of this preamble, in order for
the EPA to find a state plan ``satisfactory,'' that plan must
demonstrate that it achieves the level of emission reduction that would
result if each affected source was individually achieving its
presumptive standard of performance, after accounting for any
application of RULOF. That is, while states have the discretion to
establish the applicable standards of performance for affected sources
in their state plans (including whether to allow compliance to be
demonstrated through the use of compliance flexibilities), the
structure and purpose of CAA section 111 require that those plans
achieve an equivalent level of emission reduction as applying the EPA's
presumptive standards of performance to those sources (again, after
accounting for any application of RULOF).
Thus, state plans must adequately document and support the process
and underlying data used to establish standards of performance pursuant
to these emission guidelines. Providing such documentation is critical
to the EPA's review of state plans to determine whether they are
satisfactory. In particular, states must include in their plan
submissions information and data related to affected EGUs' emissions
and operations, including CO2 mass emissions and
corresponding electricity generation data or, for affected EGUs in
either the low load natural gas-fired subcategory or the oil-fired
subcategory, heat input data, from 40 CFR part 75 reporting for the 5-
year period immediately prior to the date the final rule is published
in the Federal Register and identify the period from which states and
affected EGUs select 8 continuous quarters of data to determine unit-
specific baselines. States must include data and documentation
sufficient for the EPA to understand and replicate their calculations
in applying the applicable degree of emission
[[Page 39992]]
limitation to individual affected EGUs to establish their standards of
performance. They must also provide any methods, assumptions, and
calculations necessary for the EPA to review plans containing
compliance flexibilities and to determine whether they achieve an
equivalent (or better) level of emission reduction as unit-specific
implementation of rate-based standards of performance. Plans must also
adequately document and demonstrate the methods employed to implement
and enforce the standards of performance such that the EPA can review
and identify measures that assure transparent and verifiable
implementation.
i. Requirements Related to Meaningful Engagement
Public engagement is a cornerstone of CAA section 111(d) state plan
development. In November 2023, the EPA finalized requirements in the
CAA section 111(d) implementing regulations at 40 CFR part 60 subpart
Ba to ensure that that all affected members of the public, not just a
particular subset, have an opportunity to participate in the state plan
development process. These requirements are intended to ensure that the
perspectives, priorities, and concerns of affected communities,
including communities that are most affected by and vulnerable to
emissions from affected EGUs as well as energy communities and energy
workers that are affected by EGU operation and construction of
pollution controls, are included in the process of establishing and
implementing standards of performance for existing EGUs, including
decisions about compliance strategies and compliance flexibilities that
may be included in a state plan. The final requirements for meaningful
engagement in subpart Ba are in addition to the preexisting public
notice requirements under subpart Ba that apply to state plan
development. This section describes the meaningful engagement
requirements finalized separately in subpart Ba and provides guidance
to states in the application of these requirements to the development
of state plans under these emission guidelines.
The fundamental purpose of CAA section 111 is to reduce emissions
from categories of stationary sources that cause, or significantly
contribute to, air pollution which may reasonably be anticipated to
endanger public health or welfare. Therefore, a key consideration in
the state's development of a state plan is the potential impact of the
proposed plan requirements on public health and welfare. Meaningful
engagement is a corollary to the longstanding requirement for public
participation, including through public hearings, in the course of
state plan development under CAA section 111(d).\953\ A robust and
meaningful engagement process is critical to ensuring that the entire
public has an opportunity to participate in the state plan development
process and that states understand and consider the full range of
impacts of a proposed plan on public health and welfare.
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\953\ 40 CFR 60.23(c)-(g); 40 CFR 60.23a(c)-(h).
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The EPA finalized the following definition of meaningful engagement
in the final subpart Ba revisions in November 2023: ``timely engagement
with pertinent stakeholders and/or their representatives in the plan
development or plan revision process.'' \954\ Furthermore, the
definition provides that ``[s]uch engagement should not be
disproportionate in favor of certain stakeholders and should be
informed by available best practices.'' \955\ The regulations also
define pertinent stakeholders, which ``include, but are not limited to,
industry, small businesses, and communities most affected by and/or
vulnerable to the impacts of the plan or plan revision.'' \956\ The
preamble for the final revisions to subpart Ba notes that ``[i]ncreased
vulnerability of communities may be attributable to, among other
reasons, an accumulation of negative environmental, health, economic,
or social conditions within these populations or communities, and a
lack of positive conditions.'' \957\ Consistent with the requirements
of subpart Ba, it is important for states to recognize and engage the
communities most affected by and/or vulnerable to the impacts of a
state plan, particularly as these communities may not have had a voice
when the affected EGUs were originally constructed.
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\954\ 40 CFR 60.21a(k); 88 FR 80480, 80500 (November 17, 2023).
\955\ Id.
\956\ 40 CFR 60.21a(l); 88 FR 80480, 80500 (November 17, 2023).
\957\ 88 FR 80480, 80500 (November 17, 2023).
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Most commenters were generally supportive of the requirement to
conduct meaningful engagement. Commenters acknowledged that some states
and utilities have already started to conduct meaningful engagement
with stakeholders like that which is required by the final subpart Ba
revisions in other policy contexts. Some commenters requested more time
in the state plan development process specifically to facilitate
conducting meaningful engagement (comments related to the state plan
development timeline are addressed section X.E.2).
In the proposed emission guidelines, the EPA provided some
information to assist states in identifying potential pertinent
stakeholders. Some commenters sought more guidance from the EPA on how
to identify pertinent stakeholders. The Agency is providing the
following discussion of the potential impacts of the emission
guidelines to assist states in identifying their pertinent
stakeholders. The EPA believes that this discussion provides a starting
point and expects that states will use their more targeted knowledge of
state- and source-specific circumstances to hone the identification of
pertinent stakeholders and conduct the necessary meaningful engagement.
As acknowledged by the EPA in the final revisions to subpart Ba,
``states are highly diverse in, among other things, their local
conditions, resources, and established practices of engagement,'' \958\
so the EPA is not finalizing any additional requirements regarding the
states' identification of a pertinent stakeholders for the purposes of
these emission guidelines. States should consider the unique
circumstances of their state and the sources within their state, with
the following discussion in mind, to tailor their meaningful
engagement. In addition, the EPA notes that the preamble to the final
subpart Ba revisions provides discussion of best practices related to
meaningful engagement.\959\
---------------------------------------------------------------------------
\958\ Id.
\959\ See id. at 80502.
---------------------------------------------------------------------------
The air pollutant of concern in these emission guidelines is
defined as greenhouse gases, and the air pollution addressed is
elevated concentrations of these gases in the atmosphere. These
elevated concentrations result in warming temperatures and other
changes to the climate system that are leading to serious and life-
threatening environmental and human health impacts, including increased
incidence of drought and flooding, damage to crops and disruption of
associated food, fiber, and fuel production systems, increased
incidence of pests, increased incidence of heat-induced illness, and
impacts on water availability and water quality. The Agency therefore
expects that states' pertinent stakeholders will include communities
within the state that are most affected by and/or vulnerable to the
impacts of climate change, including those exposed to more extreme
drought, flooding, and other severe weather impacts, including extreme
heat and cold (states should
[[Page 39993]]
refer to section III of this preamble, on climate impacts, to further
assist them in identifying their pertinent stakeholders that are
impacted by the pollution at issue in these emission guidelines).
Commenters were supportive of the notion that those impacted by climate
change are pertinent stakeholders.
Additionally, the EPA expects that another set of pertinent
stakeholders will be communities located near affected EGUs and those
near pipelines. These communities may experience impacts associated
with implementation of the state plan, including the construction and
operation of infrastructure required under a state plan. Activities
related to the construction and operation of new natural gas and
CO2 pipelines may impact individuals and communities both
locally and at larger distances from affected EGUs but near any
associated pipelines. Commenters were supportive of the notion that
communities impacted by infrastructure development required by the
state plan are pertinent stakeholders.
Because these emission guidelines address air pollution that
becomes well mixed and is long-lived in the atmosphere, the collective
impact of a state plan is not limited to the immediate vicinity of EGUs
and any associated infrastructure. The EPA therefore expects that
states will consider communities and populations within the state that
are both most impacted by particular affected EGUs and associated
pipelines as well as those that will be most affected by the overall
stringency of state plans.
The EPA also expects that states will include the energy
communities impacted by each affected EGU, including the energy workers
employed at affected EGUs (including employment in operation and
maintenance), workers who may construct and install pollution control
technology, and workers employed in associated industries such as fuel
extraction and delivery and CO2 transport and storage, as
pertinent stakeholders. These communities are impacted by power sector
trends on an ongoing basis. The EPA acknowledges that a variety of
Federal programs are available to support these communities and
encourages states to consider these programs when conducting meaningful
engagement and analyzing the impacts of compliance choices.\960\
Commenters supported encouraging states to both consider these
communities as part of meaningful engagement under these emission
guidelines as well as to take advantage of Federal resources available
for employment and training assistance, and highlighted a Colorado
state law \961\ requiring utilities to share workforce data and develop
a workforce transition plan. The EPA supports such approaches to
workforce data transparency and encourages states to provide such data
in the course of meaningful engagement and the development of state
plans.
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\960\ An April 2023 report of the Federal Interagency Working
Group on Coal and Power Plant Communities and Economic
Revitalization (Energy Communities IWG) summarizes how the
Bipartisan Infrastructure Law, CHIPS and Science Act, and Inflation
Reduction Act have greatly increased the amount of Federal funding
relevant to meeting the needs of energy communities, as well as how
the Energy Communities IWG has launched an online Clearinghouse of
broadly available Federal funding opportunities relevant for meeting
the needs and interests of energy communities, with information on
how energy communities can access Federal dollars and obtain
technical assistance to make sure these new funds can connect to
local projects in their communities. Interagency Working Group on
Coal and Power Plant Communities and Economic Revitalization.
``Revitalizing Energy Communities: Two-Year Report to the
President'' (April 2023). https://energycommunities.gov/wp-content/uploads/2023/04/IWG-Two-Year-Report-to-the-President.pdf.
\961\ Colorado Legislature, Senate Law 19-236. https://leg.colorado.gov/sites/default/files/2019a_236_signed.pdf.
---------------------------------------------------------------------------
The EPA also expects that states will include relevant balancing
authorities, systems operators and reliability coordinators that have
authority to maintain electric reliability in their jurisdiction as
part of their constructive engagement under these requirements. These
stakeholders are impacted by a state plan as they are the entities
authorized to plan for electric reliability. Visibility into unit-
specific compliance plans will help ensure those entities have adequate
lead time to plan and address any potential reliability-related issues.
Early notification and periodic follow up on unit-specific decisions,
including control technology installation and voluntary cease operation
choices and timeframes will greatly assist reliability planning
authorities.
Several commenters noted the need for consideration of communities
overburdened by existing air pollution issues, including both
greenhouse gases and co-pollutants, as pertinent stakeholders in these
emission guidelines. The Agency urges states to consider the cumulative
burden of pollution when identifying their pertinent stakeholders for
these emission guidelines, as these stakeholders may be especially
vulnerable to the impacts of a state plan or plan revision due to ``an
accumulation of negative environmental . . . conditions,'' as defined
in the final subpart Ba revisions. Many states are already implementing
policies to consider cumulative impacts in overburdened communities,
including California and New Jersey. It is also important to note that
the EPA is ``prioritizing cumulative impacts research to address the
multiple stressors to which people and communities are exposed, and
studying how combinations of stressors affect health, well-being, and
quality of life at each developmental stage throughout the course of
one's life.'' \962\ Additionally, the EPA is in the process of
developing a workplan that lays out actions the agency will take to
integrate and implement cumulative impacts within the EPA's work
through FY25. The EPA's commitments, as stated in the EPA's response to
the OIG Report, include continuing to refine analytic techniques based
on best available science, increasing the body of relevant data and
knowledge, and using outcome-based metrics to measure progress,
including quantifiable pollution reduction benefits in
communities.\963\
---------------------------------------------------------------------------
\962\ Nicolle S. Tulve, Andrew M. Geller, Scot Hagerthey, Susan
H. Julius, Emma T. Lavoie, Sarah L. Mazur, Sean J. Paul, H.
Christopher Frey, Challenges and opportunities for research
supporting cumulative impact assessments at the United States
environmental protection agency's office of research and
development, The Lancet Regional Health--Americas, Volume 30, 2024,
100666, ISSN 2667-193X, https://doi.org/10.1016/j.lana.2023.100666.
\963\ EPA Response to Draft Office of Inspector General Report,
The EPA Lacks Agencywide Policies and Guidance to Address Cumulative
Impacts and Disproportionate Health Effects on Communities with
Environmental Justice Concerns. https://www.epaoig.gov/sites/default/files/reports/2023-08/_epaoig_20230822-23-p-0029.pdf.
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The EPA recognizes that facility- and community-specific
circumstances, including the exposure of overburdened communities to
additional chemical and non-chemical stressors, may also exist. The
meaningful engagement process is designed to allow states to identify
and to enable consideration of these and other facility- and community-
specific circumstances. This includes consideration of facility- and
community-specific concerns with emissions control systems, including
CCS. States should design meaningful engagement to elicit input from
pertinent stakeholders on facility- and community-specific issues
related to implementation of emissions control systems generally, as
well as on any considerations for particular systems.
The EPA encourages states to consider regional implications,
explore opportunities for collaboration, and to share best practices.
In some cases, an affected EGU may be located near state
[[Page 39994]]
or Tribal borders and impact communities in neighboring states or
Tribal lands. Some commenters suggested that those near state or Tribal
borders may be pertinent stakeholders. The EPA agrees that it could be
reasonable, in cases where EGUs are located near borders, for the state
to consider identifying pertinent stakeholders in the neighboring state
or Tribal land and to work with the relevant air pollution control
authority of that state or Tribe to conduct meaningful engagement that
addresses cross-border impacts. Some commenters supported the notion
that those near state or Tribal borders may be pertinent stakeholders.
The revisions to subpart Ba in November of 2023 established
requirements for demonstrating how states provided meaningful
engagement with pertinent stakeholders, and these requirements apply
here. According to the requirements under subpart Ba, the state will be
required to describe, in its plan submittal: (1) A list of the
pertinent stakeholders identified by the state; (2) a summary of
engagement conducted; (3) a summary of the stakeholder input received;
and (4) a description of how stakeholder input was considered in the
development of the plan or plan revisions. The EPA will review the
state plan to ensure that it includes these required descriptions
regarding meaningful public engagement as part of its completeness
evaluation of a state plan submittal. If a state plan submission does
not include the required elements for notice and opportunity for public
participation, including the procedural requirements at 40 CFR
60.23a(i) and 60.27a(g)(2)(ix) for meaningful engagement, this may be
grounds for the EPA to find the submission incomplete or (where a plan
has become complete by operation of law) to disapprove the plan.
In approaching meaningful engagement, states should first identify
their pertinent stakeholders. As previously noted, the state should
allow for balanced participation, including communities most vulnerable
to the impacts of the plan. Next, states should develop a strategy for
engagement with the identified pertinent stakeholders. This includes
ensuring that information is made available in a timely and transparent
manner, with adequate and accessible notice. As part of this strategy
for engagement, states should also ensure that they share information
and solicit input on plan development and on any accompanying
assessments or analyses. In providing transparent and adequate notice
of plan development, states should consider that internet notice alone
may not be appropriate for all stakeholders, given lack of access to
broadband infrastructure in many communities. Thus, in addition to
internet notice, examples of prominent advertisement for engagement and
public hearing may include notice through newspapers, libraries,
schools, hospitals, travel centers, community centers, places of
worship, gas stations, convenience stores, casinos, smoke shops, Tribal
Assistance for Needy Families offices, Indian Health Services, clinics,
and/or other community health and social services as appropriate for
the emission guideline addressed. The state should also consider any
geographic, linguistic, or other barriers to participation in
meaningful engagement for members of the public.
The EPA notes that several EPA resources are available to assist
states and stakeholders in considering options for state plans. For
example, included in the docket for this rulemaking is a unit-level
proximity analysis that includes information about the population
within 5 kilometers and 10 kilometers of each EGU covered by this rule.
This analysis includes information about air emissions from each
facility, and the potential emission implications of installing CCS.
Additionally, the EPA's Power Plant Environmental Justice Screening
Methodology (PPSM) \964\ incorporates several peer-reviewed approaches
that combine air quality modeling with environmental burden and
population characteristics data to identify and connect power plants to
geographic areas potentially exposed to air pollution by those power
plants and to quantify the relative potential for environmental justice
concern in those areas. This information provides states and
stakeholders with the ability to identify the census block groups that
are potentially exposed to air pollution by each EGU, including air
pollutants in the vicinity of each EGU as well as pollutants that can
travel significant distances. Another resource available to assist
states and stakeholders is the EPA's Environmental Justice Screening
and Mapping Tool (EJScreen),\965\ which includes information at the
census block group level about existing environmental burdens as well
as socioeconomic information. Other federal resources include the
Energy Communities Interagency Working Group's online Clearinghouse,
which lists federal funding opportunities relevant for meeting the
needs and interests of energy communities, some of which may be
relevant for state plan development.
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\964\ https://www.epa.gov/power-sector/power-plant-environmental-justice-screening-methodology.
\965\ https://www.epa.gov/ejscreen.
---------------------------------------------------------------------------
In their plan submittal, states must demonstrate evidence that they
conducted meaningful engagement. In addition to a list of pertinent
stakeholders and a summary of the engagement conducted, states must
provide a summary of the input received and a description of how the
input they received was considered in plan development. The type of
information states may receive from their pertinent stakeholders could
include data on the population and demographics of communities located
near affected EGUs and associated pipelines; identification of and data
on any overburdened communities vulnerable to the impacts of the state
plan; data on the energy workers affected by anticipated compliance
strategies on the part of owners and operators; data on workforce needs
(e.g., expected number and type of jobs created, and skills required in
anticipation of compliance with the state plan); and, if relevant, data
on the population and demographics of communities near state and Tribal
borders that may be vulnerable to the impacts of the state plan. The
EPA encourages states to include such data in their demonstration of
meaningful engagement in their state plan submittal.
The EPA emphasizes to states that the meaningful engagement process
is intended to include community perspectives, particularly those
communities that, historically, may not have had a role in the state
plan development process, in the development of standards of
performance, compliance strategies, and compliance flexibilities for
affected EGUs by which they are impacted.
ii. Requirements for Transparency and Compliance Assurance
The EPA proposed and requested comment on several requirements
designed to help states ensure timely compliance by affected EGUs with
standards of performance, as well as to assist the public in tracking
affected EGUs' progress towards their compliance dates.
First, the EPA requested comment on whether to require that an
affected EGU's enforceable commitment for subcategory applicability
(e.g., a state elects to rely on an affected coal-fired steam-
generating unit's commitment to permanently cease operations before
January 1, 2039, to meet the applicability requirements for the medium-
term subcategory), must be in
[[Page 39995]]
the form of an emission limit of 0 lb CO2/MWh that applies
on the relevant date. Such an emission limit would be included in a
state regulation, permit, order, or other acceptable legal instrument
and submitted to the EPA as part of a state plan. If approved, the
affected EGU would have a federally enforceable emission limit of 0 lb
CO2/MWh that would become effective as of the date that the
EGU permanently ceases operations. The EPA requested comment on whether
such an emission limit would have any advantages or disadvantages for
compliance and enforceability relative to the alternative, which is an
enforceable commitment in a state plan to cease operation by a certain
date.
The EPA received few comments on this topic. One commenter,\966\ in
particular, did not support a specific requirement that the permit or
other enforceable commitment must be in the form of an emission limit
of 0 lb CO2/MWh, claiming it seems needlessly prescriptive.
This commenter also encouraged the EPA to recognize delegated or SIP-
approved states' enforceable permit conditions, certifications, and
voiding of authorizations, as practically enforceable.
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\966\ See Document ID No. EPA-HQ-OAR-2023-0072-0781.
---------------------------------------------------------------------------
The EPA is not finalizing a requirement that states must include
commitments to permanently cease operating in state plans in the form
of 0 lb CO2/MWh emission limits. The Agency is concluding
that it is within the discretion of the state to create an enforceable
commitment to permanently cease operation, where applicable, in the
form it deems appropriate. Such commitments may be codified in a state
regulation, permit, order, or other acceptable legal instrument and
submitted to the EPA as part of a state plan. It is important to note
that if an emission limit or some other requirement that creates an
enforceable commitment to cease operation is initially included in a
title V permit before the submission of a state plan, that condition
must be labeled as ``state-only'' or ``state-only enforceable'' until
the EPA approves the state plan, at which point the permit should be
revised to make that requirement federally enforceable. Including state
instruments (such as state permits, certifications, and other
authorizations) reflecting affected EGUs' intent to permanently cease
operation in the state plan, when such intent is the basis of receiving
a less stringent standard of performance, is necessary because state
instruments can be revised without a corresponding revision to the
state plan or standard of performance. This outcome--a source
continuing to operate into the future with a less-stringent standard of
performance that is not necessarily warranted--would undermine the
integrity of these emission guidelines.
Second, the EPA proposed and is finalizing a requirement that state
plans that include affected EGUs that plan to permanently cease
operation must require that each such affected EGU comply with
applicable state and Federal requirements for permanently ceasing
operation, including removal from its respective state's air emissions
inventory and amending or revoking all applicable permits to reflect
the permanent shutdown status of the EGU. This requirement covers
affected coal-fired steam generating EGUs in the medium-term
subcategory as well as affected EGUs that are relying on a commitment
to permanently cease operating to obtain a less stringent standard of
performance pursuant to consideration of RULOF. This requirement merely
reinforces the application of requirements under state and Federal laws
that are necessary in this context for transparency and the orderly
administration of these emission guidelines.
Third, the EPA proposed and is finalizing a requirement that each
state plan must require owners and operators of affected EGUs to
establish publicly accessible websites, referred to here as a ``Carbon
Pollution Standards for EGUs website,'' to which all reporting and
recordkeeping information for each affected EGU subject to the state
plan would be posted, including the aforementioned information required
to be submitted as part of the state plan. This information includes,
but is not limited to, emissions data and other information relevant to
determining compliance with applicable standards of performance,
information relevant to the designation and determination of compliance
with increments of progress and reporting obligations including
milestones for affected EGUs that plan to permanently cease operations,
and any extension requests made and granted pursuant to the compliance
date extension mechanism or the reliability assurance mechanism.
Although this information will also be required to be submitted
directly to the EPA and the relevant state regulatory authority, both
the EPA and stakeholders have an interest in ensuring that the
information is made accessible in a timely manner. Some commenters
agreed with these requirements. The EPA anticipates that the owners or
operators of some affected EGUs may already be posting comparable
reporting and recordkeeping information to publicly available websites
under the EPA's April 2015 Coal Combustion Residuals Rule,\967\ such
that the burden of this website requirement for these units could be
minimal.
---------------------------------------------------------------------------
\967\ See https://www.epa.gov/coalash/list-publicly-accessible-internet-sites-hosting-compliance-data-and-information-required for
a list of websites for facilities posting Coal Combustion Residuals
Rule compliance information, see also 80 FR 21301 (April 17, 2015).
---------------------------------------------------------------------------
Comment: Several commenters argued that this was a duplicative
requirement, noting that utilities already report GHG emissions data
under the Acid Rain Program and Mandatory GHG Reporting Program.
Commenters also stated that this requirement would pose a burden for
companies who would have to dedicate staff to maintaining the website.
One commenter \968\ suggested that EPA include more specific
requirements related to the format of data, notification of uploads and
removal of documentation, and summarization of content.
---------------------------------------------------------------------------
\968\ See Document ID No. EPA-HQ-OAR-2023-0072-0813.
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Response: The EPA disagrees that this requirement is duplicative of
reporting requirements under other programs. In addition to affected
EGUs having unique standards of performance and compliance schedules
under these emission guidelines, these emission guidelines also include
unique reporting requirements that are not covered by the programs
identified by the commenters, including increments of progress and
reporting on milestones. In addition, the EPA believes that this
information should be made broadly available to all stakeholders in a
timely manner, which is not necessarily accomplished via the programs
and reporting mechanisms identified by the commenters. Accordingly, the
EPA is finalizing a requirement that each state plan must require
owners and operators of affected EGUs to establish publicly accessible
websites and to post the relevant information described in this
section. Additionally, data should be available in a readily
downloadable format.
Fourth, to promote transparency and to assist the EPA and the
public in assessing progress towards compliance with state plan
requirements, the EPA proposed and is finalizing a requirement that
state plans include a requirement that the owner or operator of each
affected EGU shall report any deviation from any federally enforceable
state plan increment of progress or reporting milestone within 30
business days after
[[Page 39996]]
the owner or operator of the affected EGU knew or should have known of
the event. That is, the owner or operator must report within 30
business days if it is behind schedule such that it has missed an
increment of progress or reporting milestone. In the report, the owner
or operator of the affected EGU will be required to explain the cause
or causes of the deviation and describe all measures taken or to be
taken by the owner or operator of the EGU to cure the reported
deviation and to prevent such deviations in the future, including the
timeframes in which the owner or operator intends to cure the
deviation. The owner or operator of the EGU must submit the report to
the state regulatory agency and concurrently post the report to the
affected EGU's Carbon Pollution Standards for EGUs website.
Fifth, in the proposed action, the EPA explained its general
approach to exercising its enforcement authorities through
administrative compliance orders (``ACOs'') to ensure compliance while
addressing genuine risks to electric system reliability. The EPA
solicited comment on whether to promulgate requirements in the final
emission guidelines pertaining to the demonstrations, analysis, and
information the owner or operator of an affected EGU would have to
submit to the EPA in order to be considered for an ACO. The EPA is not
finalizing the proposed approach to use ACOs to address risks to grid
reliability.
Comment: One commenter argued that the conditions to qualify for an
ACO would make it challenging for an EGU to obtain an ACO in instances
of urgent reliability.\969\ Commenters argued that there are not any
guarantees that the EPA would act on such requests for an ACO in a
timely manner, particularly because the EPA has not set any deadline
for review and presumably would argue that any decision falls within
the EPA's enforcement discretion and is not subject to judicial review.
Additionally, one commenter argued that the proposal is unworkable for
the purposes of addressing more immediate reliability needs, specifying
that EGUs may not be able to readily obtain the information or analysis
necessary for preparing documentation for the EPA from their regional
entity or state.\970\
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\969\ See Document ID No. EPA-HQ-OAR-2023-0072-0770.
\970\ Id.
---------------------------------------------------------------------------
Another commenter argued that the proposed mechanism provides no
relief during an energy crisis because they would be offered only after
the fact to resolve any alleged violations. Therefore, the possibility
of future enforcement discretion and ACOs will not help a power
generator decide in the moment whether to keep running and risk a
violation or shut down, risking grid reliability and affecting our
customers. the commenter also stated that ACOs are enforcement actions
that carry negative implications and the potential for significant
civil penalties, and citizen groups are unlikely to exercise discretion
similar to that of the EPA, even if the EPA decides that a low (or no)
penalty is appropriate. Lastly, this commenter noted that ACOs are
typically intended to resolve relatively short-term noncompliance
events that can be remedied and that do not reflect a fundamental
inability to comply.
Response: As discussed in section XII.F and elsewhere in this
preamble, the EPA has made several adjustments and provided several
mechanisms in this final rule that have the effect of or are expressly
intended to provide grid operators and reliability authorities methods
to address grid reliability. For example, the EPA is providing that
states may include in their state plans a short-term reliability
mechanism that allows affected EGUs to comply with an emission
limitation corresponding to their baseline emission rate during periods
of grid emergency. For further detail, see section XII.F.3.a of this
preamble. This mechanism is intended to allow states to respond quickly
to emergency situations, and to avoid affected EGUs being out of
compliance or needing to work towards compliance through an ACO.
Considering the structural changes the EPA has made in these final
emission guidelines and the mechanisms it is providing states to
address grid reliability, the EPA does not believe that states and
affected EGUs will need to rely on ACOs to address compliance during
periods of grid emergency.
Finally, as explained in section VII.B of this preamble, coal-fired
steam generating EGUs that plan to permanently cease operating before
January 1, 2032, are not covered by these emission guidelines, i.e.,
they are not affected EGUs. However, to maintain the environmental
integrity of these emission guidelines, it is critical that any
existing sources that are operating as of January 1, 2032, are doing so
subject to a requirement to operate more cleanly, and therefore
essential that sources report on their actions to qualify for the
exemption. As explained in the preamble to the proposed rule and
section X.C.4 of this preamble, there are many steps the owners or
operators of EGUs must take as they get ready to permanently cease
operations and those steps vary between units and jurisdictions.
Procession in a timely manner through these steps is the best indicator
the EPA has of whether or not an existing source remains qualified for
an exemption from these emission guidelines. Should a source's plans to
cease operating change, e.g., because the relevant planning authority
has called on it to remain in operation for reliability or resource
adequacy, the state, the public, and the EPA need to be aware of that
change as soon as possible in order to appropriately address the source
under these emission guidelines. The EPA therefore believes that having
sources that plan to cease operation before January 1, 2032, report to
the Agency on the steps they have taken towards doing so is critical to
ensuring that those sources remain qualified for the exemption and thus
to maintaining the environmental integrity of these emission
guidelines.
The EPA is requiring existing coal-fired steam generating EGUs that
are in existence as of the date of a state plan submission but plan to
cease operating before January 1, 2032, to comply with certain
reporting requirements pursuant to CAA section 114(a). Among other
things, this provision gives the EPA authority to require recordkeeping
and reporting of sources for the purpose of ``developing or assisting
in the development of any implementation plan under . . . section
7411(d) of this title[ or] any standard of performance under section
7411 of this title,'' ``determining whether any person is in violation
of any such standard of any requirement of such a plan,'' or ``carrying
out any provision of this chapter.'' Owners or operators of coal-fired
steam generating EGUs that would be covered by these emission
guidelines but for their plans to permanently cease operating are
required to make reports necessary to ascertain whether they will in
fact qualify for the exemption. This reporting obligation is necessary
for preserving the integrity of the rule, and is consistent with
ensuring that states develop plans that include standards of
performance for all existing sources and for anticipating whether a
state plan may need to be revised to include a standard of performance
for an existing source that will not be eligible for an exemption from
these emission guidelines.\971\
---------------------------------------------------------------------------
\971\ The milestone reporting requirements for affected coal-
fired steam generating EGUs in the medium-term subcategory and those
relying on a shorter remaining useful life for a less-stringent
standard of performance pursuant to RULOF are authorized under both
CAA sections 114(a) and 111(d)(1), the latter of which provides that
state plans shall provide for the implementation and enforcement of
standards of performance. In that case, reporting requirements are
necessary to ensure that the predicate conditions for the sources'
standards of performance are satisfied.
---------------------------------------------------------------------------
[[Page 39997]]
The reporting requirements the EPA is promulgating for sources that
plan to permanently cease operation before January 1, 2032, are similar
to the reporting requirements the Agency is requiring for medium-term
coal-fired steam generating affected EGUs and affected EGUs relying on
a shorter remaining useful life for a less-stringent standard of
performance through RULOF. Those requirements are described in section
X.C.4 of this preamble and require the definition of milestones
tailored to individual units which are then embedded in periodic
reporting requirements to assess progress toward the cessation of
operations. However, consistent with CAA section 114, the requirements
for sources that are exempt from these emission guidelines are limited
to reporting and do not include the establishment of milestones. Thus,
the requirements are as follows: Five years before any planned date to
permanently cease operations or by the date upon which state plan is
submitted, whichever is later, the owner or operator of the EGU must
submit an initial report to the EPA that includes the following: (1) A
summary of the process steps required for the EGU to permanently cease
operation by the date included in the state plan, including the
approximate timing and duration of each step and any notification
requirements associated with deactivation of the unit. These process
steps may include, e.g., initial notice to the relevant reliability
authority of the deactivation date and submittal of an official
retirement filing (or equivalent filing) made to the EGU's reliability
authority. (2) Supporting regulatory documents, including
correspondence and official filings with the relevant regional RTO,
ISO, balancing authority, PUC, or other applicable authority; any
deactivation-related reliability assessments conducted by the RTO or
ISO; and any filings pertaining to the EGU with the SEC or notices to
investors, including but not limited to references in forms 10-K and
10-Q, in which the plans for the EGU are mentioned; any integrated
resource plans and PUC orders referring to or approving the EGU's
deactivation; any reliability analyses developed by the RTO, ISO, or
relevant reliability authority in response to the EGU's deactivation
notification; any notification from a reliability authority that the
EGU may be needed for reliability purposes notwithstanding the EGU's
intent to deactivate; and any notification to or from an RTO, ISO, or
relevant reliability authority altering the timing of deactivation for
the EGU.
For each of the remaining years prior to the date by which an EGU
has committed to permanently cease operations, the operator or operator
of an EGU must submit an annual status report to the EPA that includes:
(1) Progress on each of the process steps identified in the initial
report; and (2) supporting regulatory documents, including
correspondence and official filings with the relevant RTO, balancing
authority, PUC, or other applicable authority to demonstrate progress
toward all steps; and (3) regulatory documents, and relevant SEC
filings (listed in the preceding paragraph) that have been issued,
filed or received since the prior report.
The EPA is also requiring that EGUs that plan to permanently cease
operation by January 1, 2032, submit a final report to the EPA no later
than 6 months following its committed closure date. This report would
document any actions that the unit has taken subsequent to ceasing
operation to ensure that such cessation is permanent, including any
regulatory filings with applicable authorities or decommissioning
plans.
2. Timing of State Plan Submissions
The EPA proposed a state plan submission deadline that is 24 months
from the date of publication of the final emission guidelines, which,
at that time was 9 months longer than the default state plan submission
timeline in the proposed 40 CFR part 60, subpart Ba implementing
regulations. The EPA finalized subpart Ba with a default timeline of 18
months for state plan submissions, 40 CFR 60.23a(a)(1); regardless, the
EPA is superseding subpart Ba's timeline under these emission
guidelines and is requiring that state plans be submitted 24 months
after publication of this final rule in the Federal Register.
As discussed in the preamble to the proposed rule,\972\ these
emission guidelines apply to a relatively complex source category and
state plan development will require significant analysis, consultation,
and coordination between states, utilities, reliability authorities,
and the owners or operators of individual affected EGUs. The power
sector is subject to layers of regulatory and other requirements under
different authorities (e.g., environmental, electric reliability, SEC)
and the decisions states make under these emission guidelines will
necessarily have to accommodate overlapping considerations and
processes. States' plan development may have to integrate decision
making by not only the relevant air agency or agencies, but also ISOs,
RTOs, or other balancing authorities. While 18 months is a reasonable
timeframe to accommodate state plan development for source categories
that do not require this level of coordination, the EPA does not
believe it is reasonable to expect states and affected EGUs to
undertake the coordination and planning necessary to ensure that plans
for implementing these emission guidelines are consistent with the
broader needs and trajectory of the power sector within the default
period provided under subpart Ba.
---------------------------------------------------------------------------
\972\ 88 FR 33240, 33402-03 (May 23, 2023).
---------------------------------------------------------------------------
However, there are also notable differences between the
circumstances of the proposed versus these final emission guidelines
that are relevant to the state plan submission timeline. First, the EPA
is not finalizing emission guidelines applicable to combustion turbine
EGUs, which will significantly decrease the number of affected EGUs
that states must address in their plans. Relative to proposal, there
are approximately 184 fewer individual units to which these emission
guidelines will apply (based on information at the time of the final
rule), and the final emission guidelines do not include co-firing with
low-GHG hydrogen as a BSER. The analytical and other burdens associated
with state planning will thus be significantly lighter than anticipated
at proposal, as states will have to address not only fewer sources but
also a smaller universe of potential control strategies. Additionally,
as explained in section VII.B.1 of this preamble, these final emission
guidelines do not apply to existing coal-fired EGUs that plan to
permanently cease operation prior to January 1, 2032. While under the
proposed emission guidelines states would have had to establish
standards of performance for every existing source operating as of
January 1, 2030, states will be able to forgo addressing a subset of
these existing sources under this final rule.
In addition to states needing to address far fewer existing sources
in their state plans than anticipated under the proposed emission
guidelines, it is also not expected that the owners or operators of
sources will begin implementation of control strategies before state
plan submission. At proposal the EPA believed that some owners or
operators of affected EGUs would do feasibility and FEED studies for
CCS during state plan development,
[[Page 39998]]
i.e., before state plan submission. For other affected coal-fired EGUs,
the EPA anticipated that owners or operators would undertake certain
planning, design, and permitting steps prior to state plan
submission.\973\ In developing these final emission guidelines, the EPA
changed its earlier assumption that states and affected EGUs would take
significant steps towards planning and implementing control strategies
prior to state plan submission. There are certain preliminary steps,
such as an initial feasibility study, that the EPA expects that states
and/or affected EGUs will undertake as a typical part of the state
planning process. Under any rule or circumstances, it would not be
reasonable for a state to commit an affected EGU to installation and
operation of a certain control technology without undertaking at least
an initial assessment of that technology--this is what is accomplished
by feasibility studies. However, while the Agency believes that some
sources are currently or will be undertaking FEED studies or other
significant steps towards implementing pollution controls independent
of these emission guidelines at earlier times, the EPA is not assuming
when setting the compliance deadline that EGUs will be taking such
steps prior to the existence of a state law requirement to do so (i.e.,
prior to state plan adoption and submission).
---------------------------------------------------------------------------
\973\ 88 FR 33240, 33402 (May 23, 2023).
---------------------------------------------------------------------------
The EPA received a number of comments on the proposed 24-month
timeline for state plan submissions, which are discussed in detail
below. As a general matter, many of these comments requested a longer
timeframe for developing and submitting state plans. However, given
that the number of affected EGUs state plans will have to cover under
these final emission guidelines is very likely to be significantly
lower than anticipated based on the proposal and that the EPA is not
expecting states or owners or operators of affected EGUs to conduct
FEED studies or otherwise start work on implementation prior to state
plan submission, the EPA continues to believe that 24 months is an
appropriate timeframe. Additionally, as discussed in the preamble to
the recent revisions to the 40 CFR part 60, subpart Ba implementing
regulations, the EPA's approach to timelines for state plan submission
and review under CAA section 111(d) is informed by the need to minimize
the impacts of emissions of dangerous air pollutants on public health
and welfare by proceeding as expeditiously and as reasonably possible
while accommodating the time needed for states to develop an effective
plan.\974\ To this end, the EPA is promulgating a timeframe for state
plan submissions that is based on the minimum administrative time that
is reasonably necessary given the need for states and owners or
operators of affected EGUs to coordinate with reliability authorities
in the development of state plans. In this case, the EPA believes that
providing an additional 6 months beyond subpart Ba's 18 months for
state plan submissions is sufficient to accommodate this additional
coordination, particularly given that the number of affected EGUs that
states will be addressing in their plans is far fewer than expected
under the proposed emission guidelines.
---------------------------------------------------------------------------
\974\ See, e.g., 88 FR 80480, 80486 (November 17, 2023).
---------------------------------------------------------------------------
Comment: Several commenters supported the EPA's proposed 24-month
timeframe for state plan submissions and stressed the importance of
achieving emission reductions as quickly as possible. Commenters also
noted that, based on anecdotal evidence, 24 months is generally
sufficient to incorporate legislative, regulatory, and other
administrative procedures associates with submitting state plans. Many
commenters, however, requested that the EPA provide additional time for
states to develop and submit their state plans; many requested 36
months with some commenters asserting that even more time would be
required. Commenters asking for a longer timeframe cited reasons
including the size of states' EGU fleets and the specific BSERs
proposed for certain subcategories (i.e., CCS and hydrogen co-firing),
the need for owners or operators of affected EGUs to conduct systems
analyses and update their integrated resource plans (IRPs) prior to
making final decisions for state plans, and the need for states to get
their choices approved by the appropriate reliability and other
regulatory commissions.
Response: As explained above, the EPA has made a number of changes
in these final emission guidelines that have the effect of decreasing
the planning burden on states, including not finalizing requirements
for combustion turbine EGUs, exempting coal-fired EGUs that plan to
cease operating by January 1, 2032, finalizing fewer subcategories for
coal-fired EGUs, and not finalizing the subcategory for coal-fired EGUs
that was based on utilization level. In general, these changes will
decrease the number of units that state plans must address and also
decrease the number and complexity of decisions states must make with
regard to those units. Furthermore, 24 months is sufficient time for
states to complete the steps necessary to develop and submit a state
plan. Owners and operators are already or should already be considering
how they will operate in a future environment where sources operating
more cleanly are valued more. The EPA expects that states are already
working or will work closely with the operators and operators of
affected EGUs as those owners and operators update their IRPs and
proceed through any necessary processes with, e.g., PUCs and
reliability authorities. Thus, the Agency expects that consultation
with and between owners and operators, PUCs, and reliability
authorities is currently ongoing and will remain so throughout state
plan development and implementation. Against this backdrop of ongoing
planning and consultation, the EPA's obligation in these emission
guidelines is to ensure that state plan development and submission
occurs within a timeframe consistent with the ``adherence to [the
EPA's] 2015 finding of an urgent need to counteract the threats posed
by unregulated carbon dioxide emissions from coal-fired power plants.''
\975\ The timeframe the EPA is providing for state plan development
upfront coupled with the long lead times it is providing for compliance
with standards of performance provides states and owners or operators
ample time to ensure the orderly implementation of the control
requirements under these emission guidelines.
---------------------------------------------------------------------------
\975\ Am. Lung Ass'n v. EPA, 985 F.3d 914, 994 (D.C. Cir. 2021).
---------------------------------------------------------------------------
Comment: Several commenters asserted that the EPA should provide
longer than 24 months for state plan submissions to provide time for
states to work through their necessary rulemaking, legislative, and/or
administrative processes. Some commenters similarly stated that more
than 24 months is needed in order to accommodate meaningful engagement
on draft state plans.
Response: The default timeline provided for state plan development
and submission under 40 CFR part 60, subpart Ba is 18 months. As the
EPA acknowledged when it promulgated this timeframe, state regulatory
and legislative processes and resources can vary significantly and
influence the time needed to develop and submit state plans.\976\
However, the CAA contains
[[Page 39999]]
numerous, long-standing requirements under other programs for states to
develop and submit plans in 18 or fewer months. The EPA therefore
believes that states should be well positioned to accommodate an 18-
month state plan submission timeframe, let alone at 24-month timeframe,
from the perspective of the timing of state processes. The Agency does
not believe it would be reasonable or consistent with CAA section 111's
purpose of reducing air pollution that endangers public health and the
environment to extend state plan submission deadlines to defer to
lengthy state administrative processes.
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\976\ 88 FR 80480, 80488 (November 17, 2023).
---------------------------------------------------------------------------
Similarly, the EPA believes that 24 months provides sufficient time
for states to conduct meaningful engagement with pertinent stakeholders
under these emission guidelines. As discussed in section X.E.1.b.i of
this preamble, the EPA is providing additional information in these
final emission guidelines that states may use to inform their
meaningful engagement strategies and that can help them to fulfill
their obligations in a timely and diligent fashion. For example, the
EPA has noted a number of types of stakeholder communities to assist
states in identifying their pertinent stakeholders. It has also
provided information and tools that states may use in considering
options for state plans, including facility-specific information on air
emissions and the potential emissions implications of installing CCS.
Commenters also pointed out that several states have recently adopted
regulations, programs, and tools relevant to identifying pertinent
stakeholders and conducting meaningful engagement; such programs and
tools, in addition to states' growing body of knowledge and experience
pursuant to state initiatives and priorities, will aid states and
stakeholders alike in conducting robust meaningful engagement in the
timeframe for state plan development.
3. State Plan Revisions
As discussed in the preamble of the proposed action, the EPA
expects that the 24-month state plan submission deadline for these
emission guidelines would give states, utilities and independent power
producers, and stakeholders sufficient time to determine into which
subcategory each of the affected EGUs should fall and to formulate and
submit a state plan accordingly. However, the EPA also acknowledges
that, despite states' best efforts to accurately reflect the plans of
owners or operators with regard to affected EGUs at the time of state
plan submission, such plans may subsequently change. In general, states
have the authority and discretion to submit revised state plans to the
EPA for approval.\977\ State plan revisions are generally subject to
the same requirements as initial state plan submissions under these
emission guidelines and the subpart Ba implementing regulations,
including meaningful engagement, and the EPA reviews state plan
revisions against the applicable requirements of these emission
guidelines and the subpart Ba implementing regulations in the same
manner in which it reviews initial state plan submissions pursuant to
40 CFR 60.27a. Requirements of the initial state plan approved by the
EPA remain federally enforceable unless and until the EPA approves a
plan revision that supersedes such requirements. States and affected
EGUs should plan accordingly to avoid noncompliance.
---------------------------------------------------------------------------
\977\ 40 CFR 60.23a(a)(2), 60.28a.
---------------------------------------------------------------------------
The EPA is finalizing a state plan submission date that is 24
months after the publication of the final emission guidelines and is
finalizing the first compliance date for affected coal-fired EGUs in
the medium-term subcategory and affected natural gas- and oil-fired
EGUs of January 1, 2030. A state may choose to submit a plan revision
prior to the compliance dates in its existing state plan; however, the
EPA reiterates that any already approved federally enforceable
requirements, including milestones, increments of progress, and
standards of performance, will remain in place unless and until the EPA
approves the plan revision.
The EPA requested comment on whether it would be helpful to states
to impose a cutoff date for the submission of plan revisions before the
first compliance date. This would, in effect, establish a temporary
moratorium on plan submissions in order to allow the EPA to act on the
plans. State plan revisions would again be permitted after the final
compliance date. The EPA is not finalizing such cutoff date to provide
more flexibility to states in submitting revisions closer to the first
compliance date, in the case that EPA may be able to review those
revisions before the first compliance date.
Comment: Several commenters generally disagreed with establishing a
cutoff date for state plan revisions before the first compliance date,
arguing these timelines would be unworkable because state plan
revisions may require public notice and stakeholder engagement.
Response: The EPA is not finalizing an explicit cutoff date that
would in effect establish a temporary moratorium on plan submissions;
however, the EPA notes that, because the first compliance date under
the final emission guidelines is January 1, 2030, a plan revision
submitted after November 1, 2028 (taking into consideration 1 year for
EPA action on a state plan revision plus up to 60 days, approximately,
for a completeness determination) may not provide sufficient time for
the EPA to review and approve the plan sufficiently in advance of that
compliance date to allow sources to appropriately plan for compliance.
The EPA reiterates that EGUs will be expected to comply with any
requirements already approved in the state plan until such time as the
plan revision is approved.
4. Dual-Path Standards of Performance for Affected EGUs
As discussed in the proposed action, under the structure of these
emission guidelines, states would assign affected coal-fired EGUs to
subcategories in their state plans, and an affected EGU would not be
able to change its applicable subcategory without a state plan
revision. This is because, due to the nature of the BSERs for coal-
fired steam generating units, an affected EGU that switches into either
the medium-term or long-term subcategory may not be able to meet the
compliance obligations for a new and different subcategory without
considerable lead time; in order to ensure timely emission reductions,
it is important that states identify which subcategories affected EGUs
fall into in their state plan submissions so that affected EGUs have
certainty about their expected regulatory obligations. Therefore, as a
general matter, states must assign each affected EGU to a subcategory
and have in place all the legal instruments necessary to implement the
requirements for that subcategory by the time of state plan submission.
However, the EPA also solicited comment on a dual-path approach
that would allow coal-fired steam generating units to have two
different standards of performance submitted to the EPA in a state plan
based on potential inclusion in two different subcategories. This
proposal was based in large part on the proposed structure of the
subcategories for coal-fired affected EGUs, under which it would have
been realistic to expect that sources could prepare to comply with
either the presumptive standard of performance for, e.g., the imminent-
term subcategory and the near-term subcategory or the imminent-term
subcategory and the medium-term subcategory.
Because the final emission guidelines include only two
subcategories for coal-
[[Page 40000]]
fired affected EGUs and do not include the two subcategories for which
the dual-path approach would have been appropriate, the EPA is not
finalizing an approach that allows coal-fired steam generating units to
have two different standards of performance submitted to the EPA in a
state plan based on potential inclusion in two different subcategories.
Comment: In general, commenters supported a dual-path approach;
however, several commenters requested that the EPA accommodate a multi-
pathway approach (three or more pathways) due to the complexity of
state plans and potential for numerous compliance pathways because of
factors beyond the EGU owner or operator's control, such as
infrastructure for CCS projects and increase in electric power demand
due to electrification of the transportation sector.
Response: As stated above, the EPA is not finalizing the dual-path
approach, nor a multi-pathway approach. If an affected EGU wishes to
switch subcategories after the initial state plan approval, the state
should submit a state plan revision sufficiently in advance of the
compliance date for the subcategory into which it was assigned to
permit the EPA's review and action on that plan revision.
5. EPA Action on State Plans
Pursuant to the final revisions to 40 CFR part 60, subpart Ba, in
this action, the EPA is subject to a 60-day timeline for the
Administrator's determination of completeness of a state plan
submission and a 12-month timeline for action on state plans.\978\ The
timeframes and requirements for state plan submissions described in
this section also apply to state plan revisions.\979\
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\978\ 40 CFR 60.27a(b), (g)(1).
\979\ See generally 40 CFR 60.27a.
---------------------------------------------------------------------------
As discussed in the proposed action, the EPA would first review the
components of the state plan to determine whether the plan meets the
completeness criteria of 40 CFR 60.27a(g). The EPA must determine
whether a state plan submission has met the completeness criteria
within 60 days of its receipt of that submission. If the EPA has failed
to make a completeness determination for a state plan submission within
60 days of receipt, the submission shall be deemed, by operation of
law, complete as of that date. Subpart Ba requires the EPA to take
final action on a state plan submission within 12 months of that
submission's being deemed complete. The EPA will review the components
of state plan submissions against the applicable requirements of
subpart Ba and these emission guidelines, consistent with the
underlying requirement that state plans must be ``satisfactory'' ' per
CAA section 111(d). The Administrator would have the option to fully
approve; fully disapprove; partially approve and partially disapprove;
or conditionally approve a state plan submission.\980\ Any components
of a state plan submission that the EPA approves become federally
enforceable.
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\980\ 40 CFR 60.27a(b).
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The EPA solicited comment on the use of the timeframes regarding
EPA action on state plans in subpart Ba and commenters encouraged
reconsidering the schedule, suggesting either increasing or decreasing
the amount of time for action on state plans. In the final emission
guidelines, the EPA is not superseding the timeframes in subpart Ba
regarding EPA action on state plans and plan revisions.
Comment: One commenter suggested that the EPA should provide for
automatic extension of compliance dates for affected EGUs if the Agency
does not meet its 12-month deadline for plan approval.\981\ Other
commenters expressed concerns that the EPA will be unable to review all
plans in the 12-month timeframe. One commenter suggested that the EPA
should strive to review plans in less than the proposed 12-month
timeframe.\982\
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\981\ See Document ID No. EPA-HQ-OAR-2023-0072-0660.
\982\ See Document ID No. EPA-HQ-OAR-2023-0072-0764.
---------------------------------------------------------------------------
Response: The EPA does not believe it is appropriate to provide
automatic extensions of compliance dates based on the timeframe for EPA
action on state plan submissions. While there may be some degree of
regulatory uncertainty that stems from waiting for the Agency to act on
a state plan submission, it would not be a reasonable solution to add
to that uncertainty by also making compliance dates contingent on the
date of EPA's action. This additional uncertainty could have the effect
of unnecessarily extending the compliance schedule and delaying
emission reductions. Given that the dates on which the EPA takes final
action on individual state plans are likely to be many and varied
(based on, inter alia, when each state plan was submitted to the
Agency), such extensions would create unnecessary confusion and
potentially uneven application of the requirements for state plans. In
this action, the EPA does not find a reason to supersede the timelines
finalized in subpart Ba; therefore, review of and action on state plan
submissions will be governed by the requirements of revised subpart Ba.
6. Federal Plan Applicability and Promulgation Timing
The provisions of 40 CFR part 60, subpart Ba, apply to the EPA's
promulgation of any Federal plans under these emission guidelines. The
EPA's obligation to promulgate a Federal plan is triggered in three
situations: where a state does not submit a plan by the plan submission
deadline; where the EPA determines that a state plan submission does
not meet the completeness criteria and the time period for state plan
submission has elapsed; and where the EPA fully or partially
disapproves a state's plan.\983\ Where a state has failed to submit a
plan by the submission deadline, subpart Ba gives the EPA 12 months
from the state plan submission due date to promulgate a Federal plan;
otherwise, the 12-month period starts, as applicable, from the date the
state plan submission is deemed incomplete or from the date of the
EPA's disapproval. If the state submits and the EPA approves a state
plan submission that corrects the relevant deficiency within the 12-
month period, before the EPA promulgates a Federal plan, the EPA's
obligation to promulgate a Federal plan is relieved.\984\
---------------------------------------------------------------------------
\983\ 40 CFR 60.27a(c).
\984\ 40 CFR 60.27a(d).
---------------------------------------------------------------------------
As provided by 40 CFR 60.27a(e), a Federal plan will prescribe
standards of performance for affected EGUs of the same stringency as
required by these emission guidelines and will require compliance with
such standards as expeditiously as practicable but no later than the
final compliance date under these guidelines. However, 40 CFR
60.27a(e)(2) provides that, upon application by the owner or operator
of an affected EGU, the EPA may provide for the application of a less
stringent standard of performance or longer compliance schedule than
provided by these emission guidelines, in which case the EPA would
follow the same process and criteria in the regulations that apply to
states' provision of RULOF standards. Under subpart Ba, the EPA is also
required to conduct meaningful engagement with pertinent stakeholders
prior to promulgating a Federal plan.\985\
---------------------------------------------------------------------------
\985\ 40 CFR 60.27a(f).
---------------------------------------------------------------------------
As discussed in section X.E.2 of this preamble, the EPA is
finalizing a deadline for state plan submissions of 24 months after
publication of these final emission guidelines in the Federal Register.
Therefore, if a state fails to timely submit a state plan, the EPA
[[Page 40001]]
would be obligated to promulgate a Federal plan within 36 months of
publication of these final emission guidelines. Note that this will be
the earliest possible obligation for the EPA to promulgate a Federal
plan and that different triggers (e.g., a disapproved state plan) will
result in later obligations to promulgate Federal plans for other
states, contingent on when the obligation is triggered.
Finally, the EPA acknowledges that, if a Tribe does not seek and
obtain the authority from the EPA to establish a TIP, the EPA has the
authority to establish a Federal CAA section 111(d) plan for areas of
Indian country where designated facilities are located. A Federal plan
would apply to all designated facilities located in the areas of Indian
country covered by the Federal plan unless and until the EPA approves
an applicable TIP applicable to those facilities.
XI. Implications for Other CAA Programs
A. New Source Review Program
The CAA's New Source Review (NSR) preconstruction permitting
program applies to stationary sources that emit pollutants resulting
from new construction and modifications of existing sources. The NSR
program is authorized by CAA section 110(a)(2)(C), which requires that
each state implementation plan (SIP) ``include a program to provide for
the . . . regulation of the modification and construction of any
stationary source within the areas covered by the plan as necessary to
assure that [NAAQS] are achieved, including a permit program as
required in parts C and D [of title I of the CAA].'' The ``permit
program as required in parts C and D'' refers to the ``major NSR''
program, which applies to new ``major stationary sources'' \986\ and
``major modifications'' \987\ of existing stationary sources. The
``minor NSR'' program applies to new construction and modifications of
stationary sources that do not meet the emission thresholds for major
NSR. NSR applicability is pollutant-specific, so a source seeking to
newly construct or modify may need to obtain both major NSR and minor
NSR permits before it can begin construction.
---------------------------------------------------------------------------
\986\ 40 CFR 52.21(b)(1)(i).
\987\ 40 CFR 52.21(b)(2)(i) and the term ``net emissions
increase'' as defined at 40 CFR 52.21(b)(3).
---------------------------------------------------------------------------
Under the CAA, states have primary responsibility for issuing NSR
permits, and they can customize their programs within the limits of EPA
regulations. The Federal NSR rules applying to state permitting
authorities are found at 40 CFR 51.160 to 51.166. The EPA's primary
role is to approve state program regulations and to review, comment on,
and take any other necessary actions on draft and final permits to
assure consistency with the EPA's rules, the SIP, and the CAA. When a
state does not have EPA-approved authority to issue NSR permits, the
EPA issues the NSR permits within the state, or delegates authority to
the state to issue the NSR permits on behalf of the EPA, pursuant to
rules at 40 CFR 49.151-173, 40 CFR 52.21, and 40 CFR 124.
For the major NSR program, the requirements that apply to a source
depend on the air quality designation at the location of the source for
each of its emitted pollutants at the time the permit is issued. Major
NSR permits for sources located in an area that is designated as
attainment or unclassifiable for the NAAQS for its pollutants are
referred to as Prevention of Significant Deterioration (PSD) permits.
PSD permits can include requirements for specific pollutants for which
there are no NAAQS.\988\ Sources subject to PSD must, among other
requirements, comply with emission limitations that reflect the Best
Available Control Technology (BACT) for ``each pollutant subject to
regulation'' as specified by CAA sections 165(a)(4) and 169(3). Major
NSR permits for sources located in nonattainment areas and that emit at
or above the specified major NSR threshold for the pollutant for which
the area is designated as nonattainment are referred to as
Nonattainment NSR (NNSR) permits. Sources subject to NNSR must, among
other requirements, meet the Lowest Achievable Emission Rate (LAER)
pursuant to CAA sections 171(3) and 173(a)(2) for any pollutant subject
to NNSR. For the minor NSR program, neither the CAA nor the EPA's rules
set forth a minimum control technology requirement.
---------------------------------------------------------------------------
\988\ [thinsp]For the PSD program, ``regulated NSR pollutant''
includes any pollutant for which a NAAQS has been promulgated
(``criteria pollutants'') and any other air pollutant that meets the
requirements of 40 CFR 52.21(b)(50). Some of these non-criteria
pollutants include greenhouse gases, fluorides, sulfuric acid mist,
hydrogen sulfide, and total reduced sulfur.
---------------------------------------------------------------------------
In keeping with the goal of progress toward attaining the NAAQS,
sources seeking NNSR permits must provide or purchase ``offsets''--
i.e., decreases in emissions that compensate for the increases from the
new source or modification. For sources seeking PSD permits, offsets
are not required, but they must demonstrate that the emissions from the
project will not cause or contribute to a violation of the NAAQS or the
``PSD increments'' (i.e., margins of ``significant'' air quality
deterioration above a baseline concentration that establish an air
quality ceiling, typically below the NAAQS, for each PSD area). Sources
can often make this air quality demonstration based on the BACT level
of control or by accepting more stringent air quality-based
limitations. However, if these methods are insufficient to show that
increased emissions from the source will not cause or contribute to a
violation of air quality standards, applicants may undertake mitigation
measures that are analogous to offsets in order to satisfy this PSD
permitting criterion.
When the EPA is making NSR permitting decisions, it has legal
authority to consider potential disproportionate environmental burdens
on a case-by-case basis. Based on Executive Order (E.O.) 12898, the
EPA's Environmental Appeals Board (EAB) has held that environmental
justice considerations must be considered in connection with the
issuance of Federal PSD permits issued by EPA Regional Offices or
states acting under delegations of Federal authority. The EAB ``has . .
. encouraged permit issuers to examine any `superficially plausible'
claim that a minority or low-income population may be
disproportionately affected by a particular facility.'' \989\ EPA
guidance and EAB decisions do not advise EPA Regional Offices or
delegated NSR permitting authorities to integrate environmental justice
considerations into any particular component of the PSD permitting
review, such as the determination of BACT. The practice of EPA Regional
Offices and delegated states has been to conduct a largely freestanding
environmental justice analysis for PSD permits that can take into
account case-specific factors germane to any individual permit
decision.
---------------------------------------------------------------------------
\989\ In re Shell Gulf of Mexico, Inc., 15 E.A.D. 103, 149 and
n.71 (EAB 2010) (internal citations omitted).
---------------------------------------------------------------------------
The minimum requirements for an approvable state NSR permitting
program do not require state permitting authorities to reflect
environmental justice considerations in their permitting decisions.
However, states that implement NSR programs under an EPA-approved SIP
have discretion to consider environmental justice in their NSR
permitting actions and adopt additional requirements in the permitting
decision to address potential disproportionate environmental burdens.
Additionally, in some cases, a
[[Page 40002]]
state law requires consideration of environmental justice in the
state's permitting decisions.
Through the NSR permit review process, permitting authorities have
requirements for public participation in decision-making, which provide
discretion for permitting authorities to provide enhanced engagement
for communities with environmental justice concerns. This includes
opportunities to enhance environmental justice by facilitating
increased public participation in the formal permit consideration
process (e.g., by granting requests to extend public comment periods,
holding multiple public meetings, or providing translation services at
hearings in areas with limited English proficiency). The permitting
authority can also take informal steps to enhance participation earlier
in the process, such as inviting community groups to meet with the
permitting authority and express their concerns before a draft permit
is issued.
Additionally, in accordance with CAA 165(a)(2), the PSD regulations
require the permitting authority to ``[p]rovide opportunity for a
public hearing for interested persons to appear and submit written or
oral comments on the air quality impact of the source, alternatives to
it, the control technology required, and other appropriate
considerations.'' 40 CFR 51.166(q)(2)(v). The ``alternatives'' and
``other appropriate considerations'' language in CAA 165(a)(2) can be
interpreted to provide the permitting authority with discretion to
incorporate siting and environmental justice considerations when
issuing PSD permits--specifically, to impose permit conditions on the
basis of environmental justice considerations raised in public comments
regarding the air quality impacts of a proposed source. The EAB has
recognized that consideration of the need for a facility is within the
scope of CAA 165(a)(2) when a commenter raises the issue. The EPA has
recognized that this language provides a potential statutory foundation
in the CAA for this discretion.\990\ The Federal regulations for NNSR
permits also have an analysis of alternatives required by CAA
173(a)(5). 40 CFR 51.165(i).
---------------------------------------------------------------------------
\990\ See Memorandum from Gary S. Guzy, EPA General Counsel,
titled EPA Statutory and Regulatory Authorities Under Which
Environmental Justice Issues May Be Addressed in Permitting
(December 1, 2000).
---------------------------------------------------------------------------
1. Control Technology Reviews for Major NSR Permits
The statutory and regulatory basis for a control technology review
for a source undergoing major NSR permitting differs from the criteria
required in establishing an NSPS or emission guidelines. As such,
sources that are permitted under major NSR may have differing control
requirements for a pollutant than what is required by an applicable
standard under CAA section 111. As noted above, sources permitted under
the minor NSR program do not have a minimum control technology standard
specified by statute or EPA rule, so a permitting authority has more
flexibility in its determination of control technology for aminor NSR
permit.
For PSD permits, the permitting authority must establish emission
limitations based on BACT for each pollutant that is subject to PSD at
the new major stationary source or at each emissions unit involved in
the major modification. BACT is assessed on a case-by-case basis, and
the permitting authority, in its analysis of BACT for each pollutant,
evaluates the emission reductions that each available emissions-
reducing technology or technique would achieve, as well as the energy,
environmental, economic, and other costs associated with each
technology or technique. The CAA also specifies that BACT cannot be
less stringent than any applicable standard of performance under the
NSPS.\991\
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\991\ 42 U.S.C. 7479(3) (``In no event shall application of
`best available control technology' result in emissions of any
pollutants which will exceed the emissions allowed by any applicable
standard established pursuant to [CAA Section 111 or 112].'').
---------------------------------------------------------------------------
In conducting a BACT analysis, many permitting authorities apply
the EPA's five-step ``top-down'' approach, which the EPA recommends to
ensure that all the criteria in the CAA's definition of BACT are
considered. This approach begins with the permitting authority
identifying all available control options that have the potential for
practical application for the regulated NSR pollutant and emissions
unit under evaluation. The analysis then evaluates each option and
eliminates options that are technically infeasible, ranks the remaining
options from most to least effective, evaluates the energy,
environmental, economic impacts, and other costs of the options,
eliminates options that are not achievable based on these
considerations from the top of the list down, and ultimately selects
the most effective remaining option as BACT.\992\
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\992\ For more information on EPA's recommended BACT approach,
see U.S. Environmental Protection Agency, New Source Review Workshop
Manual (October 1990; Draft) at https://www.epa.gov/sites/default/files/2015-07/documents/1990wman.pdf and U.S. Environmental
Protection Agency, PSD and Title V Permitting Guidance for
Greenhouse Gases (March 2011; EPA-457/B-11-001) at https://www.epa.gov/sites/default/files/2015-07/documents/ghgguid.pdf.
---------------------------------------------------------------------------
While the BACT review process is intended to capture a broad array
of potential options for pollution control, the EPA has recognized that
the list of available control options need not necessarily include
inherently lower polluting processes that would fundamentally redefine
the nature of the source proposed by the permit applicant. Thus, BACT
should generally not be applied to regulate the permit applicant's
purpose or objective for the proposed facility. However, this approach
does not preclude a permitting authority from considering options that
would change aspects (either minor or significant) of an applicants'
proposed facility design in order to achieve pollutant reductions that
may or may not be deemed achievable after further evaluation at later
steps of the process. The EPA does not interpret the CAA to prohibit
fundamentally redefining the source and has recognized that permitting
authorities have the discretion to conduct a broader BACT analysis if
they desire. The ``redefining the source'' issue is ultimately a
question of degree that is within the discretion of the permitting
authority, and any decision to exclude an option on ``redefining the
source'' grounds should be explained and documented in the permit
record.
In conducting the analysis of energy, environmental and economic
impacts arising from each control option remaining under consideration,
permitting authorities have considerable discretion in deciding the
specific form of the BACT analysis and the weight to be given to the
particular impacts under consideration. The EPA and other permitting
authorities have most often used this analysis to eliminate more
stringent control technologies with significant or unusual effects that
are unacceptable in favor of the less stringent technologies with more
acceptable collateral environmental effects. Permitting authorities may
consider a wide variety of environmental impacts in this analysis, such
as solid or hazardous waste generation, discharges of polluted water
from a control device, visibility impacts, demand on local water
resources, and emissions of other pollutants subject to NSR or
pollutants not regulated under NSR such as air toxics. A permitting
authority could place more weight on the collateral environmental
effect of a control alternative on local communities--e.g., if emission
increases of co-pollutants from operating the control device may
disproportionately
[[Page 40003]]
affect a minority or low-income population--which may result in the
permitting authority eliminating that control option and ultimately
selecting a less stringent control technology for the target pollutant
as BACT because it has more acceptable collateral impacts.
In addition, this analysis may extend to considering reduced, or
excessive, energy or environmental impacts of the control alternative
at an offsite location that is in support the operation of the facility
obtaining the permit. For example, in the case of a facility that
proposes to co-fire its new stationary combustion turbines with
hydrogen procured from an offsite production facility, a permitting
authority may determine it is appropriate to weigh favorably a control
option that involves co-firing with hydrogen produced from low-GHG
emitting processes, such as electrolysis powered by renewable energy,
to recognize the reduced environmental impact of producing the fuel for
the control option.
For NNSR permits, the statutory requirement for establishing LAER
is more prescriptive and, consequently, tends to provide less
discretion to permitting authorities than the discretion allowed under
BACT. For new major stationary sources and major modifications in
nonattainment areas, LAER is defined as the most stringent emission
limitation required under a SIP or achieved in practice for a class or
category of sources. Thus, unlike BACT, the LAER requirement does not
consider economic, energy, or other environmental factors, except that
LAER is not considered achievable if the cost of control is so great
that a major new stationary source could not be built or operated.\993\
As with BACT determinations, a determination of LAER cannot be less
stringent than any applicable NSPS.\994\
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\993\ New Source Review Workshop Manual (October 1990; Draft),
page G.4.
\994\ 42 U.S.C. 7501(3); 40 CFR 51.165(a)(1)(xiii); 40 CFR part
51, appendix S, section II.A.18.
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2. NSR Implications of the NSPS
Any source that is planning to install a new or reconstructed EGU
that meets the applicability of this final NSPS will likely require an
NSR permit prior to its construction. In addition to including
conditions for GHG emissions, the NSR permit would contain emission
limitations for the non-GHG pollutants emitted by the new or
reconstructed EGU. Depending on the level of emissions for each
pollutant, the source may require a major NSR permit, minor NSR permit,
or a combination of both types of permits.
As GHGs are regulated pollutants under the PSD program, this NSPS
serves as the minimum level of control in determining BACT for any new
major stationary source or major modification that meets the
applicability of this NSPS and commences construction on its affected
EGU(s) after the date of publication of the proposed NSPS in the
Federal Register. However, as explained above, the fact that a minimum
control requirement for BACT is established by an applicable NSPS does
not mean that a permitting authority cannot select a more stringent
control level for the PSD permit or consider control technologies for
BACT beyond those that were considered in developing the NSPS. The
authority for BACT is separate from that of BSER, and it requires a
case-by-case review of a specific stationary source at the time its
owner or operator applies for a PSD permit. Accordingly, the BACT
analysis for a source with an applicable NSPS should reflect source-
specific factors and any advances in control technology, reductions in
the costs or other impacts of using particular control strategies, or
other relevant information that may have become available after the EPA
issued the NSPS.
3. NSR Implications of the Emission Guidelines
With respect to the final emission guidelines, each state will
develop a plan that establishes standards of performance for each
affected EGU in the state that meets the applicability criteria of this
emission guidelines. In doing so, a state agency may develop a plan
that requires an existing stationary source to undertake a physical or
operational change. Under the NSR program, when a stationary source
undertakes a physical or operational change, even if it is doing so to
comply with a national or state level requirement, the source may need
to obtain a preconstruction NSR permit, with the type of permit (i.e.,
NNSR, PSD, or minor NSR) depending on the amount of the emissions
increase resulting from the change and the air quality designation at
the location of the source for its emitted pollutants. However, since
emission guidelines are intended to reduce emissions at an existing
stationary source, a NSR permit may not be needed to perform the
physical or operational change required by the state plan if the change
will not increase emissions at the source.
As noted elsewhere in this preamble, sources that will be complying
with their state plan's standards of performance by installing and
operating CCS could experience criteria pollutant emission increases
that may result in the source triggering major NSR requirements. If a
source with an affected EGU does trigger major NSR requirements for one
or more pollutants as a result of complying with its standards of
performance, the permitting authority would conduct a control
technology review (i.e., BACT or LAER, as appropriate) for each of the
pollutants and require that the source comply with the other applicable
major NSR requirements. As noted in section VII of this preamble, in
light of concerns expressed by stakeholders over possible co-pollutant
increases from CCS retrofit projects, the EPA plans to review its NSR
guidance and determine how it can be updated to better assist permit
applicants and permitting authorities in conducting BACT reviews for
sources that intend to install CCS.
States may also establish the standards of performance in their
plans in such a way so that their affected sources, in complying with
those standards, in fact would not have emission increases that trigger
major NSR requirements. To achieve this, the state would need to
conduct an analysis consistent with the NSR regulatory requirements
that supports its determination that as long as affected sources comply
with the standards of performance, their emissions would not increase
in a way that trigger major NSR requirements. For example, a state
could, as part of its state plan, develop enforceable conditions for a
source expected to trigger major NSR that would effectively limit the
unit's ability to increase its emissions in amounts that would trigger
major NSR (effectively establishing a synthetic minor limitation).\995\
Some commenters asserted that base load units may not be able to
readily rely on this option to limit their emission increases given the
need for those units to respond to demand and maintain grid
reliability. In these cases, states may adopt other strategies in their
state plans to ensure that base load units have the needed flexibility
to operate and do so without triggering major NSR requirements.
---------------------------------------------------------------------------
\995\ Certain stationary sources that emit or have the potential
to emit a pollutant at a level that is equal to or greater than
specified thresholds are subject to major source requirements. See,
e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A synthetic
minor limitation is a legally and practicably enforceable
restriction that has the effect of limiting emissions below the
relevant level and that a source voluntarily obtains to avoid major
stationary source requirements, such as the PSD or title V
permitting programs. See, e.g., 40 CFR 52.21(b)(4), 51.166(b)(4),
70.2 (definition of ``potential to emit'').
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[[Page 40004]]
B. Title V Program
Title V regulations require each permit to include emission
limitations and standards, including operational requirements and
limitations that assure compliance with all applicable requirements.
Requirements resulting from these rules that are imposed on EGUs or
other potentially affected entities that have title V operating permits
are applicable requirements under the title V regulations and would
need to be incorporated into the source's title V permit in accordance
with the schedule established in the title V regulations. For example,
if the permit has a remaining life of 3 years or more, a permit
reopening to incorporate the newly applicable requirement shall be
completed no later than 18 months after promulgation of the applicable
requirement. If the permit has a remaining life of less than 3 years,
the newly applicable requirement must be incorporated at permit
renewal.\996\ Additionally, proceedings to reopen and issue a permit
shall follow the same procedures that apply to initial permit issuance
and only affect the parts of the permit for which cause to reopen
exists. The reopening of permits is expected to be made as
expeditiously as possible.\997\
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\996\ See 40 CFR 70.7(f)(1)(i).
\997\ See 40 CFR 70.7(f)(2).
---------------------------------------------------------------------------
In the proposal, the EPA also indicated that if a state needs to
include provisions related to the state plan in a source's title V
permit before submitting the plan to the EPA, these limits should be
labeled as ``state-only'' or ``not federally enforceable'' until the
EPA has approved the state plan. The EPA solicited comments on whether,
and under what circumstances, states might use this mechanism. While no
specific comments were received on this point, the EPA would like to
further clarify that in finalizing this direction, the intention is to
ensure that meaningful public participation is available during the
development of a state plan, rather than limiting engagement to the
permitting process. While the public would have the opportunity to
comment on the individual permit provisions, this would not allow for
the opportunity to comment on the plan as a whole before it is
finalized.
XII. Summary of Cost, Environmental, and Economic Impacts
In accordance with E.O. 12866 and 13563, the guidelines of the
Office of Management and Budget (OMB) Circular A-4 and the EPA's
Guidelines for Preparing Economic Analyses, the EPA prepared an RIA for
these final actions. The RIA is separate from the EPA's statutory BSER
determinations and did not influence the EPA's choice of BSER for any
of the regulated source categories or subcategories. This RIA presents
the expected economic consequences of the EPA's final rules, including
analysis of the benefits and costs associated with the projected
emission reductions for three illustrative scenarios. The first
scenario represents the final NSPS and emission guidelines in
combination. The second and third scenarios represent different
stringencies of the combined policies. All three illustrative scenarios
are compared against a single baseline. For detailed descriptions of
the three illustrative scenarios and the baseline, see section 1 of the
RIA, which is titled ``Regulatory Impact Analysis for the 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'' and is available in the rulemaking docket.\998\
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\998\ The EPA also examined the final rules under a variety of
different assumptions regarding demand, gas price, and
contemporaneous rulemakings and determined that those alternative
projections, inclusive of CCS buildout and cost profiles, would not
alter any BSER design parameters selected in this action. For
further discussion, see the technical memorandum, IPM Sensitivity
Runs, available in the rulemaking docket.
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The three scenarios detailed in the RIA, including the final rules
scenario, are illustrative in nature and do not represent the plans
that states may ultimately pursue. As there are considerable
flexibilities afforded to states in developing their state plans, the
EPA does not have sufficient information to assess specific compliance
measures on a unit-by-unit basis. Nonetheless, the EPA believes that
such illustrative analysis can provide important insights.
In the RIA, the EPA evaluates the potential impacts of the three
illustrative scenarios using the present value (PV) of costs, benefits,
and net benefits, calculated for the years 2024 to 2047 from the
perspective of 2019. In addition, the EPA presents the assessment of
costs, benefits, and net benefits for specific snapshot years,
consistent with the Agency's historic practice. These specific snapshot
years are 2028, 2030, 2035, 2040, and 2045. In addition to the core
benefit-cost analysis, the RIA also includes analyses of anticipated
economic and energy impacts, environmental justice impacts, and
employment impacts.
The analysis presented in this preamble section summarizes key
results of the illustrative final rules scenario. For detailed benefit-
cost results for the three illustrative scenarios and results of the
variety of impact analysis just mentioned, please see the RIA, which is
available in the docket for this action.
It should be noted that for the RIA for this rulemaking, the EPA
undertook the same approach to determine benefits and costs as it has
generally taken in prior rulemakings concerning the electric power
sector. It does not rely on the benefit-cost results included in the
RIA as part of its BSER analysis. Rather, the BSER analysis considers
the BSER criteria as set out in CAA section 111(a)(1) and the caselaw--
including the costs of the controls to the source, the amount of
emission reductions, and other criteria--as described in section V.C.2.
A. Air Quality Impacts
For the analysis of the final rules, total cumulative power sector
CO2 emissions between 2028 and 2047 are projected to be
1,382 million metric tons lower under the illustrative final rules
scenario than under the baseline. Table 4 shows projected aggregate
annual electricity sector emission changes for the illustrative final
rules scenario, relative to the baseline.
Table 4--Projected Electricity Sector Emission Impacts for the Illustrative Final Rules Scenario, Relative to the Baseline
--------------------------------------------------------------------------------------------------------------------------------------------------------
Direct PM2.5
CO2 (million Annual NOX Ozone season Annual SO2 (thousand Mercury
metric tons) (thousand NOX (thousand (thousand short tons) (tons)
short tons) short tons) short tons)
--------------------------------------------------------------------------------------------------------------------------------------------------------
2028....................................................... -38 -20 -6 -34 -2 -0.1
[[Page 40005]]
2030....................................................... -50 -20 -7 -20 -2 -0.1
2035....................................................... -123 -49 -19 -90 -1 -0.1
2040....................................................... -54 -6 -6 -4 2 0.2
2045....................................................... -42 -24 -14 -41 -2 -0.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
Note: Ozone season is the May through September period in this analysis.
B. Compliance Cost Impacts
The power industry's compliance costs are represented in this
analysis as the change in electric power generation costs between the
baseline and illustrative scenarios, including the cost of monitoring,
reporting, and recordkeeping. In simple terms, these costs are an
estimate of the increased power industry expenditures required to
comply with the final actions.
The compliance assumptions--and, therefore, the projected
compliance costs--set forth in this analysis are illustrative in nature
and do not represent the plans that states may ultimately pursue. The
illustrative final rules scenario is designed to reflect, to the extent
possible, the scope and nature of the final rules. However, there is
uncertainty with regards to the precise measures that states will adopt
to meet the requirements because there are flexibilities afforded to
the states in developing their state plans.
The IRA is projected to accelerate the ongoing shift towards lower-
emitting technology. In particular, under the baseline tax credits for
low-emitting technology results in growing generation share for
renewable resources and the deployment of 11 GW of CCS retrofits on
existing coal-fired steam generating units by 2035. New combined cycle
builds are 20 GW by 2030, and existing coal capacity continues to
decline, falling to 84 GW by 2030 and 31 GW by 2040. Under the
illustrative final rules scenario, the EPA projects an incremental 8 GW
of CCS retrofits on existing coal-fired steam generating units by 2035
relative to the baseline. By 2035, relative to the baseline, new
combined cycle builds are 2 GW lower, new combustion turbine builds are
10 GW higher, and wind and solar additions are 15 GW higher. Total coal
capacity is projected to be 73 GW in 2030 and 19 GW by 2040. As a
result, the compliance cost of the final rules is lower than it would
be absent the IRA.
We estimate the PV of the projected compliance costs for the
analysis of the final standards for new combustion turbines and for
existing steam generating EGUs over the 2024 to 2047 period, as well as
estimate the equivalent annual value (EAV) of the flow of the
compliance costs over this period. The EAV represents a flow of
constant annual values that, had they occurred annually, would yield a
sum equivalent to the PV. All dollars are in 2019 dollars. We estimate
the PV and EAV using discount rates of 2 percent, 3 percent, and 7
percent.\999\ The PV of compliance costs discounted at the 2 percent
rate is estimated to be about 19 billion, with an EAV of about 0.98
billion. At the 3 percent rate, the PV of compliance costs is estimated
to be about 15 billion, with an EAV of about 0.91 billion. At the 7
percent discount rate, the PV of compliance costs is estimated to be
about 7.5 billion, with an EAV of about 0.65 billion. To put this in
perspective, this levelized compliance cost is roughly one percent of
the total projected levelized cost to produce electricity over the same
timeframe under the baseline.
---------------------------------------------------------------------------
\999\ Results using the 2 percent discount rate were not
included in the proposals for these actions. The 2003 version of
OMB's Circular A-4 had generally recommended 3 percent and 7 percent
as default rates to discount social costs and benefits. The analysis
of the proposed rules used these two recommended rates. In November
2023, OMB finalized an update to Circular A-4, in which it
recommended the general application of a 2 percent rate to discount
social costs and benefits (subject to regular updates). The Circular
A-4 update also recommended consideration of the shadow price of
capital when costs or benefits are likely to accrue to capital. As a
result of the update to Circular A-4, we include cost and benefits
results calculated using a 2 percent discount rate.
---------------------------------------------------------------------------
Section 3 of the RIA presents detailed discussions of the
compliance cost projections for the final rule requirements, as well as
projections of compliance costs for less and more stringent regulatory
options.
C. Economic and Energy Impacts
These final actions have economic and energy market implications.
The energy impact estimates presented here reflect the EPA's
illustrative analysis of the final rules. States are afforded
flexibility to implement the final rules, and thus the estimated
impacts could be different to the extent states make different choices
than those assumed in the illustrative analysis. In addition, as
discussed in section VII.E.1 of this preamble, the factors driving
these impacts, including potential revenue streams for captured carbon,
may change over the next 25 years, leading the estimated impacts to be
different than reality. Table 5 presents a variety of energy market
impact estimates for 2028, 2030, 2035, 2040, and 2045 for the
illustrative final rules scenario, relative to the baseline.
Table 5--Summary of Certain Energy Market Impacts for the Illustrative Final Rules Scenario, Relative to the
Baseline
[Percent change]
----------------------------------------------------------------------------------------------------------------
2028 (%) 2030 (%) 2035 (%) 2040 (%) 2045 (%)
----------------------------------------------------------------------------------------------------------------
Retail electricity prices...................... -1 0 1 0 1
Average price of coal delivered to power sector -1 -1 0 0 -32
Coal production for power sector use........... -6 -4 -21 15 -84
Price of natural gas delivered to power sector. -2 0 3 0 0
Price of average Henry Hub (spot).............. -2 -1 3 0 0
[[Page 40006]]
Natural gas use for electricity generation..... -1 -2 4 0 2
----------------------------------------------------------------------------------------------------------------
These and other energy market impacts are discussed more
extensively in section 3 of the RIA.
More broadly, changes in production in a directly regulated sector
may have effects on other markets when output from that sector--for
these rules, electricity--is used as an input in the production of
other goods. It may also affect upstream industries that supply goods
and services to the sector, along with labor and capital markets, as
these suppliers alter production processes in response to changes in
factor prices. In addition, households may change their demand for
particular goods and services due to changes in the price of
electricity and other final goods prices. Economy-wide models--and,
more specifically, computable general equilibrium (CGE) models--are
analytical tools that can be used to evaluate the broad impacts of a
regulatory action. A CGE-based approach to cost estimation concurrently
considers the effect of a regulation across all sectors in the economy.
In 2015, the EPA established a Science Advisory Board (SAB) panel
to consider the technical merits and challenges of using economy-wide
models to evaluate costs, benefits, and economic impacts in regulatory
analysis. In its final report, the SAB recommended that the EPA begin
to integrate CGE modeling into applicable regulatory analysis to offer
a more comprehensive assessment of the effects of air
regulations.\1000\ In response to the SAB's recommendations, the EPA
developed a new CGE model called SAGE designed for use in regulatory
analysis. A second SAB panel performed a peer review of SAGE, and the
review concluded in 2020.\1001\
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\1000\ U.S. EPA. 2017. SAB Advice on the Use of Economy-Wide
Models in Evaluating the Social Costs, Benefits, and Economic
Impacts of Air Regulations. EPA-SAB-17-012.
\1001\ U.S. EPA. 2020. Technical Review of EPA's Computable
General Equilibrium Model, SAGE. EPA-SAB-20-010.
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The EPA used SAGE to evaluate potential economy-wide impacts of
these final rules, and the results are contained in section 5.2 of the
RIA. Note that SAGE does not currently estimate changes in emissions
nor account for environmental benefits. The annualized social cost
estimated in SAGE for the finalized rules is approximately $1.32
billion (2019 dollars) between 2024 and 2047 using a 4.5 percent
discount rate that is consistent with the internal discount rate in the
model. Under the assumption that compliance costs from IPM in 2056
continue until 2081, the equivalent annualized value for social costs
in the SAGE model is $1.51 billion (2019 dollars) over the period from
2024 to 2081, again using a 4.5 percent discount rate that is
consistent with the internal discount rate of the model. The social
cost estimate reflects the combined effect of the final rules'
requirements and interactions with IRA subsidies for specific
technologies that are expected to see increased use in response to the
final rules. We are not able to identify their relative roles
currently.
At proposal, the EPA solicited comment on the SAGE analysis
presented in the RIA appendix. The SAGE analysis of the final rules is
responsive to those comments. The comments received were supportive of
the use of SAGE for estimating economy-wide social costs and other
economy-wide impacts alongside the IPM-based cost and benefit
estimates. The comments also suggested a variety of sensitivity
analyses and several longer-term research goals for improving the
capabilities of SAGE, such as adding a representation of emissions
changes. For more detailed comment summaries and responses, see the
response to comments in the docket for these actions.
Environmental regulation may affect groups of workers differently,
as changes in abatement and other compliance activities cause labor and
other resources to shift. An employment impact analysis describes the
characteristics of groups of workers potentially affected by a
regulation, as well as labor market conditions in affected occupations,
industries, and geographic areas. Employment impacts of these final
actions are discussed more extensively in section 5 of the RIA.
D. Benefits
This section includes the estimated total benefits and the
estimated net benefits of the final rules.
1. Total Benefits
Pursuant to E.O. 12866, the RIA for these actions analyzes the
benefits associated with the projected emission changes under the final
rules to inform the EPA and the public about these projected impacts.
These final rules are projected to reduce national emissions of
CO2, SO2, NOX, and PM2.5,
which we estimate will provide climate benefits and public health
benefits. The potential climate, health, welfare, and water quality
impacts of these emission changes are discussed in detail in the RIA.
In the RIA, the EPA presents the projected monetized climate benefits
due to reductions in CO2 emissions and the monetized health
benefits attributable to changes in SO2, NOX, and
PM2.5 emissions, based on the emissions estimates in
illustrative scenarios described previously. We monetize benefits of
the final rules and evaluate other costs in part to enable a comparison
of costs and benefits pursuant to E.O. 12866, but we recognize that
there are substantial uncertainties and limitations in monetizing
benefits, including benefits that have not been quantified or
monetized.
We emphasize that the monetized benefits analysis is entirely
distinct from the statutory BSER determinations finalized herein and is
presented solely for the purposes of complying with E.O. 12866. As
discussed in more detail in the proposal and earlier in this action,
the EPA weighed the relevant statutory factors to determine the
appropriate standards and did not rely on the monetized benefits
analysis for purposes of determining the standards. E.O. 12866
separately requires the EPA to perform a benefit-cost analysis,
including monetizing costs and benefits where practicable, and the EPA
has conducted such an analysis.
The EPA estimates the climate benefits of GHG emissions reductions
expected from the final rules using estimates of the social cost of
greenhouse gases (SC-GHG) that reflect recent advances in the
scientific
[[Page 40007]]
literature on climate change and its economic impacts and that
incorporate recommendations made by the National Academies of Science,
Engineering, and Medicine.\1002\ The EPA published and used these
estimates in the RIA for the Final Oil and Gas Rulemaking, Standards of
Performance for New, Reconstructed, and Modified Sources and Emissions
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate
Review, which was signed by the EPA Administrator on December 2,
2023.\1003\ The EPA solicited public comment on the methodology and use
of these estimates in the RIA for the Agency's December 2022 Oil and
Gas Supplemental Proposal and has conducted an external peer review of
these estimates, as described further below. Section 4 of the RIA lays
out the details of the updated SC-GHG used within this final rule.
---------------------------------------------------------------------------
\1002\ National Academies of Sciences, Engineering, and Medicine
(National Academies). 2017. Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide. National Academies
Press.
\1003\ U.S. EPA. (2023). 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.''
Washington, DC: U.S. EPA.
---------------------------------------------------------------------------
The SC-GHG is the monetary value of the net harm to society
associated with a marginal increase in GHG emissions in a given year,
or the benefit of avoiding that increase. In principle, SC-GHG includes
the value of all climate change impacts (both negative and positive),
including (but not limited to) changes in net agricultural
productivity, human health effects, property damage from increased
flood risk and natural disasters, disruption of energy systems, risk of
conflict, environmental migration, and the value of ecosystem services.
The SC-GHG, therefore, reflects the societal value of reducing
emissions of the gas in question by 1 metric ton and is the
theoretically appropriate value to use in conducting benefit-cost
analyses of policies that affect GHG emissions. In practice, data and
modeling limitations restrain the ability of SC-GHG estimates to
include all physical, ecological, and economic impacts of climate
change, implicitly assigning a value of zero to the omitted climate
damages. The estimates are, therefore, a partial accounting of climate
change impacts and likely underestimate the marginal benefits of
abatement.
Since 2008, the EPA has used estimates of the social cost of
various greenhouse gases (i.e., SC-CO2, SC-CH4,
and SC-N2O), collectively referred to as the ``social cost
of greenhouse gases'' (SC-GHG), in analyses of actions that affect GHG
emissions. The values used by the EPA from 2009 to 2016, and since
2021--including in the proposal--have been consistent with those
developed and recommended by the IWG on the SC-GHG; and the values used
from 2017 to 2020 were consistent with those required by E.O. 13783,
which disbanded the IWG. During 2015-2017, the National Academies
conducted a comprehensive review of the SC-CO2 and issued a
final report in 2017 recommending specific criteria for future updates
to the SC-CO2 estimates, a modeling framework to satisfy the
specified criteria, and both near-term updates and longer-term research
needs pertaining to various components of the estimation process.\1004\
The IWG was reconstituted in 2021 and E.O. 13990 directed it to develop
a comprehensive update of its SC-GHG estimates, recommendations
regarding areas of decision-making to which SC-GHG should be applied,
and a standardized review and updating process to ensure that the
recommended estimates continue to be based on the best available
economics and science going forward.
---------------------------------------------------------------------------
\1004\ Ibid.
---------------------------------------------------------------------------
The EPA is a member of the IWG and is participating in the IWG's
work under E.O. 13990. As noted in previous EPA RIAs (including in the
proposal RIA for this rulemaking), while that process continues, the
EPA is continuously reviewing developments in the scientific literature
on the SC-GHG, including more robust methodologies for estimating
damages from emissions, and is looking for opportunities to further
improve SC-GHG estimation.\1005\ In the December 2022 Oil and Gas
Supplemental Proposal RIA,\1006\ the Agency included a sensitivity
analysis of the climate benefits of that rule using a new set of SC-GHG
estimates that incorporates recent research addressing recommendations
of the National Academies \1007\ in addition to using the interim SC-
GHG estimates presented in the Technical Support Document: Social Cost
of Carbon, Methane, and Nitrous Oxide Interim Estimates under Executive
Order 13990 \1008\ that the IWG recommended for use until updated
estimates that address the National Academies' recommendations are
available.
---------------------------------------------------------------------------
\1005\ The EPA strives to base its analyses on the best
available science and economics, consistent with its
responsibilities, for example, under the Information Quality Act.
\1006\ U.S. EPA. (2023). 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.''
Washington, DC: U.S. EPA.
\1007\ Ibid.
\1008\ Interagency Working Group on Social Cost of Carbon (IWG).
2021 (February). Technical Support Document: Social Cost of Carbon,
Methane, and Nitrous Oxide: Interim Estimates under Executive Order
13990. United States Government.
---------------------------------------------------------------------------
The EPA solicited public comment on the sensitivity analysis and
the accompanying draft technical report, External Review Draft of
Report on the Social Cost of Greenhouse Gases: Estimates Incorporating
Recent Scientific Advances, which explains the methodology underlying
the new set of estimates and was included as supplemental material to
the RIA for the December 2022 Oil and Gas Supplemental Proposal.\1009\
The response to comments document can be found in the docket for that
action.
---------------------------------------------------------------------------
\1009\ 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.
---------------------------------------------------------------------------
To ensure that the methodological updates adopted in the technical
report are consistent with economic theory and reflect the latest
science, the EPA also initiated an external peer review panel to
conduct a high-quality review of the technical report, completed in May
2023. The peer reviewers commended the Agency on its development of the
draft update, calling it a much-needed improvement in estimating the
SC-GHG and a significant step toward addressing the National Academies'
recommendations with defensible modeling choices based on current
science. The peer reviewers provided numerous recommendations for
refining the presentation and for future modeling improvements,
especially with respect to climate change impacts and associated
damages that are not currently included in the analysis. Additional
discussion of omitted impacts and other updates were incorporated in
the technical report to address peer reviewer recommendations. Complete
information about the external peer review, including the peer reviewer
selection process, the final report with individual recommendations
from peer reviewers, and the EPA's response to each recommendation is
available on
[[Page 40008]]
the EPA's website.\1010\ An overview of the methodological updates
incorporated into the new SC-GHG estimates is provided in the RIA
section 4.2. A more detailed explanation of each input and the modeling
process is provided in the technical report, EPA Report on the Social
Cost of Greenhouse Gases: Estimates Incorporating Recent Scientific
Advances.\1011\
---------------------------------------------------------------------------
\1010\ https://www.epa.gov/environmental-economics/scghg-tsd-peer-review.
\1011\ U.S. EPA (2023). 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.''
Washington, DC: U.S. EPA.
---------------------------------------------------------------------------
In addition to CO2, these final rules are expected to
reduce annual, national total emissions of NOX and
SO2 and direct PM2.5. Because NOX and
SO2 are also precursors to secondary formation of ambient
PM2.5, reducing these emissions would reduce human exposure
to annual average ambient PM2.5 and would reduce the
incidence of PM2.5-attributable health effects. These final
rules are also expected to reduce national ozone season NOX
emissions. In the presence of sunlight, NOX and VOCs can
undergo a chemical reaction in the atmosphere to form ozone. Reducing
NOX emissions in most locations reduces human exposure to
ozone and the incidence of ozone-related health effects, though the
degree to which ozone is reduced will depend in part on local
concentration levels of VOCs. The RIA estimates the health benefits of
changes in PM2.5 and ozone concentrations. The health effect
endpoints, effect estimates, benefit unit-values, and how they were
selected are described in the Estimating PM2.5- and Ozone-Attributable
Health Benefits TSD.\1012\ Our approach for updating the endpoints and
to identify suitable epidemiologic studies, baseline incidence rates,
population demographics, and valuation estimates is summarized in
section 4 of the RIA.
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\1012\ U.S. EPA. (2023). Estimating PM2.5- and Ozone-
Attributable Health Benefits. Research Triangle Park, NC: U.S.
Environmental Protection Agency, Office of Air Quality Planning and
Standards, Health and Environmental Impact Division.
---------------------------------------------------------------------------
The following PV and EAV estimates reflect projected benefits over
the 2024 to 2047 period, discounted to 2024 in 2019 dollars, for the
analysis of the final rules. We monetize benefits of the final rules
and evaluate other costs in part to enable a comparison of costs and
benefits pursuant to E.O. 12866, but we recognize that there are
substantial uncertainties and limitations in monetizing benefits,
including benefits that have not been quantified. The projected PV of
monetized climate benefits is about $270 billion, with an EAV of about
$14 billion using the SC-CO2 discounted at 2 percent.\1013\
The projected PV of monetized health benefits is about $120 billion,
with an EAV of about $6.3 billion discounted at 2 percent. Combining
the projected monetized climate and health benefits yields a total PV
estimate of about $390 billion and EAV estimate of $21 billion.
---------------------------------------------------------------------------
\1013\ Monetized climate benefits are discounted using a 2
percent discount rate, consistent with the EPA's updated estimates
of the SC-CO2. The 2003 version of OMB's Circular A-4 had
generally recommended 3 percent and 7 percent as default discount
rates for costs and benefits, though as part of the Interagency
Working Group on the Social Cost of Greenhouse Gases, OMB had also
long recognized that climate effects should be discounted only at
appropriate consumption-based discount rates. In November 2023, OMB
finalized an update to Circular A-4, in which it recommended the
general application of a 2 percent discount rate to costs and
benefits (subject to regular updates), as well as the consideration
of the shadow price of capital when costs or benefits are likely to
accrue to capital (OMB 2023). Because the SC-CO2
estimates reflect net climate change damages in terms of reduced
consumption (or monetary consumption equivalents), the use of the
social rate of return on capital (7 percent under OMB Circular A-4
(2003)) to discount damages estimated in terms of reduced
consumption would inappropriately underestimate the impacts of
climate change for the purposes of estimating the SC-CO2.
See section 4.2 of the RIA for more discussion.
---------------------------------------------------------------------------
At a 3 percent discount rate, these final rules are expected to
generate projected PV of monetized health benefits of about $100
billion, with an EAV of about $6.1 billion. Climate benefits remain
discounted at 2 percent in this benefits analysis and are estimated to
be about $270 billion, with an EAV of about $14 billion using the SC-
CO2. Thus, these final rules would generate a PV of
monetized benefits of about $370 billion, with an EAV of about $20
billion discounted at a 3 percent rate.
At a 7 percent discount rate, these final rules are expected to
generate projected PV of monetized health benefits of about $59
billion, with an EAV of about $5.2 billion. Climate benefits remain
discounted at 2 percent in this benefits analysis and are estimated to
be about $270 billion, with an EAV of about $14 billion using the SC-
CO2. Thus, these final rules would generate a PV of
monetized benefits of about $330 billion, with an EAV of about $19
billion discounted at a 7 percent rate.
The results presented in this section provide an incomplete
overview of the effects of the final rules. The monetized climate
benefits estimates do not include important benefits that we are unable
to fully monetize due to data and modeling limitations. In addition,
important health, welfare, and water quality benefits anticipated under
these final rules are not quantified. We anticipate that taking non-
monetized effects into account would show the total benefits of the
final rules to be greater than this section reflects. Discussion of the
non-monetized health, climate, welfare, and water quality benefits is
found in section 4 of the RIA.
2. Net Benefits
The final rules are projected to reduce greenhouse gas emissions in
the form of CO2, producing a projected PV of monetized
climate benefits of about $270 billion, with an EAV of about $14
billion using the SC-CO2 discounted at 2 percent. The final
rules are also projected to reduce emissions of NOX,
SO2 and direct PM2.5 leading to national health
benefits from PM2.5 and ozone in most years, producing a
projected PV of monetized health benefits of about $120 billion, with
an EAV of about $6.3 billion discounted at 2 percent. Thus, these final
rules are expected to generate a PV of monetized benefits of $390
billion, with an EAV of $21 billion discounted at a 2 percent rate. The
PV of the projected compliance costs are $19 billion, with an EAV of
about $0.98 billion discounted at 2 percent. Combining the projected
benefits with the projected compliance costs yields a net benefit PV
estimate of about $370 billion and EAV of about $20 billion.
At a 3 percent discount rate, the final rules are expected to
generate projected PV of monetized health benefits of about $100
billion, with an EAV of about $6.1 billion. Climate benefits remain
discounted at 2 percent in this net benefits analysis. Thus, the final
rules would generate a PV of monetized benefits of about $370 billion,
with an EAV of about $20 billion discounted at 3 percent. The PV of the
projected compliance costs are about $15 billion, with an EAV of $0.91
billion discounted at 3 percent. Combining the projected benefits with
the projected compliance costs yields a net benefit PV estimate of
about $360 billion and an EAV of about $19 billion.
At a 7 percent discount rate, the final rules are expected to
generate projected PV of monetized health benefits of about $59
billion, with an EAV of about $5.2 billion. Climate benefits remain
discounted at 2 percent in this net benefits analysis. Thus, the final
rules would generate a PV of monetized benefits of about $330 billion,
with an EAV of about $19 billion discounted at 7 percent. The PV of the
projected compliance costs are about $7.5 billion,
[[Page 40009]]
with an EAV of $0.65 billion discounted at 7 percent. Combining the
projected benefits with the projected compliance costs yields a net
benefit PV estimate of about $320 billion and an EAV of about $19
billion.
See section 7 of the RIA for additional information on the
estimated net benefits of these rules.
E. Environmental Justice Analytical Considerations and Stakeholder
Outreach and Engagement
For this action, the analysis described in this section and in the
RIA is presented for the purpose of providing the public with an
analysis of potential EJ concerns associated with these rulemakings,
consistent with E.O. 14096. This analysis did not inform the
determinations made to support the final rules.
The EPA defines EJ as ``the just treatment and meaningful
involvement of all people regardless of income, race, color, national
origin, Tribal affiliation, or disability, in agency decision-making
and other Federal activities that affect human health and the
environment so that people: (i) Are fully protected from
disproportionate and adverse human health and environmental effects
(including risks) and hazards, including those related to climate
change, the cumulative impacts of environmental and other burdens, and
the legacy of racism or other structural or systemic barriers; and (ii)
have equitable access to a healthy, sustainable, and resilient
environment in which to live, play, work, learn, grow, worship, and
engage in cultural and subsistence practices.'' \1014\ In recognizing
that particular communities of EJ concern often bear an unequal burden
of environmental harms and risks, the EPA continues to consider ways of
protecting them from adverse public health and environmental effects of
air pollution.
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\1014\ https://www.federalregister.gov/documents/2023/04/26/2023-08955/revitalizing-our-nations-commitment-to-environmental-justice-for-all.
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1. Analytical Considerations
For purposes of analyzing regulatory impacts, the EPA relies upon
its June 2016 ``Technical Guidance for Assessing Environmental Justice
in Regulatory Analysis,'' \1015\ which provides recommendations that
encourage analysts to conduct the highest quality analysis feasible,
recognizing that data limitations, time, resource constraints, and
analytical challenges will vary by media and circumstance. The
Technical Guidance states that a regulatory action may involve
potential EJ concerns if it could: (1) Create new disproportionate
impacts on communities with EJ concerns; (2) exacerbate existing
disproportionate impacts on communities with EJ concerns; or (3)
present opportunities to address existing disproportionate impacts on
communities with EJ concerns through this action under development.
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\1015\ See https://www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
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The EPA's EJ technical guidance states that ``[t]he analysis of
potential EJ concerns for regulatory actions should address three
questions: (1) Are there potential EJ concerns associated with
environmental stressors affected by the regulatory action for
population groups of concern in the baseline? (2) Are there potential
EJ concerns associated with environmental stressors affected by the
regulatory action for population groups of concern for the regulatory
option(s) under consideration? (3) For the regulatory option(s) under
consideration, are potential EJ concerns created or mitigated compared
to the baseline?'' \1016\
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\1016\ See https://www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
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To address these questions in the context of these final rules, the
EPA developed a unique analytical approach that considers the purpose
and specifics of these rulemakings, as well as the nature of known and
potential disproportionate and adverse exposures and impacts. However,
due to data limitations, it is possible that our analysis failed to
identify disparities that may exist, such as potential EJ
characteristics (e.g., residence of historically redlined areas),
environmental impacts (e.g., other ozone metrics), and more granular
spatial resolutions (e.g., neighborhood scale) that were not evaluated.
Also due to data and resource limitations, we discuss climate EJ
impacts of this action qualitatively (section 6.3 of the RIA).
For these rules, we employ two types of analysis to respond to the
previous three questions: proximity analyses and exposure analyses.
Both types of analysis can inform whether there are potential EJ
concerns for population groups of concern in the baseline (question
1).\1017\ In contrast, only the exposure analyses, which are based on
future air quality modeling, can inform whether there will be potential
EJ concerns due to the implementation of the regulatory options under
consideration (question 2) and whether potential EJ concerns will be
created or mitigated compared to the baseline (question 3).
---------------------------------------------------------------------------
\1017\ The baseline for proximity analyses is current population
information, whereas the baseline for ozone exposure analyses are
the future years in which the regulatory options will be implemented
(e.g., 2023 and 2026).
---------------------------------------------------------------------------
In section 6 of the RIA, we utilize the two types of analysis to
address the three EJ questions by quantitatively evaluating: (1) the
proximity of affected facilities to populations of potential EJ concern
(section 6.4); and (2) the potential for disproportionate ozone and
PM2.5 concentrations in the baseline and concentration
changes after rule implementation across different demographic groups
on the basis of race, ethnicity, poverty status, employment status,
health insurance status, life expectancy, redlining, Tribal land, age,
sex, educational attainment, and degree of linguistic isolation
(section 6.5). It is important to note that due to the corresponding
small magnitude of the ozone and PM2.5 concentration changes
relative to the baseline concentrations in each modeled future year,
these rules are expected to have a small impact on the distribution of
exposures across each demographic group. Each of these analyses should
be considered independently of each other as each was performed to
answer separate questions and is associated with unique limitations and
uncertainties.
a. Proximity Analyses
Baseline demographic proximity analyses can be relevant for
identifying populations that may be exposed to local environmental
stressors, such as local NO2 and SO2 emitted from
affected sources in these final rules, traffic, or noise. The Agency
has conducted a demographic analysis of the populations living near
facilities impacted by these rules including 114 facilities for which
the EPA is unaware of existing retirement plans by 2032, 23 facilities
(a subset of the 114 facilities) with known retirement plans between
2033-2040, and 94 facilities (also a subset of the 114 facilities)
without known retirement plans before 2040. The baseline analysis
indicates that on average the populations living within 5 km and 10 km
of 114 facilities impacted by the final rules without announced
retirement by 2032 have a higher percentage of the population that is
American Indian, below the Federal poverty level, and below two times
the Federal poverty level than the national average. In addition, the
population living within 50 kilometers of the same 114 facilities has a
higher percentage of the population that is Black. Relating these
results to EJ question 1, we conclude that there may be potential EJ
concerns associated with directly emitted pollutants that are affected
by
[[Page 40010]]
the regulatory actions for certain population groups of concern in the
baseline (question 1). However, as proximity to affected facilities
does not capture variation in baseline exposures across communities,
nor does it indicate that any exposures or impacts will occur, these
results should not be interpreted as a direct measure of exposure
impact. The full results of the demographic analysis can be found in
RIA section 6.4. The methodology and the results of the demographic
analysis for the final rules are presented in a technical report,
Analysis of Demographic Factors for Populations Living Near Coal-Fired
Electric Generating Units (EGUs) for the Section 111 NSPS and Emissions
Guidelines--Final, available in the docket for these actions.
b. Exposure Analyses
While the exposure analyses can respond to all three EJ questions,
correctly interpreting the results requires an understanding of several
important caveats. First, recognizing the flexibility afforded to each
state in implementing the final guidelines, the results below are based
on analysis of several illustrative compliance scenarios which
represent potential compliance outcomes in each state. This analysis
does not consider any potential impact of the meaningful engagement
provisions or all of the other protections that are in place that can
reduce the risks of localized emissions increases in a manner that is
protective of public health, safety, and the environment. It is also
important to note that the potential emissions changes discussed below
are relative to a projected baseline, and any localized decreases or
increases are subject to the uncertainty of the baseline projections
discussed in section 3.7 of the RIA. This uncertainty becomes
increasingly relevant in later years in which baseline modeling
projects substantial reductions in emissions relative to today.
Furthermore, several additional caveats should be noted that are
specific to the exposure analysis. For example, the air pollutant
exposure metrics are limited to those used in the benefits assessment.
For ozone, that is the maximum daily 8-hour average, averaged across
the April through September warm season (AS-MO3) and for
PM2.5 that is the annual average. This ozone metric likely
smooths potential daily ozone gradients and is not directly relatable
to the NAAQS whereas the PM2.5 metric is more similar to the
long-term PM2.5 standard. The air quality modeling estimates
are also based on state and fuel level emission data paired with
facility-level baseline emissions and provided at a resolution of 12
square kilometers. Additionally, here we focus on air quality changes
due to these rulemakings and infer post-policy ozone and
PM2.5 exposure burden impacts. Note, we discuss climate EJ
impacts of these actions qualitatively (section 6.3 of the RIA).
Exposure analysis results are provided in two formats: aggregated
and distributional. The aggregated results provide an overview of
potential ozone exposure differences across populations at the
national- and state-levels, while the distributional results show
detailed information about ozone concentration changes experienced by
everyone within each population.
These rules are also expected to reduce emissions of direct
PM2.5, NOX, and SO2 nationally.
Because NOX and SO2 are also precursors to
secondary formation of ambient PM2.5 and because
NOX is a precursor to ozone formation, reducing these
emissions would impact human exposure. Quantitative ozone and
PM2.5 exposure analyses can provide insight into all three
EJ questions, so they are performed to evaluate potential
disproportionate impacts of these rulemakings. Even though both the
proximity and exposure analyses can potentially improve understanding
of baseline EJ concerns (question 1), the two should not be directly
compared. This is because the demographic proximity analysis does not
include air quality information and is based on current, not future,
population information.
The baseline analysis of ozone and PM2.5 concentration
burden responds to question 1 from the EPA's EJ technical guidance more
directly than the proximity analyses, as it evaluates a form of the
environmental stressor targeted by the regulatory action. As discussed
in the RIA, our analysis indicates that baseline ozone and
PM2.5 concentration will decline substantially relative to
today's levels for all demographic groups in all future modeled years,
and these baseline levels of ozone and PM2.5 can be
considered to be relatively low. However, there are differences in
exposure among demographic groups within these relatively low levels of
baseline exposure. Baseline PM2.5 and ozone exposure
analyses show that certain populations, such as residents of redlined
census tracts, those linguistically isolated, Hispanic populations,
Asian populations, and those without a high school diploma may
experience higher ozone and PM2.5 exposures as compared to
the national average. American Indian populations, residents of Tribal
Lands, populations with higher life expectancy or with life expectancy
data unavailable, children, and unemployed populations may also
experience disproportionately higher ozone concentrations than the
reference group. Black populations may also experience
disproportionately higher PM2.5 concentrations than the
reference group. Therefore, also in response to question 1, there
likely are potential EJ concerns associated with ozone and
PM2.5 exposures affected by the regulatory actions for
population groups of concern in the baseline. However, these baseline
exposure results have not been fully explored and additional analyses
are likely needed to understand potential implications.
Relative to the low baseline levels of exposure modeled in future
years for PM2.5 and ozone, exposure analyses show that the
final rules will result in modest but widespread reductions in
PM2.5 and ozone concentrations in virtually all areas of the
country, although some limited areas may experience small increases in
ozone concentrations relative to forecasted conditions without the
rule. The extent of areas experiencing ozone increases varies among
snapshot years. Due to the small magnitude of the exposure changes
across population demographics associated with these rulemakings
relative to the magnitude of the baseline disparities, we infer that
post-policy EJ ozone and PM2.5 concentration burdens are
likely to remain after implementation of the regulatory action
(question 2).
Question 3 asks whether potential EJ concerns will be created or
mitigated compared to the baseline. Due to the very small magnitude of
differences across demographic population post-policy impacts, we do
not find evidence that disparities among communities with EJ concerns
will be exacerbated or mitigated by the regulatory alternatives under
consideration regarding PM2.5 exposures in all future years
evaluated and ozone exposures for most demographic groups in the future
years evaluated. In 2035, under the illustrative compliance scenarios
analyzed, it is possible that Asian populations, Hispanic populations,
and those linguistically isolated, and those living on Tribal land may
experience a slight exacerbation of ozone exposure disparities at the
national level (question 3), compared to baseline ozone levels.
Additionally at the national level, those living on Tribal land may
experience a slight exacerbation of ozone exposure disparities in 2040
and a slight mitigation of ozone exposure disparities in 2028 and 2030.
At the state level,
[[Page 40011]]
ozone exposure disparities may be either mitigated or exacerbated for
certain demographic groups, also to a small degree. As discussed above,
it is important to note that this analysis does not consider any
potential impact of the meaningful engagement provisions or all of the
other protections that are in place that can reduce the risks of
localized emissions increases in a manner that is protective of public
health, safety, and the environment.
2. Outreach and Engagement
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. This outreach allowed the EPA to gather information
from a variety of viewpoints while also providing parties with an
overview of the EPA's work to reduce GHG emissions from the power
sector.
Prior to the May 2023 proposal, the EPA opened a public docket for
pre-proposal input.\1018\ The EPA continued to engage with interested
parties by speaking on the EPA National Community Engagement call and
the National Tribal Air Association Policy Update call in September
2022. Following publication of the proposal, the EPA hosted two
informational webinars on June 6 and 7, 2023, specially targeted
towards tribal environmental professionals, tribal nations, and
communities with environmental justice concerns. The purpose of these
webinars was to provide an overview of the proposal, information on how
to effectively engage in the regulatory process and provide the EPA an
opportunity to answer questions. The EPA held virtual public hearings
on June 13, 14, and 15, 2023, that allowed the public an opportunity to
present comments and information regarding the proposed rules.
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\1018\ EPA-HQ-OAR-2022-0723.
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The EPA recently finalized revisions to the subpart Ba implementing
regulations requiring states to conduct meaningful engagement with
pertinent stakeholders as part of the state plan development process.
The EPA underscores the importance of this part of the state plan
development process. For more detailed information on meaningful
engagement, see section X.E.1.b.i of this preamble.
F. Grid Reliability Considerations and Reliability-Related Mechanisms
1. Overview
The Federal Energy Regulatory Commission (FERC) is the federal
agency with vested authority to ensure reliability of the bulk power
system (16 U.S.C. 824o). FERC oversees and approves reliability
standards that are developed by NERC and then become mandatory for all
owners and operators of the bulk power system. Regional wholesale
energy markets, like RTOs, ISOs, public service commissions, balancing
authorities, and reliability coordinators all have reliability related
responsibilities. The EPA's role under the CAA section 111 is to reduce
emissions of dangerous air pollutants, including those emitted from the
electric power sector. In doing so, it has a long, and exemplary
history of ensuring its public-health-based emissions standards and
guidelines that impact the power sector are sensitive to reliability-
related issues and constructed in a manner that does not interfere with
grid operators' responsibility to deliver reliable power. The EPA met
with many entities with responsibility over the reliability of the bulk
power system in crafting these final rules to make certain the rules
will not impede their ability to ensure reliability of the bulk power
system. This section outlines the array of modifications made in these
final actions, outlined in section I.G of this preamble, that
collectively help ensure that these final actions will not interfere
with systems operators' ability to continue providing reliable power.
Additional to this suite of adjustments, the EPA is introducing both a
short-term reliability mechanism for emergency situations and a
reliability assurance mechanism available for states to include in
their state plans for additional flexibility. In response to the May
2023 proposed rule, the EPA received extensive comments regarding grid
reliability and resource adequacy from balancing authorities,
independent system operators and regional transmission organizations,
state regulators, power companies, and other stakeholders. The EPA
engaged with each of these group of commenters to garner a granular
understanding of their reliability-related concerns. Additionally, the
EPA met repeatedly with technical staff and Commissioners of FERC, DOE,
NERC, and other reliability experts during the course of this
rulemaking. At FERC's invitation, the EPA participated in FERC's Annual
Reliability Technical Conference on November 9, 2023. Further, the EPA
solicited additional comment on reliability-related mechanisms as part
of the November 2023 supplemental proposed rule.
Comment: Several comments from grid operators raised the concern
that the proposed rules have the potential to trigger material negative
impacts to grid reliability. Concerns coalesced around the loss of firm
dispatchable assets which they view as outpacing the development and
interconnection of new assets that do not possess commensurate
reliability attributes. Other commenters maintained that the proposals
included adequate lead times for reliability planning, and that
reliability attributes are currently sourced by a collection of assets,
and as such a collection of future assets will be able to provide the
requisite reliability attributes. Some commenters also asserted that
the proposals would actually improve transparency around unit-specific
decisions, which are often not communicated transparently with adequate
notice, leading to a better reliability planning process.
Response: These final rules include a number of flexibilities and
rule adjustments that will accommodate appropriate planning decisions
by affected sources, system planners, and reliability authorities in a
way that allows for the continued reliable operation of the electric
grid. These final actions also include adjustments and improvements,
with specific provisions related to compliance timing and system
emergencies, that address reliability concerns. The rules do not
interfere with ongoing efforts by key stakeholders to appropriately
plan for an evolving electric system. The EPA agrees that transparency
around unit-specific planning is of paramount importance to enabling
systems operators advanced notice to plan for continued reliable bulk
power operations.
The EPA initiated follow-up conversations with all balancing
authorities and systems operators that submitted public comments to
ensure a granular and thorough understanding of all reliability-related
concerns raised in response to the proposed rules. In addition, the EPA
solicited additional comment on reliability related mechanisms in the
supplemental proposal issued in November 2023. The EPA examined the
record carefully and responded with a suite of changes to the proposal
that, though not always explicitly directed at addressing concerns
raised with respect to reliability, nonetheless collectively help
ensure EPA's rules will not interfere
[[Page 40012]]
with grid operators' responsibilities to provide reliable power.
As discussed earlier in this preamble, the EPA is finalizing
several adjustments to provisions in the proposed rules that address
reliability concerns and ensure that these rules provide adequate
flexibilities and assurance mechanisms that allow grid operators to
continue to fulfill their responsibilities to maintain the reliability
of the bulk-power system. These adjustments include restructuring the
subcategories for coal-fired steam generating EGUs: the EPA is not
finalizing the proposed imminent or near term subcategory structure
which should provide states with a wider planning latitude, and units
with cease operations dates prior to January 1, 2032 are not regulated
by this final rule. Importantly, the compliance timeline for installing
CCS in the long-term subcategory has been extended by an additional 2
years. The EPA is not finalizing the 30 percent hydrogen co-firing BSER
for the intermediate subcategory for new combustion turbines. These
changes facilitate reliability planning and operations by providing
more lead time for CCS installation-related compliance. The adjusted
scope of these actions also provides additional time for the EPA to
consult with a broad range of stakeholders, including grid operators,
to deliberate and determine the best way to address emissions from
existing gas turbines while respecting their contribution to electric
reliability in the foreseeable future. In addition to these
adjustments, as detailed in section X.D of this preamble, the EPA is
offering states a suite of voluntary compliance flexibilities that
could be used to address reliability concerns. These compliance
flexibilities include clarifying the circumstances under which it may
be appropriate for states to employ RULOF to establish source specific
standards of performance and compliance schedules for affected EGUs to
address reliability, allowing emission averaging, trading, and unit-
specific mass-based compliance mechanisms for certain subcategories--
provided that they achieve an equivalent level of emission reduction
consistent with the application of individual rate-based standards of
performance, and, for certain mechanisms, that they include a backstop
emission rate, and offering a compliance date extension for affected
new and existing EGUs that encounter unanticipated delays with control
technology implementation.
The EPA believes the adjustments made to the final rules outlined
above are sufficient to ensure the rules can be implemented without
impairing the ability of grid operators to deliver reliable power. The
EPA is nonetheless finalizing additional reliability-related
instruments to provide further certainty that implementation of these
final rules will not intrude on grid operators' ability to ensure
reliability. The short-term reliability mechanism is available for both
new and existing units and is designed to provide additional
flexibility through an alternative compliance strategy during acute
system emergencies that threaten reliability. The reliability assurance
mechanism will be available for existing units that intend to cease
operating, but, for unforeseen reasons, need to temporarily remain
online to support reliability beyond the planned cease operation date.
This reliability assurance mechanism, which requires a specific and
adequate showing of reliability need that is satisfactory to the EPA,
is intended for circumstances where there is insufficient time to
complete a state plan revision, and it is limited to the amount of time
substantiated, which may not exceed 1 year. The EPA intends to consult
with FERC for advice on applications of reliability need that exceed 6
months. These instruments will be presumptively approvable, provided
they meet the requirements defined in these emission guidelines, if
states choose to incorporate them into their plans.
Comment: Commenters from industry and grid operators expressed
support for the inclusion of a requirement that states include in their
state plans a demonstration of consultation with all relevant
reliability authorities to facilitate planning. Other commenters
asserted that the proposals included sufficient coordination with
reliability authorities, through the Initial Reporting Milestone Status
Report requirements.
Response: The EPA agrees that planning for reliability is
critically important. Indeed, all stakeholders generally agree that
effective planning is essential to ensuring electric reliability is
maintained.\1019\ State planning, including coordination and
transparency across jurisdictions, is particularly important given that
state plans in one jurisdiction can impact the reliability and resource
adequacy of other system operators. The EPA is finalizing, as part of
the state plan development process, that states are required to conduct
meaningful engagement with stakeholders. As part of this required
meaningful engagement, states are strongly encouraged to consult with
the relevant balancing authorities and reliability coordinators for
their affected sources and to share available unit-specific
requirements and compliance information in a timely fashion. Sharing
regulatory requirements and unit-specific compliance information with
balancing authorities and reliability coordinators in a timely manner
will promote early and informed reliability planning. Strong system-
planning processes of utility transmission companies and RTOs are among
the most important tools to assure that reliability will not be
adversely affected by regulations.1020 1021 A robust
planning process that recognizes the different roles of states and
their relevant balancing authorities, transmission planners, and
reliability coordinators should help to identify potential resource
adequacy or reliability issues early in the state planning process.
States will also be able to address reliability-related issues through
a revision in their state plan, including to address issues that were
not foreseen during the state planning process.
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\1019\ ``Electric System Reliability and EPA Regulation of GHG
Emissions from Power Plants: 2023,'' Susan Tierney, Analysis Group,
November 7, 2023.
\1020\ ``Electric System Reliability and EPA Regulation of GHG
Emissions from Power Plants: 2023,'' Susan Tierney, November 7,
2023.
\1021\ ``Modernizing Governance: Key to Electric Grid
Reliability'', Kleinman Center for Energy Policy, University of
Pennsylvania, March 2024.
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In addition to these measures, DOE has authority pursuant to
section 202(c) of the Federal Power Act to, on its own motion or by
request, order, among other things, the temporary generation of
electricity from particular sources in certain emergency conditions,
including during events that would result in a shortage of electric
energy, when the Secretary of Energy determines that doing so will meet
the emergency and serve the public interest. An affected source
operating pursuant to such an order is deemed not to be operating in
violation of its environmental requirements. Such orders may be issued
for 90 days and may be extended in 90-day increments after consultation
with EPA. DOE has historically issued section 202(c) orders at the
request of electric generators and grid operators such as RTOs in order
to enable the supply of additional generation in times of expected
emergency-related generation shortfalls.
Congress provided section 202(c) as the primary mechanism to ensure
that when generation is needed to meet an emergency, environmental
protections will not prevent a source from meeting that need. To date,
section 202(c) has worked well, allowing, for example,
[[Page 40013]]
additional generation to come online to meet demand in the California
Independent System Operator and PJM territories in 2022.\1022\ Section
202(c) has also been used to allow generators to remain online pending
completion of infrastructure needed to facilitate reliable replacement
of those generators. The EPA continues to believe that section 202(c)
is an effective mechanism for meeting the purpose of ensuring that all
physically available generation will be available as needed to meet an
emergency situation, regardless of environmental regulatory
constraints. Given the heightened concerns about reliability expressed
by commenters in the context of this rule and ongoing changes in the
electricity sector, however, this final action includes an additional
supplemental short-term reliability mechanism that states may elect to
include in their state plans. States that adopt this mechanism could
make it available for sources to use without needing action by DOE
under section 202(c). Of course, section 202(c) would continue to be
available for sources subject to this rule for emergency situations
where EPA's short-term reliability mechanism would not apply.
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\1022\ DOE. DOE's Use of Federal Power Act Emergency Authority.
https://www.energy.gov/ceser/does-use-federal-power-act-emergency-authority.
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Many electric reliability and bulk-power system authorities,
including FERC and the regulated wholesale markets, are actively
engaged in activities to ensure the reliability of the transmission
grid, while paying careful attention to the changing resource mix and
the ongoing trends in the power sector.1023 1024 There are
multiple agencies and entities that have some authority and
responsibility to ensure electric reliability. These include state
utility commissions, balancing authorities, reliability coordinators,
DOE, FERC, and NERC. The EPA's central mission is to protect human
health and the environment and the EPA does not have direct authority
or responsibility to ensure electric reliability. Still, the EPA
believes reliability of the bulk power system is of paramount
importance, and has included additional measures in these final actions
that are delineated throughout this section, evaluated the resource
adequacy implications in the final TSD, Resource Adequacy Analysis, and
conducted capacity expansion modeling of the final rules in a manner
that takes into account resource adequacy needs. Additionally, the EPA
performed a variety of other sensitivity analyses including an
examination of higher electricity demand (many areas are reporting
accelerated load growth forecasts due to data centers, increased
manufacturing, crypto currency, electrification and other factors) and
the 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. These results are detailed
in the technical memoranda in the docket titled, IPM Sensitivity Runs
and Resource Adequacy Analysis: Vehicle Rules, Final 111 EGU Rules,
ELG, and MATS.
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\1023\ See Resource Adequacy Analysis document for further
analysis and exploration of these important elements.
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The EPA has carefully examined all comments related to reliability
that were submitted during the public comment period for the proposal
and for the supplemental notice. The Agency has engaged in dialogue
with each of the balancing authorities regarding the content of their
submitted comments. Based on this extensive engagement and
consultation, the Agency's analysis of the impacts of these rules, and
the various features of this rule that will work in tandem to ensure
the standards and emission guidelines finalized here are achievable and
can respond to future reliability and resource adequacy needs, the EPA
has concluded these final rules will not interfere with grid operators'
ability to continue delivering reliable power.
The EPA received a range of opinions during the comment process,
and also during FERC's Annual Reliability Conference, some of which
expressed that the proposed rule could provide a net benefit to
reliability planning given the enhanced visibility into unit-specific
compliance plans.\1025\ This section discusses the additional
compliance flexibilities and reliability instruments that have been
included in these final rules.
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\1025\ ``In the current environment, grid operators are unsure
about when resources may retire, increasing uncertainty and making
planning harder. The proposed rules have long timelines for
enactment, giving states, utilities, and grid operators plenty of
time to plan for the transition.'' From ``Prepared Statement of Ric
O'Connell Executive Director, GridLab,'' Testimony before FERC
Annual Reliability Technical Conference on November 9, 2023.
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The EPA has carefully considered the importance of reliability of
the bulk-power system in developing these final rules. Stakeholders
have recognized the EPA's long and successful history of ensuring its
power sector rules are crafted to deliver significant public health
benefits while not impairing the ability of grid operators to ensure
reliable power.\1026\ The entities responsible for ensuring
reliability, which encompass electric utilities, RTOs and ISOs,
reliability coordinators, other grid operators, utility and non-utility
energy companies, and Federal and state regulators, have also
historically met challenges in navigating power sector environmental
obligations while maintaining reliability.\1027\
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\1026\ ``Electric System Reliability and EPA Regulation of GHG
Emissions from Power Plants,'' Susan Tierney, November 7, 2023.
\1027\ ``Greenhouse Gas Emission Reductions From Existing Power
Plants: Options to Ensure Electric System Reliability,'' Susan
Tierney, May 2014.
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2. Compliance Flexibilities for New and Existing Affected EGUs
These final rules include three key compliance flexibilities for
new and existing sources and reliability coordinators so that they can
continue to plan for the reliable operation of the electric system;
RULOF, emissions averaging and trading, and compliance extensions of up
to 1 year for units installing control technology. As discussed in
section X.C.2 of this preamble, states may use the RULOF provisions to
address circumstances in which reliability or resource adequacy is a
concern. Use of RULOF may be appropriate where reliability or resource
adequacy considerations for a particular EGU are fundamentally
different from those considered when developing these emission
guidelines, which may make it unreasonable for an affected EGU to
comply with a standard of performance by the prescribed date. Under
these circumstances, the state may choose to particularize the
compliance obligations for the affected EGU in order to address the
reliability or resource adequacy concern. As explained in section
X.C.2, the EPA believes any adjustments that are needed will take the
form of different compliance timelines. RULOF is relevant at the stage
of establishing standards of performance and compliance schedules to
affected EGUs as a state plan is being developed or revised.
States have the ability to use emission averaging or trading, as
well as unit-specific mass-based compliance, as described in section
X.D of this preamble, which may also provide reliability-related
benefits. The use of these alternative compliance flexibilities is not
required, but states may employ these flexibilities, provided they
demonstrate that their programs achieve an equivalent level of emission
reduction with unit-specific application
[[Page 40014]]
of rate-based standards of performance and apply requirements relevant
to the particular flexibility, as specified in section X.D. These
compliance flexibilities are voluntary, and states may choose whether
to allow their use in state plans, subject to certain conditions.
However, states may find that the reliability-specific adjustments
discussed below provide sufficient flexibility in lieu of the
mechanisms described in section X.D.
States may incorporate into their state plans a mechanism that
allows compliance date extensions up to 1 year for an existing affected
EGU that is in the process of installing a control technology to meet
its standard of performance in the state plan, under specific
circumstances, a detailed discussion can be found in section X.C.1.d of
this document. As discussed in section VIII.N of this document, the
Administrator may provide a similar extension for new combustion
turbines. The state or Administrator may allow the extension of the
compliance date if the source demonstrates a delay in the construction
or implementation of the control technology resulting from causes that
are entirely outside the owner or operator's control. These may include
delays in obtaining a final construction permit, after a timely and
complete application, or delays due to documented supply chain issues;
for example, a backlog for step-up transformer equipment. This
compliance date extension is not expressly offered for reliability
purposes, but rather as a flexibility to account for unforeseen and
uncontrollable lags in construction or implementation of control
technology to meet the unit's standard of performance, in instances
where a source can demonstrate efforts to comply by the required
timeframes as part of these final actions, including evidence that it
took the necessary steps to comply with sufficient lead time to meet
the compliance schedule absent unusual problems, and that those
problems are entirely outside the source's control and the source's
actions or inactions did not contribute to the delay. This potential
extension can help ensure that sufficient capacity is available by
providing additional time for an affected EGU to operate for a specific
amount of time while it resolves delays related to installation of
pollution controls.
If the owner/operator of an affected EGU encounters a delay outside
of the owner or operator's control, and which prevents the source from
meeting its compliance obligations, the affected EGU must follow the
procedures outlined in the state plan for documenting the basis for the
extension.\1028\ Any delay in implementation that will necessitate a
compliance date extension of more than 1 year must be done through a
state plan revision to adjust the compliance schedule using RULOF as a
basis. See section X.C.2 of this preamble for information on RULOF.
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\1028\ Assuming the affected EGU is in a state that has included
the extension mechanism in its approved plan.
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A similar 1-year compliance date extension flexibility for units
implementing control technologies that encounter a delay outside of the
owner or operator's control which prevents the source from meeting
compliance obligations is also available to certain new sources, which
are directly regulated by the EPA. This is described in section VIII.N
of this preamble.
3. Reliability Mechanisms
While the EPA believes the significant structural adjustments and
compliance flexibilities that are discussed above are adequate to
ensure that the implementation of these final rules does not interfere
with systems operators' ability to ensure electric reliability, the EPA
is also finalizing two reliability-related mechanisms as additional
safeguards. These mechanisms include a short-term reliability mechanism
for unexpected and short-duration emergency events, and a reliability
assurance mechanism for units with retirement dates that are
enforceable in the state plan, provided there is a documented and
verified reliability concern. The EPA notes that these mechanisms must
be included in the state plan to be utilized by the owners/operators of
existing affected EGUs subject to requirements in the state plan.
Sections XII.3.a, and XII.3.b of this preamble describe presumptively
approvable methodologies for incorporating these mechanisms into a
state plan.
a. Short-Term Reliability Mechanism
Comment: Multiple commenters requested an explicit short-term
mechanism which could accommodate emergency situations and provide
additional flexibility to affected sources. Commenters requested that
the mechanism include additional rule flexibilities that could
potentially be used during emergency conditions that would help
reliability authorities avert a load shed event. A mechanism would
function as an additional automated flexibility measure with a clearly
articulated emergency provision for affected sources to respond to
short-duration emergency grid situations. Some commenters requested a
mechanism that is distinct from the process established by DOE's
emergency authority under the Federal Power Act (section 202(c)),
whereby DOE is required by the terms of section 202(c) to issue orders
tailored to best meet particularized emergency circumstances.\1029\
Other commenters highlighted the numerous rule flexibilities that were
designed to accommodate reliability concerns and emergency conditions
and indicated that the EPA's rule need not overly accommodate
reliability and resource adequacy concerns since the primary burden for
developing solutions falls to industry, grid operators, reliability
coordinators, state planners, and other stakeholders. These commenters
indicated that it is important to consider any trade-offs with
additional flexibility measures, in particular any trade-offs with
emissions implications.
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\1029\ https://www.energy.gov/ceser/does-use-federal-power-act-emergency-authority.
---------------------------------------------------------------------------
Response: The EPA agrees with the latter commenters and expects
that the broader adjustments in the final rules, in addition to the
compliance flexibilities offered to states in section X.D of this
document, along with DOE's pre-existing section 202(c) authority, are
sufficient to enable an affected unit to respond to emergencies as
needed and still comply with the annual requirements of these actions.
As an additional safeguard measure, the EPA is finalizing a short-term
reliability mechanism to assure that these final actions will not
interfere with grid operators' ability to ensure electric reliability.
More specifically, the EPA has determined that some accommodation
during grid emergencies, which are rare, is warranted in order to
provide some additional flexibility to help system planners, affected
sources, state regulators, and reliability authorities meet demand and
avert load shed when such emergencies occur. The EPA believes this
additional flexibility is warranted, given the projected increase in
extreme weather events exacerbated by climate change.
A short-term reliability mechanism for new sources is included in
the final NSPS. Similarly, a short-term mechanism is offered to states
to include in state plans for use with existing sources during specific
and defined periods of time where the grid is under extreme strain. The
short-term reliability mechanism is linked to specific conditions under
which the system operators may not have
[[Page 40015]]
sufficient available generation to call upon to meet electric demand,
and various reliability authorities have issued emergency alerts to
rectify the situation. These emergency alerts are most often associated
with extreme weather events where electric demand increases and there
are often unexpected transmission and generation outages. Recent
examples of short-term emergency alert conditions include Winter Storm
Uri in 2021 and Winter Storm Elliot in 2022, both of which included
unanticipated generator outages and triggered emergency grid
operations. The EPA expects that the broader adjustments to the final
rules, in combination with the compliance flexibilities described in
section XII.F.2 of this document, are sufficient to enable an affected
unit to respond to grid emergencies as needed and still comply with the
annual requirements of these actions. Nonetheless, the EPA is
finalizing this short-term reliability mechanism, available to states
to include at their discretion, to provide an additional layer of
assurance that these final actions will not interfere with the grid
operator's ability to ensure electric reliability.
A short-term reliability mechanism is included for new sources in
the final NSPS, and additionally offered to states to include in state
plans for existing sources. The mechanism provides affected sources
additional flexibility during rare and extreme emergency events, when
all available generators are called upon to meet electric demand. For
new sources, the mechanism allows sources to calculate applicability
and compliance without using the emissions and operational data
produced during these discrete events, with appropriate
documentation.\1030\ For existing sources, the mechanism allows sources
to use the baseline emission rate during these discrete events, also
with appropriate documentation.\1031\
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\1030\ The performance standard shall be the Phase I standard
for the affected new source under the NSPS.
\1031\ The baseline emission rate for existing sources is the
CO2 mass emissions and corresponding electricity
generation data for a given affected EGU from any continuous 8-
quarter period from 40 CFR part 75 reporting within the 5-year
period immediately prior to the date the final rule is published in
the Federal Register.
---------------------------------------------------------------------------
The mechanism is only applicable during an Energy Emergency Alert
level 2 or 3 as defined by NERC Reliability Standard EOP-011-2 or its
successor, which requires plans and sets procedures for reliability
entities to help avert disruptions in electric service during emergency
conditions.\1032\ The NERC reliability standard articulates roles and
responsibilities, defines notification processes for reliability
coordinators and operators, requires a plan for grid management
practices, and specifies a compliance monitoring process. Notably, the
standard defines three levels of Energy Emergency Alerts (EEA) that
guide reliability coordinators during energy emergencies and assist
with communicating information across the system and with the public to
avert potential disruptions:
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\1032\ NERC Reliability Standards, https://www.nerc.com/pa/Stand/Pages/ReliabilityStandards.aspx, and NERC Emergency
Preparedness and Operations (Reliability Standard EOP-011-2).
https://www.nerc.com/pa/Stand/Reliability%20Standards/EOP-011-2.pdf.
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EEA-1: All available generation resources in use--The
Balancing Authority is experiencing conditions where all available
generation resources are committed to meet firm load, firm
transactions, and reserve commitments, and is concerned about
sustaining its required Contingency Reserves.
EEA-2: Load management procedures in effect--The Balancing
Authority is no longer able to provide its expected energy requirements
and is an energy deficient Balancing Authority. An energy deficient
Balancing Authority has implemented its Operating Plan(s) to mitigate
Emergencies. An energy deficient Balancing Authority is still able to
maintain its minimum Contingency Reserve requirement.
EEA-3: Firm Load interruption is imminent or in progress--
The energy deficient Balancing Authority is unable to meet minimum
Contingency Reserve requirements.
The alerts are typically issued in reaction to emergencies as they
develop, are generally rare, and most often have been issued during
extreme weather events, such as hurricanes, cold weather events, and
heatwaves. The most concerning alert is EEA-3, where interruption of
electric service through controlled load shed is imminent for some
areas, although load shed does not necessarily occur under every EEA-3
declaration. According to NERC, 25 EEA-3s were declared in 2022, an
increase of 15 EEA-3 declarations over 2021. Nine of the EEA-3
declarations in 2022 included shedding of firm load. While the number
of declarations increased from 2021, the amount of load that was shed
during the 2022 events was less than 10 percent of the previous
year.\1033\ All of the EEA-3 declarations in 2022 were related to
extreme weather impacts, according to NERC.\1034\
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\1033\ 2023 State of Reliability Technical Assessment, NERC.
https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/NERC_SOR_2023_Technical_Assessment.pdf.
\1034\ Ibid.
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Other emergency events (EEA-1 and EEA-2) are more frequent,
although also relatively rare, based upon recent data. Data for the
largest ISOs and RTOs indicate that EEA-1 and EEA-2 can occur several
times over a year, for relatively brief periods in most instances, in
response to developing reliability emergencies.\1035\ Across the
country, reliability coordinators (RCs) are charged by NERC to
implement reliability standards and issue EEAs.\1036\ The RCs monitor,
track, and issue alerts according to the NERC alert protocol. This data
is also generally supposed to be publicly available on each reliability
coordinator's website, which documents the frequency and duration of
emergency alerts. However, while there are requirements to report
events where EEA-3 was declared to NERC \1037\ and NERC publicly tracks
use of EEA-3,\1038\ EEA-1 events are the least likely to be documented
consistently, for example, there is no similar publicly available
tracking and reporting for use of EEA-1 alerts in a centralized and
consistent manner.
---------------------------------------------------------------------------
\1035\ Since 2021, ERCOT issued two EEA-1 events, two EEA-2
events, and one EEA-3 event (all for events occurring over an 8-hour
period one day in 2021, and for 1 hour in 2023). In SPP, since 2021,
there were eight EEA-1 events, five EEA-2 events, and two EEA-3
events (occurring over 5 days). The EEA-1 and EEA-2 events lasted
between 1 and 19 hours. In MISO, there was a 2-day event in 2021
that resulted in an EEA magnitude 1, 2, or 3 alert through the day
and into the next day. One EEA-1 event in 2022 lasted for a half
hour and an EEA-2 event for 3 hours. In 2023, there was an EEA-2
event for 9.5 hours. In PJM, no alerts were issued in 2021. In 2022,
roughly a dozen alerts were issued. Some lasted minutes, while
others lasted half a day. One event stretched for 3 days. There were
two alerts issued in 2023, lasting roughly 3 and 1 hours each. While
this data is not comprehensive, it is indicative of the frequency
and duration of emergency events that fall under the NERC
reliability standard alert process. See: ERCOT Market Notices, SPP
Historical Advisories and Alerts, https://www.oasis.oati.com/SWPP/;
MISO Maximum Generation Emergency Declarations (2023), https://www.oasis.oati.com/woa/docs/MISO/MISOdocs/Capacity_Emergency_Historical_Information.pdf; and MISO Maximum
Generation Emergency Declarations (2023), https://www.oasis.oati.com/woa/docs/MISO/MISOdocs/Capacity_Emergency_Historical_Information.pdf. See also PJM
Emergency Procedures and Postings, https://emergencyprocedures.pjm.com/ep/pages/dashboard.jsf.
\1036\ NERC Organization Certification (January 2024). https://www.nerc.com/pa/comp/Pages/Registration.aspx.
\1037\ https://www.nerc.com/comm/PC/Performance%20Analysis%20Subcommittee%20PAS%202013/M-11_Energy_Emergency_Alerts.pdf.
\1038\ https://www.nerc.com/pa/RAPA/ri/Pages/EEA2andEEA3.aspx.
---------------------------------------------------------------------------
Energy Emergency Alerts also have an important geographic and/or
regional component, since most emergencies affect a particular
geographic zone, and hence a smaller number of generators are subject
to the alert in most instances.
[[Page 40016]]
During extreme and large-scale weather events, the alerts often cover a
much broader geographic area, such as when Winter Storm Elliott
impacted two-thirds of the lower 48 states and rapidly intensified into
a bomb cyclone in December 2022. Many areas declared EEAs, and four
states experienced operator-controlled load shed and 2.1 million
customers experienced power outages.\1039\ When these events occur, a
much larger group of affected sources would be potentially
covered.\1040\ It should be noted that issuance of EEA's is not just
dependent on a generator's availability, but also, generation
deliverability, as transmission constraints due to operational
conditions or planned maintenance activities can lead to issuance of
EEA's that help ensure system stability and reliability.
---------------------------------------------------------------------------
\1039\ 2023 State of Reliability Technical Assessment, NERC.
https://www.nerc.com/pa/RAPA/PA/Performance%20Analysis%20DL/NERC_SOR_2023_Technical_Assessment.pdf.
\1040\ For example, the entire footprint of SPP currently
includes roughly 50 individual coal-steam units, reflecting roughly
19 GW of capacity.
\1040\ For PJM, there are currently roughly 65 individual coal-
steam units with total capacity of roughly 30 GW, which could
potentially be covered by a regionwide alert. These estimates are
considerably lower when known and committed coal-steam retirements
are excluded. Within the PJM footprint, there are 27 control areas
or transmission zones where emergency procedures are applied.
---------------------------------------------------------------------------
The EPA's assessment is that these alerts generally occur
infrequently, only rarely persist for as long as several days, and are
indicative of a grid under strain. When the alerts are more prolonged,
lasting for several days, they are generally dictated by persistent
extreme weather with widespread impacts and a higher probability of
load shed. The short-term reliability mechanism offers sources that
come under a documented level 2 and or 3 EEA, combined with a
documented request from the balancing authority to deviate from its
scheduled operations, for example, by increasing output in response to
the alert. In other words, only the specific units called upon, or
otherwise instructed to increase output beyond the planned day-ahead or
other near-term expected output during an EEA level 2 or 3 event are
eligible for this flexibility, with proper documentation.
For new sources, the emissions and/or generation data will not be
counted when determining applicability and the use of the sources'
Phase 1 standard of performance may be used for compliance
determinations through the duration of these events, as long as
appropriate documentation is provided. For existing sources, states may
choose to temporarily apply an alternative standard of performance, or
a unit's baseline emission performance rate, when demonstrating
compliance with the final standards, with appropriate documentation. It
should be emphasized that these final emission guidelines require
compliance with the standards of performance on an annual basis (or
rolling annual average for new sources), as opposed to a shorter period
such as hourly, daily, or monthly. This relatively long compliance
period provides significant flexibility for sources that face
circumstances whereby their emission performance may change temporarily
due to various factors, including in response to grid emergency
conditions. Nonetheless, this mechanism is included in these final
rules to ensure that affected sources have the additional flexibility
needed to meet demand during emergency conditions.\1041\
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\1041\ For example, units with installed CCS technology may be
called upon to run at full capacity (i.e., without the parasitic
load of the carbon capture equipment). The EPA does not expect this
to be a typical response as units are economically disincentivized
to shut off or bypass control equipment given the tax credit
incentives in IRC section 45Q.
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The short-term reliability mechanism references EEA-2 and EEA-3 for
several reasons. First, balancing authorities and grid operators do not
necessarily have to take action under EEA-1 conditions, such as calling
on interruptible loads. As such, there is much less cost or
inconvenience to declaring EEA-1, as a general matter, and EEA-2 and
EEA-3 events are more aligned with events that are rare or truly
represent emergency conditions. Second, EEA-1 events are a preparatory
step in anticipation of potentially worsening conditions, as opposed to
an indicator of imminent load-shed. Thus, under EEA-1, balancing
authorities and grid operators do not generally take actions such as
calling for voluntary demand reduction or calling on interruptible
loads, and reliability coordinators are afforded more discretion for
declaring an EEA-1. As such, there is much less cost or inconvenience
to declaring EEA-1, as a general matter, and providing operational or
cost relief under EEA-1 could create an incentive to deploy it more
routinely. In addition, waiving significant regulatory requirements
before taking actions such as calling for voluntary demand reductions
or calling upon contractually arranged interruptible loads would not be
commensurate to the significance of the various response actions.
Third, reliability coordinators are afforded more discretion for
declaring an EEA-1, and thus may have a potential incentive to deploy
it more routinely if there is some operational or cost relief
associated with it. And lastly, the reporting of EEA-1 is not
consistent throughout the country, and there is some degree of
opaqueness associated with the frequency and duration of EEA-1 events,
thus making it a less robust mechanism threshold for purposes of
aligning it with the requirements of this final action. For these
reasons, the EPA believes that EEA-2 and EEA-3 are the appropriate
threshold for inclusion in the short-term reliability mechanism and
better represent rare or truly emergency conditions in which providing
a limited exemption from a significant environmental requirement is
justifiable.
Thus, the EPA believes that the selection of EEA-2 and EEA-3 are
aligned with the conditions envisioned where an affected source might
need temporarily relief, in order to offer reliability coordinators and
balancing authorities the flexibility needed during emergency events to
maintain reliability. In addition, as explained earlier, DOE's 202(c)
authority is an additional mechanism that can be deployed under certain
emergency conditions, which may occur outside any EEA-2 or EEA-3 event.
These tools, either individually or in combination, help provide
additional assurance that sources and reliability coordinators can
continue to maintain a reliable system.
The mechanism is available to states to include in their state
plans in an explicit manner, which will allow additional flexibility to
sources in those states during short-term reliability emergencies.
Inclusion of the reliability mechanism in a state plan must be part of
the public comment process that each state must undertake. The comment
process will afford full notice and the opportunity for the public
comment, and the state plan will need to specify alternative
performance standards for each specific affected source during these
events (as defined in this section). The state plan must clearly
indicate the specific parameters of emergency alerts cited as part of
this mechanism, the relevant reliability coordinators that are
authorized to issue the alerts in the state, and the compliance
entities who are affected by this action (i.e., affected sources).
These sources must provide documentation of emergencies, as indicated
in this section. The documentation must include evidence of the alert
from the issuing entity, duration of the alert, and requests by
reliability entities to sources to increase output in response to the
emergency. The source must supply this
[[Page 40017]]
information to the state regulatory entities and to the EPA when
demonstrating compliance with the annual performance standards. This
demonstration will indicate the discrete periods where the alternative
standards or emission rates were in place, coinciding with the
emergency alerts.
The calculation of the emission rate for an affected source in a
state that adopts the short-term reliability mechanism must adhere to
the following during potential emergency alerts:
When demonstrating annual compliance with the standard of
performance, the existing affected source may apply its baseline
emission rate in lieu of its standard of performance for the hours of
operation that correspond to the duration of the alert; and
The existing affected EGU would demonstrate compliance
based on application of its baseline emission performance rate standard
of performance for the documented hours it operated under a revised
schedule due to an EEA 2 or 3.
For new sources, the EGU would demonstrate compliance
based on application of its phase 1 performance standard for the
documented hours it operated under a revised schedule due to an EEA 2
or 3. with the same documentation listed above.
Supplemental reporting, recordkeeping and documentation required:
Documentation that the EEA was in effect from the entity
issuing the alert, along with documentation of the exact duration of
the event; \1042\
---------------------------------------------------------------------------
\1042\ https://www.nerc.com/pa/Stand/Reliability%20Standards/EOP-011-2.pdf.
---------------------------------------------------------------------------
Documentation from the entity issuing the alert that the
EEA included the affected source/region where the unit was located; and
Documentation that the source was instructed to increase
output beyond the planned day-ahead or other near-term expected output
and/or was asked to remain in operation outside of its scheduled
dispatch during emergency conditions from a reliability coordinator,
balancing authority, or ISO/RTO.
b. Reliability Assurance Mechanism
The EPA gave considerable attention and thought to comments from
all stakeholders concerning potential reliability-related
considerations. As noted earlier, the EPA engaged in extensive
stakeholder outreach and provided additional opportunity for public
comment as part of the supplemental notice for small businesses, since
similar reliability-related concerns were raised. This section provides
additional background, as well as approvable language, for a
reliability assurance mechanism that states have the option to
incorporate into their state plans.
Comment: Some commenters cautioned that EPA rules could exacerbate
an ongoing concern that firm, dispatchable assets are exiting the grid
at a faster pace than new capacity can be deployed and that most new
electric generating capacity does not provide the equivalent
reliability attributes as the capacity being retired. Several
commenters provided examples where units with publicly announced
retirement dates were delayed by reliability entities and coordinators
due, in part, to the potential for energy shortfalls that might
increase reliability risks in the ISO. Many commenters cited findings
from NERC that highlighted the potential for capacity shortfalls, some
of which are already in effect in some areas. Other commenters asserted
that there is no need for a reliability assurance mechanism given the
sufficient lead times in the proposal and the various flexibilities
already provided. Some commenters included analysis that showed
resource adequacy shortfalls over the forecasted time horizon were
limited and manageable under the proposal.
Response: The EPA believes that the provisions in these final
actions are sufficient to accommodate installation of pollution
controls and reliability planning. The EPA has further articulated the
use of RULOF, which can be deployed under the state planning and
revision processes, for specific circumstances related to reliability.
The EPA is also finalizing compliance flexibilities that can address
delays to the installation or permitting of control technologies or
associated infrastructure that are beyond the control of the EGU owner/
operator. The EPA acknowledges that isolated issues could unfold over
the course of the implementation timeline that could not have been
foreseen during the planning process and that may require units to
remain online beyond their planned cease operation dates to maintain
reliability.
The EPA does not agree that the final rule will result in long-term
adverse reliability impacts.1043 1044 Nevertheless, as an
added safeguard, the EPA is finalizing a reliability assurance
mechanism for existing affected sources that have committed to cease
operation but, for unforeseen reasons, need to temporarily remain
online to support reliability for a discrete amount of time beyond
their planned date to cease operations. The primary mechanism to
address reliability-related issues for units with cease operations
dates is through the state plan revision process. This reliability
assurance mechanism is designed to enable extensions for cease
operation dates when there is insufficient time to complete a state
plan revision. Under this reliability assurance mechanism, which can
only be accessed if included in a state plan, units could obtain up to
a 1-year extension of a cease operation date. If a state decides to
include the mechanism in its state plan, then the mechanism must be
disclosed during the public comment process that states must undertake.
Under this reliability assurance mechanism, units may obtain extensions
only for the amount of time substantiated through their applications
and approved by the appropriate EPA Regional Administrator. For
extension requests greater than 6 months, EPA will seek the advice of
FERC in these cases and therefore applications must be submitted to
FERC, as well as to the appropriate EPA Regional Administrator. The
date from which an extension can be given is the enforceable date in
the state plan, including any cease operation dates in state plans that
are prior to January 1, 2032.
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\1043\ ``Bulk System Reliability for Tomorrow's Grid'' The
Brattle Group, December 20, 2023.
\1044\ ``The Future of Resource Adequacy'' The Department of
Energy, April 2024.
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These provisions are similar in part to a reliability-related
flexibility provided by the EPA for the MATS rule finalized in December
2011. On December 16, 2011, the EPA issued a memorandum \1045\
outlining an Enforcement Response Policy whereby affected sources enter
into a CAA section 113(a) administrative order for up to 1 year for
narrow circumstances including when the deactivation of a unit or delay
in installation of controls due to factors beyond the owner's/
operator's control could have an adverse, localized impact on electric
reliability. Under MATS, affected sources were required to come into
compliance with standards within 3 years of the effective date. The EPA
believed flexibility was warranted given potential constraints around
the availability of control equipment and associated skilled workforce
for all affected sources within the compliance window. While a 1-year
extension as
[[Page 40018]]
part of CAA section 112(i)(3)(B) was broadly available to affected
sources, additional time through an administrative order was limited to
units that were demonstrated to be critical for reliability purposes
under the Enforcement Response Policy.\1046\ FERC's role in this
process, which was developed with extensive stakeholder input,\1047\
was to assess the submitted request to ensure any application was
adequately substantiated with respect to its reliability-related
claims. While several affected EGUs requested and were granted a 1-year
CAA section 112(i)(3)(B) compliance extension by their permitting
authority, OECA only issued five administrative orders in connection to
the Enforcement Response Policy.\1048\ These orders relied upon a FERC
review of the reliability risks associated with the loss of specific
units, following the accompanying FERC policy memorandum
guidance.\1049\ The 2012 MATS Final Rule was ultimately implemented
over the 2015-2016 timeframe without challenges to grid reliability.
---------------------------------------------------------------------------
\1045\ https://www.epa.gov/sites/default/files/documents/mats-erp.pdf.
\1046\ December 16, 2011, memorandum, ``The Environmental
Protection Agency's Enforcement Response Policy For Use Of Clean Air
Act Section 113(a) Administrative Orders In Relation To Electric
Reliability And The Mercery and Air Toxics Standard'' from Cynthia
Giles, Assistant Administrator of the Office of Enforcement and
Compliance Assurance.
\1047\ See FERC Docket No. PL12-1-000.
\1048\ https://www.epa.gov/enforcement/enforcement-response-policy-mercury-and-air-toxics-standard-mats.
\1049\ https://www.ferc.gov/sites/default/files/2020-04/E-5_9.pdf.
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Given the array of adjustments made to the rule explained above,
and the ability of states to address unanticipated changes in
circumstances through the state plan revision process, the EPA does not
anticipate that this mechanism, if included by states in the planning
process, will be heavily utilized. This mechanism provides an assurance
to system planners and affected sources, which can provide additional
time for the state to execute a state plan revision, if needed. For
states choosing to include this option in their state plans, the
reliability assurance mechanism can provide units up to a 1-year
extension of the scheduled cease operation date without a state plan
revision, provided the reliability need is adequately justified and the
extension is limited to the time for which the reliability need is
demonstrated. This mechanism can accommodate situations when, with
little notice, the relevant reliability authority determines that an
EGU scheduled to cease operations is needed beyond that date, in order
to maintain reliability during the 12 months leading up to or after the
EGU is scheduled to retire. For potential situations in which system
planners, affected sources, and reliability authorities identify a
reliability concern, including a potential resource adequacy shortfall
and an associated demonstration of increased loss of load expectation,
more than one year in advance, this approach allows for the time needed
for states to undertake a state plan revision process. The EPA
recognizes that successful reliability planning involves many
stakeholders and is a complex long-term process. For this reason, the
EPA is encouraging states to consult electric reliability authorities
during the state plan process, as part of the requirements under
Meaningful Engagement (see section X.E.1.b.i of this document). The EPA
acknowledges that there may be isolated instances in which the
deactivation or retirement of a unit could have impacts on the electric
grid in the future that cannot be predicted or planned for with
specificity during the state planning process, wherein all anticipated
reliability-related issues would be analyzed and addressed. This
mechanism is not intended for use with units encountering unforeseen
delays in installation of control technologies, as such issues are
addressed through compliance flexibilities discussed in section
XII.F.2, or for units subject to an obligation to operate that is not
based on the reliability criteria included here.
To ensure that reliability claims, following the specific
requirements delineated below, submitted through this mechanism are
sufficiently well documented, the EPA is requiring that the unit's
relevant reliability Planning Authority(ies) certify that the claims
are accurate and that the identified reliability problem both exists
and requires the specific relief requested. Additionally, the EPA
intends to seek the advice of FERC, the Federal agency with authority
to oversee the reliability of the bulk-power system, to incorporate a
review of applications for this mechanism that request more than 6
months of additional operating time beyond the existing date by which
the unit is scheduled to cease operations to resolve a reliability
issue. Additional operating time is available for up to 12 months from
the unit's cease operation date through this mechanism. Any relief
request exceeding 12 months would need to be addressed through the
state plan revision process outlined in section X.E.3. In determining
whether to grant a request under this mechanism, the EPA will assess
whether the associated Planning Authority's reliability analysis
identifies and supports, in a detailed and reasoned fashion,
anticipated noncompliance with a Reliability Standard, substantiated by
specific metrics described below, should a unit go offline per its
established commitment. To assist in its determination, the EPA will
seek FERC's advice regarding whether analysis of the reliability risk
and the potential for violation of a mandatory Reliability Standard or
increased loss of load expectation is adequately supported in the filed
documentation.
This mechanism is for existing sources that have relied on a
commitment to cease operating for purposes of these emission
guidelines. Such reliance might occur in three circumstances: (1) units
that plan to cease operation before January 1, 2032, and that are
therefore exempt because they have elected to have enforceable cease
operations dates in the state plan; (2) affected EGUs that choose to
employ 40 percent natural gas co-firing by 2030 with a retirement date
of no later than January 1, 2039; or (3) affected EGUs that have
source-specific standards of performance based on remaining useful
life, pursuant to the RULOF provisions outlined in section X.C.2 of
this document. In each of these cases, units would have a commitment to
cease operating by a date certain. This mechanism would allow for
extensions of those dates to address unforeseen reliability or reserve
margin concerns that arise due to changes in circumstances after the
state plan has been finalized. Therefore, the date from which an
extension can be given under this mechanism is the enforceable cease
operations date in the state plan, including those prior to January 1,
2032. Only operators/owners of units that have satisfied all applicable
milestones, metrics, and reporting obligations outlined in section
X.C.3, and section X.C.4 for units with cease operation dates prior to
January 1, 2032, would be eligible to use this mechanism.
This mechanism creates additional flexibility for specified narrow
circumstances for existing sources and provides additional time and
flexibility to allow a state, if necessary, to submit a plan revision
should circumstances persist. In other words, this mechanism would be
for use only when there is insufficient time to complete a state plan
revision.
States can decide whether to include this extension mechanism in
their state plans. If included in a state plan, the mechanism would be
triggered when a unit submits an application to the EPA Regional
Administrator where it faces an unforeseen situation that creates a
[[Page 40019]]
reliability issue should that unit go offline consistent with its
commitment to cease operations--for example, if the reliability
coordinator identifies an unexpected capacity shortfall and determines
that a specific unit(s) in a state(s) is needed to remain operational
to satisfy a specific and documented reliability concern related to a
unit's planned retirement. This mechanism would allow extensions, if
approved by the Regional EPA Administrator, for units to operate after
committed retirement dates without a full state plan revision. Any
existing standard of performance finalized in the state plan under
RULOF or the natural gas co-firing subcategory would remain in place.
States have the discretion to place additional requirements on units
requesting extensions. The relevant EPA Regional Administrator would
approve the reliability assurance application or reject it if it were
found that that the reliability assertion was not adequately supported.
Units would need to substantiate the claim that they must remain online
for reliability purposes with documentation demonstrating a forecasted
reliability failure should the unit be taken offline, and this
justification would need to be submitted to the appropriate EPA
Regional Administrator and, for extensions exceeding 6 months, also to
FERC, as described below. Extensions would be granted only for the
duration of time demonstrated through the documentation, not to exceed
12 months, inclusive of the 6-month extension that is available and the
relevant Planning Authority(ies) must certify that the claims are
accurate and that the identified reliability problem both exists and
requires the specific relief requested. Any further extension would
require a state plan revision.
The process and documentation required to demonstrate that a unit
is required to stay online because it is reliability-critical is
described in this section.
In order to use this mechanism for an extension, certain conditions
must be met by the unit and substantiated in written electronic
notification to the appropriate EPA Regional Administrator, with an
identical copy submitted to FERC for extension requests exceeding 6
months. More specifically, those conditions are that, where
appropriate, the EGU owner complied with all applicable reporting
obligations and milestones as described in sections X.C.4 (for units in
the medium-term subcategory and units relying on a cease operation date
for a less stringent standard of performance pursuant to RULOF), and
section X.E.1.b.ii (for units with cease operation dates before January
1, 2032). No less than 30 days prior to the compliance date for
applications for extensions of less than 6 months, and no less than 45
days prior to the compliance date for applications for extensions
exceeding 6 months, but no earlier than 12 months prior to the
compliance date (any requests over 12 months prior to a compliance date
should be addressed through state plan revisions), a written complete
application to activate the reliability assurance mechanism must be
submitted to the appropriate EPA Regional Administrator, with a copy
submitted to the state, including information responding to each of the
seven elements listed as follows.
A copy of an extension request exceeding 6 months must also be
submitted to FERC through a process and at an office of FERC's
designation, including any additional specific information identified
by FERC and responding to each of the following elements:
(1) Analysis of the reliability risk if the unit were not in
operation demonstrating that the continued operation of the unit after
the applicable compliance date is critical to maintaining electric
reliability, such that retirement of that unit would trigger one or
more of the following: (A) would result in noncompliance with at least
one of the mandatory reliability standards approved by FERC, or (B)
would cause the loss of load expectation to increase beyond the level
targeted by regional system planners as part of their established
procedures for that particular region; specifically, this requires a
clear demonstration that each unit would be needed to maintain the
targeted level of resource adequacy.\1050\ In addition, a projection
substantiating the duration of the requested extension must be included
for the length of time that the unit is expected to extend its cease-
operations date because it is reliability-critical with accompanying
analysis supporting the timeframe, not to exceed 12 months. The
demonstration must satisfactorily substantiate at least one of the two
conditions outlined above. Any unit that has received a Reliability
Must Run Designation or equivalent from a reliability coordinator or
balancing authority would fit this description. The types of
information that will be helpful, based on the prior reliability
extension process developed for MATS between the EPA and FERC include,
but are not limited to, system planning and operations studies, system
restoration studies or plans, operating procedures, and mitigation
plans required by applicable Reliability Standards as defined by FERC
in its May 17, 2012, Policy Statement issued to clarify requirements
for the reliability extensions available through MATS.\1051\
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\1050\ Probabilistic Assessment: Technical Guideline Document,
NERC, August 2016.
\1051\ ``Policy Statement on the Commission's Role Regarding the
Environmental Protection Agency's Mercury and Air Toxics Standards''
FERC, Issued May 17, 2012, at PL12-1-000.
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(2) Analysis submitted by the relevant Planning Authority that
verifies the reliability related claims, or presents a separate and
equivalent analysis, confirming the asserted reliability risk if the
unit were not in operation, or an explanation of why such a concurrence
or separate analysis cannot be provided, and where necessary, any
related system wide or regional analysis. This analysis or concurrence
must include a substantiation for the duration of the extension
request.
(3) Copies of any written comments from third parties regarding the
extension.
(4) Demonstration from the unit owner/operator, grid operator and
other relevant entities that they have a plan that includes appropriate
actions, including bringing on new capacity or transmission, to resolve
the underlying reliability issue, including the steps and timeframes
for implementing measures to rectify the underlying reliability issue.
(5) Retirement date extensions allowed through this mechanism will
be granted for only the increment of time that is substantiated by the
reliability need and supporting documentation and may not exceed 12
months, inclusive of the 6-month extensions available with RTO, ISO,
and reliability coordinator certification.
(6) For units affected by these emissions guidelines, states may
choose to require the application to identify the level of operation
that is required to avoid the documented reliability risk, and
consistent with that level propose alternative compliance requirements,
such as alternative standards or consistent utilization constraints for
the duration of the extension. The EPA Regional Office may, within 30
days of the submission, reject the application if the submission is
incomplete with respect to the above requirements or if the reliability
assertion is not adequately supported.
(7) Only owners/operators of units that have satisfied all
applicable milestone and reporting requirements and obligations under
section X.C.3., and section X.C.4 for units with cease
[[Page 40020]]
operation dates prior to January 1, 2032, may use this mechanism for an
extension as those sources will have provided information enabling the
state and the public to assess that the units have diligently taken all
actions necessary to meet their enforceable cease operations dates and
demonstrate the use of all available tools to meet reliability
challenges. Units that have failed to meet these obligations may make
extension requests through the state plan revision process.
The EPA intends to consult with FERC in a timely manner on
reliability-critical claims given FERC's expertise on reliability
issues. The EPA may also seek advice from other reliability experts, to
inform the EPA's decision. The EPA intends to decide whether it will
grant a compliance extension for a retiring unit based on a documented
reliability need within 30 days of receiving the application for
applications less than 6 months, and within 45 days for applications
exceeding 6 months to account for time needed to consult with FERC.
Whether to grant an extension to an owner/operator is solely the
decision of the EPA Regional Administrator.
For units already subject to standards of performance through state
plans including those co-firing until 2039, and for units with
specific, tailored and differentiated compliance dates developed
through RULOF that employ this mechanism, those standards would apply
during the extension.
4. Considerations for Evaluating 111 Final Actions With Other EPA Rules
Consistent with the EPA's statutory obligations under a range of
CAA programs, the Agency has recently initiated and/or finalized
multiple rulemakings to reduce emissions of air pollutants, air toxics,
and greenhouse gases from the power sector. The EPA has conducted an
assessment of the potential impacts of these regulatory efforts on grid
resource adequacy, which is examined and discussed in the final TSD,
Resource Adequacy Analysis. This analysis is informed by regional
reserve margin targets, regional transmission capability, and generator
availability. Moreover, as described in this action, the EPA designs
its programs, implementation compliance flexibilities, and backstop
mechanisms to be robust to future uncertainties and various compliance
pathways for the collective of market and regulatory drivers. Finally,
the backstop reliability mechanisms discussed in this section are, by
design, similar to mechanisms utilized in the EPA's proposed Effluent
Limitations Guidelines (ELG) rulemaking. There, to ensure that units
choosing to permanently cease the combustion of coal by a particular
date in their permits are not restricted from operation in the event of
an emergency related to load balancing, the permit conditions allow for
grid emergency exemptions (88 FR 18900). Harmonizing the use of similar
criteria for emergency related reliability concerns across the two
rules further buttresses unit confidence that grid reliability and
environmental responsibilities will not come into conflict. It also
streamlines the demonstrations and evidence that a unit must provide in
such events. This cross-regulatory harmonization ensures that the
Agency can successfully meet its CWA and CAA responsibilities regarding
public health in a manner consistent with grid stability as it has
consistently done throughout its 54-year history.
The EPA has taken into consideration, to the extent possible, the
alignment of compliance timeframes and other aspects of these policies
for affected units. For each regulatory effort, there has been
coordination and alignment of requirements and timelines, to the extent
possible. The potential impact of these various regulatory efforts is
further examined in the final TSD, Resource Adequacy Analysis.
Additionally, the EPA considered the impact of this suite of power
sector rules by performing a variety of sensitivity analyses described
in XII.F.3. These considerations are discussed in the technical
memoranda, IPM Sensitivity Runs and Resource Adequacy Analysis: Vehicle
Rules, Final 111 EGU Rules, ELG, and MATS, available in the rulemaking
docket.
XIII. Statutory and Executive Order Reviews
Additional information about these statutes and Executive orders
can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 14094: Modernizing Regulatory Review
This action is a ``significant regulatory action'' as defined under
section 3(f)(1) of Executive Order 12866, as amended by Executive Order
14094. Accordingly, EPA, submitted this action to the Office of
Management and Budget (OMB) for Executive Order 12866 review. Any
changes made in response to recommendations received as part of
Executive Order 12866 review have been documented in the docket.
The EPA prepared an analysis of the potential costs and benefits
associated with these actions. This analysis, ``Regulatory Impact
Analysis for the New Source Performance Standards for Greenhouse Gas
Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired
Electric Generating Units; Emission Guidelines for Greenhouse Gas
Emissions from Existing Fossil Fuel-Fired Electric Generating Units;
and Repeal of the Affordable Clean Energy Rule,'' is available in the
docket and describes in detail the EPA's assumptions and characterizes
the various sources of uncertainties affecting the estimates.
Table 6 presents the estimated present values (PV) and equivalent
annualized values (EAV) of the projected climate benefits, health
benefits, compliance costs, and net benefits of the final rules in 2019
dollars discounted to 2024. This analysis covers the impacts of the
final standards for new combustion turbines and for existing steam
generating EGUs. The estimated monetized net benefits are the projected
monetized benefits minus the projected monetized costs of the final
rules.
Under E.O. 12866, the EPA is directed to consider the costs and
benefits of its actions. Accordingly, in addition to the projected
climate benefits of the final rules from anticipated reductions in
CO2 emissions, the projected monetized health benefits
include those related to public health associated with projected
reductions in PM2.5 and ozone concentrations. The projected
health benefits are associated with several point estimates and are
presented at real discount rates of 2, 3 and 7 percent. As shown in
section 4.3.9 of the RIA, there are health benefits in the years 2028,
2030, 2035, and 2045 and health disbenefits in 2040. The projected
climate benefits in this table are based on estimates of the social
cost of carbon (SC-CO2) at a 2 percent near-term Ramsey
discount rate and are discounted using a 2 percent discount rate to
obtain the PV and EAV estimates in the table. The power industry's
compliance costs are represented in this analysis as the change in
electric power generation costs between the baseline and illustrative
policy scenarios. In simple terms, these costs are an estimate of the
increased power industry expenditures required to implement the final
requirements.
These results present an incomplete overview of the potential
effects of the final rules because important categories of benefits--
including benefits from reducing HAP emissions--were not monetized and
are therefore not reflected in the benefit-cost tables. The EPA
anticipates that taking non-monetized effects into account would
[[Page 40021]]
show the final rules to have a greater net benefit than this table
reflects.
Table 6--Projected Benefits, Compliance Costs, and Net Benefits of the Final Rules, 2024 Through 2047
[Billions 2019$, discounted to 2024] \a\
----------------------------------------------------------------------------------------------------------------
Present value (PV)
--------------------------------------------------------
2% Discount rate 3% Discount rate 7% Discount rate
----------------------------------------------------------------------------------------------------------------
Climate Benefits \c\................................... 270 270 270
Health Benefits \d\.................................... 120 100 59
Compliance Costs....................................... 19 15 7.5
Net Benefits \e\....................................... 370 360 320
----------------------------------------------------------------------------------------------------------------
Equivalent Annualized Value (EAV) \b\
----------------------------------------------------------------------------------------------------------------
Climate Benefits \c\................................... 14 14 14
Health Benefits \d\.................................... 6.3 6.1 5.2
Compliance Costs....................................... 0.98 0.91 0.65
Net Benefits \e\....................................... 20 19 19
--------------------------------------------------------
Non-Monetized Benefits \e\............................. Benefits from reductions in HAP emissions
Ecosystem benefits associated with reductions in
emissions of CO2, NOX, SO2, PM, and HAP
Reductions in exposure to ambient NO2 and SO2
Improved visibility (reduced haze) from PM2.5
reductions
----------------------------------------------------------------------------------------------------------------
\a\ Values have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding.
\b\ The annualized present value of costs and benefits are calculated over the 24-year period from 2024 to 2047.
\c\ Monetized climate benefits are based on reductions in CO2 emissions and are calculated using three different
estimates of the SC-CO2 (under 1.5 percent, 2.0 percent, and 2.5 percent near-term Ramsey discount rates). For
the presentational purposes of this table, we show the climate benefits associated with the SC-CO2 at the 2
percent near-term Ramsey discount rate. Please see section 4 of the RIA for the full range of monetized
climate benefit estimates.
\d\ The projected monetized air quality related benefits include those related to public health associated with
reductions in PM2.5 and ozone concentrations. The projected health benefits are associated with several point
estimates and are presented at real discount rates of 2, 3, and 7 percent. This table presents the net health
benefit impact over the analytic timeframe of 2024 to 2047. As shown in section 4.3.9 of the RIA, there are
health benefits in the years 2028, 2030, 2035, and 2045 and health disbenefits in 2040.
\e\ Several categories of climate, human health, and welfare benefits from CO2, NOX, SO2, PM and HAP emissions
reductions remain unmonetized and are thus not directly reflected in the quantified benefit estimates in this
table. See section 4.2 of the RIA for a discussion of climate effects that are not yet reflected in the SC-CO2
and thus remain unmonetized and section 4.4 of the RIA for a discussion of other non-monetized benefits.
As shown in table 6, the final rules are projected to reduce
greenhouse gas emissions in the form of CO2, producing a
projected PV of monetized climate benefits of about $270 billion, with
an EAV of about $14 billion using the SC-CO2 discounted at 2
percent. The final rules are also projected to reduce emissions of
NOX, SO2 and direct PM2.5 leading to
national health benefits from PM2.5 and ozone in most years,
producing a projected PV of monetized health benefits of about $120
billion, with an EAV of about $6.3 billion discounted at 2 percent.
Thus, these final rules are expected to generate a PV of monetized
benefits of $390 billion, with an EAV of $21 billion discounted at a 2
percent rate. The PV of the projected compliance costs are $19 billion,
with an EAV of about $0.98 billion discounted at 2 percent. Combining
the projected benefits with the projected compliance costs yields a net
benefit PV estimate of about $370 billion and EAV of about $20 billion.
At a 3 percent discount rate, the final rules are expected to
generate projected PV of monetized health benefits of about $100
billion, with an EAV of about $6.1 billion. Climate benefits remain
discounted at 2 percent in this net benefits analysis. Thus, the final
rules would generate a PV of monetized benefits of about $370 billion,
with an EAV of about $20 billion discounted at 3 percent. The PV of the
projected compliance costs are about $15 billion, with an EAV of $0.91
billion discounted at 3 percent. Combining the projected benefits with
the projected compliance costs yields a net benefit PV estimate of
about $360 billion and an EAV of about $19 billion.
At a 7 percent discount rate, the final rules are expected to
generate projected PV of monetized health benefits of about $59
billion, with an EAV of about $5.2 billion. Climate benefits remain
discounted at 2 percent in this net benefits analysis. Thus, the final
rules would generate a PV of monetized benefits of about $330 billion,
with an EAV of about $19 billion discounted at 7 percent. The PV of the
projected compliance costs are about $7.5 billion, with an EAV of $0.65
billion discounted at 7 percent. Combining the projected benefits with
the projected compliance costs yields a net benefit PV estimate of
about $320 billion and an EAV of about $19 billion.
We also note that the RIA follows the EPA's historic practice of
using a detailed technology-rich partial equilibrium model of the
electricity and related fuel sectors to estimate the incremental costs
of producing electricity under the requirements of proposed and final
major EPA power sector rules. In section 5.2 of the RIA for these
actions, the EPA has also included an economy-wide analysis that
considers additional facets of the economic response to the final
rules, including the full resource requirements of the expected
compliance pathways, some of which are paid for through subsidies. The
social cost estimates in the economy-wide analysis and discussed in
section 5.2 of the RIA are still far below the projected benefits of
the final rules.
B. Paperwork Reduction Act (PRA)
1. 40 CFR Part 60, Subpart TTTT
This action does not impose any new information collection burden
under the PRA. OMB has previously approved the information collection
activities
[[Page 40022]]
contained in the existing regulations and has assigned OMB control
number 2060-0685.
2. 40 CFR Part 60, Subpart TTTTa
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned EPA ICR number 2771.01. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here. The
information collection requirements are not enforceable until OMB
approves them.
Respondents/affected entities: Owners and operators of fossil-fuel
fired EGUs.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 2.
Frequency of response: Annual.
Total estimated burden: 110 hours (per year). Burden is defined at
5 CFR 1320.3(b).
Total estimated cost: $12,000 (per year), includes $0 annualized
capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
3. 40 CFR Part 60, Subpart UUUUa
This action does not impose an information collection burden under
the PRA.
4. 40 CFR Part 60, Subpart UUUUb
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The ICR document that
the EPA prepared has been assigned EPA ICR number 2770.01. You can find
a copy of the ICR in the docket for this rule, and it is briefly
summarized here. The information collection requirements are not
enforceable until OMB approves them.
This rule imposes specific requirements on state governments with
existing fossil fuel-fired steam generating units. The information
collection requirements are based on the recordkeeping and reporting
burden associated with developing, implementing, and enforcing a plan
to limit GHG emissions from these existing EGUs. These recordkeeping
and reporting requirements are specifically authorized by CAA section
114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to
the recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The annual burden for this collection of information for the states
(averaged over the first 3 years following promulgation) is estimated
to be 89,000 hours at a total annual labor cost of $11.7 million. The
annual burden for the Federal government associated with the state
collection of information (averaged over the first 3 years following
promulgation) is estimated to be 24,000 hours at a total annual labor
cost of $1.7 million. Burden is defined at 5 CFR 1320.3(b).
Respondents/affected entities: States with one or more designated
facilities covered under subpart UUUUb.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 43.
Frequency of response: Once.
Total estimated burden: 89,000 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $11.7 million, includes $35,000 annualized
capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
C. Regulatory Flexibility Act (RFA)
Pursuant to sections 603 and 609(b) of the RFA, the EPA prepared an
initial regulatory flexibility analysis (IRFA) for the proposed rule
and convened a Small Business Advocacy Review (SBAR) Panel to obtain
advice and recommendations from small entity representatives that
potentially would be subject to the rule's requirements. Summaries of
the IRFA and Panel recommendations are presented in the supplemental
proposed rule at 88 FR 80582 (November 20, 2023). The complete IRFA and
Panel Report are available in the docket for this action.\1052\
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\1052\ See Document ID No. EPA-HQ-OAR-2023-0072-8109 and
Document ID No. EPA-HQ-OAR-2023-0072-8108.
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As required by section 604 of the RFA, the EPA prepared a final
regulatory flexibility analysis (FRFA) for this action. The FRFA
provides a statement of the need for, and objectives of, the rule;
addresses the issues raised by public comments on the IRFA for the
proposed rule, including public comments filed by the Chief Counsel for
Advocacy of the Small Business Administration; describes the small
entities to which the rule will apply; describes the projected
reporting, recordkeeping and other compliance requirements of the rule
and their impacts; and describes the steps the agency has taken to
minimize impacts on small entities consistent with the stated
objectives of the Clean Air Act. The complete FRFA is available for
review in the docket and is summarized here. The scope of the FRFA is
limited to the NSPS. The impacts of the emission guidelines are not
evaluated here because the emission guidelines do not place explicit
requirements on the regulated industry. Those impacts will be evaluated
pursuant to the development of a Federal plan.
In 2009, the EPA concluded that GHG emissions endanger our nation's
public health and welfare. Since that time, the evidence of the harms
posed by GHG emissions has only grown and Americans experience the
destructive and worsening effects of climate change every day. Fossil
fuel-fired EGUs are the nation's largest stationary source of GHG
emissions, representing 25 percent of the United States' total GHG
emissions in 2021. At the same time, a range of cost-effective
technologies and approaches to reduce GHG emissions from these sources
are available to the power sector, and multiple projects are in various
stages of operation and development. Congress has also acted to provide
funding and other incentives to encourage the deployment of these
technologies to achieve reductions in GHG emissions from the power
sector.
In this notice, the EPA is finalizing several actions under CAA
section 111 to reduce the significant quantity of GHG emissions from
fossil fuel-fired EGUs by establishing emission guidelines and 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 BSER that,
[[Page 40023]]
taking into account costs, energy requirements, and other statutory
factors, is adequately demonstrated.
These final actions ensure that EGUs reduce their GHG emissions in
a manner that is cost-effective and improve 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 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.
The significant issues raised in public comments specifically in
response to the initial regulatory flexibility analysis came from the
Office of Advocacy within the Small Business Administration (Advocacy).
The EPA agreed that convening a SBAR Panel was warranted because the
EPA solicited comment on a number of policy options that, if finalized,
could affect the estimate of total compliance costs and therefore the
impacts on small entities. The EPA issued an IRFA and solicited comment
on regulatory flexibilities for small business in a supplemental
proposed rule, published in November 2023.
Advocacy provided further substantive comments on the IRFA that
accompanied the November 2023 supplemental proposed rule. The comments
reiterated the concerns raised in its original comment letter on the
proposed rule and further made the following claims: (1) the IRFA does
not provide small entities an accurate description of the impacts of
the proposed rule, (2) small entities remain concerned that the EPA has
not taken reliability concerns seriously.
In response to these comments and feedback during the SBAR Panel,
the EPA revised its small business assessment to incorporate the final
SBA guidelines (effective March 17th 2023) when performing the
screening analysis to identify small businesses that have built or have
planned/committed builds of combustion turbines since 2017. The EPA
also treated additional entities within this subset as small based on
feedback received during the panel process. The net effect of these
changes is to increase the total compliance cost attributed to small
entities, and the number of small entities potentially affected. The
EPA additionally increased the assumed delivered hydrogen price to
$1.15/kg.
Further, the EPA is finalizing multiple adjustments to the proposed
rule that ensure the requirements in the 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.
To estimate the number of small businesses potentially impacted by
the NSPS, the EPA performed a small entity screening analysis for
impacts on all affected EGUs by comparing compliance costs to historic
revenues at the ultimate parent company level. The EPA reviewed
historical data and planned builds since 2017 to determine the universe
of NGCC and natural gas combustion turbine additions. Next, the EPA
followed SBA size standards to determine which ultimate parent entities
should be considered small entities in this analysis.
Once the costs of the rule were calculated, the costs attributed to
small entities were calculated by multiplying the total costs to the
share of the historical build attributed to small entities. These costs
were then shared to individual entities using the ratio of their build
to total small entity additions in the historical dataset.
The EPA assessed the economic and financial impacts of the rule
using the ratio of compliance costs to the value of revenues from
electricity generation, focusing in particular on entities for which
this measure is greater than 1 percent. Of the 14 entities that own
NGCC units considered in this analysis, three are projected to
experience compliance costs greater than or equal to 1 percent of
generation revenues in 2035 and none are projected to experience
compliance costs greater than or equal to 3 percent of generation
revenues in 2035.
Prior to the November 2023 supplemental proposed rule, the EPA
convened a SBAR Panel to obtain recommendations from small entity
representatives (SERs) on elements of the regulation. The Panel
identified significant alternatives for consideration by the
Administrator of the EPA, which were summarized in a final report.
Based on the Panel recommendations, as well as comments received in
response to both the May 2023 proposed rule and the November 2023
supplemental proposed rule, the EPA is finalizing several regulatory
alternatives that could accomplish the stated objectives of the Clean
Air Act while minimizing any significant economic impact of the final
rule on small entities. Discussion of those alternatives is provided
below.
Mechanisms for reliability relief: As described in section XII.F of
this preamble, the EPA is finalizing several adjustments to provisions
in the proposed rules that address reliability concerns and ensure that
the final rules provide adequate flexibilities and assurance mechanisms
that allow grid operators to continue to fulfill their responsibilities
to maintain the reliability of the bulk-power system. The EPA is
additionally finalizing additional reliability-related instruments to
provide further certainty that implementation of these final rules will
not intrude on grid operator's ability to ensure reliability. The
short-term reliability emergency mechanism, which is available for both
new and existing units, is designed to provide an alternative
compliance strategy during acute system emergencies when reliability
might be threatened. The reliability assurance mechanism will be
available for existing units that intend to cease operating, but, for
unforeseen reasons, need to temporarily remain online to support
reliability beyond the planned cease operation date. This reliability
assurance mechanism, which requires an adequate showing of reliability
need, is intended to apply to circumstances where there is insufficient
time to complete a state plan revision. Whether to grant an extension
to an owner/operator is solely the decision of the EPA. Concurrence or
approval of FERC is not a condition but may inform EPA's decision.
These instruments will be presumptively approvable, provided they meet
the requirements defined in these emission guidelines, if states choose
to incorporate them into their plans.
Throughout the SBAR Panel outreach, SERs expressed concerns that
the proposed rule will have significant reliability impacts, including
that areas with transmission system limitations and energy market
constraints risk power interruption if replacement generation cannot be
put in place before retirements. SERs recommended that Regional
Transmission Organizations (RTOs) be involved to evaluate safety and
reliability concerns.
SERs additionally stated that the proposed rule relies on the
continued development of technologies not currently in wide use and
large-scale investments in new infrastructure and that the proposed
rule pushes these technologies significantly faster than the
infrastructure will be ready and sooner than the SERs can justify
investment to their stakeholders and ratepayers. SERs stated that this
is of particular concern for small entities that are retiring
generation in response to other regulatory mandates and need to replace
that generation to continue serving their customers.
[[Page 40024]]
The suite of comprehensive adjustments in the final rules, along
with the two explicit reliability mechanisms are directly responsive to
SER's statements and concerns about grid reliability and the impact of
retiring generating on small businesses.
Subcategories: Throughout the SBAR Panel, SERs expressed concerns
that control requirements on rural electric cooperatives may be an
additional hardship on economically disadvantaged communities and small
entities. SERs stated that the EPA should further evaluate increased
energy costs, transmission upgrade costs, and infrastructure
encroachment which are concrete effects on the disproportionately
impacted communities. Additionally, SERs stated hydrogen and CCS cannot
be BSER because they are not commercially available and viable in very
rural areas.
The EPA solicited comment on potential exclusions or subcategories
for small entities that would be based on the class, type, or size of
the source and be consistent with the Clean Air Act. The EPA also
solicited comment on whether rural electric cooperatives and small
utility distribution systems (serving 50,000 customers or less) can
expect to have access to hydrogen and CCS infrastructure, and if a
subcategory for these units is appropriate.
The EPA evaluated public comments received and determined that
establishing a separate subcategory for rural electric cooperatives was
not warranted. However, the EPA is not finalizing the low-GHG hydrogen
BSER pathway. In response to concerns raised by small business and
other commenters, the EPA conducted additional analysis of the BSER
criteria and its proposed determination that low-GHG hydrogen co-firing
qualified as the BSER. This additional analysis led the EPA to assess
that the cost of low-GHG hydrogen in 2030 will likely be higher than
proposed, and these higher cost estimates and associated uncertainties
related to its nationwide availability were key factors in the EPA's
decision to revise its 2030 cost estimate for delivered low-GHG
hydrogen and are reflected in the increased price. For CCS, as
discussed in sections VIII.F.4.c.iv and VII.C.1.a of this preamble, the
EPA considered geographic availability of sequestration, as well as the
timelines, materials, and workforce necessary for installing CCS, and
determined they are sufficient. Moreover, while the BSER is premised on
source-to-sink CO2 pipelines and sequestration, the EPA
notes that many EGUs in rural areas are primed to take advantage of
synergy with the broader deployment of CCS in other industries.
Capture, pipelines, and sequestration are already in place or in
advanced stages of deployment for ethanol production from corn, an
industry rooted in rural areas. The high purity CO2 from
ethanol production provides advantageous economics for CCS.
The EPA believes the decision to not finalize a low-GHG hydrogen
BSER pathway is responsive to SER's statements and concerns regarding
the availability of low-GHG hydrogen in very rural areas.
In addition, the EPA is preparing a Small Entity Compliance Guide
to help small entities comply with this rule. The guide will be
available 60 days after publication of the final rule at https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.
D. Unfunded Mandates Reform Act of 1995 (UMRA)
The NSPS contain a Federal mandate under UMRA, 2 U.S.C. 1531-1538,
that may result in expenditures of $100 million or more for the private
sector in any one year. The NSPS do not contain an unfunded mandate of
$100 million or more as described in UMRA, 2 U.S.C. 1531-1538 for
state, local, and tribal governments, in the aggregate. Accordingly,
the EPA prepared, under section 202 of UMRA, a written statement of the
benefit-cost analysis, which is in section XIII.A of this preamble and
in the RIA.
The repeal of the ACE Rule and emission guidelines do not contain
an unfunded mandate of $100 million or more as described in UMRA, 2
U.S.C. 1531-1538, and do not significantly or uniquely affect small
governments. The emission guidelines do not impose any direct
compliance requirements on regulated entities, apart from the
requirement for states to develop plans to implement the guidelines
under CAA section 111(d) for designated EGUs. The burden for states to
develop CAA section 111(d) plans in the 24-month period following
promulgation of the emission guidelines was estimated and is listed in
section XIII.B, but this burden is estimated to be below $100 million
in any one year. As explained in section X.E.6, the emission guidelines
do not impose specific requirements on tribal governments that have
designated EGUs located in their area of Indian country.
These actions are not subject to the requirements of section 203 of
UMRA because they contain no regulatory requirements that might
significantly or uniquely affect small governments. In light of the
interest in these actions among governmental entities, the EPA
initiated consultation with governmental entities. The EPA invited the
following 10 national organizations representing state and local
elected officials to a virtual meeting on September 22, 2022: (1)
National Governors Association, (2) National Conference of State
Legislatures, (3) Council of State Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6) National Association of
Counties, (7) International City/County Management Association, (8)
National Association of Towns and Townships, (9) County Executives of
America, and (10) Environmental Council of States. These 10
organizations representing elected state and local officials have been
identified by the EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. Also, the
EPA invited air and utility professional groups who may have state and
local government members, including the Association of Air Pollution
Control Agencies, National Association of Clean Air Agencies, and
American Public Power Association, Large Public Power Council, National
Rural Electric Cooperative Association, and National Association of
Regulatory Utility Commissioners to participate in the meeting. The
purpose of the consultation was to provide general background on these
rulemakings, answer questions, and solicit input from state and local
governments. For a summary of the UMRA consultation see the memorandum
in the docket titled Federalism Pre-Proposal Consultation
Summary.\1053\
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E. Executive Order 13132: Federalism
These actions do not have federalism implications as that term is
defined in E.O. 13132. Consistent with the cooperative federalism
approach directed by the Clean Air Act, states will establish standards
of performance for existing sources under the emission guidelines set
out in this final rule. These actions will not have substantial direct
effects on the states, on the relationship between the national
government and the states, or on the distribution of power and
responsibilities among the various levels of government.
Although the direct compliance costs may not be substantial, the
EPA nonetheless elected to consult with representatives of state and
local governments in the process of
[[Page 40025]]
developing these actions to permit them to have meaningful and timely
input into their development. The EPA's consultation regarded planned
actions for the NSPS and emission guidelines. The EPA invited the
following 10 national organizations representing state and local
elected officials to a virtual meeting on September 22, 2022: (1)
National Governors Association, (2) National Conference of State
Legislatures, (3) Council of State Governments, (4) National League of
Cities, (5) U.S. Conference of Mayors, (6) National Association of
Counties, (7) International City/County Management Association, (8)
National Association of Towns and Townships, (9) County Executives of
America, and (10) Environmental Council of States. These 10
organizations representing elected state and local officials have been
identified by the EPA as the ``Big 10'' organizations appropriate to
contact for purpose of consultation with elected officials. Also, the
EPA invited air and utility professional groups who may have state and
local government members, including the Association of Air Pollution
Control Agencies, National Association of Clean Air Agencies, and
American Public Power Association, Large Public Power Council, National
Rural Electric Cooperative Association, and National Association of
Regulatory Utility Commissioners to participate in the meeting. The
purpose of the consultation was to provide general background on these
rulemakings, answer questions, and solicit input from state and local
governments. For a summary of the Federalism consultation see the
memorandum in the docket titled Federalism Pre-Proposal Consultation
Summary.\1054\
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F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
These actions do not have tribal implications, as specified in
Executive Order 13175. The NSPS imposes requirements on owners and
operators of new or reconstructed stationary combustion turbines and
the emission guidelines do not impose direct requirements on tribal
governments. Tribes are not required to develop plans to implement the
emission guidelines developed under CAA section 111(d) for designated
EGUs. The EPA is aware of two fossil fuel-fired steam generating units
located in Indian country, and one fossil fuel-fired steam generating
units owned or operated by tribal entities. The EPA notes that the
emission guidelines do not directly impose specific requirements on EGU
sources, including those located in Indian country, but before
developing any standards for sources on tribal land, the EPA would
consult with leaders from affected tribes. Thus, Executive Order 13175
does not apply to these actions.
Because the EPA is aware of tribal interest in these rules and
consistent with the EPA Policy on Consultation and Coordination with
Indian Tribes, the EPA offered government-to-government consultation
with tribes and conducted outreach and engagement.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks Populations and Low-Income Populations
This action is subject to Executive Order 13045 (62 FR 19885, April
23, 1997) because it is a significant regulatory action as defined by
E.O. 12866(3)(f)(1), and the EPA believes that the environmental health
or safety risk addressed by this action has a disproportionate effect
on children. Accordingly, the Agency has evaluated the environmental
health and welfare effects of climate change on children. GHGs
contribute to climate change and are emitted in significant quantities
by the power sector. The EPA believes that the GHG emission reductions
resulting from implementation of these standards and guidelines will
further improve children's health. The assessment literature cited in
the EPA's 2009 Endangerment Findings concluded that certain populations
and life stages, including children, the elderly, and the poor, are
most vulnerable to climate-related health effects (74 FR 66524,
December 15, 2009). The assessment literature since 2016 strengthens
these conclusions by providing more detailed findings regarding these
groups' vulnerabilities and the projected impacts they may experience.
These assessments describe how children's unique physiological and
developmental factors contribute to making them particularly vulnerable
to climate change. Impacts to children are expected from heat waves,
air pollution, infectious and waterborne illnesses, and mental health
effects resulting from extreme weather events. In addition, children
are among those especially susceptible to most allergic diseases, as
well as health effects associated with heat waves, storms, and floods.
Additional health concerns may arise in low-income households,
especially those with children, if climate change reduces food
availability and increases prices, leading to food insecurity within
households. More detailed information on the impacts of climate change
to human health and welfare is provided in section III of this
preamble. Under these final actions, the EPA expects that
CO2 emissions reductions will improve air quality and
mitigate climate impacts which will benefit the health and welfare of
children.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
These actions, which are significant regulatory actions under
Executive Order 12866, are likely to have to have a significant adverse
effect on the supply, distribution or use of energy. The EPA has
prepared a Statement of Energy Effects for these actions as follows.
The EPA estimates a 1.4 percent increase in retail electricity prices
on average, across the contiguous U.S. in 2035, and a 42 percent
reduction in coal-fired electricity generation in 2035 as a result of
these actions. The EPA projects that utility power sector delivered
natural gas prices will increase 3 percent in 2035. As outlined in the
Final TSD, Resource Adequacy Analysis, available in the docket for this
rulemaking, the EPA demonstrates that compliance with the final rules
can be achieved while maintaining resource adequacy, and that the rules
include additional flexibility measures designed to address
reliability-related concerns. For more information on the estimated
energy effects, please refer section 3 of the RIA, which is in the
public docket.
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This rulemaking involves technical standards. Therefore, the EPA
conducted searches for the New Source Performance Standards for
Greenhouse Gas Emissions from New, Modified, and Reconstructed Fossil
Fuel-Fired Electric Generating Units; Emission Guidelines for
Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric
Generating Units; and Repeal of the Affordable Clean Energy Rule
through the Enhanced National Standards Systems Network (NSSN) Database
managed by the American National Standards Institute (ANSI). Searches
were conducted for EPA Method 19 of 40 CFR part 60, appendix A. No
applicable voluntary consensus standards (VCS) were identified for EPA
Method 19. For additional information, please see the March 23, 2023,
memorandum titled Voluntary Consensus Standard Results for New Source
Performance Standards for
[[Page 40026]]
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.\1055\
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In accordance with the requirements of 1 CFR part 51, the EPA is
incorporating the following 10 voluntary consensus standards by
reference in the final rule.
ANSI C12.20-2010, American National Standard for
Electricity Meters--0.2 and 0.5 Accuracy Classes (Approved August 31,
2010) is cited in the final rule to assure consistent monitoring of
electric output. This standard establishes the physical aspects and
acceptable performance criteria for 0.2 and 0.5 accuracy class
electricity meters. These meters would be used to measure hourly
electric output that would be used, in part, to calculate compliance
with an emissions standard.
ASME PTC 22-2014, Gas Turbines: Performance Test Codes,
(Issued December 31, 2014), is cited in the final rule to provide
directions and rules for conduct and reporting of results of thermal
performance tests for open cycle simple cycle combustion turbines. The
object is to determine the thermal performance of the combustion
turbine when operating at test conditions and correcting these test
results to specified reference conditions. PTC 22 provides explicit
procedures for the determination of the following performance results:
corrected power, corrected heat rate (efficiency), corrected exhaust
flow, corrected exhaust energy, and corrected exhaust temperature.
Tests may be designed to satisfy different goals, including absolute
performance and comparative performance.
ASME PTC 46-1996, Performance Test Code on Overall Plant
Performance, (Issued October 15, 1997), is cited in the final rule to
provide uniform test methods and procedures for the determination of
the thermal performance and electrical output of heat-cycle electric
power plants and combined heat and power units (PTC 46 is not
applicable to simple cycle combustion turbines). Test results provide a
measure of the performance of a power plant or thermal island at a
specified cycle configuration, operating disposition and/or fixed power
level, and at a unique set of base reference conditions. PTC 46
provides explicit procedures for the determination of the following
performance results: corrected net power, corrected heat rate, and
corrected heat input.
ASTM D388-99 (Reapproved 2004), Standard Classification of
Coals by Rank, covers the classification of coals by rank, that is,
according to their degree of metamorphism, or progressive alteration,
in the natural series from lignite to anthracite. It is used to define
coal as a fuel type which is then referenced when defining coal-fired
electric generating units, one of the subjects of this rule.
ASTM D396-98, Standard Specification for Fuel Oils, covers
grades of fuel oil intended for use in various types of fuel-oil-
burning equipment under various climatic and operating conditions.
These include Grades 1 and 2 (for use in domestic and small industrial
burners), Grade 4 (heavy distillate fuels or distillate/residual fuel
blends used in commercial/industrial burners equipped for this
viscosity range), and Grades 5 and 6 (residual fuels of increasing
viscosity and boiling range, used in industrial burners).
ASTM D975-08a, Standard Specification for Diesel Fuel
Oils, covers seven grades of diesel fuel oils based on grade, sulfur
content, and volatility. These grades range from Grade No. 1-D S15 (a
special-purpose, light middle distillate fuel for use in diesel engine
applications requiring a fuel with 15 ppm sulfur (maximum) and higher
volatility than that provided by Grade No. 2-D S15 fuel) to Grade No.
4-D (a heavy distillate fuel, or a blend of distillate and residual
oil, for use in low- and medium-speed diesel engines in applications
involving predominantly constant speed and load).
ASTM D3699-08, Standard Specification for Kerosine,
including Appendix X1, (Approved September 1, 2008) covers two grades
of kerosene suitable for use in critical kerosene burner applications:
No. 1-K (a special low sulfur grade kerosene suitable for use in non-
flue-connected kerosene burner appliances and for use in wick-fed
illuminating lamps) and No. 2-K (a regular grade kerosene suitable for
use in flue-connected burner appliances and for use in wick-fed
illuminating lamps). It is used to define kerosene, which is a type of
uniform fuel listed in this rule.
ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, (Approved July 15, 2011) covers biodiesel (B100) Grades S15
and S500 for use as a blend component with middle distillate fuels. It
is used to define biodiesel, which is a type of uniform fuel listed in
this rule.
ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
(Approved August 1, 2010) covers fuel blend grades of 6 to 20 volume
percent biodiesel with the remainder being a light middle or middle
distillate diesel fuel, collectively designated as B6 to B20. It is
used to define biodiesel blends, which is a type of uniform fuel listed
in this rule.
ISO 2314:2009(E), Gas turbines-Acceptance tests, Third
edition (December 15, 2009) is cited in the final rule for its guidance
on determining performance characteristics of stationary combustion
turbines. ISO 2314 specifies guidelines and procedures for preparing,
conducting and reporting thermal acceptance tests in order to determine
and/or verify electrical power output, mechanical power, thermal
efficiency (heat rate), turbine exhaust gas energy and/or other
performance characteristics of open-cycle simple cycle combustion
turbines using combustion systems supplied with gaseous and/or liquid
fuels as well as closed-cycle and semi closed-cycle simple cycle
combustion turbines. It can also be applied to simple cycle combustion
turbines in combined cycle power plants or in connection with other
heat recovery systems. ISO 2314 includes procedures for the
determination of the following performance parameters, corrected to the
reference operating parameters: electrical or mechanical power output
(gas power, if only gas is supplied), thermal efficiency or heat rate;
and combustion turbine engine exhaust energy (optionally exhaust
temperature and flow).
The EPA determined that the ANSI, ASME, ASTM, and ISO standards,
notwithstanding the age of the standards, are reasonably available
because they are available for purchase from the following addresses:
American National Standards Institute (ANSI), 25 West 43rd Street, 4th
Floor, New York, NY 10036-7422, +1.212.642.4900, [email protected],
www.ansi.org; American Society of Mechanical Engineers (ASME), Two Park
Avenue, New York, NY 10016-5990, +1.800.843.2763,
[email protected], www.asme.org; ASTM International, 100 Barr
Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959,
+1.610.832.9500, www.astm.org; International Organization for
Standardization (ISO), Chemin de Blandonnet 8, CP 401, 1214 Vernier,
Geneva, Switzerland, +41.22.749.01.11, [email protected],
www.iso.org.
[[Page 40027]]
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
The EPA believes that the human health or environmental conditions
that exist prior to these actions result in or have the potential to
result in disproportionate and adverse human health or environmental
effects on communities with environmental justice concerns. Baseline
PM2.5 and ozone and exposure analyses show that certain
populations, such as residents of redlined census tracts, those
linguistically isolated, Hispanic, Asian, and those without a high
school diploma may experience higher ozone and PM2.5
exposures as compared to the national average. American Indian
populations, residents of Tribal Lands, populations with life
expectancy data unavailable, children, and unemployed populations may
also experience disproportionately higher ozone concentrations than the
national average. Black populations may also experience
disproportionately higher PM2.5 concentrations than the
national average.
For existing sources, the EPA believes that this action is not
likely to change existing disproportionate and adverse disparities
among communities with EJ concerns regarding PM2.5 exposures
in all future years evaluated and ozone exposures for most demographic
groups in the future years evaluated. However, in 2035, under the
illustrative compliance scenarios analyzed, it is possible that Asian
populations, Hispanic populations, and those linguistically isolated,
and those living on Tribal land may experience a slight exacerbation of
ozone exposure disparities at the national level (EJ question 3).
Additionally at the national level, those living on Tribal land may
experience a slight exacerbation of ozone exposure disparities in 2040
and a slight mitigation of ozone exposure disparities in 2028 and 2030.
At the state level, ozone exposure disparities may be either mitigated
or exacerbated for certain demographic groups analyzed, also to a small
degree. As discussed above, it is important to note that this analysis
does not consider any potential impact of the meaningful engagement
provisions or all of the other protections that are in place that can
reduce the risks of localized emissions increases in a manner that is
protective of public health, safety, and the environment.
For new sources, the EPA believes that it is not practicable to
assess whether this action is likely to result in new disproportionate
and adverse effects on communities with environmental justice concerns,
because the location and number of new sources is unknown. However, the
EPA believes that the projected total cumulative power sector reduction
of 1,365 million metric tons of CO2 emissions between 2028
and 2047 will have a beneficial effect on populations at risk of
climate change effects/impacts. Research indicates that racial, ethnic,
and low socioeconomic status, vulnerable lifestages, and geographic
locations may leave individuals uniquely vulnerable to climate change
health impacts in the U.S.
The information supporting this Executive Order review is contained
in section XII.E of this preamble and in section 6, Environmental
Justice Impacts of the RIA, which is in the public docket.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit the rule
report to each House of the Congress and to the Comptroller General of
the United States. This action meets the criteria set forth in 5 U.S.C.
804(2).
XIV. Statutory Authority
The statutory authority for the actions in this rulemaking is
provided by sections 111, 302, and 307(d)(1) of the CAA as amended (42
U.S.C. 7411, 7602, 7607(d)(1)). These actions are subject to section
307(d) of the CAA (42 U.S.C. 7607(d)).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedures,
Air pollution control, Incorporation by reference, Reporting and
recordkeeping requirements.
Michael S. Regan,
Administrator.
For the reasons set forth in the preamble, the EPA amends 40 CFR
part 60 as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
Subpart A--General Provisions
0
2. Section 60.17 is amended by:
0
a. Revising paragraphs (d)(1), (g)(15) and (16), (h)(38), (43), (47),
(145), (206), and (212), the introductory text of paragraph (i);
0
b. Removing note 1 to paragraph (k) and paragraph (l);
0
c. Redesignating paragraphs (j) through (u) as shown in the following
table:
------------------------------------------------------------------------
Old paragraph New paragraph
------------------------------------------------------------------------
(j)....................................... (k).
(k)....................................... (m).
(m) through (o)........................... (n) through (p).
(p) through (r)........................... (r) through (t).
(s)....................................... (q).
(t)....................................... (j).
(u)....................................... (l).
------------------------------------------------------------------------
0
d. Revising newly-redesignated paragraphs (j) and (l), the introductory
text to newly-redesignated paragraph (m), newly-redesignated paragraph
(n), and the introductory text to newly-redesignated paragraphs (o),
(q), and (r).
The revisions read as follows:
Sec. 60.17 Incorporations by reference.
* * * * *
(d) * * *
(1) ANSI No. C12.20-2010 American National Standard for Electricity
Meters--0.2 and 0.5 Accuracy Classes (Approved August 31, 2010); IBR
approved for Sec. Sec. 60.5535(d); 60.5535a(d); 60.5860b(a).
* * * * *
(g) * * *
(15) ASME PTC 22-2014, Gas Turbines: Performance Test Codes,
(Issued December 31, 2014); IBR approved for Sec. Sec. 60.5580;
60.5580a.
(16) ASME PTC 46-1996, Performance Test Code on Overall Plant
Performance, (Issued October 15,1997); IBR approved for Sec. Sec.
60.5580; 60.5580a.
* * * * *
(h) * * *
(38) ASTM D388-99 (Reapproved 2004) [egr]1(ASTM D388-
99R04), Standard Classification of Coals by Rank, (Approved June 1,
2004); IBR approved for Sec. Sec. 60.41; 60.45(f); 60.41Da; 60.41b;
60.41c; 60.251; 60.5580; 60.5580a.
* * * * *
(43) ASTM D396-98, Standard Specification for Fuel Oils, (Approved
April 10, 1998); IBR approved for Sec. Sec. 60.41b; 60.41c; 60.111(b);
60.111a(b); 60.5580; 60.5580a.
* * * * *
(47) ASTM D975-08a, Standard Specification for Diesel Fuel Oils,
(Approved October 1, 2008); IBR approved for Sec. Sec. 60.41b; 60.41c;
60.5580; 60.5580a.
* * * * *
(145) ASTM D3699-08, Standard Specification for Kerosine, including
Appendix X1, (Approved September 1,
[[Page 40028]]
2008); IBR approved for Sec. Sec. 60.41b; 60.41c; 60.5580; 60.5580a.
* * * * *
(206) ASTM D6751-11b, Standard Specification for Biodiesel Fuel
Blend Stock (B100) for Middle Distillate Fuels, including Appendices X1
through X3, (Approved July 15, 2011), IBR approved for Sec. Sec.
60.41b, 60.41c, 60.5580, and 60.5580a.
* * * * *
(212) ASTM D7467-10, Standard Specification for Diesel Fuel Oil,
Biodiesel Blend (B6 to B20), including Appendices X1 through X3,
(Approved August 1, 2010), IBR approved for Sec. Sec. 60.41b, 60.41c,
60.5580, and 60.5580a.
* * * * *
(i) Association of Official Analytical Chemists, 1111 North 19th
Street, Suite 210, Arlington, VA 22209; phone: (301) 927-7077; website:
https://www.aoac.org/.
* * * * *
(j) CSA Group (CSA) (formerly Canadian Standards Association), 178
Rexdale Boulevard, Toronto, Ontario, Canada; phone: (800) 463-6727;
website: https://shop.csa.ca.
(1) CSA B415.1-10, Performance Testing of Solid-fuel-burning
Heating Appliances, (March 2010), IBR approved for Sec. Sec. 60.534;
60.5476.
(2) [Reserved]
* * * * *
(l) European Standards (EN), European Committee for
Standardization, Management Centre, Avenue Marnix 17, B-1000 Brussels,
Belgium; phone: + 32 2 550 08 11; website: https://www.en-standard.eu.
(1) DIN EN 303-5:2012E (EN 303-5), Heating boilers--Part 5: Heating
boilers for solid fuels, manually and automatically stoked, nominal
heat output of up to 500 kW--Terminology, requirements, testing and
marking, (October 2012), IBR approved for Sec. 60.5476.
(2) [Reserved]
* * * * *
(m) GPA Midstream Association, 6060 American Plaza, Suite 700,
Tulsa, OK 74135; phone: (918) 493-3872; website: www.gpamidstream.org.
* * * * *
(n) International Organization for Standardization (ISO), 1, ch. de
la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland; phone:
+ 41 22 749 01 11; website: www.iso.org.
(1) ISO 8178-4: 1996(E), Reciprocating Internal Combustion
Engines--Exhaust Emission Measurement--part 4: Test Cycles for
Different Engine Applications, IBR approved for Sec. 60.4241(b).
(2) ISO 2314:2009(E), Gas turbines-Acceptance tests, Third edition
(December 15, 2009), IBR approved for Sec. Sec. 60.5580; 60.5580a.
(3) ISO 8316: Measurement of Liquid Flow in Closed Conduits--Method
by Collection of the Liquid in a Volumetric Tank (1987-10-01)--First
Edition, IBR approved for Sec. 60.107a(d).
(4) ISO 10715:1997(E), Natural gas--Sampling guidelines, (First
Edition, June 1, 1997), IBR approved for Sec. 60.4415(a).
(o) National Technical Information Services (NTIS), 5285 Port Royal
Road, Springfield, Virginia 22161.
* * * * *
(q) Pacific Lumber Inspection Bureau (formerly West Coast Lumber
Inspection Bureau), 1010 South 336th Street #210, Federal Way, WA
98003; phone: (253) 835.3344; website: www.plib.org.
* * * * *
(r) Technical Association of the Pulp and Paper Industry (TAPPI),
15 Technology Parkway South, Suite 115, Peachtree Corners, GA 30092;
phone (800) 332-8686; website: www.tappi.org.
* * * * *
Subpart TTTT--Standards of Performance for Greenhouse Gas Emissions
for Electric Generating Units
0
3. Section 60.5508 is revised to read as follows:
Sec. 60.5508 What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of greenhouse gas (GHG) emissions from a
steam generating unit or an integrated gasification combined cycle
(IGCC) facility that commences construction after January 8, 2014,
commences reconstruction after June 18, 2014, or commences modification
after January 8, 2014, but on or before May 23, 2023. This subpart also
establishes emission standards and compliance schedules for the control
of GHG emissions from a stationary combustion turbine that commences
construction after January 8, 2014, but on or before May 23, 2023, or
commences reconstruction after June 18, 2014, but on or before May 23,
2023. An affected steam generating unit, IGCC, or stationary combustion
turbine shall, for the purposes of this subpart, be referred to as an
affected electric generating unit (EGU).
0
4. Section 60.5509 is revised to read as follows:
Sec. 60.5509 What are my general requirements for complying with this
subpart?
(a) Except as provided for in paragraph (b) of this section, the
GHG standards included in this subpart apply to any steam generating
unit or IGCC that commenced construction after January 8, 2014, or
commenced modification or reconstruction after June 18, 2014, that
meets the relevant applicability conditions in paragraphs (a)(1) and
(2) of this section. The GHG standards included in this subpart also
apply to any stationary combustion turbine that commenced construction
after January 8, 2014, but on or before May 23, 2023, or commenced
reconstruction after June 18, 2014, but on or before May 23, 2023, that
meets the relevant applicability conditions in paragraphs (a)(1) and
(2) of this section.
(1) Has a base load rating greater than 260 gigajoules per hour
(GJ/h) (250 million British thermal units per hour (MMBtu/h)) of fossil
fuel (either alone or in combination with any other fuel); and
(2) Serves a generator or generators capable of selling greater
than 25 megawatts (MW) of electricity to a utility power distribution
system.
(b) You are not subject to the requirements of this subpart if your
affected EGU meets any of the conditions specified in paragraphs (b)(1)
through (10) of this section.
(1) Your EGU is a steam generating unit or IGCC whose annual net-
electric sales have never exceeded one-third of its potential electric
output or 219,000 megawatt-hour (MWh), whichever is greater, and is
currently subject to a federally enforceable permit condition limiting
annual net-electric sales to no more than one-third of its potential
electric output or 219,000 MWh, whichever is greater.
(2) Your EGU is capable of deriving 50 percent or more of the heat
input from non-fossil fuel at the base load rating and is also subject
to a federally enforceable permit condition limiting the annual
capacity factor for all fossil fuels combined of 10 percent (0.10) or
less.
(3) Your EGU is a combined heat and power unit that is subject to a
federally enforceable permit condition limiting annual net-electric
sales to no more than either 219,000 MWh or the product of the design
efficiency and the potential electric output, whichever is greater.
(4) Your EGU serves a generator along with other steam generating
unit(s), IGCC, or stationary combustion turbine(s) where the effective
generation capacity (determined based on a prorated output of the base
load rating
[[Page 40029]]
of each steam generating unit, IGCC, or stationary combustion turbine)
is 25 MW or less.
(5) Your EGU is a municipal waste combustor that is subject to
subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration
unit that is subject to subpart CCCC of this part.
(7) Your EGU is a steam generating unit or IGCC that undergoes a
modification resulting in an hourly increase in CO2
emissions (mass per hour) of 10 percent or less (2 significant
figures). Modified units that are not subject to the requirements of
this subpart pursuant to this paragraph (b)(7) continue to be existing
units under section 111 with respect to CO2 emissions
standards.
(8) Your EGU is a stationary combustion turbine that is not capable
of combusting natural gas (e.g., not connected to a natural gas
pipeline).
(9) Your EGU derives greater than 50 percent of the heat input from
an industrial process that does not produce any electrical or
mechanical output or useful thermal output that is used outside the
affected EGU.
(10) Your EGU is subject to subpart TTTTa of this part.
0
5. Section 60.5520 is revised to read as follows:
Sec. 60.5520 What CO2 emissions standard must I meet?
(a) For each affected EGU subject to this subpart, you must not
discharge from the affected EGU any gases that contain CO2
in excess of the applicable CO2 emission standard specified
in table 1 or 2 to this subpart, consistent with paragraphs (b), (c),
and (d) of this section, as applicable.
(b) Except as specified in paragraphs (c) and (d) of this section,
you must comply with the applicable gross or net energy output
standard, and your operating permit must include monitoring,
recordkeeping, and reporting methodologies based on the applicable
gross or net energy output standard. For the remainder of this subpart
(for sources that do not qualify under paragraphs (c) and (d) of this
section), where the term ``gross or net energy output'' is used, the
term that applies to you is ``gross energy output.''
(c) As an alternate to meeting the requirements in paragraph (b) of
this section, an owner or operator of a stationary combustion turbine
may petition the Administrator in writing to comply with the alternate
applicable net energy output standard. If the Administrator grants the
petition, beginning on the date the Administrator grants the petition,
the affected EGU must comply with the applicable net energy output-
based standard included in this subpart. Your operating permit must
include monitoring, recordkeeping, and reporting methodologies based on
the applicable net energy output standard. For the remainder of this
subpart, where the term ``gross or net energy output'' is used, the
term that applies to you is ``net energy output.'' Owners or operators
complying with the net output-based standard must petition the
Administrator to switch back to complying with the gross energy output-
based standard.
(d) Owners or operators of a stationary combustion turbine that
maintain records of electric sales to demonstrate that the stationary
combustion turbine is subject to a heat input-based standard in table 2
to this subpart that are only permitted to burn one or more uniform
fuels, as described in paragraph (d)(1) of this section, are only
subject to the monitoring requirements in paragraph (d)(1). Owners or
operators of all other stationary combustion turbines that maintain
records of electric sales to demonstrate that the stationary combustion
turbines are subject to a heat input-based standard in table 2 are only
subject to the requirements in paragraph (d)(2) of this section.
(1) Owners or operators of stationary combustion turbines that are
only permitted to burn fuels with a consistent chemical composition
(i.e., uniform fuels) that result in a consistent emission rate of 69
kilograms per gigajoule (kg/GJ) (160 lb CO2/MMBtu) or less
are not subject to any monitoring or reporting requirements under this
subpart. These fuels include, but are not limited to hydrogen, natural
gas, methane, butane, butylene, ethane, ethylene, propane, naphtha,
propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and
biodiesel. Stationary combustion turbines qualifying under this
paragraph are only required to maintain purchase records for permitted
fuels.
(2) Owners or operators of stationary combustion turbines permitted
to burn fuels that do not have a consistent chemical composition or
that do not have an emission rate of 69 kg/GJ (160 lb CO2/
MMBtu) or less (e.g., non-uniform fuels such as residual oil and non-
jet fuel kerosene) must follow the monitoring, recordkeeping, and
reporting requirements necessary to complete the heat input-based
calculations under this subpart.
0
6. Section 60.5525 is revised to read as follows:
Sec. 60.5525 What are my general requirements for complying with this
subpart?
Combustion turbines qualifying under Sec. 60.5520(d)(1) are not
subject to any requirements in this section other than the requirement
to maintain fuel purchase records for permitted fuel(s). For all other
affected sources, compliance with the applicable CO2
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See table 1 or 2 to this subpart
for the applicable CO2 emission standards.
(a) You must be in compliance with the emission standards in this
subpart that apply to your affected EGU at all times. However, you must
determine compliance with the emission standards only at the end of the
applicable operating month, as provided in paragraph (a)(1) of this
section.
(1) For each affected EGU subject to a CO2 emissions
standard based on a 12-operating-month rolling average, you must
determine compliance monthly by calculating the average CO2
emissions rate for the affected EGU at the end of the initial and each
subsequent 12-operating-month period.
(2) Consistent with Sec. 60.5520(d)(2), if your affected
stationary combustion turbine is subject to an input-based
CO2 emissions standard, you must determine the total heat
input in GJ or MMBtu from natural gas (HTIPng) and the total
heat input from all other fuels combined (HTIPo) using one
of the methods under Sec. 60.5535(d)(2). You must then use the
following equation to determine the applicable emissions standard
during the compliance period:
Equation 1 to Paragraph (a)(2)
[GRAPHIC] [TIFF OMITTED] TR09MY24.055
[[Page 40030]]
Where:
CO2 emission standard = the emission standard during the
compliance period in units of kg/GJ (or lb/MMBtu).
HTIPng = the heat input in GJ (or MMBtu) from natural
gas.
HTIPo = the heat input in GJ (or MMBtu) from all fuels
other than natural gas.
50 = allowable emission rate in kg/GJ for heat input derived from
natural gas (use 120 if electing to demonstrate compliance using lb
CO2/MMBtu).
69 = allowable emission rate in kg/GJ for heat input derived from
all fuels other than natural gas (use 160 if electing to demonstrate
compliance using lb CO2/MMBtu).
(b) At all times you must operate and maintain each affected EGU,
including associated equipment and monitors, in a manner consistent
with safety and good air pollution control practice. The Administrator
will determine if you are using consistent operation and maintenance
procedures based on information available to the Administrator that may
include, but is not limited to, fuel use records, monitoring results,
review of operation and maintenance procedures and records, review of
reports required by this subpart, and inspection of the EGU.
(c) Within 30 days after the end of the initial compliance period
(i.e., no more than 30 days after the first 12-operating-month
compliance period), you must make an initial compliance determination
for your affected EGU(s) with respect to the applicable emissions
standard in table 1 or 2 to this subpart, in accordance with the
requirements in this subpart. The first operating month included in the
initial 12-operating-month compliance period shall be determined as
follows:
(1) For an affected EGU that commences commercial operation (as
defined in 40 CFR 72.2) on or after October 23, 2015, the first month
of the initial compliance period shall be the first operating month (as
defined in Sec. 60.5580) after the calendar month in which emissions
reporting is required to begin under:
(i) Section 60.5555(c)(3)(i), for units subject to the Acid Rain
Program; or
(ii) Section 60.5555(c)(3)(ii)(A), for units that are not in the
Acid Rain Program.
(2) For an affected EGU that has commenced commercial operation (as
defined in 40 CFR 72.2) prior to October 23, 2015:
(i) If the date on which emissions reporting is required to begin
under 40 CFR 75.64(a) has passed prior to October 23, 2015, emissions
reporting shall begin according to Sec. 60.5555(c)(3)(i) (for Acid
Rain program units), or according to Sec. 60.5555(c)(3)(ii)(B) (for
units that are not subject to the Acid Rain Program). The first month
of the initial compliance period shall be the first operating month (as
defined in Sec. 60.5580) after the calendar month in which the rule
becomes effective; or
(ii) If the date on which emissions reporting is required to begin
under 40 CFR 75.64(a) occurs on or after October 23, 2015, then the
first month of the initial compliance period shall be the first
operating month (as defined in Sec. 60.5580) after the calendar month
in which emissions reporting is required to begin under Sec.
60.5555(c)(3)(ii)(A).
(3) For a modified or reconstructed EGU that becomes subject to
this subpart, the first month of the initial compliance period shall be
the first operating month (as defined in Sec. 60.5580) after the
calendar month in which emissions reporting is required to begin under
Sec. 60.5555(c)(3)(iii).
(4) Electric sales by your affected facility generated when it
operated during a system emergency as defined in Sec. 60.5580 are
excluded for applicability with the base load standard if you can
sufficiently provide the documentation listed in Sec. 60.5560(i).
0
7. Section 60.5535 is amended by revising paragraphs (a), (b), (c)(3),
(d)(1), (e), and (f) to read as follows:
Sec. 60.5535 How do I monitor and collect data to demonstrate
compliance?
(a) Combustion turbines qualifying under Sec. 60.5520(d)(1) are
not subject to any requirements in this section other than the
requirement to maintain fuel purchase records for permitted fuel(s). If
your combustion turbine uses non-uniform fuels as specified under Sec.
60.5520(d)(2), you must monitor heat input in accordance with paragraph
(c)(1) of this section, and you must monitor CO2 emissions
in accordance with either paragraph (b), (c)(2), or (c)(5) of this
section. For all other affected sources, you must prepare a monitoring
plan to quantify the hourly CO2 mass emission rate (tons/h),
in accordance with the applicable provisions in 40 CFR 75.53(g) and
(h). The electronic portion of the monitoring plan must be submitted
using the ECMPS Client Tool and must be in place prior to reporting
emissions data and/or the results of monitoring system certification
tests under this subpart. The monitoring plan must be updated as
necessary. Monitoring plan submittals must be made by the Designated
Representative (DR), the Alternate DR, or a delegated agent of the DR
(see Sec. 60.5555(d) and (e)).
(b) You must determine the hourly CO2 mass emissions in
kg from your affected EGU(s) according to paragraphs (b)(1) through (5)
of this section, or, if applicable, as provided in paragraph (c) of
this section.
(1) For an affected EGU that combusts coal you must, and for all
other affected EGUs you may, install, certify, operate, maintain, and
calibrate a CO2 continuous emission monitoring system (CEMS)
to directly measure and record hourly average CO2
concentrations in the affected EGU exhaust gases emitted to the
atmosphere, and a flow monitoring system to measure hourly average
stack gas flow rates, according to 40 CFR 75.10(a)(3)(i). As an
alternative to direct measurement of CO2 concentration,
provided that your EGU does not use carbon separation (e.g., carbon
capture and storage), you may use data from a certified oxygen
(O2) monitor to calculate hourly average CO2
concentrations, in accordance with 40 CFR 75.10(a)(3)(iii). If you
measure CO2 concentration on a dry basis, you must also
install, certify, operate, maintain, and calibrate a continuous
moisture monitoring system, according to 40 CFR 75.11(b).
Alternatively, you may either use an appropriate fuel-specific default
moisture value from 40 CFR 75.11(b) or submit a petition to the
Administrator under 40 CFR 75.66 for a site-specific default moisture
value.
(2) For each continuous monitoring system that you use to determine
the CO2 mass emissions, you must meet the applicable
certification and quality assurance procedures in 40 CFR 75.20 and
appendices A and B to 40 CFR part 75.
(3) You must use only unadjusted exhaust gas volumetric flow rates
to determine the hourly CO2 mass emissions rate from the
affected EGU; you must not apply the bias adjustment factors described
in Section 7.6.5 of appendix A to 40 CFR part 75 to the exhaust gas
flow rate data.
(4) You must select an appropriate reference method to setup
(characterize) the flow monitor and to perform the on-going RATAs, in
accordance with 40 CFR part 75. If you use a Type-S pitot tube or a
pitot tube assembly for the flow RATAs, you must calibrate the pitot
tube or pitot tube assembly; you may not use the 0.84 default Type-S
pitot tube coefficient specified in Method 2.
(5) Calculate the hourly CO2 mass emissions (kg) as
described in paragraphs (b)(5)(i) through (iv) of this section. Perform
this calculation only for ``valid operating hours'', as defined in
Sec. 60.5540(a)(1).
(i) Begin with the hourly CO2 mass emission rate (tons/
h), obtained either from equation F-11 in appendix F to 40
[[Page 40031]]
CFR part 75 (if CO2 concentration is measured on a wet
basis), or by following the procedure in section 4.2 of appendix F to
part 75 (if CO2 concentration is measured on a dry basis).
(ii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in 40 CFR
72.2), to convert it to tons of CO2.
(iii) Finally, multiply the result from paragraph (b)(5)(ii) of
this section by 907.2 to convert it from tons of CO2 to kg.
Round off to the nearest kg.
(iv) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under 40 CFR 75.57(e) and must be reported
electronically under 40 CFR 75.64(a)(6). You must use these data to
calculate the hourly CO2 mass emissions.
(c) * * *
(3) For each ``valid operating hour'' (as defined in Sec.
60.5540(a)(1), multiply the hourly tons/h CO2 mass emission
rate from paragraph (c)(2) of this section by the EGU or stack
operating time in hours (as defined in 40 CFR 72.2), to convert it to
tons of CO2. Then, multiply the result by 907.2 to convert
from tons of CO2 to kg. Round off to the nearest two
significant figures.
* * * * *
(d) * * *
(1) If you operate a source subject to an emissions standard
established on an output basis (e.g., lb of CO2 per gross or
net MWh of energy output), you must install, calibrate, maintain, and
operate a sufficient number of watt meters to continuously measure and
record the hourly gross electric output or net electric output, as
applicable, from the affected EGU(s). These measurements must be
performed using 0.2 class electricity metering instrumentation and
calibration procedures as specified under ANSI No. C12.20-2010
(incorporated by reference, see Sec. 60.17). For a combined heat and
power (CHP) EGU, as defined in Sec. 60.5580, you must also install,
calibrate, maintain, and operate meters to continuously (i.e., hour-by-
hour) determine and record the total useful thermal output. For process
steam applications, you will need to install, calibrate, maintain, and
operate meters to continuously determine and record the hourly steam
flow rate, temperature, and pressure. Your plan shall ensure that you
install, calibrate, maintain, and operate meters to record each
component of the determination, hour-by-hour.
* * * * *
(e) Consistent with Sec. 60.5520, if two or more affected EGUs
serve a common electric generator, you must apportion the combined
hourly gross or net energy output to the individual affected EGUs
according to the fraction of the total steam load and/or direct
mechanical energy contributed by each EGU to the electric generator.
Alternatively, if the EGUs are identical, you may apportion the
combined hourly gross or net electrical load to the individual EGUs
according to the fraction of the total heat input contributed by each
EGU. You may also elect to develop, demonstrate, and provide
information satisfactory to the Administrator on alternate methods to
apportion the gross energy output. The Administrator may approve such
alternate methods for apportioning the gross energy output whenever the
demonstration ensures accurate estimation of emissions regulated under
this part.
(f) In accordance with Sec. Sec. 60.13(g) and 60.5520, if two or
more affected EGUs that implement the continuous emission monitoring
provisions in paragraph (b) of this section share a common exhaust gas
stack you must monitor hourly CO2 mass emissions in
accordance with one of the following procedures:
(1) If the EGUs are subject to the same emissions standard in table
1 or 2 to this subpart, you may monitor the hourly CO2 mass
emissions at the common stack in lieu of monitoring each EGU
separately. If you choose this option, the hourly gross or net energy
output (electric, thermal, and/or mechanical, as applicable) must be
the sum of the hourly loads for the individual affected EGUs and you
must express the operating time as ``stack operating hours'' (as
defined in 40 CFR 72.2). If you attain compliance with the applicable
emissions standard in Sec. 60.5520 at the common stack, each affected
EGU sharing the stack is in compliance.
(2) As an alternative, or if the EGUs are subject to different
emission standards in table 1 or 2 to this subpart, you must either:
(i) Monitor each EGU separately by measuring the hourly
CO2 mass emissions prior to mixing in the common stack or
(ii) Apportion the CO2 mass emissions based on the
unit's load contribution to the total load associated with the common
stack and the appropriate F-factors. You may also elect to develop,
demonstrate, and provide information satisfactory to the Administrator
on alternate methods to apportion the CO2 emissions. The
Administrator may approve such alternate methods for apportioning the
CO2 emissions whenever the demonstration ensures accurate
estimation of emissions regulated under this part.
* * * * *
0
8. Section 60.5540 is revised to read as follows:
Sec. 60.5540 How do I demonstrate compliance with my CO2 emissions
standard and determine excess emissions?
(a) In accordance with Sec. 60.5520, if you are subject to an
output-based emission standard or you burn non-uniform fuels as
specified in Sec. 60.5520(d)(2), you must demonstrate compliance with
the applicable CO2 emission standard in table 1 or 2 to this
subpart as required in this section. For the initial and each
subsequent 12-operating-month rolling average compliance period, you
must follow the procedures in paragraphs (a)(1) through (8) of this
section to calculate the CO2 mass emissions rate for your
affected EGU(s) in units of the applicable emissions standard (e.g.,
either kg/MWh or kg/GJ). You must use the hourly CO2 mass
emissions calculated under Sec. 60.5535(b) or (c), as applicable, and
either the generating load data from Sec. 60.5535(d)(1) for output-
based calculations or the heat input data from Sec. 60.5535(d)(2) for
heat-input-based calculations. Combustion turbines firing non-uniform
fuels that contain CO2 prior to combustion (e.g., blast
furnace gas or landfill gas) may sample the fuel stream to determine
the quantity of CO2 present in the fuel prior to combustion
and exclude this portion of the CO2 mass emissions from
compliance determinations.
(1) Each compliance period shall include only ``valid operating
hours'' in the compliance period, i.e., operating hours for which:
(i) ``Valid data'' (as defined in Sec. 60.5580) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (kg) and, if a heat input-based standard applies, all the
parameters used to determine total heat input for the hour are also
obtained; and
(ii) The corresponding hourly gross or net energy output value is
also valid data (Note: For hours with no useful output, zero is
considered to be a valid value).
(2) You must exclude operating hours in which:
(i) The substitute data provisions of 40 CFR 75 are applied for any
of the parameters used to determine the hourly CO2 mass
emissions or, if a heat input-based standard applies, for any
parameters used to determine the hourly heat input;
(ii) An exceedance of the full-scale range of a continuous emission
monitoring system occurs for any of the
[[Page 40032]]
parameters used to determine the hourly CO2 mass emissions
or, if applicable, to determine the hourly heat input; or
(iii) The total gross or net energy output (Pgross/net)
or, if applicable, the total heat input is unavailable.
(3) For each compliance period, at least 95 percent of the
operating hours in the compliance period must be valid operating hours,
as defined in paragraph (a)(1) of this section.
(4) You must calculate the total CO2 mass emissions by
summing the valid hourly CO2 mass emissions values from
Sec. 60.5535 for all of the valid operating hours in the compliance
period.
(5) For each valid operating hour of the compliance period that was
used in paragraph (a)(4) of this section to calculate the total
CO2 mass emissions, you must determine Pgross/net
(the corresponding hourly gross or net energy output in MWh) according
to the procedures in paragraphs (a)(5)(i) and (ii) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(1)(i) of this section, if there is no gross
or net electrical output, but there is mechanical or useful thermal
output, you must still determine the gross or net energy output for
that hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross
electrical, mechanical, or useful thermal output, you must use that
hour in the compliance determination. For hours or partial hours where
the gross electric output is equal to or less than the auxiliary loads,
net electric output shall be counted as zero for this calculation.
(i) Calculate Pgross/net for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of MWh. To convert each hourly gross or net energy output
(consistent with Sec. 60.5520) value reported under 40 CFR part 75 to
MWh, multiply by the corresponding EGU or stack operating time.
Equation 1 to paragraph (a)(5)(i)
[GRAPHIC] [TIFF OMITTED] TR09MY24.064
Where:
Pgross/net = In accordance with Sec. 60.5520, gross or
net energy output of your affected EGU for each valid operating hour
(as defined in Sec. 60.5540(a)(1)) in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater
pumps at steam generating units in MWh. Not applicable to stationary
combustion turbines, IGCC EGUs, or EGUs complying with a net energy
output based standard.
(Pe)A = Electric energy used for any auxiliary loads in
MWh. Not applicable for determining Pgross.
(Pt)PS = Useful thermal output of steam (measured
relative to standard ambient temperature and pressure (SATP)
conditions, as applicable) that is used for applications that do not
generate additional electricity, produce mechanical energy output,
or enhance the performance of the affected EGU. This is calculated
using the equation specified in paragraph (a)(5)(ii) of this section
in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions, as applicable) from heat recovery that
is used for applications other than steam generation or performance
enhancement of the affected EGU in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions, as applicable) from any integrated equipment is used for
applications that do not generate additional steam, electricity,
produce mechanical energy output, or enhance the performance of the
affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least 20.0 percent of
the total gross or net energy output consists of electric or direct
mechanical output and 20.0 percent of the total gross or net energy
output consists of useful thermal output on a 12-operating-month
rolling average basis, or 1.0 for all other affected EGUs.
(ii) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the
following equation:
Equation 2 to Paragraph (a)(5)(ii)
[GRAPHIC] [TIFF OMITTED] TR09MY24.056
Where:
Qm = Measured useful thermal output flow in kg (lb) for
the operating hour.
H = Enthalpy of the useful thermal output at measured temperature
and pressure (relative to SATP conditions or the energy in the
condensate return line, as applicable) in Joules per kilogram (J/kg)
(or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.
(6) Sources complying with energy output-based standards must
calculate the basis (i.e., denominator) of their actual 12-operating
month emission rate in accordance with paragraph (a)(6)(i) of this
section. Sources complying with heat input based standards must
calculate the basis of their actual 12-operating month emission rate in
accordance with paragraph (a)(6)(ii) of this section.
(i) In accordance with Sec. 60.5520 if you are subject to an
output-based standard, you must calculate the total gross or net energy
output for the affected EGU's compliance period by summing the hourly
gross or net energy output values for the affected EGU that you
determined under paragraph (a)(5) of this section for all of the valid
operating hours in the applicable compliance period.
(ii) If you are subject to a heat input-based standard, you must
calculate the total heat input for each fuel fired during the
compliance period. The calculation of total heat input for each
individual fuel must include all valid operating hours and must also be
consistent with any fuel-specific procedures specified within your
selected monitoring option under Sec. 60.5535(d)(2).
(7) If you are subject to an output-based standard, you must
calculate the CO2 mass emissions rate for the affected
EGU(s) (kg/MWh) by dividing the total CO2 mass emissions
value calculated according to the procedures in paragraph (a)(4) of
this section by the total gross or net energy output value calculated
according to the procedures in paragraph (a)(6)(i) of this section.
Round off the result to two significant figures if the calculated value
is less than 1,000; round the result to three significant figures if
the calculated value is greater than 1,000. If you are subject to a
heat input-based standard, you must calculate the CO2 mass
emissions rate for the affected EGU(s) (kg/GJ or lb/MMBtu) by dividing
the total CO2 mass emissions value calculated according to
the procedures in paragraph (a)(4) of this section by the total heat
input calculated according to the procedures in paragraph (a)(6)(ii) of
this section.
[[Page 40033]]
Round off the result to two significant figures.
(b) In accordance with Sec. 60.5520, to demonstrate compliance
with the applicable CO2 emission standard, for the initial
and each subsequent 12-operating-month compliance period, the
CO2 mass emissions rate for your affected EGU must be
determined according to the procedures specified in paragraph (a)(1)
through (8) of this section and must be less than or equal to the
applicable CO2 emissions standard in table 1 or 2 to this
subpart, or the emissions standard calculated in accordance with Sec.
60.5525(a)(2).
0
9. Section 60.5555 is amended by revising paragraphs (a)(2)(iv) and
(v), (f), and (g) to read as follows.
Sec. 60.5555 What reports must I submit and when?
(a) * * *
(2) * * *
(iv) The percentage of valid operating hours in each 12-operating-
month compliance period described in paragraph (a)(1) of this section
(i.e., the total number of valid operating hours (as defined in Sec.
60.5540(a)(1)) in that period divided by the total number of operating
hours in that period, multiplied by 100 percent);
(v) Consistent with Sec. 60.5520, the CO2 emissions
standard (as identified in table 1 or 2 to this subpart) with which
your affected EGU must comply; and
* * * * *
(f) If your affected EGU captures CO2 to meet the
applicable emissions standard, you must report in accordance with the
requirements of 40 CFR part 98, subpart PP, and either:
(1) Report in accordance with the requirements of 40 CFR part 98,
subpart RR, or subpart VV, if injection occurs on-site;
(2) Transfer the captured CO2 to an EGU or facility that
reports in accordance with the requirements of 40 CFR part 98, subpart
RR, or subpart VV, if injection occurs off-site; or
(3) Transfer the captured CO2 to a facility that has
received an innovative technology waiver from EPA pursuant to paragraph
(g) of this section.
(g) Any person may request the Administrator to issue a waiver of
the requirement that captured CO2 from an affected EGU be
transferred to a facility reporting under 40 CFR part 98, subpart RR,
or subpart VV. To receive a waiver, the applicant must demonstrate to
the Administrator that its technology will store captured
CO2 as effectively as geologic sequestration, and that the
proposed technology will not cause or contribute to an unreasonable
risk to public health, welfare, or safety. In making this
determination, the Administrator shall consider (among other factors)
operating history of the technology, whether the technology will
increase emissions or other releases of any pollutant other than
CO2, and permanence of the CO2 storage. The
Administrator may test the system or require the applicant to perform
any tests considered by the Administrator to be necessary to show the
technology's effectiveness, safety, and ability to store captured
CO2 without release. The Administrator may grant conditional
approval of a technology, with the approval conditioned on monitoring
and reporting of operations. The Administrator may also withdraw
approval of the waiver on evidence of releases of CO2 or
other pollutants. The Administrator will provide notice to the public
of any application under this provision and provide public notice of
any proposed action on a petition before the Administrator takes final
action.
0
10. Section 60.5560 is amended by adding paragraphs (h) and (i) to read
as follows:
Sec. 60.5560 What records must I maintain?
* * * * *
(h) For stationary combustion turbines, you must keep records of
electric sales to determine the applicable subcategory.
(i) You must keep the records listed in paragraphs (i)(1) through
(3) of this section to demonstrate that your affected facility operated
during a system emergency.
(1) Documentation that the system emergency to which the affected
EGU was responding was in effect from the entity issuing the alert, and
documentation of the exact duration of the event;
(2) Documentation from the entity issuing the alert that the system
emergency included the affected source/region where the affected
facility was located, and
(3) Documentation that the affected facility was instructed to
increase output beyond the planned day-ahead or other near-term
expected output and/or was asked to remain in operation outside its
scheduled dispatch during emergency conditions from a Reliability
Coordinator, Balancing Authority, or Independent System Operator/
Regional Transmission Organization.
0
11. Section 60.5580 is amended by:
0
a. Revising the definitions for ``Annual capacity factor'', and ``Base
load rating'';
0
b. Revising and republishing the definition for ``Coal''; and
0
c. Revising the definitions for ``Combined cycle unit'', ``Combined
head and power unit or CHP unit'', ``Design efficiency'', ``Distillate
oil'', ``ISO conditions'', ``Net electric sales'', and ``System
emergency''.
The revisions and republications read as follows:
Sec. 60.5580 What definitions apply to this subpart?
* * * * *
Annual capacity factor means the ratio between the actual heat
input to an EGU during a calendar year and the potential heat input to
the EGU had it been operated for 8,760 hours during a calendar year at
the base load rating. Actual and potential heat input derived from non-
combustion sources (e.g., solar thermal) are not included when
calculating the annual capacity factor.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis plus the maximum amount of
heat input derived from non-combustion source (e.g., solar thermal), as
determined by the physical design and characteristics of the EGU at
International Organization for Standardization (ISO) conditions. For a
stationary combustion turbine, base load rating includes the heat input
from duct burners.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by ASTM International in ASTM D388-99R04
(incorporated by reference, see Sec. 60.17), coal refuse, and
petroleum coke. Synthetic fuels derived from coal for the purpose of
creating useful heat, including, but not limited to, solvent-refined
coal, gasified coal (not meeting the definition of natural gas), coal-
oil mixtures, and coal-water mixtures are included in this definition
for the purposes of this subpart.
Combined cycle unit means a stationary combustion turbine from
which the heat from the turbine exhaust gases is recovered by a heat
recovery steam generating unit (HRSG) to generate additional
electricity.
Combined heat and power unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that simultaneously
produces both electric (or mechanical) and useful thermal output from
the same primary energy source.
Design efficiency means the rated overall net efficiency (e.g.,
electric plus useful thermal output) on a lower heating value basis at
the base load rating, at ISO conditions, and at the maximum useful
thermal output (e.g., CHP unit with condensing steam turbines would
determine the design efficiency at the maximum level of extraction and/
or bypass). Design efficiency shall be determined using one
[[Page 40034]]
of the following methods: ASME PTC 22-2014, ASME PTC 46-1996, ISO
2314:2009(E) (all incorporated by reference, see Sec. 60.17), or an
alternative approved by the Administrator.
Distillate oil means fuel oils that comply with the specifications
for fuel oil numbers 1 and 2, as defined in ASTM D396-98 (incorporated
by reference, see Sec. 60.17); diesel fuel oil numbers 1 and 2, as
defined in ASTM D975-08a (incorporated by reference, see Sec. 60.17);
kerosene, as defined in ASTM D3699-08 (incorporated by reference, see
Sec. 60.17); biodiesel as defined in ASTM D6751-11b (incorporated by
reference, see Sec. 60.17); or biodiesel blends as defined in ASTM
D7467-10 (incorporated by reference, see Sec. 60.17).
* * * * *
ISO conditions means 288 Kelvin (15 [deg]C, 59 [deg]F), 60 percent
relative humidity and 101.3 kilopascals (14.69 psi, 1 atm) pressure.
* * * * *
Net-electric sales means:
(1) The gross electric sales to the utility power distribution
system minus purchased power; or
(2) For combined heat and power facilities, where at least 20.0
percent of the total gross energy output consists of electric or direct
mechanical output and at least 20.0 percent of the total gross energy
output consists of useful thermal output on a 12-operating month basis,
the gross electric sales to the utility power distribution system minus
purchased power of the thermal host facility or facilities.
(3) Electricity supplied to other facilities that produce
electricity to offset auxiliary loads are included when calculating
net-electric sales.
(4) Electric sales during a system emergency are not included when
calculating net-electric sales.
* * * * *
System emergency means periods when the Reliability Coordinator has
declared an Energy Emergency Alert level 2 or 3 as defined by NERC
Reliability Standard EOP-011-2 or its successor.
* * * * *
0
12. Table 1 to subpart TTTT is revised to read as follows:
Table 1 to Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Steam Generating Units and Integrated Gasification Combined Cycle
Facilities That Commenced Construction After January 8, 2014, and
Reconstruction or Modification After June 18, 2014
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
------------------------------------------------------------------------
Affected EGU CO2 Emission standard
------------------------------------------------------------------------
Newly constructed steam generating unit 640 kg CO2/MWh of gross energy
or integrated gasification combined output (1,400 lb CO2/MWh-
cycle (IGCC). gross).
Reconstructed steam generating unit or 910 kg CO2/MWh of gross energy
IGCC that has base load rating of output (2,000 lb CO2/MWh-
2,100 GJ/h (2,000 MMBtu/h) or less. gross).
Reconstructed steam generating unit or 820 kg CO2/MWh of gross energy
IGCC that has a base load rating output (1,800 lb CO2/MWh-
greater than 2,100 GJ/h (2,000 MMBtu/ gross).
h).
Modified steam generating unit or IGCC. A unit-specific emission limit
determined by the unit's best
historical annual CO2 emission
rate (from 2002 to the date of
the modification); the
emission limit will be no
lower than:
(1) 820 kg CO2/MWh of gross
energy output (1,800 lb CO2/
MWh-gross) for units with a
base load rating greater than
2,100 GJ/h (2,000 MMBtu/h); or
(2) 910 kg CO2/MWh of gross
energy output (2,000 lb CO2/
MWh-gross) for units with a
base load rating of 2,100 GJ/h
(2,000 MMBtu/h) or less.
------------------------------------------------------------------------
0
13. Table 2 to subpart TTTT is revised to read as follows:
Table 2 to Subpart TTTT of Part 60--CO2 Emission Standards for Affected
Stationary Combustion Turbines That Commenced Construction After
January 8, 2014, and Reconstruction After June 18, 2014 (Net Energy
Output-Based Standards Applicable as Approved by the Administrator)
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
------------------------------------------------------------------------
Affected EGU CO2 Emission standard
------------------------------------------------------------------------
Newly constructed or reconstructed 450 kg CO2/MWh (1,000 lb CO2/
stationary combustion turbine that MWh) of gross energy output;
supplies more than its design or
efficiency or 50 percent, whichever is 470 kg CO2/MWh (1,030 lb CO2/
less, times its potential electric MWh) of net energy output.
output as net-electric sales on both a
12-operating month and a 3-year
rolling average basis and combusts
more than 90% natural gas on a heat
input basis on a 12-operating-month
rolling average basis.
[[Page 40035]]
Newly constructed or reconstructed 50 kg CO2/GJ (120 lb CO2/MMBtu)
stationary combustion turbine that of heat input.
supplies its design efficiency or 50
percent, whichever is less, times its
potential electric output or less as
net-electric sales on either a 12-
operating month or a 3-year rolling
average basis and combusts more than
90% natural gas on a heat input basis
on a 12-operating-month rolling
average basis].
Newly constructed and reconstructed Between 50 to 69 kg CO2/GJ (120
stationary combustion turbine that to 160 lb CO2/MMBtu) of heat
combusts 90% or less natural gas on a input as determined by the
heat input basis on a 12-operating- procedures in Sec. 60.5525.
month rolling average basis.
------------------------------------------------------------------------
0
14. Table 3 to subpart TTTT is revised to read as follows:
Table 3 to Subpart TTTT of Part 60--Applicability of Subpart A of Part
60 (General Provisions) to Subpart TTTT
----------------------------------------------------------------------------------------------------------------
General provisions citation Subject of citation Applies to subpart TTTT Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1.......................... Applicability.......... Yes....................
Sec. 60.2.......................... Definitions............ Yes.................... Additional terms
defined in Sec.
60.5580.
Sec. 60.3.......................... Units and Abbreviations Yes....................
Sec. 60.4.......................... Address................ Yes.................... Does not apply to
information reported
electronically through
ECMPS. Duplicate
submittals are not
required.
Sec. 60.5.......................... Determination of Yes....................
construction or
modification.
Sec. 60.6.......................... Review of plans........ Yes....................
Sec. 60.7.......................... Notification and Yes.................... Only the requirements
Recordkeeping. to submit the
notifications in Sec.
60.7(a)(1) and (3)
and to keep records of
malfunctions in Sec.
60.7(b), if
applicable.
Sec. 60.8(a)....................... Performance tests...... No.....................
Sec. 60.8(b)....................... Performance test method Yes.................... Administrator can
alternatives. approve alternate
methods
Sec. 60.8(c)-(f)................... Conducting performance No.....................
tests.
Sec. 60.9.......................... Availability of Yes....................
Information.
Sec. 60.10......................... State authority........ Yes....................
Sec. 60.11......................... Compliance with No.
standards and
maintenance
requirements.
Sec. 60.12......................... Circumvention.......... Yes....................
Sec. 60.13 (a)-(h), (j)............ Monitoring requirements No..................... All monitoring is done
according to part 75.
Sec. 60.13 (i)..................... Monitoring requirements Yes.................... Administrator can
approve alternative
monitoring procedures
or requirements
Sec. 60.14......................... Modification........... Yes (steam generating
units and IGCC
facilities).
No (stationary
combustion turbines).
Sec. 60.15......................... Reconstruction......... Yes....................
Sec. 60.16......................... Priority list.......... No.....................
Sec. 60.17......................... Incorporations by Yes....................
reference.
Sec. 60.18......................... General control device No.....................
requirements.
Sec. 60.19......................... General notification Yes.................... Does not apply to
and reporting notifications under
requirements. Sec. 75.61 or to
information reported
through ECMPS.
----------------------------------------------------------------------------------------------------------------
0
15. Add subpart TTTTa to read as follows:
Subpart TTTTa--Standards of Performance for Greenhouse Gas Emissions
for Modified Coal-Fired Steam Electric Generating Units and New
Construction and Reconstruction Stationary Combustion Turbine Electric
Generating Units
Applicability
Sec.
60.5508a What is the purpose of this subpart?
60.5509a Am I subject to this subpart?
Emissions Standards
60.5515a Which pollutants are regulated by this subpart?
60.5520a What CO2 emissions standard must I meet?
60.5525a What are my general requirements for complying with this
subpart?
Monitoring and Compliance Determination Procedures
60.5535a How do I monitor and collect data to demonstrate
compliance?
60.5540a How do I demonstrate compliance with my CO2
emissions standard and determine excess emissions?
Notification, Reports, and Records
60.5550a What notifications must I submit and when?
60.5555a What reports must I submit and when?
60.5560a What records must I maintain?
60.5565a In what form and how long must I keep my records?
Other Requirements and Information
60.5570a What parts of the general provisions apply to my affected
EGU?
60.5575a Who implements and enforces this subpart?
60.5580a What definitions apply to this subpart?
[[Page 40036]]
Table 1 to Subpart TTTTa of Part 60--CO2 Emission
Standards for Affected Stationary Combustion Turbines That Commenced
Construction or Reconstruction After May 23, 2023 (Gross or Net
Energy Output-Based Standards Applicable as Approved by the
Administrator)
Table 2 to Subpart TTTTa of Part 60--CO2 Emission
Standards for Affected Steam Generating Units or IGCC That Commenced
Modification After May 23, 2023
Table 3 to Subpart TTTTa of Part 60--Applicability of Subpart A of
Part 60 (General Provisions) to Subpart TTTTa
Subpart TTTTa--Standards of Performance for Greenhouse Gas
Emissions for Modified Coal-Fired Steam Electric Generating Units
and New Construction and Reconstruction Stationary Combustion
Turbine Electric Generating Units
Applicability
Sec. 60.5508a What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of greenhouse gas (GHG) emissions from a
coal-fired steam generating unit or integrated gasification combined
cycle facility (IGCC) that commences modification after May 23, 2023.
This subpart also establishes emission standards and compliance
schedules for the control of GHG emissions from a stationary combustion
turbine that commences construction or reconstruction after May 23,
2023. An affected coal-fired steam generating unit, IGCC, or stationary
combustion turbine shall, for the purposes of this subpart, be referred
to as an affected electric generating unit (EGU).
Sec. 60.5509a Am I subject to this subpart?
(a) Except as provided for in paragraph (b) of this section, the
GHG standards included in this subpart apply to any steam generating
unit or IGCC that combusts coal and that commences modification after
May 23, 2023, that meets the relevant applicability conditions in
paragraphs (a)(1) and (2) of this section. The GHG standards included
in this subpart also apply to any stationary combustion turbine that
commences construction or reconstruction after May 23, 2023, that meets
the relevant applicability conditions in paragraphs (a)(1) and (2) of
this section.
(1) Has a base load rating greater than 260 gigajoules per hour
(GJ/h) (250 million British thermal units per hour (MMBtu/h)) of fossil
fuel (either alone or in combination with any other fuel); and
(2) Serves a generator or generators capable of selling greater
than 25 megawatts (MW) of electricity to a utility power distribution
system.
(b) You are not subject to the requirements of this subpart if your
affected EGU meets any of the conditions specified in paragraphs (b)(1)
through (8) of this section.
(1) Your EGU is a steam generating unit or IGCC whose annual net-
electric sales have never exceeded one-third of its potential electric
output or 219,000 megawatt-hour (MWh), whichever is greater, and is
currently subject to a federally enforceable permit condition limiting
annual net-electric sales to no more than one-third of its potential
electric output or 219,000 MWh, whichever is greater.
(2) Your EGU is capable of deriving 50 percent or more of the heat
input from non-fossil fuel at the base load rating and is also subject
to a federally enforceable permit condition limiting the annual
capacity factor for all fossil fuels combined of 10 percent (0.10) or
less.
(3) Your EGU is a combined heat and power unit that is subject to a
federally enforceable permit condition limiting annual net-electric
sales to no more than either 219,000 MWh or the product of the design
efficiency and the potential electric output, whichever is greater.
(4) Your EGU serves a generator along with other steam generating
unit(s), IGCC, or stationary combustion turbine(s) where the effective
generation capacity (determined based on a prorated output of the base
load rating of each steam generating unit, IGCC, or stationary
combustion turbine) is 25 MW or less.
(5) Your EGU is a municipal waste combustor that is subject to
subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration
unit that is subject to subpart CCCC of this part.
(7) Your EGU is a steam generating unit or IGCC that undergoes a
modification resulting in an hourly increase in CO2
emissions (mass per hour) of 10 percent or less (2 significant
figures). Modified units that are not subject to the requirements of
this subpart pursuant to this subsection continue to be existing units
under section 111 with respect to CO2 emissions standards.
(8) Your EGU derives greater than 50 percent of the heat input from
an industrial process that does not produce any electrical or
mechanical output or useful thermal output that is used outside the
affected EGU.
Emission Standards
Sec. 60.5515a Which pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases.
The greenhouse gas standard in this subpart is in the form of a
limitation on emission of carbon dioxide.
(b) PSD and Title V thresholds for greenhouse gases.
(1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to
GHG emissions from affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP
approved by the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to
GHG emissions from affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from affected facilities, the ``pollutant that is subject to
any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas
emissions from affected facilities, the ``pollutant that is subject to
any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 71.2.
Sec. 60.5520a What CO2 emissions standard must I meet?
(a) For each affected EGU subject to this subpart, you must not
discharge from the affected EGU any gases that contain CO2
in excess of the applicable CO2 emission standard specified
in table 1 to this subpart, consistent with paragraphs (b), (c), and
(d) of this section, as applicable.
(b) Except as specified in paragraphs (c) and (d) of this section,
you must comply with the applicable gross or net energy output
standard, and your operating permit must include monitoring,
recordkeeping, and reporting methodologies based on the applicable
gross or net energy output standard. For the remainder of this subpart
(for sources that do not qualify
[[Page 40037]]
under paragraphs (c) and (d) of this section), where the term ``gross
or net energy output'' is used, the term that applies to you is ``gross
energy output.''
(c) As an alternative to meeting the requirements in paragraph (b)
of this section, an owner or operator of a stationary combustion
turbine may petition the Administrator in writing to comply with the
alternate applicable net energy output standard. If the Administrator
grants the petition, beginning on the date the Administrator grants the
petition, the affected EGU must comply with the applicable net energy
output-based standard included in this subpart. Your operating permit
must include monitoring, recordkeeping, and reporting methodologies
based on the applicable net energy output standard. For the remainder
of this subpart, where the term ``gross or net energy output'' is used,
the term that applies to you is ``net energy output.'' Owners or
operators complying with the net output-based standard must petition
the Administrator to switch back to complying with the gross energy
output-based standard.
(d) Owners or operators of a stationary combustion turbine that
maintain records of electric sales to demonstrate that the stationary
combustion turbine is subject to a heat input-based standard in table 1
to this subpart that are only permitted to burn one or more uniform
fuels, as described in paragraph (d)(1) of this section, are only
subject to the monitoring requirements in paragraph (d)(1). Owners or
operators of all other stationary combustion turbines that maintain
records of electric sales to demonstrate that the stationary combustion
turbines are subject to a heat input-based standard in table 1 are only
subject to the requirements in paragraph (d)(2) of this section.
(1) Owners or operators of stationary combustion turbines that are
only permitted to burn fuels with a consistent chemical composition
(i.e., uniform fuels) that result in a consistent emission rate of 69
kilograms per gigajoule (kg/GJ) (160 lb CO2/MMBtu) or less
are not subject to any monitoring or reporting requirements under this
subpart. These fuels include, but are not limited to hydrogen, natural
gas, methane, butane, butylene, ethane, ethylene, propane, naphtha,
propylene, jet fuel, kerosene, No. 1 fuel oil, No. 2 fuel oil, and
biodiesel. Stationary combustion turbines qualifying under this
paragraph are only required to maintain purchase records for permitted
fuels.
(2) Owners or operators of stationary combustion turbines permitted
to burn fuels that do not have a consistent chemical composition or
that do not have an emission rate of 69 kg/GJ (160 lb CO2/
MMBtu) or less (e.g., non-uniform fuels such as residual oil and non-
jet fuel kerosene) must follow the monitoring, recordkeeping, and
reporting requirements necessary to complete the heat input-based
calculations under this subpart.
Sec. 60.5525a What are my general requirements for complying with
this subpart?
Combustion turbines qualifying under Sec. 60.5520a(d)(1) are not
subject to any requirements in this section other than the requirement
to maintain fuel purchase records for permitted fuel(s). For all other
affected sources, compliance with the applicable CO2
emission standard of this subpart shall be determined on a 12-
operating-month rolling average basis. See table 1 to this subpart for
the applicable CO2 emission standards.
(a) You must be in compliance with the emission standards in this
subpart that apply to your affected EGU at all times. However, you must
determine compliance with the emission standards only at the end of the
applicable operating month, as provided in paragraph (a)(1) of this
section.
(1) For each affected EGU subject to a CO2 emissions
standard based on a 12-operating-month rolling average, you must
determine compliance monthly by calculating the average CO2
emissions rate for the affected EGU at the end of the initial and each
subsequent 12-operating-month period.
(2) Consistent with Sec. 60.5520a(d)(2), if your affected
stationary combustion turbine is subject to an input-based
CO2 emissions standard, you must determine the total heat
input in GJ or MMBtu from natural gas (HTIPng) and the total heat input
from all other fuels combined (HTIPo) using one of the methods under
Sec. 60.5535a(d)(2). You must then use the following equation to
determine the applicable emissions standard during the compliance
period:
Equation 1 to Paragraph (a)(2)
[GRAPHIC] [TIFF OMITTED] TR09MY24.057
Where:
CO2 emission standard = the emission standard during the
compliance period in units of kg/GJ (or lb/MMBtu).
HTIPng = the heat input in GJ (or MMBtu) from natural
gas.
HTIPo = the heat input in GJ (or MMBtu) from all fuels
other than natural gas.
50 = allowable emission rate in lb kg/GJ for heat input derived from
natural gas (use 120 if electing to demonstrate compliance using lb
CO2/MMBtu).
69 = allowable emission rate in lb kg/GJ for heat input derived from
all fuels other than natural gas (use 160 if electing to demonstrate
compliance using lb CO2/MMBtu).
(3) Owners/operators of a base load combustion turbine with a base
load rating of less than 2,110 GJ/h (2,000 MMBtu/h) and/or an
intermediate or base load combustion turbine burning fuels other than
natural gas may elect to determine a site-specific emissions rate using
one of the following equations. Combustion turbines co-firing hydrogen
are not required to use the fuel adjustment parameter.
(i) For base load combustion turbines:
Equation 2 to Paragraph (a)(3)(i)
[GRAPHIC] [TIFF OMITTED] TR09MY24.058
[[Page 40038]]
Where:
CO2 emission standard = the emission standard during the
compliance period in units of kg/MWh (or lb/MWh)
BLERL = Base load emissions standard for natural gas-
fired combustion turbines with base load ratings greater than 2,110
GJ/h (2,000 MMBtu/h). 360 kg CO2/MWh-gross (800 lb
CO2/MWh-gross) or 370 kg CO2/MWh-net (820 lb
CO2/MWh-net); 43 kg CO2/MWh-gross (100 lb
CO2/MWh-gross) or 42 kg CO2/MWh-net (97 lb
CO2/MWh-net); as applicable
BLERS = Base load emissions standard for natural gas-
fired combustion turbines with a base load rating of 260 GJ/h (250
MMBtu/h). 410 kg CO2/MWh-gross (900 lb CO2/
MWh-gross) or 420 kg CO2/MWh-net (920 lb CO2/
MWh-net); 49 kg CO2/MWh-gross (108 lb CO2/MWh-
gross) or 50 kg CO2/MWh-net (110 lb CO2/MWh-
net); as applicable
BLRL = Minimum base load rating of large combustion
turbines 2,110 GJ/h (2,000 MMBtu/h)
BLRS = Base load rating of smallest combustion turbine
260 GJ/h (250 MMBtu/h)
BLRA = Base load rating of the actual combustion turbine
in GJ/h (or MMBtu/h)
HIERA = Heat input-based emissions rate of the actual
fuel burned in the combustion turbine (lb CO2/MMBtu). Not
to exceed 69 kg/GJ (160 lb CO2/MMBtu)
HIERNG = Heat input-based emissions rate of natural gas
50 kg/GJ (120 lb CO2/MMBtu)
(ii) For intermediate load combustion turbines:
Equation 3 to Paragraph (a)(3)(ii)
[GRAPHIC] [TIFF OMITTED] TR09MY24.059
Where:
CO2 emission standard = the emission standard during the
compliance period in units of kg/MWh (or lb/MWh)
ILER = Intermediate load emissions rate for natural gas-fired
combustion turbines. 520 kg/MWh-gross (1,150 lb CO2/MWh-
gross) or 530 kg CO2/MWh-net (1,160 lb CO2/
MWh-net) or 450 kg/MWh-gross (1,100 lb CO2/MWh-gross) or
460 kg CO2/MWh-net (1,110 lb CO2/MWh-net) as
applicable
HIERA = Heat input-based emissions rate of the actual
fuel burned in the combustion turbine (lb CO2/MMBtu). Not
to exceed 69 kg/GJ (160 lb CO2/MMBtu)
HIERNG = Heat input-based emissions rate of natural gas
50 kg/GJ (120 lb CO2/MMBtu)
(b) At all times you must operate and maintain each affected EGU,
including associated equipment and monitors, in a manner consistent
with safety and good air pollution control practice. The Administrator
will determine if you are using consistent operation and maintenance
procedures based on information available to the Administrator that may
include, but is not limited to, fuel use records, monitoring results,
review of operation and maintenance procedures and records, review of
reports required by this subpart, and inspection of the EGU.
(c) Within 30 days after the end of the initial compliance period
(i.e., no more than 30 days after the first 12-operating-month
compliance period), you must make an initial compliance determination
for your affected EGU(s) with respect to the applicable emissions
standard in table 1 to this subpart, in accordance with the
requirements in this subpart. The first operating month included in the
initial 12-operating-month compliance period shall be determined as
follows:
(1) For an affected EGU that commences commercial operation (as
defined in 40 CFR 72.2), the first month of the initial compliance
period shall be the first operating month (as defined in Sec.
60.5580a) after the calendar month in which emissions reporting is
required to begin under:
(i) Section 60.5555a(c)(3)(i), for units subject to the Acid Rain
Program; or
(ii) Section 60.5555a(c)(3)(ii), for units that are not in the Acid
Rain Program.
(2) For a modified or reconstructed EGU that becomes subject to
this subpart, the first month of the initial compliance period shall be
the first operating month (as defined in Sec. 60.5580a) after the
calendar month in which emissions reporting is required to begin under
Sec. 60.5555a(c)(3)(iii).
(3) Emissions of CO2 emitted by your affected facility
and the output of the affected facility generated when it operated
during a system emergency as defined in Sec. 60.5580a are excluded for
both applicability and compliance with the relevant standards of
performance if you can sufficiently provide the documentation listed in
Sec. 60.5560a(i). The relevant standard of performance for affected
EGUs that operate during a system emergency depends on the subcategory,
as described in paragraphs (c)(3)(i) and (ii) of this section.
(i) For intermediate and base load combustion turbines that operate
during a system emergency, you comply with the standard for low load
combustion turbines specified in table 1 to this subpart.
(ii) For modified steam generating units, you must not discharge
from the affected EGU any gases that contain CO2 in excess
of 230 lb CO2/MMBtu.
Monitoring and Compliance Determination Procedures
Sec. 60.5535a How do I monitor and collect data to demonstrate
compliance?
(a) Combustion turbines qualifying under Sec. 60.5520a(d)(1) are
not subject to any requirements in this section other than the
requirement to maintain fuel purchase records for permitted fuel(s). If
your combustion turbine uses non-uniform fuels as specified under Sec.
60.5520a(d)(2), you must monitor heat input in accordance with
paragraph (c)(1) of this section, and you must monitor CO2
emissions in accordance with either paragraph (b), (c)(2), or (c)(5) of
this section. For all other affected sources, you must prepare a
monitoring plan to quantify the hourly CO2 mass emission
rate (tons/h), in accordance with the applicable provisions in 40 CFR
75.53(g) and (h). The electronic portion of the monitoring plan must be
submitted using the ECMPS Client Tool and must be in place prior to
reporting emissions data and/or the results of monitoring system
certification tests under this subpart. The monitoring plan must be
updated as necessary. Monitoring plan submittals must be made by the
Designated Representative (DR), the Alternate DR, or a delegated agent
of the DR (see Sec. 60.5555a(d) and (e)).
(b) You must determine the hourly CO2 mass emissions in
kg from your affected EGU(s) according to paragraphs (b)(1) through (5)
of this section, or, if applicable, as provided in paragraph (c) of
this section.
(1) For an affected EGU that combusts coal you must, and for all
other affected EGUs you may, install, certify, operate, maintain, and
calibrate a CO2 continuous emission monitoring system (CEMS)
to directly measure and record hourly average CO2
concentrations in the affected EGU exhaust gases emitted to the
atmosphere, and a flow monitoring system to measure hourly average
stack gas flow rates, according to 40 CFR 75.10(a)(3)(i). As an
alternative to direct measurement of CO2 concentration,
provided that your EGU does not use carbon separation (e.g., carbon
capture and storage), you may use data from a certified oxygen
[[Page 40039]]
(O2) monitor to calculate hourly average CO2 concentrations,
in accordance with 40 CFR 75.10(a)(3)(iii). If you measure
CO2 concentration on a dry basis, you must also install,
certify, operate, maintain, and calibrate a continuous moisture
monitoring system, according to 40 CFR 75.11(b). Alternatively, you may
either use an appropriate fuel-specific default moisture value from 40
CFR 75.11(b) or submit a petition to the Administrator under 40 CFR
75.66 for a site-specific default moisture value.
(2) For each continuous monitoring system that you use to determine
the CO2 mass emissions, you must meet the applicable
certification and quality assurance procedures in 40 CFR 75.20 and
appendices A and B to 40 CFR part 75.
(3) You must use only unadjusted exhaust gas volumetric flow rates
to determine the hourly CO2 mass emissions rate from the
affected EGU; you must not apply the bias adjustment factors described
in Section 7.6.5 of appendix A to 40 CFR part 75 to the exhaust gas
flow rate data.
(4) You must select an appropriate reference method to setup
(characterize) the flow monitor and to perform the on-going RATAs, in
accordance with 40 CFR part 75. If you use a Type-S pitot tube or a
pitot tube assembly for the flow RATAs, you must calibrate the pitot
tube or pitot tube assembly; you may not use the 0.84 default Type-S
pitot tube coefficient specified in Method 2.
(5) Calculate the hourly CO2 mass emissions (kg) as
described in paragraphs (b)(5)(i) through (iv) of this section. Perform
this calculation only for ``valid operating hours'', as defined in
Sec. 60.5540(a)(1).
(i) Begin with the hourly CO2 mass emission rate (tons/
h), obtained either from Equation F-11 in appendix F to 40 CFR part 75
(if CO2 concentration is measured on a wet basis), or by
following the procedure in section 4.2 of appendix F to 40 CFR part 75
(if CO2 concentration is measured on a dry basis).
(ii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in 40 CFR
72.2), to convert it to tons of CO2.
(iii) Finally, multiply the result from paragraph (b)(5)(ii) of
this section by 907.2 to convert it from tons of CO2 to kg.
Round off to the nearest kg.
(iv) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under 40 CFR 75.57(e) and must be reported
electronically under 40 CFR 75.64(a)(6). You must use these data to
calculate the hourly CO2 mass emissions.
(c) If your affected EGU exclusively combusts liquid fuel and/or
gaseous fuel, as an alternative to complying with paragraph (b) of this
section, you may determine the hourly CO2 mass emissions
according to paragraphs (c)(1) through (4) of this section. If you use
non-uniform fuels as specified in Sec. 60.5520a(d)(2), you may
determine CO2 mass emissions during the compliance period
according to paragraph (c)(5) of this section.
(1) If you are subject to an output-based standard and you do not
install CEMS in accordance with paragraph (b) of this section, you must
implement the applicable procedures in appendix D to 40 CFR part 75 to
determine hourly EGU heat input rates (MMBtu/h), based on hourly
measurements of fuel flow rate and periodic determinations of the gross
calorific value (GCV) of each fuel combusted.
(2) For each measured hourly heat input rate, use Equation G-4 in
appendix G to 40 CFR part 75 to calculate the hourly CO2
mass emission rate (tons/h). You may determine site-specific carbon-
based F-factors (Fc) using Equation F-7b in section 3.3.6 of appendix F
to 40 CFR part 75, and you may use these Fc values in the emissions
calculations instead of using the default Fc values in the Equation G-4
nomenclature.
(3) For each ``valid operating hour'' (as defined in Sec.
60.5540(a)(1), multiply the hourly tons/h CO2 mass emission
rate from paragraph (c)(2) of this section by the EGU or stack
operating time in hours (as defined in 40 CFR 72.2), to convert it to
tons of CO2. Then, multiply the result by 907.2 to convert
from tons of CO2 to kg. Round off to the nearest two
significant figures.
(4) The hourly CO2 tons/h values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under 40 CFR 75.57(e) and must be reported
electronically under 40 CFR 75.64(a)(6). You must use these data to
calculate the hourly CO2 mass emissions.
(5) If you operate a combustion turbine firing non-uniform fuels,
as an alternative to following paragraphs (c)(1) through (4) of this
section, you may determine CO2 emissions during the
compliance period using one of the following methods:
(i) Units firing fuel gas may determine the heat input during the
compliance period following the procedure under Sec. 60.107a(d) and
convert this heat input to CO2 emissions using Equation G-4
in appendix G to 40 CFR part 75.
(ii) You may use the procedure for determining CO2
emissions during the compliance period based on the use of the Tier 3
methodology under 40 CFR 98.33(a)(3).
(d) Consistent with Sec. 60.5520a, you must determine the basis of
the emissions standard that applies to your affected source in
accordance with either paragraph (d)(1) or (2) of this section, as
applicable:
(1) If you operate a source subject to an emissions standard
established on an output basis (e.g., lb CO2 per gross or
net MWh of energy output), you must install, calibrate, maintain, and
operate a sufficient number of watt meters to continuously measure and
record the hourly gross electric output or net electric output, as
applicable, from the affected EGU(s). These measurements must be
performed using 0.2 class electricity metering instrumentation and
calibration procedures as specified under ANSI No. C12.20-2010
(incorporated by reference, see Sec. 60.17). For a combined heat and
power (CHP) EGU, as defined in Sec. 60.5580a, you must also install,
calibrate, maintain, and operate meters to continuously (i.e., hour-by-
hour) determine and record the total useful thermal output. For process
steam applications, you will need to install, calibrate, maintain, and
operate meters to continuously determine and record the hourly steam
flow rate, temperature, and pressure. Your plan shall ensure that you
install, calibrate, maintain, and operate meters to record each
component of the determination, hour-by-hour.
(2) If you operate a source subject to an emissions standard
established on a heat-input basis (e.g., lb CO2/MMBtu) and
your affected source uses non-uniform heating value fuels as delineated
under Sec. 60.5520a(d), you must determine the total heat input for
each fuel fired during the compliance period in accordance with one of
the following procedures:
(i) Appendix D to 40 CFR part 75;
(ii) The procedures for monitoring heat input under Sec.
60.107a(d);
(iii) If you monitor CO2 emissions in accordance with
the Tier 3 methodology under 40 CFR 98.33(a)(3), you may convert your
CO2 emissions to heat input using the appropriate emission
factor in table C-1 of 40 CFR part 98. If your fuel is not listed in
table C-1, you must determine a fuel-specific carbon-based F-factor
(Fc) in accordance with section 12.3.2 of EPA Method 19 of appendix A-7
to this part, and you must convert your CO2 emissions to
heat input using Equation G-4 in appendix G to 40 CFR part 75.
[[Page 40040]]
(e) Consistent with Sec. 60.5520a, if two or more affected EGUs
serve a common electric generator, you must apportion the combined
hourly gross or net energy output to the individual affected EGUs
according to the fraction of the total steam load and/or direct
mechanical energy contributed by each EGU to the electric generator.
Alternatively, if the EGUs are identical, you may apportion the
combined hourly gross or net electrical load to the individual EGUs
according to the fraction of the total heat input contributed by each
EGU. You may also elect to develop, demonstrate, and provide
information satisfactory to the Administrator on alternate methods to
apportion the gross or net energy output. The Administrator may approve
such alternate methods for apportioning the gross or net energy output
whenever the demonstration ensures accurate estimation of emissions
regulated under this part.
(f) In accordance with Sec. Sec. 60.13(g) and 60.5520a, if two or
more affected EGUs that implement the continuous emission monitoring
provisions in paragraph (b) of this section share a common exhaust gas
stack you must monitor hourly CO2 mass emissions in
accordance with one of the following procedures:
(1) If the EGUs are subject to the same emissions standard in table
1 to this subpart, you may monitor the hourly CO2 mass
emissions at the common stack in lieu of monitoring each EGU
separately. If you choose this option, the hourly gross or net energy
output (electric, thermal, and/or mechanical, as applicable) must be
the sum of the hourly loads for the individual affected EGUs and you
must express the operating time as ``stack operating hours'' (as
defined in 40 CFR 72.2). If you attain compliance with the applicable
emissions standard in Sec. 60.5520a at the common stack, each affected
EGU sharing the stack is in compliance; or
(2) As an alternative to the requirements in paragraph (f)(1) of
this section, or if the EGUs are subject to different emission
standards in table 1 to this subpart, you must either:
(i) Monitor each EGU separately by measuring the hourly
CO2 mass emissions prior to mixing in the common stack or
(ii) Apportion the CO2 mass emissions based on the
unit's load contribution to the total load associated with the common
stack and the appropriate F-factors. You may also elect to develop,
demonstrate, and provide information satisfactory to the Administrator
on alternate methods to apportion the CO2 emissions. The
Administrator may approve such alternate methods for apportioning the
CO2 emissions whenever the demonstration ensures accurate
estimation of emissions regulated under this part.
(g) In accordance with Sec. Sec. 60.13(g) and 60.5520a if the
exhaust gases from an affected EGU that implements the continuous
emission monitoring provisions in paragraph (b) of this section are
emitted to the atmosphere through multiple stacks (or if the exhaust
gases are routed to a common stack through multiple ducts and you elect
to monitor in the ducts), you must monitor the hourly CO2
mass emissions and the ``stack operating time'' (as defined in 40 CFR
72.2) at each stack or duct separately. In this case, you must
determine compliance with the applicable emissions standard in table 1
or 2 to this subpart by summing the CO2 mass emissions
measured at the individual stacks or ducts and dividing by the total
gross or net energy output for the affected EGU.
Sec. 60.5540a How do I demonstrate compliance with my CO2 emissions
standard and determine excess emissions?
(a) In accordance with Sec. 60.5520a, if you are subject to an
output-based emission standard or you burn non-uniform fuels as
specified in Sec. 60.5520a(d)(2), you must demonstrate compliance with
the applicable CO2 emission standard in table 1 to this
subpart as required in this section. For the initial and each
subsequent 12-operating-month rolling average compliance period, you
must follow the procedures in paragraphs (a)(1) through (8) of this
section to calculate the CO2 mass emissions rate for your
affected EGU(s) in units of the applicable emissions standard (e.g.,
either kg/MWh or kg/GJ). You must use the hourly CO2 mass
emissions calculated under Sec. 60.5535a(b) or (c), as applicable, and
either the generating load data from Sec. 60.5535a(d)(1) for output-
based calculations or the heat input data from Sec. 60.5535a(d)(2) for
heat-input-based calculations. Combustion turbines firing non-uniform
fuels that contain CO2 prior to combustion (e.g., blast
furnace gas or landfill gas) may sample the fuel stream to determine
the quantity of CO2 present in the fuel prior to combustion
and exclude this portion of the CO2 mass emissions from
compliance determinations.
(1) Each compliance period shall include only ``valid operating
hours'' in the compliance period, i.e., operating hours for which:
(i) ``Valid data'' (as defined in Sec. 60.5580a) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (kg) and, if a heat input-based standard applies, all the
parameters used to determine total heat input for the hour are also
obtained; and
(ii) The corresponding hourly gross or net energy output value is
also valid data (Note: For hours with no useful output, zero is
considered to be a valid value).
(2) You must exclude operating hours in which:
(i) The substitute data provisions of part 75 of this chapter are
applied for any of the parameters used to determine the hourly
CO2 mass emissions or, if a heat input-based standard
applies, for any parameters used to determine the hourly heat input;
(ii) An exceedance of the full-scale range of a continuous emission
monitoring system occurs for any of the parameters used to determine
the hourly CO2 mass emissions or, if applicable, to
determine the hourly heat input; or
(iii) The total gross or net energy output (Pgross/net)
or, if applicable, the total heat input is unavailable.
(3) For each compliance period, at least 95 percent of the
operating hours in the compliance period must be valid operating hours,
as defined in paragraph (a)(1) of this section.
(4) You must calculate the total CO2 mass emissions by
summing the valid hourly CO2 mass emissions values from
Sec. 60.5535a for all of the valid operating hours in the compliance
period.
(5) For each valid operating hour of the compliance period that was
used in paragraph (a)(4) of this section to calculate the total
CO2 mass emissions, you must determine Pgross/net
(the corresponding hourly gross or net energy output in MWh) according
to the procedures in paragraphs (a)(5)(i) and (ii) of this section, as
appropriate for the type of affected EGU(s). For an operating hour in
which a valid CO2 mass emissions value is determined
according to paragraph (a)(1)(i) of this section, if there is no gross
or net electrical output, but there is mechanical or useful thermal
output, you must still determine the gross or net energy output for
that hour. In addition, for an operating hour in which a valid
CO2 mass emissions value is determined according to
paragraph (a)(1)(i) of this section, but there is no (i.e., zero) gross
electrical, mechanical, or useful thermal output, you must use that
hour in the compliance determination. For hours or partial hours where
the gross electric output is equal to or less than the auxiliary loads,
net electric output shall be counted as zero for this calculation.
(i) Calculate Pgross/net for your affected EGU using the
following equation. All terms in the equation must be expressed in
units of MWh. To convert each
[[Page 40041]]
hourly gross or net energy output (consistent with Sec. 60.5520a)
value reported under part 75 of this chapter to MWh, multiply by the
corresponding EGU or stack operating time.
Equation 1 to Paragraph (a)(5)(i)
[GRAPHIC] [TIFF OMITTED] TR09MY24.060
Where:
Pgross/net = In accordance with Sec. 60.5520a, gross or
net energy output of your affected EGU for each valid operating hour
(as defined in Sec. 60.5540a(a)(1)) in MWh.
(Pe)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(Pe)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(Pe)IE = Electric energy output plus mechanical energy
output (if any) of your affected EGU's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(Pe)FW = Electric energy used to power boiler feedwater
pumps at steam generating units in MWh. Not applicable to stationary
combustion turbines, IGCC EGUs, or EGUs complying with a net energy
output based standard.
(Pe)A = Electric energy used for any auxiliary loads in
MWh. Not applicable for determining Pgross.
(Pt)PS = Useful thermal output of steam (measured
relative to standard ambient temperature and pressure (SATP)
conditions, as applicable) that is used for applications that do not
generate additional electricity, produce mechanical energy output,
or enhance the performance of the affected EGU. This is calculated
using the equation specified in paragraph (a)(5)(ii) of this section
in MWh.
(Pt)HR = Non steam useful thermal output (measured
relative to SATP conditions, as applicable) from heat recovery that
is used for applications other than steam generation or performance
enhancement of the affected EGU in MWh.
(Pt)IE = Useful thermal output (relative to SATP
conditions, as applicable) from any integrated equipment is used for
applications that do not generate additional steam, electricity,
produce mechanical energy output, or enhance the performance of the
affected EGU in MWh.
TDF = Electric Transmission and Distribution Factor of 0.95 for a
combined heat and power affected EGU where at least on an annual
basis 20.0 percent of the total gross or net energy output consists
of useful thermal output on a 12-operating-month rolling average
basis, or 1.0 for all other affected EGUs.
(ii) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the following
equation:
Equation 2 to Paragraph (a)(5)(ii)
[GRAPHIC] [TIFF OMITTED] TR09MY24.061
Where:
Qm = Measured useful thermal output flow in kg (lb) for
the operating hour.
H = Enthalpy of the useful thermal output at measured temperature
and pressure (relative to SATP conditions or the energy in the
condensate return line, as applicable) in Joules per kilogram (J/kg)
(or Btu/lb).
CF = Conversion factor of 3.6 x 10\9\ J/MWh or 3.413 x 10\6\ Btu/
MWh.
(6) Sources complying with energy output-based standards must
calculate the basis (i.e., denominator) of their actual annual emission
rate in accordance with paragraph (a)(6)(i) of this section. Sources
complying with heat input based standards must calculate the basis of
their actual annual emission rate in accordance with paragraph
(a)(6)(ii) of this section.
(i) In accordance with Sec. 60.5520a if you are subject to an
output-based standard, you must calculate the total gross or net energy
output for the affected EGU's compliance period by summing the hourly
gross or net energy output values for the affected EGU that you
determined under paragraph (a)(5) of this section for all of the valid
operating hours in the applicable compliance period.
(ii) If you are subject to a heat input-based standard, you must
calculate the total heat input for each fuel fired during the
compliance period. The calculation of total heat input for each
individual fuel must include all valid operating hours and must also be
consistent with any fuel-specific procedures specified within your
selected monitoring option under Sec. 60.5535(d)(2).
(7) If you are subject to an output-based standard, you must
calculate the CO2 mass emissions rate for the affected
EGU(s) (kg/MWh) by dividing the total CO2 mass emissions
value calculated according to the procedures in paragraph (a)(4) of
this section by the total gross or net energy output value calculated
according to the procedures in paragraph (a)(6)(i) of this section.
Round off the result to two significant figures if the calculated value
is less than 1,000; round the result to three significant figures if
the calculated value is greater than 1,000. If you are subject to a
heat input-based standard, you must calculate the CO2 mass
emissions rate for the affected EGU(s) (kg/GJ or lb/MMBtu) by dividing
the total CO2 mass emissions value calculated according to
the procedures in paragraph (a)(4) of this section by the total heat
input calculated according to the procedures in paragraph (a)(6)(ii) of
this section. Round off the result to two significant figures.
(8) You may exclude CO2 mass emissions and output
generated from your affected EGU from your calculations for hours
during which the affected EGU operated during a system emergency, as
defined in Sec. 60.5580a, if you can provide the information listed in
Sec. 60.5560a(i). While operating during a system emergency, your
compliance determination depends on your subcategory or unit type, as
listed in paragraphs (a)(8)(i) through (ii) of this section.
(i) For affected EGUs in the intermediate or base load subcategory,
your CO2 emission standard while operating during a system
emergency is the applicable emission standard for low load combustion
turbines.
(ii) For affected modified steam generating units, your
CO2 emission standard while operating during a system
emergency is 230 lb CO2/MMBtu.
(b) In accordance with Sec. 60.5520a, to demonstrate compliance
with the applicable CO2 emission standard, for the initial
and each subsequent 12-operating-month compliance period, the
CO2 mass emissions rate for your affected EGU must be
determined
[[Page 40042]]
according to the procedures specified in paragraph (a)(1) through (8)
of this section and must be less than or equal to the applicable
CO2 emissions standard in table 1 to this subpart, or the
emissions standard calculated in accordance with Sec. 60.5525a(a)(2).
(c) If you are the owner or operator of a new or reconstructed
stationary combustion turbine operating in the base load subcategory,
are installing add-on controls, and are unable to comply with the
applicable Phase 2 CO2 emission standard specified in table
1 to this subpart due to circumstances beyond your control, you may
request a compliance date extension of no longer than one year beyond
the effective date of January 1, 2032, and may only receive an
extension once. The extension request must contain a demonstration of
necessity that includes the following:
(1) A demonstration that your affected EGU cannot meet its
compliance date due to circumstances beyond your control and you have
taken all steps reasonably possible to install the controls necessary
for compliance by the effective date up to the point of the delay. The
demonstration shall:
(i) Identify each affected unit for which you are seeking the
compliance extension;
(ii) Identify and describe the controls to be installed at each
affected unit to comply with the applicable CO2 emission
standard in table 1 to this subpart;
(iii) Describe and demonstrate all progress towards installing the
controls and that you have acted consistently with achieving timely
compliance, including;
(A) Any and all contract(s) entered into for the installation of
the identified controls or an explanation as to why no contract is
necessary or obtainable;
(B) Any permit(s) obtained for the installation of the identified
controls or, where a required permit has not yet been issued, a copy of
the permit application submitted to the permitting authority and a
statement from the permit authority identifying its anticipated
timeframe for issuance of such permit(s).
(iv) Identify the circumstances that are entirely beyond your
control and that necessitate additional time to install the identified
controls. This may include:
(A) Information gathered from control technology vendors or
engineering firms demonstrating that the necessary controls cannot be
installed or started up by the applicable compliance date listed in
table 1 to this subpart;
(B) Documentation of any permit delays; or
(C) Documentation of delays in construction or permitting of
infrastructure (e.g., CO2 pipelines) that is necessary for
implementation of the control technology;
(v) Identify a proposed compliance date no later than one year
after the applicable compliance date listed in table 1 to this subpart.
(2) The Administrator is charged with approving or disapproving a
compliance date extension request based on his or her written
determination that your affected EGU has or has not made each of the
necessary demonstrations and provided all of the necessary
documentation according to paragraph (c)(1) of this section. The
following must be included:
(i) All documentation required as part of this extension must be
submitted by you to the Administrator no later than 6 months prior to
the applicable effective date for your affected EGU.
(ii) You must notify the Administrator of the compliance date
extension request at the time of the submission of the request.
Notification, Reports, and Records
Sec. 60.5550a What notifications must I submit and when?
(a) You must prepare and submit the notifications specified in
Sec. Sec. 60.7(a)(1) and (3) and 60.19, as applicable to your affected
EGU(s) (see table 3 to this subpart).
(b) You must prepare and submit notifications specified in 40 CFR
75.61, as applicable, to your affected EGUs.
Sec. 60.5555a What reports must I submit and when?
(a) You must prepare and submit reports according to paragraphs (a)
through (d) of this section, as applicable.
(1) For affected EGUs that are required by Sec. 60.5525a to
conduct initial and on-going compliance determinations on a 12-
operating-month rolling average basis, you must submit electronic
quarterly reports as follows. After you have accumulated the first 12-
operating months for the affected EGU, you must submit a report for the
calendar quarter that includes the twelfth operating month no later
than 30 days after the end of that quarter. Thereafter, you must submit
a report for each subsequent calendar quarter, no later than 30 days
after the end of the quarter.
(2) In each quarterly report you must include the following
information, as applicable:
(i) Each rolling average CO2 mass emissions rate for
which the last (twelfth) operating month in a 12-operating-month
compliance period falls within the calendar quarter. You must calculate
each average CO2 mass emissions rate for the compliance
period according to the procedures in Sec. 60.5540a. You must report
the dates (month and year) of the first and twelfth operating months in
each compliance period for which you performed a CO2 mass
emissions rate calculation. If there are no compliance periods that end
in the quarter, you must include a statement to that effect;
(ii) If one or more compliance periods end in the quarter, you must
identify each operating month in the calendar quarter where your EGU
violated the applicable CO2 emission standard;
(iii) If one or more compliance periods end in the quarter and
there are no violations for the affected EGU, you must include a
statement indicating this in the report;
(iv) The percentage of valid operating hours in each 12-operating-
month compliance period described in paragraph (a)(1) of this section
(i.e., the total number of valid operating hours (as defined in Sec.
60.5540a(a)(1)) in that period divided by the total number of operating
hours in that period, multiplied by 100 percent);
(v) Consistent with Sec. 60.5520a, the CO2 emissions
standard (as identified in table 1 or 2 to this subpart) with which
your affected EGU must comply; and
(vi) Consistent with Sec. 60.5520a, an indication whether or not
the hourly gross or net energy output (Pgross/net) values
used in the compliance determinations are based solely upon gross
electrical load.
(3) In the final quarterly report of each calendar year, you must
include the following:
(i) Consistent with Sec. 60.5520a, gross energy output or net
energy output sold to an electric grid, as applicable to the units of
your emission standard, over the four quarters of the calendar year;
and
(ii) The potential electric output of the EGU.
(b) You must submit all electronic reports required under paragraph
(a) of this section using the Emissions Collection and Monitoring Plan
System (ECMPS) Client Tool provided by the Clean Air Markets Division
in the Office of Atmospheric Programs of EPA.
(c)(1) For affected EGUs under this subpart that are also subject
to the Acid Rain Program, you must meet all applicable reporting
requirements and submit reports as required under subpart G of part 75
of this chapter.
(2) For affected EGUs under this subpart that are not in the Acid
Rain Program, you must also meet the reporting requirements and submit
[[Page 40043]]
reports as required under subpart G of part 75 of this chapter, to the
extent that those requirements and reports provide applicable data for
the compliance demonstrations required under this subpart.
(3)(i) For all newly-constructed affected EGUs under this subpart
that are also subject to the Acid Rain Program, you must begin
submitting the quarterly electronic emissions reports described in
paragraph (c)(1) of this section in accordance with 40 CFR 75.64(a),
i.e., beginning with data recorded on and after the earlier of:
(A) The date of provisional certification, as defined in 40 CFR
75.20(a)(3); or
(B) 180 days after the date on which the EGU commences commercial
operation (as defined in 40 CFR 72.2).
(ii) For newly-constructed affected EGUs under this subpart that
are not subject to the Acid Rain Program, you must begin submitting the
quarterly electronic reports described in paragraph (c)(2) of this
section, beginning with data recorded on and after the date on which
reporting is required to begin under 40 CFR 75.64(a), if that date
occurs on or after May 23, 2023.
(iii) For reconstructed or modified units, reporting of emissions
data shall begin at the date on which the EGU becomes an affected unit
under this subpart, provided that the ECMPS Client Tool is able to
receive and process net energy output data on that date. Otherwise,
emissions data reporting shall be on a gross energy output basis until
the date that the Client Tool is first able to receive and process net
energy output data.
(4) If any required monitoring system has not been provisionally
certified by the applicable date on which emissions data reporting is
required to begin under paragraph (c)(3) of this section, the maximum
(or in some cases, minimum) potential value for the parameter measured
by the monitoring system shall be reported until the required
certification testing is successfully completed, in accordance with 40
CFR 75.4(j), 40 CFR 75.37(b), or section 2.4 of appendix D to part 75
of this chapter (as applicable). Operating hours in which
CO2 mass emission rates are calculated using maximum
potential values are not ``valid operating hours'' (as defined in Sec.
60.5540(a)(1)), and shall not be used in the compliance determinations
under Sec. 60.5540.
(d) For affected EGUs subject to the Acid Rain Program, the reports
required under paragraphs (a) and (c)(1) of this section shall be
submitted by:
(1) The person appointed as the Designated Representative (DR)
under 40 CFR 72.20; or
(2) The person appointed as the Alternate Designated Representative
(ADR) under 40 CFR 72.22; or
(3) A person (or persons) authorized by the DR or ADR under 40 CFR
72.26 to make the required submissions.
(e) For affected EGUs that are not subject to the Acid Rain
Program, the owner or operator shall appoint a DR and (optionally) an
ADR to submit the reports required under paragraphs (a) and (c)(2) of
this section. The DR and ADR must register with the Clean Air Markets
Division (CAMD) Business System. The DR may delegate the authority to
make the required submissions to one or more persons.
(f) If your affected EGU captures CO2 to meet the
applicable emission standard, you must report in accordance with the
requirements of 40 CFR part 98, subpart PP, and either:
(1) Report in accordance with the requirements of 40 CFR part 98,
subpart RR, or subpart VV, if injection occurs on-site;
(2) Transfer the captured CO2 to a facility that reports
in accordance with the requirements of 40 CFR part 98, subpart RR, or
subpart VV, if injection occurs off-site; or
(3) Transfer the captured CO2 to a facility that has
received an innovative technology waiver from EPA pursuant to paragraph
(g) of this section.
(g) Any person may request the Administrator to issue a waiver of
the requirement that captured CO2 from an affected EGU be
transferred to a facility reporting under 40 CFR part 98, subpart RR,
or subpart VV. To receive a waiver, the applicant must demonstrate to
the Administrator that its technology will store captured
CO2 as effectively as geologic sequestration, and that the
proposed technology will not cause or contribute to an unreasonable
risk to public health, welfare, or safety. In making this
determination, the Administrator shall consider (among other factors)
operating history of the technology, whether the technology will
increase emissions or other releases of any pollutant other than
CO2, and permanence of the CO2 storage. The
Administrator may test the system, or require the applicant to perform
any tests considered by the Administrator to be necessary to show the
technology's effectiveness, safety, and ability to store captured
CO2 without release. The Administrator may grant conditional
approval of a technology, with the approval conditioned on monitoring
and reporting of operations. The Administrator may also withdraw
approval of the waiver on evidence of releases of CO2 or
other pollutants. The Administrator will provide notice to the public
of any application under this provision and provide public notice of
any proposed action on a petition before the Administrator takes final
action.
Sec. 60.5560a What records must I maintain?
(a) You must maintain records of the information you used to
demonstrate compliance with this subpart as specified in Sec. 60.7(b)
and (f).
(b)(1) For affected EGUs subject to the Acid Rain Program, you must
follow the applicable recordkeeping requirements and maintain records
as required under subpart F of part 75 of this chapter.
(2) For affected EGUs that are not subject to the Acid Rain
Program, you must also follow the recordkeeping requirements and
maintain records as required under subpart F of part 75 of this
chapter, to the extent that those records provide applicable data for
the compliance determinations required under this subpart. Regardless
of the prior sentence, at a minimum, the following records must be
kept, as applicable to the types of continuous monitoring systems used
to demonstrate compliance under this subpart:
(i) Monitoring plan records under 40 CFR 75.53(g) and (h);
(ii) Operating parameter records under 40 CFR 75.57(b)(1) through
(4);
(iii) The records under 40 CFR 75.57(c)(2), for stack gas
volumetric flow rate;
(iv) The records under 40 CFR 75.57(c)(3) for continuous moisture
monitoring systems;
(v) The records under 40 CFR 75.57(e)(1), except for paragraph
(e)(1)(x), for CO2 concentration monitoring systems or O2
monitors used to calculate CO2 concentration;
(vi) The records under 40 CFR 75.58(c)(1), specifically paragraphs
(c)(1)(i), (ii), and (viii) through (xiv), for oil flow meters;
(vii) The records under 40 CFR 75.58(c)(4), specifically paragraphs
(c)(4)(i), (ii), (iv), (v), and (vii) through (xi), for gas flow
meters;
(viii) The quality-assurance records under 40 CFR 75.59(a),
specifically paragraphs (a)(1) through (12) and (15), for CEMS;
(ix) The quality-assurance records under 40 CFR 75.59(a),
specifically paragraphs (b)(1) through (4), for fuel flow meters; and
(x) Records of data acquisition and handling system (DAHS)
verification under 40 CFR 75.59(e).
(c) You must keep records of the calculations you performed to
determine the hourly and total CO2 mass emissions (tons)
for:
[[Page 40044]]
(1) Each operating month (for all affected EGUs); and
(2) Each compliance period, including, each 12-operating-month
compliance period.
(d) Consistent with Sec. 60.5520a, you must keep records of the
applicable data recorded and calculations performed that you used to
determine your affected EGU's gross or net energy output for each
operating month.
(e) You must keep records of the calculations you performed to
determine the percentage of valid CO2 mass emission rates in
each compliance period.
(f) You must keep records of the calculations you performed to
assess compliance with each applicable CO2 mass emissions
standard in table 1 or 2 to this subpart.
(g) You must keep records of the calculations you performed to
determine any site-specific carbon-based F-factors you used in the
emissions calculations (if applicable).
(h) For stationary combustion turbines, you must keep records of
electric sales to determine the applicable subcategory.
(i) You must keep the records listed in paragraphs (i)(1) through
(3) of this section to demonstrate that your affected facility operated
during a system emergency.
(1) Documentation that the system emergency to which the affected
EGU was responding was in effect from the entity issuing the alert and
documentation of the exact duration of the system emergency;
(2) Documentation from the entity issuing the alert that the system
emergency included the affected source/region where the affected
facility was located; and
(3) Documentation that the affected facility was instructed to
increase output beyond the planned day-ahead or other near-term
expected output and/or was asked to remain in operation outside its
scheduled dispatch during emergency conditions from a Reliability
Coordinator, Balancing Authority, or Independent System Operator/
Regional Transmission Organization.
Sec. 60.5565a In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available
for expeditious review.
(b) You must maintain each record for 5 years after the date of
conclusion of each compliance period.
(c) You must maintain each record on site for at least 2 years
after the date of each occurrence, measurement, maintenance, corrective
action, report, or record, according to Sec. 60.7. Records that are
accessible from a central location by a computer or other means that
instantly provide access at the site meet this requirement. You may
maintain the records off site for the remaining year(s) as required by
this subpart.
Other Requirements and Information
Sec. 60.5570a What parts of the general provisions apply to my
affected EGU?
Notwithstanding any other provision of this chapter, certain parts
of the general provisions in Sec. Sec. 60.1 through 60.19, listed in
table 3 to this subpart, do not apply to your affected EGU.
Sec. 60.5575a Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the EPA, or a
delegated authority such as your state, local, or Tribal agency. If the
Administrator has delegated authority to your state, local, or Tribal
agency, then that agency (as well as the EPA) has the authority to
implement and enforce this subpart. You should contact your EPA
Regional Office to find out if this subpart is delegated to your state,
local, or Tribal agency.
(b) In delegating implementation and enforcement authority of this
subpart to a state, local, or Tribal agency, the Administrator retains
the authorities listed in paragraphs (b)(1) through (5) of this section
and does not transfer them to the state, local, or Tribal agency. In
addition, the EPA retains oversight of this subpart and can take
enforcement actions, as appropriate.
(1) Approval of alternatives to the emission standards.
(2) Approval of major alternatives to test methods.
(3) Approval of major alternatives to monitoring.
(4) Approval of major alternatives to recordkeeping and reporting.
(5) Performance test and data reduction waivers under Sec.
60.8(b).
Sec. 60.5580a What definitions apply to this subpart?
As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subpart A (general
provisions) of this part.
Annual capacity factor means the ratio between the actual heat
input to an EGU during a calendar year and the potential heat input to
the EGU had it been operated for 8,760 hours during a calendar year at
the base load rating. Actual and potential heat input derived from non-
combustion sources (e.g., solar thermal) are not included when
calculating the annual capacity factor.
Base load combustion turbine means a stationary combustion turbine
that supplies more than 40 percent of its potential electric output as
net-electric sales on both a 12-operating month and a 3-year rolling
average basis.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady state basis plus the maximum amount of
heat input derived from non-combustion source (e.g., solar thermal), as
determined by the physical design and characteristics of the EGU at
International Organization for Standardization (ISO) conditions. For a
stationary combustion turbine, base load rating includes the heat input
from duct burners.
Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite in ASTM D388-99R04 (incorporated by
reference, see Sec. 60.17), coal refuse, and petroleum coke. Synthetic
fuels derived from coal for the purpose of creating useful heat,
including, but not limited to, solvent-refined coal, gasified coal (not
meeting the definition of natural gas), coal-oil mixtures, and coal-
water mixtures are included in this definition for the purposes of this
subpart.
Coal-fired Electric Generating Unit means a steam generating unit
or integrated gasification combined cycle unit that combusts coal on or
after the date of modification or at any point after December 31, 2029.
Combined cycle unit means a stationary combustion turbine from
which the heat from the turbine exhaust gases is recovered by a heat
recovery steam generating unit (HRSG) to generate additional
electricity.
Combined heat and power unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that simultaneously
produces both electric (or mechanical) and useful thermal output from
the same primary energy source.
Design efficiency means the rated overall net efficiency (e.g.,
electric plus useful thermal output) on a higher heating value basis at
the base load rating, at ISO conditions, and at the maximum useful
thermal output (e.g., CHP unit with condensing steam turbines would
determine the design efficiency at the maximum level of extraction and/
or bypass). Design efficiency shall be determined using one of the
following methods: ASME PTC 22-2014, ASME PTC 46-1996, ISO 2314:2009
(E) (all incorporated by reference, see Sec. 60.17), or an alternative
approved by the Administrator. When determining the design efficiency,
the output of integrated equipment and energy storage are included.
[[Page 40045]]
Distillate oil means fuel oils that comply with the specifications
for fuel oil numbers 1 and 2, as defined in ASTM D396-98 (incorporated
by reference, see Sec. 60.17); diesel fuel oil numbers 1 and 2, as
defined in ASTM D975-08a (incorporated by reference, see Sec. 60.17);
kerosene, as defined in ASTM D3699-08 (incorporated by reference, see
Sec. 60.17); biodiesel as defined in ASTM D6751-11b (incorporated by
reference, see Sec. 60.17); or biodiesel blends as defined in ASTM
D7467-10 (incorporated by reference, see Sec. 60.17).
Electric Generating units or EGU means any steam generating unit,
IGCC unit, or stationary combustion turbine that is subject to this
rule (i.e., meets the applicability criteria).
Fossil fuel means natural gas, petroleum, coal, and any form of
solid, liquid, or gaseous fuel derived from such material for the
purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at ISO
conditions and includes, but is not limited to, natural gas, refinery
fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
Gross energy output means:
(1) For stationary combustion turbines and IGCC, the gross electric
or direct mechanical output from both the EGU (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expander(s)) plus 100 percent of the useful thermal output.
(2) For steam generating units, the gross electric or mechanical
output from the affected EGU(s) (including, but not limited to, output
from steam turbine(s), combustion turbine(s), and gas expander(s))
minus any electricity used to power the feedwater pumps plus 100
percent of the useful thermal output;
(3) For combined heat and power facilities, where at least 20.0
percent of the total gross energy output consists of useful thermal
output on a 12-operating-month rolling average basis, the gross
electric or mechanical output from the affected EGU (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expander(s)) minus any electricity used to power the feedwater
pumps (the electric auxiliary load of boiler feedwater pumps is not
applicable to IGCC facilities), that difference divided by 0.95, plus
100 percent of the useful thermal output.
Heat recovery steam generating unit (HRSG) means an EGU in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
Integrated gasification combined cycle facility or IGCC means a
combined cycle facility that is designed to burn fuels containing 50
percent (by heat input) or more solid-derived fuel not meeting the
definition of natural gas, plus any integrated equipment that provides
electricity or useful thermal output to the affected EGU or auxiliary
equipment. The Administrator may waive the 50 percent solid-derived
fuel requirement during periods of the gasification system
construction, startup and commissioning, shutdown, or repair. No solid
fuel is directly burned in the EGU during operation.
Intermediate load combustion turbine means a stationary combustion
turbine that supplies more than 20 percent but less than or equal to 40
percent of its potential electric output as net-electric sales on both
a 12-operating month and a 3-year rolling average basis.
ISO conditions means 288 Kelvin (15 [deg]C, 59 [deg]F), 60 percent
relative humidity and 101.3 kilopascals (14.69 psi, 1 atm) pressure.
Liquid fuel means any fuel that is present as a liquid at ISO
conditions and includes, but is not limited to, distillate oil and
residual oil.
Low load combustion turbine means a stationary combustion turbine
that supplies 20 percent or less of its potential electric output as
net-electric sales on both a 12-operating month and a 3-year rolling
average basis.
Mechanical output means the useful mechanical energy that is not
used to operate the affected EGU(s), generate electricity and/or
thermal energy, or to enhance the performance of the affected EGU.
Mechanical energy measured in horsepower hour should be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. Finally,
natural gas does not include the following gaseous fuels: Landfill gas,
digester gas, refinery gas, sour gas, blast furnace gas, coal-derived
gas, producer gas, coke oven gas, or any gaseous fuel produced in a
process which might result in highly variable CO2 content or
heating value.
Net-electric output means the amount of gross generation the
generator(s) produces (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net-electric sales means:
(1) The gross electric sales to the utility power distribution
system minus purchased power; or
(2) For combined heat and power facilities, where at least 20.0
percent of the total gross energy output consists of useful thermal
output on a 12-operating month basis, the gross electric sales to the
utility power distribution system minus the applicable percentage of
purchased power of the thermal host facility or facilities. The
applicable percentage of purchase power for CHP facilities is
determined based on the percentage of the total thermal load of the
host facility supplied to the host facility by the CHP facility. For
example, if a CHP facility serves 50 percent of a thermal host's
thermal demand, the owner/operator of the CHP facility would subtract
50 percent of the thermal host's electric purchased power when
calculating net-electric sales.
(3) Electricity supplied to other facilities that produce
electricity to offset auxiliary loads are included when calculating
net-electric sales.
(4) Electric sales during a system emergency are not included when
calculating net-electric sales.
Net energy output means:
(1) The net electric or mechanical output from the affected EGU
plus 100 percent of the useful thermal output; or
(2) For combined heat and power facilities, where at least 20.0
percent of the total gross or net energy output consists of useful
thermal output on a 12-operating-month rolling average basis, the net
electric or mechanical output from the affected EGU divided by 0.95,
plus 100 percent of the useful thermal output.
Operating month means a calendar month during which any fuel is
combusted in the affected EGU at any time.
Petroleum means crude oil or a fuel derived from crude oil,
including, but not limited to, distillate and residual oil.
Potential electric output means the base load rating design
efficiency at the maximum electric production rate (e.g., CHP units
with condensing steam turbines will operate at maximum electric
production) multiplied by the base load rating (expressed in MMBtu/
[[Page 40046]]
h) of the EGU, multiplied by 10\6\ Btu/MMBtu, divided by 3,413 Btu/KWh,
divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr (e.g., a 35
percent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil fuel
heat input capacity would have a 306,000 MWh 12-month potential
electric output capacity).
Solid fuel means any fuel that has a definite shape and volume, has
no tendency to flow or disperse under moderate stress, and is not
liquid or gaseous at ISO conditions. This includes, but is not limited
to, coal, biomass, and pulverized solid fuels.
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25 [deg]C, 77 [deg]F) and 100.0 kilopascals (14.504 psi,
0.987 atm) pressure. The enthalpy of water at SATP conditions is 50
Btu/lb.
Stationary combustion turbine means all equipment including, but
not limited to, the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emission control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, (e.g., onsite photovoltaics),
integrated energy storage (e.g., onsite batteries), heat recovery
system, or auxiliary equipment. Stationary means that the combustion
turbine is not self-propelled or intended to be propelled while
performing its function. It may, however, be mounted on a vehicle for
portability. A stationary combustion turbine that burns any solid fuel
directly is considered a steam generating unit.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected EGU(s) or
auxiliary equipment.
System emergency means periods when the Reliability Coordinator has
declared an Energy Emergency Alert level 2 or 3 as defined by NERC
Reliability Standard EOP-011-2 or its successor.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to part 75 of this chapter. For CEMS, the initial
certification requirements in 40 CFR 75.20 and appendix A to 40 CFR
part 75 must be met before quality-assured data are reported under this
subpart; for on-going quality assurance, the daily, quarterly, and
semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of
appendix B to 40 CFR part 75 must be met and the data validation
criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to 40 CFR
part 75. For fuel flow meters, the initial certification requirements
in section 2.1.5 of appendix D to 40 CFR part 75 must be met before
quality-assured data are reported under this subpart (except for
qualifying commercial billing meters under section 2.1.4.2 of appendix
D to 40 CFR part 75), and for on-going quality assurance, the
provisions in section 2.1.6 of appendix D to 40 CFR part 75 apply
(except for qualifying commercial billing meters).
Violation means a specified averaging period over which the
CO2 emissions rate is higher than the applicable emissions
standard located in table 1 to this subpart.
Table 1 to Subpart TTTTa of Part 60--CO2 Emission Standards for Affected
Stationary Combustion Turbines That Commenced Construction or
Reconstruction After May 23, 2023 (Gross or Net Energy Output-Based
Standards Applicable as Approved by the Administrator)
[Note: Numerical values of 1,000 or greater have a minimum of 3
significant figures and numerical values of less than 1,000 have a
minimum of 2 significant figures]
------------------------------------------------------------------------
Affected EGU category CO2 emission standard
------------------------------------------------------------------------
Base load combustion turbines..... For 12-operating month averages
beginning before January 2032, 360
to 560 kg CO2/MWh (800 to 1,250 lb
CO2/MWh) of gross energy output; or
370 to 570 kg CO2/MWh (820 to 1,280
lb CO2/MWh) of net energy output as
determined by the procedures in
Sec. 60.5525a.
For 12-operating month averages
beginning after December 2031, 43
to 67 kg CO2/MWh (100 to 150 lb CO2/
MWh) of gross energy output; or 42
to 64 kg CO2/MWh (97 to 139 lb CO2/
MWh) of net energy output as
determined by the procedures in
Sec. 60.5525a.
Intermediate load combustion 530 to 710 kg CO2/MWh (1,170 to
turbines. 1,560 lb CO2/MWh) of gross energy
output; or 540 to 700 kg CO2/MWh
(1,190 to 1,590 lb CO2/MWh) of net
energy output as determined by the
procedures in Sec. 60.5525a.
Low load combustion turbines...... Between 50 to 69 kg CO2/GJ (120 to
160 lb CO2/MMBtu) of heat input as
determined by the procedures in
Sec. 60.5525a.
------------------------------------------------------------------------
[[Page 40047]]
Table 2 to Subpart TTTTa of Part 60--CO2 Emission Standards for Affected
Steam Generating Units or IGCC That Commenced Modification After May 23,
2023
------------------------------------------------------------------------
Affected EGU CO2 Emission standard
------------------------------------------------------------------------
Modified coal-fired steam A unit-specific emissions standard
generating unit. determined by an 88.4 percent
reduction in the unit's best
historical annual CO2 emission rate
(from 2002 to the date of the
modification).
------------------------------------------------------------------------
Table 3 to Subpart TTTTa of Part 60--Applicability of Subpart A of Part 60 (General Provisions) to Subpart TTTTa
----------------------------------------------------------------------------------------------------------------
Applies to subpart
General provisions citation Subject of citation TTTTa Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1........................ Applicability......... Yes.
Sec. 60.2........................ Definitions........... Yes................... Additional terms defined in
Sec. 60.5580a.
Sec. 60.3........................ Units and Yes.
Abbreviations.
Sec. 60.4........................ Address............... Yes................... Does not apply to
information reported
electronically through
ECMPS. Duplicate
submittals are not
required.
Sec. 60.5........................ Determination of Yes.
construction or
modification.
Sec. 60.6........................ Review of plans....... Yes.
Sec. 60.7........................ Notification and Yes................... Only the requirements to
Recordkeeping. submit the notifications
in Sec. 60.7(a)(1) and
(3) and to keep records of
malfunctions in Sec.
60.7(b), if applicable.
Sec. 60.8(a)..................... Performance tests..... No....................
Sec. 60.8(b)..................... Performance test Yes................... Administrator can approve
method alternatives. alternate methods.
Sec. 60.8(c)-(f)................. Conducting performance No....................
tests.
Sec. 60.9........................ Availability of Yes.
Information.
Sec. 60.10....................... State authority....... Yes.
Sec. 60.11....................... Compliance with No....................
standards and
maintenance
requirements.
Sec. 60.12....................... Circumvention......... Yes.
Sec. 60.13 (a)-(h), (j).......... Monitoring No.................... All monitoring is done
requirements. according to part 75.
Sec. 60.13 (i)................... Monitoring Yes................... Administrator can approve
requirements. alternative monitoring
procedures or
requirements.
Sec. 60.14....................... Modification.......... Yes (steam generating
units and IGCC
facilities) No
(stationary
combustion turbines)..
Sec. 60.15....................... Reconstruction........ Yes.
Sec. 60.16....................... Priority list......... No....................
Sec. 60.17....................... Incorporations by Yes.
reference.
Sec. 60.18....................... General control device No....................
requirements.
Sec. 60.19....................... General notification Yes................... Does not apply to
and reporting notifications under Sec.
requirements. 75.61 or to information
reported through ECMPS.
----------------------------------------------------------------------------------------------------------------
Subpart UUUUa--[Reserved]
0
16. Remove and reserve subpart UUUUa.
0
17. Add subpart UUUUb to read as follows:
Sec.
Subpart UUUUb--Emission Guidelines for Greenhouse Gas Emissions for
Electric Utility Generating Units
Introduction
60.5700b What is the purpose of this subpart?
60.5705b Which pollutants are regulated by this subpart?
60.5710b Am I affected by this subpart?
60.5715b What is the review and approval process for my State plan?
60.5720b What if I do not submit a State plan or my State plan is
not approvable?
60.5725b In lieu of a State plan submittal, are there other
acceptable option(s) for a State to meet its CAA section 111(d)
obligations?
60.5730b Is there an approval process for a negative declaration
letter?
State Plan Requirements
60.5740b What must I include in my federally enforceable State plan?
60.5775b What standards of performance must I include in my State
plan?
60.5780b What compliance dates and compliance periods must I include
in my State plan?
60.5785b What are the timing requirements for submitting my State
plan?
60.5790b What is the procedure for revising my State plan?
60.5795b Commitment to review emission guidelines for coal-fired
affected EGUs
Applicability of State Plans to Affected EGUs
60.5840b Does this subpart directly affect EGU owners or operators
in my State?
60.5845b What affected EGUs must I address in my State plan?
60.5850b What EGUs are excluded from being affected EGUs?
Recordkeeping and Reporting Requirements
60.5860b What applicable monitoring, recordkeeping, and reporting
requirements do I need to include in my State plan for affected
EGUs?
60.5865b What are my recordkeeping requirements?
60.5870b What are my reporting and notification requirements?
[[Page 40048]]
60.5875b How do I submit information required by these emission
guidelines to the EPA?
60.5876b What are the recordkeeping and reporting requirements for
EGUs that have committed to permanently cease operations by January
1, 2032?
Definitions
60.5880b What definitions apply to this subpart?
Subpart UUUUb--Emission Guidelines for Greenhouse Gas Emissions for
Electric Utility Generating Units
Introduction
Sec. [thinsp]60.5700b What is the purpose of this subpart?
This subpart establishes emission guidelines and approval criteria
for State plans that establish standards of performance limiting
greenhouse gas (GHG) emissions from an affected steam generating unit.
An affected steam generating unit shall, for the purposes of this
subpart, be referred to as an affected EGU. These emission guidelines
are developed in accordance with section 111(d) of the Clean Air Act
and subpart Ba of this part. State plans under the emission guidelines
in this subpart are also subject to the requirements of subpart Ba. To
the extent any requirement of this subpart is inconsistent with the
requirements of subparts A or Ba of this part, the requirements of this
subpart shall apply.
Sec. [thinsp]60.5705b Which pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases
(GHG). The emission guidelines for greenhouse gases established in this
subpart are expressed as carbon dioxide (CO2) emission
performance rates.
(b) PSD and Title V Thresholds for Greenhouse Gases.
(1) For the purposes of 40 CFR[thinsp]51.166(b)(49)(ii), with
respect to GHG emissions from facilities regulated in the State plan,
the ``pollutant that is subject to the standard promulgated under
section 111 of the Act'' shall be considered to be the pollutant that
otherwise is subject to regulation under the Act as defined in 40
CFR[thinsp]51.166(b)(48) and in any State Implementation Plan (SIP)
approved by the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR[thinsp]51.166(b)(48).
(2) For the purposes of 40 CFR[thinsp]52.21(b)(50)(ii), with
respect to GHG emissions from facilities regulated in the State plan,
the ``pollutant that is subject to the standard promulgated under
section 111 of the Act'' shall be considered to be the pollutant that
otherwise is subject to regulation under the Act as defined in 40
CFR[thinsp]52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from facilities regulated in the State plan, the ``pollutant
that is subject to any standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is
``subject to regulation'' as defined in 40 CFR[thinsp]70.2.
(4) For the purposes of 40 CFR[thinsp]71.2, with respect to GHG
emissions from facilities regulated in the State plan, the ``pollutant
that is subject to any standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is
``subject to regulation'' as defined in 40 CFR[thinsp]71.2.
Sec. [thinsp]60.5710b Am I affected by this subpart?
(a) If you are the Governor of a State in the contiguous United
States with one or more affected EGUs that must be addressed in your
State plan as indicated in Sec. [thinsp]60.5845b, you must submit a
State plan to the U.S. Environmental Protection Agency (EPA) that
implements the emission guidelines contained in this subpart. If you
are the Governor of a State in the contiguous United States with no
affected EGUs, or if all EGUs in your State are excluded from being
affected EGUs per Sec. [thinsp]60.5850b, you must submit a negative
declaration letter in place of the State plan.
(b) If you are a coal-fired steam generating unit that has
demonstrated that it plans to permanently cease operation prior to
January 1, 2032, consistent with Sec. 60.5740b(a)(9)(ii), and that
would be an affected EGU under these emissions guidelines but for Sec.
60.5850b(k), you must comply with Sec. 60.5876b.
Sec. [thinsp]60.5715b What is the review and approval process for my
State plan?
(a) The EPA will determine the completeness of your State plan
submission according to Sec. 60.27a(g). The timeline for completeness
determinations is provided in Sec. 60.27a(g)(1).
(b) The EPA will act on your State plan submission according to
Sec. 60.27a. The Administrator will have 12 months after the date the
final State plan or State plan revision (as allowed under Sec.
[thinsp]60.5790b) is found to be complete to fully approve, partially
approve, conditionally approve, partially disapprove, and/or fully
disapprove such State plan or revision or each portion thereof.
Sec. [thinsp]60.5720b What if I do not submit a State plan or my
State plan is not approvable?
(a) If you do not submit an approvable State plan the EPA will
develop a Federal plan for your State according to Sec.
[thinsp]60.27a. The Federal plan will implement the emission guidelines
contained in this subpart. Owners and operators of affected EGUs not
covered by an approved State plan must comply with a Federal plan
implemented by the EPA for the State.
(b) After a Federal plan has been implemented in your State, it
will be withdrawn when your State submits, and the EPA approves, a
State plan replacing the relevant portion(s) of the Federal plan.
Sec. [thinsp]60.5725b In lieu of a State plan submittal, are there
other acceptable option(s) for a State to meet its CAA section 111(d)
obligations?
A State may meet its CAA section 111(d) obligations only by
submitting a State plan or a negative declaration letter (if
applicable).
Sec. [thinsp]60.5730b Is there an approval process for a negative
declaration letter?
No. The EPA has no formal review process for negative declaration
letters. Once your negative declaration letter has been received,
consistent with the electronic submission requirements in Sec.
[thinsp]60.5875b, the EPA will place a copy in the public docket and
publish a notice in the Federal Register. If, at a later date, an
affected EGU for which construction commenced on or before January 8,
2014, reconstruction on or before June 18, 2014, or modification on or
before May 23, 2023, is found in your State, you will be found to have
failed to submit a State plan as required, and a Federal plan
implementing the emission guidelines contained in this subpart, when
promulgated by the EPA, will apply to that affected EGU until you
submit, and the EPA approves, a State plan.
State Plan Requirements
Sec. [thinsp]60.5740b What must I include in my federally enforceable
State plan?
(a) You must include the components described in paragraphs (a)(1)
through (13) of this section in your State plan submittal. The final
State plan must meet the requirements and include the information
required under Sec. [thinsp]60.5775b and must also meet any
administrative and technical completeness criteria listed in Sec.
[thinsp]60.27a(g)(2) and (3) that are not otherwise specifically
enumerated here.
(1) Identification of affected EGUs. Consistent with Sec.
[thinsp]60.25a(a), you must identify the affected EGUs covered by
[[Page 40049]]
your State plan and all affected EGUs in your State that meet the
applicability criteria in Sec. [thinsp]60.5845b. You must also
identify the subcategory into which you have classified each affected
EGU. States must subcategorize affected EGUs into one of the following
subcategories:
(i) Long-term coal-fired steam generating units, consisting of
coal-fired steam generating units that are not medium-term coal-fired
steam generating units and do not plan to permanently cease operation
before January 1, 2039.
(ii) Medium-term coal-fired steam generating units, consisting of
coal-fired steam generating units that have elected to commit to
permanently cease operations by a date after December 31, 2031, and
before January 1, 2039.
(iii) Base load oil-fired steam generating units, consisting of
oil-fired steam generating units with an annual capacity factor greater
than or equal to 45 percent.
(iv) Intermediate load oil-fired steam generating units, consisting
of oil-fired steam generating units with an annual capacity factor
greater than or equal to 8 percent and less than 45 percent.
(v) Low load oil-fired steam generating units, consisting of oil-
fired steam generating units with an annual capacity factor less than 8
percent.
(vi) Base load natural gas-fired steam generating units, consisting
of natural gas-fired steam generating units with an annual capacity
factor greater than or equal to 45 percent.
(vii) Intermediate load natural gas-fired steam generating units,
consisting of natural gas-fired steam generating units with an annual
capacity factor greater than or equal to 8 percent and less than 45
percent.
(viii) Low load natural gas-fired steam generating units,
consisting of natural gas-fired steam generating units with an annual
capacity factor less than 8 percent.
(2) Inventory of Data from Affected EGUs. You must include an
inventory of the following data from the affected EGUs:
(i) The nameplate capacity of the affected EGU, as defined in Sec.
60.5880b.
(ii) The base load rating of the affected EGU, as defined in Sec.
60.5880b.
(iii) The data within the continuous 5-year period immediately
prior to May 9, 2024 including:
(A) The sum of the CO2 emissions during each quarter in
the 5-year period.
(B) For affected EGUs in all subcategories except the low load
natural gas- and oil-fired subcategories, the sum of the gross energy
output during each quarter in the 5-year period; for affected EGUs in
the low load natural gas- and oil-fired subcategories, the sum of the
heat input during each quarter in the 5-year period.
(C) The heat input for each fuel type combusted during each quarter
in the 5-year period.
(D) The start date and end date of the most representative
continuous 8-quarter period used to determine the baseline of emission
performance under Sec. 60.5775b(d), the sum of the CO2 mass
emissions during that period, the sum of the gross energy output or,
for affected EGUs in the low load natural gas-fired subcategory or low
load oil-fired subcategory, the sum of the heat input during that
period, and sum of the heat input for each fuel type combusted during
that period.
(3) Standards of Performance. You must include all standards of
performance for each affected EGU according to Sec. 60.5775b.
Standards of performance must be established at a level of performance
that does not exceed the level calculated through the use of the
methods described in Sec. 60.5775b(b), unless a State establishes a
standard of performance pursuant to Sec. 60.5775b(e).
(4) Requirements related to Subcategory Applicability. (i) You must
include the following enforceable requirements to establish an affected
EGU's applicability for each of the following subcategories:
(A) For medium-term coal-fired steam generating units, you must
include a requirement to permanently cease operations by a date after
December 31, 2031, and before January 1, 2039.
(B) For steam generating units that meet the definition of natural
gas- or oil-fired, and that either retain the capability to fire coal
after May 9, 2024, that fired any coal during the 5-year period prior
to that date, or that will fire any coal after that date and before
January 1, 2030, you must include a requirement to remove the
capability to fire coal before January 1, 2030.
(C) For each affected EGU, you must also estimate coal, oil, and
natural gas usage by heat input for the first 3 calendar years after
January 1, 2030.
(D) For affected EGUs that plan to permanently cease operation, you
must include a requirement that each such affected EGU comply with
applicable State and Federal requirements for permanently ceasing
operation, including removal from its respective State's air emissions
inventory and amending or revoking all applicable permits to reflect
the permanent shutdown status of the EGU.
(5) Increments of Progress. You must include in your State plan
legally enforceable increments of progress as required elements for
affected EGUs in the long-term coal-fired steam generating unit and
medium-term coal-fired steam generating unit subcategories.
(i) For affected EGUs in the long-term coal-fired steam generating
unit subcategory using carbon capture to meet their applicable standard
of performance and affected EGUs in the medium-term coal-fired steam
generating unit subcategory using natural gas co-firing to meet their
applicable standard of performance, State plans must assign calendar-
date deadlines to each of the increments of progress described in
subsection (a)(5)(i) and meet the website reporting obligations of
subsection (a)(5)(iii):
(A) Submittal of a final control plan for the affected EGU to the
appropriate air pollution control agency. The final control plan must
be consistent with the subcategory declaration for each affected EGU in
the State plan.
(1) For each affected unit in the long-term coal-fired steam
generating unit subcategory, the final control plan must include
supporting analysis for the affected EGU's control strategy, including
a feasibility and/or front-end engineering and design (FEED) study.
(2) For each affected unit in the medium-term coal-fired steam
generating unit subcategory, the final control plan must include
supporting analysis for the affected EGU's control strategy, including
the design basis for modifications at the facility, the anticipated
timeline to achieve full compliance, and the benchmarks the facility
anticipates along the way.
(B) Completion of awarding of contracts. The owner or operator of
an affected EGU can demonstrate compliance with this increment of
progress by submitting sufficient evidence that the appropriate
contracts have been awarded.
(1) For each affected unit in the long-term coal-fired steam
generating unit subcategory, awarding of contracts for emission control
systems or for process modifications, or issuance of orders for the
purchase of component parts to accomplish emission control or process
modification.
(2) For each affected unit in the medium-term coal-fired steam
generating unit subcategory, awarding of contracts for boiler
modifications, or issuance of orders for the purchase of component
parts to accomplish boiler modifications.
(C) Initiation of on-site construction or installation of emission
control equipment or process change.
(1) For each affected unit in the long-term coal-fired steam
generating unit
[[Page 40050]]
subcategory, initiation of on-site construction or installation of
emission control equipment or process change required to achieve 90
percent carbon capture on an annual basis.
(2) For each affected unit in the medium-term coal-fired steam
generating unit subcategory, initiation of on-site construction or
installation of any boiler modifications necessary to enable natural
gas co-firing at a level of 40 percent on an annual average basis.
(D) Completion of on-site construction or installation of emission
control equipment or process change.
(1) For each affected unit in the long-term coal-fired steam
generating unit subcategory, completion of on-site construction or
installation of emission control equipment or process change required
to achieve 90 percent carbon capture on an annual basis.
(2) For each affected unit in the medium-term coal-fired steam
generating unit subcategory, completion of on-site construction of any
boiler modifications necessary to enable natural gas co-firing at a
level of 40 percent on an annual average basis.
(E) Commencement of permitting actions related to pipeline
construction. The owner or operator of an affected EGU must demonstrate
that they have commenced permitting actions by a date specified in the
State plan. Evidence in support of the demonstration must include
pipeline planning and design documentation that informed the permitting
process, a complete list of pipeline-related permitting applications,
including the nature of the permit sought and the authority to which
each permit application was submitted, an attestation that the list of
pipeline-related permits is complete with respect to the authorizations
required to operate each affected unit at full compliance with the
standard of performance, and a timeline to complete all pipeline
permitting activities.
(1) For affected units in the long-term coal-fired steam generating
unit subcategory, this increment of progress applies to each affected
EGU that adopts CCS to meet the standard of performance and ensure
timely completion of CCS-related pipeline infrastructure.
(2) For affected units in the medium-term coal-fired steam
generating unit subcategory, this increment of progress applies to each
affected EGU that adopts natural gas co-firing to meet the standard of
performance and ensures timely completion of any pipeline
infrastructure needed to transport natural gas to designated
facilities.
(F) For each affected unit in the long-term coal-fired steam
generating unit subcategory, a report identifying the geographic
location where CO2 will be injected underground, how the
CO2 will be transported from the capture location to the
storage location, and the regulatory requirements associated with the
sequestration activities, as well as an anticipated timeline for
completing related permitting activities.
(G) Compliance with the standard of performance as follows:
(1) For each affected unit in the medium-term coal-fired
subcategory, by January 1, 2030.
(2) For each affected unit in the long-term coal-fired steam
generating subcategory, by January 1, 2032.
(ii) For any affected unit in the long-term coal-fired steam
generating unit subcategory that will meet its applicable standard of
performance using a control other than CCS or in the medium-term coal-
fired steam generating unit subcategory that will meet its applicable
standard of performance using a control other than natural gas co-
firing:
(A) The State plan must include appropriate increments of progress
consistent with 40 CFR 60.21a(h) specific to the affected unit's
control strategy.
(1) The increment of progress corresponding to 40 CFR 60.21a(h)(1)
must be assigned the earliest calendar date among the increments.
(2) The increment of progress corresponding to 40 CFR 60.21a(h)(5)
must be assigned calendar dates as follows: for affected EGUs in the
long-term coal-fired steam generating subcategory, no later than
January 1, 2032; and for affected EGUs in the medium-term coal-fired
steam generating subcategory, no later than January 1, 2030.
(iii) The owner or operator of the affected EGU must post within 30
business days of the State plan submittal a description of the
activities or actions that constitute the increments of progress and
the schedule for achieving the increments of progress on the Carbon
Pollution Standards for EGUs website required by Sec. 60.5740b(a)(10).
As the calendar dates for each increment of progress occurs, the owner
or operator of the affected EGU must post within 30 business days any
documentation necessary to demonstrate that each increment of progress
has been met on the Carbon Pollution Standards for EGUs website
required by Sec. 60.5740b(a)(10).
(iv) You must include in your State plan a requirement that the
owner or operator of each affected EGU shall report to the State
regulatory agency any deviation from any federally enforceable State
plan increment of progress within 30 business days after the owner or
operator of the affected EGU knew or should have known of the event.
This report must explain the cause or causes of the deviation and
describe all measures taken or to be taken by the owner or operator of
the EGU to cure the reported deviation and to prevent such deviations
in the future, including the timeframes in which the owner or operator
intends to cure the deviation. You must also include in your State plan
a requirement that the owner or operator of the affected EGU to post a
report of any deviation from any federally enforceable increment of
progress on the Carbon Pollution Standards for EGUs website required by
Sec. 60.5740b(a)(10) within 30 business days.
(6) Reporting Obligations and Milestones for Affected EGUs that
Have Demonstrated They Plan to Permanently Cease Operations. You must
include in your State plan legally enforceable reporting obligations
and milestones for affected EGUs in the medium-term coal-fired steam
generating unit (Sec. 60.5740b(a)(1)(ii)) subcategory, and for
affected EGUs that invoke RULOF based on a unit's remaining useful life
according to paragraphs (a)(6)(i) through (v) of this section:
(i) Five years before the date the affected EGU permanently ceases
operations (either the date used to determine the applicable
subcategory under these emission guidelines or the date used to invoke
RULOF based on remaining useful life) or 60 days after State plan
submission, whichever is later, the owner or operator of the affected
EGU must submit an Initial Milestone Report to the applicable air
pollution control agency that includes the information in paragraphs
(a)(6)(i)(A) through (D) of this section:
(A) A summary of the process steps required for the affected EGU to
permanently cease operations by the date included in the State plan,
including the approximate timing and duration of each step and any
notification requirements associated with deactivation of the unit.
(B) A list of key milestones that will be used to assess whether
each process step has been met, and calendar day deadlines for each
milestone. These milestones must include at least the initial notice to
the relevant reliability authority or authorities of an EGU's
deactivation date and submittal of an official retirement filing with
the EGU's relevant reliability authority or authorities.
(C) An analysis of how the process steps, milestones, and
associated timelines included in the Milestone
[[Page 40051]]
Report compare to the timelines of similar EGUs within the State that
have permanently ceased operations within the 10 years prior to the
date of promulgation of these emission guidelines.
(D) Supporting regulatory documents, which include those listed in
paragraphs (a)(6)(i)(D)(1) through (3) of this section:
(1) Any correspondence and official filings with the relevant
Regional Transmission Organization (RTO), Independent System Operator,
Balancing Authority, Public Utilities Commission (PUC), or other
applicable authority;
(2) Any deactivation-related reliability assessments conducted by
the RTO or Independent System Operator;
(3) Any filings with the United States Securities and Exchange
Commission or notices to investors, including but not limited to, those
listed in paragraphs (a)(6)(i)(D)(3)(i) through (v) of this section.
(i) References in forms 10-K and 10-Q, in which the plans for the
EGU are mentioned;
(ii) Any integrated resource plans and PUC orders approving the
EGU's deactivation;
(iii) Any reliability analyses developed by the RTO, Independent
System Operator, or relevant reliability authority in response to the
EGU's deactivation notification;
(iv) Any notification from a relevant reliability authority that
the EGU may be needed for reliability purposes notwithstanding the
EGU's intent to deactivate; and
(v) Any notification to or from an RTO, Independent System
Operator, or Balancing Authority altering the timing of deactivation
for the EGU.
(ii) For each of the remaining years prior to the date by which an
affected EGU has committed to permanently cease operations that is
included in the State plan, the owner or operator of the affected EGU
must submit an annual Milestone Status Report that includes the
information in paragraphs (a)(6)(ii)(A) and (B) of this section:
(A) Progress toward meeting all milestones identified in the
Initial Milestone Report, described in Sec. 60.5740b(a)(6)(i); and
(B) Supporting regulatory documents and relevant SEC filings,
including correspondence and official filings with the relevant RTO,
Independent System Operator, Balancing Authority, PUC, or other
applicable authority to demonstrate compliance with or progress toward
all milestones.
(iii) No later than six months from the date the affected EGU
permanently ceases operations (either the date used to determine the
applicable subcategory under these emission guidelines or the date used
to invoke RULOF based on remaining useful life), the owner or operator
of the affected EGU must submit a Final Milestone Status Report. This
report must document any actions that the EGU has taken subsequent to
ceasing operation to ensure that such cessation is permanent, including
any regulatory filings with applicable authorities or decommissioning
plans.
(iv) The owner or operator of the affected EGU must post their
Initial Milestone Report, as described in paragraph (a)(6)(i) of this
section; annual Milestone Status Reports, as described in paragraph
(a)(6)(ii) of this section; and Final Milestone Status Report, as
described in paragraph (a)(6)(iii) of this section; including the
schedule for achieving milestones and any documentation necessary to
demonstrate that milestones have been achieved, on the Carbon Pollution
Standards for EGUs website required by paragraph (a)(10) of this
section within 30 business days of being filed.
(v) You must include in your State plan a requirement that the
owner or operator of each affected EGU shall report to the State
regulatory agency any deviation from any federally enforceable State
plan reporting milestone within 30 business days after the owner or
operator of the affected EGU knew or should have known of the event.
This report must explain the cause or causes of the deviation and
describe all measures taken or to be taken by the owner or operator of
the EGU to cure the reported deviation and to prevent such deviations
in the future, including the timeframes in which the owner or operator
intends to cure the deviation. You must also include in your State plan
a requirement that the owner or operator of the affected EGU to post a
report of any deviation from any federally enforceable reporting
milestone on the Carbon Pollution Standards for EGUs website required
by Sec. 60.5740b(a)(10) within 30 business days.
(7) Identification of applicable monitoring, reporting, and
recordkeeping requirements for each affected EGU. You must include in
your State plan all applicable monitoring, reporting and recordkeeping
requirements, including initial and ongoing quality assurance and
quality control procedures, for each affected EGU and the requirements
must be consistent with or no less stringent than the requirements
specified in Sec. 60.5860b.
(8) State reporting. You must include in your State plan a
description of the process, contents, and schedule for State reporting
to the EPA about State plan implementation and progress.
(9) Specific requirements for existing coal-fired steam generating
EGUs. Your State plan must include the requirements in paragraphs
(a)(9)(i) through (iii) of this section specifically for existing coal-
fired steam generating EGUs:
(i) Your State plan must require that any existing coal-fired
steam-generating EGU shall operate only subject to a standard of
performance pursuant to Sec. 60.5775b or under an exemption of
applicability provided under Sec. 60.5850b (including any extension of
the date by which an EGU has committed to cease operating pursuant to
the reliability assurance mechanism, described in paragraph (a)(13) of
this section).
(ii) You must include a list of the coal-fired steam generating
EGUs that are existing sources at the time of State plan submission and
that plan to permanently cease operation before January 1, 2032, and
the calendar dates by which they have committed to cease operating.
(iii) The State plan must provide that an existing coal-fired steam
generating EGU operating past the date listed in the State plan
pursuant to paragraph (a)(9)(ii) of this section is in violation of
that State plan, except to the extent the existing coal-fired steam
generating EGU has received an extension of its date for ceasing
operation pursuant to the reliability assurance mechanism, described in
paragraph (a)(13) of this section.
(10) Carbon Pollution Standards for EGUs Websites. You must require
in your State plan that owners or operators of affected EGUs establish
a publicly accessible ``Carbon Pollution Standards for EGUs Website''
and that they post relevant documents to this website. You must require
in your State plan that owners or operators of affected EGUs post their
subcategory designations and compliance schedules as well as any
emissions data and other information needed to demonstrate compliance
with a standard of performance to this website in a timely manner. This
information includes, but is not limited to, emissions data and other
information relevant to determining compliance with applicable
standards of performance, information relevant to the designation and
determination of compliance with increments of progress and reporting
obligations including milestones for affected EGUs that plan to
permanently cease operations, and any extension requests made and
[[Page 40052]]
granted pursuant to the compliance date extension mechanism or the
reliability assurance mechanism. Data should be available in a readily
downloadable format. In addition, you must establish a website that
displays the links to these websites for all affected EGUs in your
State plan.
(11) Compliance Date Extension. You may include in your State plan
provisions allowing for a compliance date extension for owners or
operators of affected EGU(s) that are installing add-on controls and
that are unable to meet the applicable standard of performance by the
compliance date specified in Sec. 60.5740b(a)(4)(i) due to
circumstances beyond the owner or operator's control. Such provisions
may allow an owner or operator of an affected EGU to request an
extension of no longer than one year from the specified compliance date
and may only allow the owner or operator to receive an extension once.
The optional State plan mechanism must provide that an extension
request contains a demonstration of necessity that includes the
following:
(i) A demonstration that the owner or operator of the affected EGU
cannot meet its compliance date due to circumstances beyond the owner
or operator's control and that the owner or operator has met all
relevant increments of progress and otherwise taken all steps
reasonably possible to install the controls necessary for compliance by
the specified compliance date up to the point of the delay. The
demonstration shall:
(A) Identify each affected unit for which the owner or operator is
seeking the compliance extension;
(B) Identify and describe the controls to be installed at each
affected unit to comply with the applicable standard of performance
pursuant to Sec. 60.5775b;
(C) Describe and demonstrate all progress towards installing the
controls and that the owner or operator has itself acted consistent
with achieving timely compliance, including:
(1) Any and all contract(s) entered into for the installation of
the identified controls or an explanation as to why no contract is
necessary or obtainable; and
(2) Any permit(s) obtained for the installation of the identified
controls or, where a required permit has not yet been issued, a copy of
the permit application submitted to the permitting authority and a
statement from the permit authority identifying its anticipated
timeframe for issuance of such permit(s).
(D) Identify the circumstances that are entirely beyond the owner
or operator's control and that necessitate additional time to install
the identified controls. This may include:
(1) Information gathered from control technology vendors or
engineering firms demonstrating that the necessary controls cannot be
installed or started up by the applicable compliance date listed in
Sec. 60.5740b(a)(4)(i);
(2) Documentation of any permit delays; or
(3) Documentation of delays in construction or permitting of
infrastructure (e.g., CO2 pipelines) that is necessary for
implementation of the control technology;
(E) Identify a proposed compliance date no later than one year
after the applicable compliance date listed in Sec. 60.5740b(a)(4)(i)
and, if necessary, updated calendar dates for the increments of
progress that have not yet been met.
(ii) The State air pollution control agency is charged with
approving or disapproving a compliance date extension request based on
its written determination that the affected EGU has or has not made
each of the necessary demonstrations and provided all of the necessary
documentation according to paragraphs (a)(11)(i)(A) through (E) of this
section. The following provisions for approval must be included in the
mechanism:
(A) All documentation required as part of this extension must be
submitted by the owner or operator of the affected EGU to the State air
pollution control agency no later than 6 months prior to the applicable
compliance date for that affected EGU.
(B) The owner or operator of the affected EGU must notify the
relevant EPA Regional Administrator of their compliance date extension
request at the time of the submission of the request.
(C) The owner or operator of the affected EGU must post their
application for the compliance date extension request to the Carbon
Pollution Standards for EGUs website, described in Sec.
60.5740b(a)(10), when they submit the request to the State air
pollution control agency.
(D) The owner or operator of the affected EGU must post the State's
determination on the compliance date extension request to the Carbon
Pollution Standards for EGUs website, described in Sec.
60.5740b(a)(10), upon receipt of the determination and, if the request
is approved, update the information on the website related to the
compliance date and increments of progress dates within 30 days of the
receipt of the State's approval.
(12) Short-Term Reliability Mechanism. You may include in your
State plan provisions for a short-term reliability mechanism for
affected EGUs in your State that operate during a system emergency, as
defined in Sec. 60.5880b. Such a mechanism must include the components
listed in paragraphs (a)(12)(i) through (vi) of this section.
(i) A requirement that the short-term reliability mechanism is
available only during system emergencies as defined in Sec. 60.5880b.
The State plan must identify the entity or entities that are authorized
to issue system emergencies for the State.
(ii) A provision that, for the duration of a documented system
emergency, an impacted affected EGU may comply with an emission
limitation corresponding to its baseline emission performance rate, as
calculated under Sec. 60.5775b(d), in lieu of its otherwise applicable
standard of performance. The State plan must clearly identify the
alternative emission limitation that corresponds to the affected EGU's
baseline emission rate and include it as an enforceable emission
limitation that may be applied only during periods of system emergency.
(iii) A requirement that an affected EGU impacted by the system
emergency and complying with an alternative emission limitation must
provide documentation, as part of its compliance demonstration, of the
system emergency according to (a)(12)(iii)(A) through (D) of this
section and that it was impacted by that system emergency.
(A) Documentation that the system emergency was in effect from the
entity issuing the system emergency and documentation of the exact
duration of the event;
(B) Documentation from the entity issuing the system emergency that
the system emergency included the affected source/region where the unit
was located;
(C) Documentation that the source was instructed to increase output
beyond the planned day-ahead or other near-term expected output and/or
was asked to remain in operation outside of its scheduled dispatch
during emergency conditions from a Reliability Coordinator, Balancing
Authority, or Independent System Operator/RTO; and
(D) Data collected during the event including the sum of the
CO2 emissions, the sum of the gross energy output, and the
resulting CO2 emissions performance rate.
(iv) A requirement to document the hours an affected EGU operated
under a system emergency and the enforceable emission limitation,
whether the applicable standard of performance or
[[Page 40053]]
the alternative emission limitation, under which that affected EGU
operated during those hours.
(v) A provision that, for the purpose of demonstrating compliance
with the applicable standard of performance, the affected EGU would
comply with its baseline emissions rate as calculated under Sec.
60.5775b(d) in lieu of its otherwise applicable standard of performance
for the hours of operation that correspond to the duration of the
event.
(vi) The inclusion of provisions defining the short-term
reliability mechanism must be part of the public comment process as
part of the State plan's development.
(13) Reliability Assurance Mechanism. You may include provisions
for a reliability assurance mechanism in your State plan. If included,
such provisions would allow for one extension, not to exceed 12-months
of the date by which an affected EGU has committed to permanently cease
operations based on a demonstration consistent with this paragraph
(a)(13) that operation of the affected EGU is necessary for electric
grid reliability.
(i) The State plan must require that the reliability assurance
mechanism would only be appliable to the following EGUs which, for the
purpose of this paragraph (a)(13), are collectively referred to as
``eligible EGUs'':
(A) Coal-fired steam generating units that are exempt from these
emission guidelines pursuant to Sec. 60.5850b(k),
(B) Affected EGUs in the medium-term coal-fired steam-generating
subcategory that have enforceable commitments to permanently cease
operation before January 1, 2039, in the State plan, and
(C) Affected EGUs that have enforceable dates to permanently cease
operation included in the State plan pursuant to Sec. 60.24a(g).
(ii)The date from which an extension would run is the date included
in the State plan by which an eligible EGU has committed to permanently
cease operation.
(iii) The State plan must provide that an extension is only
available to owners or operators of affected EGUs that have satisfied
all applicable increments of progress and reporting obligations and
milestones in paragraphs (a)(5) and (6) of this section. This includes
requiring that the owner or operator of an affected EGU has posted all
information relevant to such increments of progress and reporting
obligations and milestones on the Carbon Pollution Standards for EGUs
website, described in Sec. 60.5740b(a)(10).
(iv) The State plan must provide that any applicable standard of
performance for an affected EGU must remain in place during the
duration of an extension provided under this mechanism.
(v) The State plan may provide for requests for an extension of up
to 12 months without a State plan revision.
(A) For an extension of 6 months or less, the owner or operator of
the eligible EGU requesting the extension must submit the information
in paragraph (a)(13)(vi) to the applicable EPA Regional Administrator
to review and approve or disapprove the extension request.
(B) For an extension of more than 6 months and up to 12 months, the
owner or operator of the eligible EGU requesting the extension must
submit the information in paragraph (a)(13)(vii) to the Federal Energy
Regulatory Commission (through a process and at an office of the
Federal Energy Regulatory Commission's designation) and to the
applicable EPA Regional Administrator to review and approve or
disapprove the extension request.
(vi) The State plan must require that to apply for an extension for
6 months or less, described in paragraph (a)(13)(v)(A) of this section,
the owner or operator of an eligible EGU must submit a complete written
application that includes the information listed in paragraphs
(a)(13)(vi)(A) through (D) of this section no less than 30 days prior
to the cease operation date, but no earlier than 12 months prior to the
cease operation date.
(A) An analysis of the reliability risk that clearly demonstrates
that the eligible EGU is critical to maintaining electric reliability.
The analysis must include a projection of the length of time that the
EGU is expected to be reliability-critical and the length of the
requested extension must be no longer than this period or 6 months,
whichever is shorter. In order to show an approvable reliability need,
the analysis must clearly demonstrate that an eligible EGU ceasing
operation by the date listed in the State plan would cause one or more
of the conditions listed in paragraphs (a)(13)(vi)(A)(1) or (2) of this
section. An eligible EGU that has received a Reliability Must Run
designation, or equivalent from a Reliability Coordinator or Balancing
Authority, would fulfill those conditions.
(1) Result in noncompliance with at least one of the mandatory
reliability standards approved by FERC; or
(2) Would cause the loss of load expectation to increase beyond the
level targeted by regional system planners as part of their established
procedures for that particular region; specifically, this requires a
clear demonstration that the eligible EGU would be needed to maintain
the targeted level of resource adequacy.
(B) Certification from the relevant reliability planning authority
that the claims of reliability risk are accurate and that the
identified reliability problem both exists and requires the specific
relief requested. This certification must be accompanied by a written
analysis by the relevant planning authority consistent with paragraph
(a)(13)(vi)(A) of this section, confirming the asserted reliability
risk if the eligible EGU was not in operation. The information from the
relevant reliability planning authority must also include any related
system-wide or regional analysis and a substantiation of the length of
time that the eligible EGU is expected to be reliability critical.
(C) Copies of any written comments from third parties regarding the
extension.
(D) Demonstration from the owner or operator of the eligible EGU,
grid operator, and other relevant entities of a plan, including
appropriate actions to bring on new capacity or transmission, to
resolve the underlying reliability issue is leading to the need to
employ this reliability assurance mechanism, including the steps and
timeframes for implementing measures to rectify the underlying
reliability issue.
(E) Any other information requested by the applicable EPA Regional
Administrator or the Federal Energy Regulatory Commission.
(vii) The State plan must require that to apply for an extension
longer than 6 months but up to 12 months, described in paragraph
(a)(13)(v)(B) of this section, the owner or operator of an eligible EGU
must submit a complete written application that includes the
information listed in (a)(13)(vi)(A) through (E) of this section,
except that the period of time under (a)(13)(vi)(A) would be 12 months.
For requests for extensions longer than 6 months, this application must
be submitted to the EPA Regional Administrator no less than 45 days
prior to the date for ceasing operation listed in the State plan, but
no earlier than 12 months prior to that date.
(viii) The State plan must provide that extensions will only be
granted for the period of time that is substantiated by the reliability
need and the submitted analysis and documentation, and shall not exceed
12 months in total.
(ix) The State plan must provide that the reliability assurance
mechanism shall not be used more than once to
[[Page 40054]]
extend an eligible EGU's planned cease operation date.
(x) The EPA Regional Administrator may reject the application if
the submission is incomplete with respect to the requirements listed in
paragraphs (a)(13)(vi)(A) through (E) of this section or if the
submission does not adequately support the asserted reliability risk or
the period of time for which the eligible EGU is anticipated to be
reliability critical.
(b) [Reserved]
Sec. 60.5775b What standards of performance must I include in my
State plan?
(a) For each affected EGU, your State plan must include the
standard of performance that applies for the affected EGU. A standard
of performance for an affected EGU may take the following forms:
(1) A rate-based standard of performance for an individual affected
EGU that does not exceed the level calculated through the use of the
methods described in Sec. 60.5775b(c) and (d).
(2) A standard of performance in an alternate form, which may apply
for affected EGUs in the long-term coal-fired steam generating unit
subcategory or the medium-term coal-fired steam generating unit
subcategory, as provided for in Sec. 60.5775b(e).
(b) Standard(s) of performance for affected EGUs included under
your State plan must be demonstrated to be quantifiable, verifiable,
non-duplicative, permanent, and enforceable with respect to each
affected EGU. The State plan submittal must include the methods by
which each standard of performance meets each of the following
requirements:
(1) An affected EGU's standard of performance is quantifiable if it
can be reliably measured in a manner that can be replicated.
(2) An affected EGU's standard of performance is verifiable if
adequate monitoring, recordkeeping and reporting requirements are in
place to enable the State and the Administrator to independently
evaluate, measure, and verify compliance with the standard of
performance.
(3) An affected EGU's standard of performance is non-duplicative
with respect to a State plan if it is not already incorporated as an
standard of performance in the State plan.
(4) An affected EGU's standard of performance is permanent if the
standard of performance must be met continuously unless it is replaced
by another standard of performance in an approved State plan revision.
(5) An affected EGU's standard of performance is enforceable if:
(i) A technically accurate limitation or requirement, and the time
period for the limitation or requirement, are specified;
(ii) Compliance requirements are clearly defined;
(iii) The affected EGUs are responsible for compliance and liable
for violations identified;
(iv) Each compliance activity or measure is enforceable as a
practical matter, as defined by 40 CFR 49.167; and
(v) The Administrator, the State, and third parties maintain the
ability to enforce against violations (including if an affected EGU
does not meet its standard of performance based on its emissions) and
secure appropriate corrective actions: in the case of the
Administrator, pursuant to CAA sections 113(a)-(h); in the case of a
State, pursuant to its State plan, State law or CAA section 304, as
applicable; and in the case of third parties, pursuant to CAA section
304.
(c) Methodology for establishing presumptively approvable standards
of performance, for affected EGUs in each subcategory.
(1) Long-term coal-fired steam generating units
(i) BSER is CCS with 90 percent capture of CO2.
(ii) Degree of emission limitation is 88.4 percent reduction in
emission rate (lb CO2/MWh-gross).
(iii) Presumptively approvable standard of performance is an
emission rate limit defined by an 88.4 percent reduction in annual
emission rate (lb CO2/MWh-gross) from the unit-specific
baseline.
(2) Medium-term coal-fired steam generating units
(i) BSER is natural gas co-firing at 40 percent of the heat input
to the unit.
(ii) Degree of emission limitation is a 16 percent reduction in
emission rate (lb CO2/MWh-gross).
(iii) Presumptively approvable standard of performance is an
emission rate limit defined by a 16 percent reduction in annual
emission rate (lb CO2/MWh-gross) from the unit-specific
baseline.
(iv) For units in this subcategory that have an amount of co-firing
that is reflected in the baseline operation, States must account for
such preexisting co-firing in adjusting the degree of emission
limitation (e.g., for an EGU co-fires natural gas at a level of 10
percent of the total annual heat input during the applicable 8-quarter
baseline period, the corresponding degree of emission limitation would
be adjusted to 12 percent to reflect the preexisting level of natural
gas co-firing).
(3) Base load oil-fired steam generating units.
(i) BSER is routine methods of operation and maintenance.
(ii) Degree of emission limitation is a 0 percent increase in
emission rate (lb CO2/MWh-gross).
(iii) Presumptively approvable standard of performance is an annual
emission rate limit of 1,400 lb CO2/MWh-gross.
(4) Intermediate load oil-fired steam generating units.
(i) BSER is routine methods of operation and maintenance.
(ii) Degree of emission limitation is a 0 percent increase in
emission rate (lb CO2/MWh-gross).
(iii) Presumptively approvable standard of performance is an annual
emission rate limit of 1,600 lb CO2/MWh-gross.
(5) Low load oil-fired steam generating units.
(i) BSER is uniform fuels.
(ii) Degree of emission limitation is 170 lb CO2/MMBtu.
(iii) Presumptively approvable standard of performance is an annual
emission rate limit of 170 lb CO2/MMBtu.
(6) Base load natural gas-fired steam generating units.
(i) BSER is routine methods of operation and maintenance.
(ii) Degree of emission limitation is a 0 percent increase in
emission rate (lb CO2/MWh-gross).
(iii) Presumptively approvable standard of performance is an annual
emission rate limit of 1,400 lb CO2/MWh-gross.
(7) Intermediate load natural gas-fired steam generating units.
(i) BSER is routine methods of operation and maintenance.
(ii) Degree of emission limitation is a 0 percent increase in
emission rate (lb CO2/MWh-gross).
(iii) Presumptively approvable standard of performance is an annual
emission rate limit of 1,600 lb CO2/MWh-gross.
(8) Low load natural gas-fired steam generating.
(i) BSER is uniform fuels.
(ii) Degree of emission limitation is 130 lb CO2/MMBtu.
(iii) Presumptively approvable standard of performance is an annual
emission rate limit of 130 lb CO2/MMBtu.
(d) Methodology for establishing the unit-specific baseline of
emission performance.
(1) A State shall use the CO2 mass emissions and
corresponding electricity
[[Page 40055]]
generation or, for affected EGUs in the low load oil- or natural gas-
fired subcategory, heat input data for a given affected EGU from the
most representative continuous 8-quarter period from 40 CFR part 75
reporting within the 5-year period immediately prior to May 9, 2024.
(2) For the continuous 8 quarters of data, a State shall divide the
total CO2 emissions (in the form of pounds) over that
continuous time period by either the total gross electricity generation
(in the form of MWh) or, for affected EGUs in the low load oil- or
natural gas-fired subcategory, total heat input (in the form of MMBtu)
over that same time period to calculate baseline CO2
emission performance in lb CO2 per MWh or lb CO2
per MMBtu.
(e) Your State plan may include a standard of performance in an
alternate form that differs from the presumptively approvable standard
of performance specified in Sec. 60.5775b(a)(1), as follows:
(1) An aggregate rate-based standard of performance (lb
CO2/MWh-gross) that applies for a group of affected EGUs
that share the same owner or operator, as calculated on a gross
generation weighted average basis, provided the standard of performance
meets the requirements of paragraph (f) of this section.
(2) A mass-based standard of performance in the form of an annual
limit on allowable mass CO2 emissions for an individual
affected EGU, provided the standard of performance meets the
requirements of paragraph (g) of this section.
(3) A rate-based standard of performance (lb CO2/MWh-
gross) implemented through a rate-based emission trading program, such
that an affected EGU must meet the specified lb CO2/MWh-
gross rate that applies for the affected EGU, and where an affected EGU
may surrender compliance instruments denoted in 1 short ton of
CO2 to adjust its reported lb CO2/MWh-gross rate
for the purpose of demonstrating compliance, provided the standard of
performance meets the requirements of paragraph (h) of this section.
(4) A mass-based standard of performance in the form of an annual
CO2 budget implemented through a mass-based CO2
emission trading program, where an affected EGU must surrender
CO2 allowances in an amount equal to its reported mass
CO2 emissions, provided the standard of performance meets
the requirements of paragraph (i) of this section.
(f) Where your State plan includes a standard of performance in the
form of an aggregate rate-based standard of performance (lb
CO2/MWh-gross) that applies for a group of affected EGUs
that share the same owner or operator, as calculated on a gross
generation weighted average basis, your State plan must include:
(1) The presumptively approvable rate-based standard of performance
(lb CO2/MWh-gross) that would apply under paragraph (a)(1)
of this section, and as determined in accordance with paragraphs (c)
and (d) of this section, to each of the affected EGUs that form the
group.
(2) Documentation of any assumptions underlying the calculation of
the aggregate rate-based standard of performance (lb CO2/
MWh-gross).
(3) The process for calculating the aggregate gross generation
weighted average emission rate (lb CO2/MWh-gross) at the end
of each compliance period, based on the reported emissions (lb
CO2) and utilization (MWh-gross) of each of the affected
EGUs that form the group.
(4) Measures to implement and enforce the annual aggregate rate-
based standard of performance, including the basis for determining
owner or operator compliance with the aggregate standard of performance
and provisions to address any changes to owners or operators in the
course of implementation.
(5) A demonstration of how the application of the aggregate rate-
based standard of performance will achieve equivalent or better
emission reduction as would be achieved through the application of a
rate-based standard of performance (lb CO2/MWh-gross) that
would apply pursuant to paragraph (a)(1) of this section, and as
determined in accordance with paragraphs (c) and (d) of this section.
(g) Where your State plan includes a standard of performance in the
form of an annual limit on allowable mass CO2 emissions for
an individual affected EGU, your State plan must include:
(1) The presumptively approvable rate-based standard of performance
(lb CO2/MWh-gross) that would apply to the affected EGU
under paragraph (a)(1) of this section, and as determined in accordance
with paragraphs (c) and (d) of this section.
(2) The utilization level used to calculate the mass CO2
limit, by multiplying the assumed utilization level (MWh-gross) by the
presumptively approvable rate-based standard of performance (lb
CO2/MWh-gross), including the underlying data used for the
calculation and documentation of any assumptions underlying this
calculation.
(3) Measures to implement and enforce the annual limit on mass
CO2 emissions, including provisions that address assurance
of achievement of equivalent emission performance.
(4) A demonstration of how the application of the mass
CO2 limit for the affected EGU will achieve equivalent or
better emission reduction as would be achieved through the application
of a rate-based standard of performance (lb CO2/MWh-gross)
that would apply pursuant to paragraph (a)(1) of this section, and as
determined in accordance with paragraphs (c) and (d) of this section.
(5) The backstop rate-based emission rate requirement (lb
CO2/MWh-gross) that will also be applied to the affected EGU
on an annual basis.
(6) For affected EGUs in the long-term coal-fired steam generating
unit subcategory, in lieu of paragraphs (g)(2), (4), and (5) of this
section, you may include a presumptively approvable mass CO2
limit based on the product of the rate-based standard of performance
(lb CO2/MWh-gross) under paragraph (a)(1) of this section
multiplied by a level of utilization (MWh-gross) corresponding to an
annual capacity factor of 80 percent for the individual affected EGU
with a backstop rate-based emission rate requirement equivalent to a
reduction in baseline emission performance of 80 percent on an annual
calendar-year basis.
(h) Where your State plan includes a standard of performance in the
form of a rate-based standard of performance (lb CO2/MWh-
gross) implemented through a rate-based emission trading program, your
State plan must include:
(1) The presumptively approvable rate-based standard of performance
(lb CO2/MWh-gross) that applies to each of the affected EGUs
participating in the rate-based emission trading program under
paragraph (a)(1) of this section, and as determined in accordance with
paragraphs (c) and (d) of this section.
(2) Measures to implement and enforce the rate-based emission
trading program, including the basis for awarding compliance
instruments (denoted in 1 ton of CO2) to an affected EGU
that performs better on an annual basis than its rate-based standard of
performance, and the process for demonstration of compliance that
includes the surrender of such compliance instruments by an affected
EGU that exceeds its rate-based standard of performance.
(3) A demonstration of how the use of the rate-based emission
trading program will achieve equivalent or better emission reduction as
would be achieved through the application of a
[[Page 40056]]
rate-based standard of performance (lb CO2/MWh-gross) that
would apply pursuant to paragraph (a)(1) of this section, and as
determined in accordance with paragraphs (c) and (d) of this section.
(i) Where your State plan includes a mass-based standard of
performance implemented through a mass-based CO2 emission
trading program, where an affected EGU must surrender CO2
allowances in an amount equal to its reported mass CO2
emissions, your State plan must include:
(1) The presumptively approvable rate-based standard of performance
(lb CO2/MWh-gross) that would apply to each affected EGU
participating in the trading program under paragraph (a)(1) of this
section, and as determined in accordance with paragraphs (c) and (d) of
this section.
(2) The calculation of the mass CO2 budget contribution
for each participating affected EGU, determined by multiplying the
assumed utilization level (MWh-gross) of the affected EGU by its
presumptively approvable rate-based standard of performance (lb
CO2/MWh-gross), including the underlying data used for the
calculation and documentation of any assumptions underlying this
calculation.
(3) Measures to implement and enforce the annual budget of the
mass-based CO2 emission trading program, including
provisions that address assurance of achievement of equivalent emission
performance.
(4) A demonstration of how the application of the CO2
emission budget for the group of participating affected EGUs will
achieve equivalent or better emission performance as would be achieved
through the application of a rate-based standard of performance (lb
CO2/MWh-gross) that would apply to each participating
affected EGU under paragraph (a)(1) of this section, and as determined
in accordance with paragraphs (c) and (d) of this section.
(5) The backstop rate-based emission rate requirement (lb
CO2/MWh-gross) that will also be applied to each
participating affected EGU on an annual basis.
(j) In order to use the provisions of Sec. 60.24a(e) through (h)
to apply a less stringent standard of performance or longer compliance
schedule to an affected EGU based on consideration of electric grid
reliability, including resource adequacy, under these emission
guidelines, a State must provide the following with its State plan
submission:
(1) An analysis of the reliability risk clearly demonstrating that
the particular affected EGU is critical to maintaining electric
reliability such that requiring it to comply with the applicable
requirements under paragraph (c) of this section or Sec. 60.5780b
would trigger non-compliance with at least one of the mandatory
reliability standards approved by the Federal Energy Regulatory
Commission or would cause the loss of load expectation to increase
beyond the level targeted by regional system planners as part of their
established procedures for that particular region; specifically, a
clear demonstration is required that the particular affected EGU would
be needed to maintain the targeted level of resource adequacy. The
analysis must also include a projection of the period of time for which
the particular affected EGU is expected to be reliability critical and
substantiate the basis for applying a less stringent standard of
performance or longer compliance schedule consistent with 40 CFR
60.24a(e).
(2) An analysis by the relevant reliability planning authority that
corroborates the asserted reliability risk identified in the analysis
under paragraph (j)(1) of this section and confirms that requiring the
particular affected EGU to comply with its applicable requirements
under paragraph (c) of this section or Sec. 60.5780b would trigger
non-compliance with at least one of the mandatory reliability standards
approved by the Federal Energy Regulatory Commission or would cause the
loss of load expectation to increase beyond the level targeted by
regional system planners as part of their established procedures for
that particular region, and also confirms the period of time for which
the EGU is projected to be reliability critical.
(3) A certification from the relevant reliability planning
authority that the claims of reliability risk are accurate and that the
identified reliability problem both exists and requires the specific
relief requested.
Sec. 60.5780b What compliance dates and compliance periods must I
include in my State plan?
(a) The State plan must include the following compliance dates:
(1) For affected EGUs in the long-term coal-fired subcategory, the
State plan must require compliance with the applicable standards of
performance starting no later than January 1, 2032, unless the State
has applied a later compliance date pursuant to Sec. 60.24a(e) through
(h).
(2) For affected EGUs in the medium-term coal-fired subcategory,
the base load oil-fired subcategory, the intermediate load oil-fired
steam generating subcategory, the low load oil-fired subcategory, the
base load natural gas-fired subcategory, the intermediate load natural
gas-fired subcategory, and the low load natural gas-fired subcategory,
the State plan must require compliance with the applicable standards of
performance starting no later than January 1, 2030, unless State has
applied a later compliance date pursuant to Sec. 60.24a(e) through
(h).
(b) The State plan must require affected EGUs to achieve compliance
with their applicable standards of performance for each compliance
period as defined in Sec. 60.5880b.
Sec. 60.5785b What are the timing requirements for submitting my
State plan?
(a) You must submit a State plan or a negative declaration letter
with the information required under Sec. 60.5740b by May 11, 2026.
(b) You must submit all information required under paragraph (a) of
this section according to the electronic reporting requirements in
Sec. 60.5875b.
Sec. 60.5790b What is the procedure for revising my State plan?
EPA-approved State plans can be revised only with approval by the
Administrator. The Administrator will approve a State plan revision if
it is satisfactory with respect to the applicable requirements of this
subpart and all applicable requirements of subpart Ba of this part. If
one (or more) of State plan elements in Sec. 60.5740b require
revision, the State must submit a State plan revision pursuant to Sec.
60.28a.
Sec. 60.5795b Commitment to review emission guidelines for coal-fired
affected EGUs
EPA will review and, if appropriate, revise these emission
guidelines as they apply to coal-fired steam generating affected EGUs
by January 1, 2041. Notwithstanding this commitment, EPA need not
review these emission guidelines if the Administrator determines that
such review is not appropriate in light of readily available
information on their continued appropriateness.
Applicability of State Plans to Affected EGUs
Sec. 60.5840b Does this subpart directly affect EGU owners or
operators in my State?
(a) This subpart does not directly affect EGU owners or operators
in your State, except as provided in Sec. 60.5710b(b). However,
affected EGU owners or operators must comply with the State plan that a
State develops to
[[Page 40057]]
implement the emission guidelines contained in this subpart.
(b) If a State does not submit a State plan to implement and
enforce the standards of performance contained in this subpart by May
11, 2026, or the EPA disapproves State plan, the EPA will implement and
enforce a Federal plan, as provided in Sec. 60.5720b, applicable to
each affected EGU within the State.
Sec. 60.5845b What affected EGUs must I address in my State plan?
(a) The EGUs that must be addressed by your State plan are:
(1) Any affected EGUs that were in operation or had commenced
construction on or before January 8, 2014;
(2) Coal-fired steam generating units that commenced a modification
on or before May 23, 2023.
(b) An affected EGU is a steam generating unit that meets the
relevant applicability conditions specified in paragraphs (b)(1)
through (2) of this section, as applicable, except as provided in Sec.
60.5850b.
(1) Serves a generator capable of selling greater than 25 MW to a
utility power distribution system; and
(2) Has a base load rating (i.e., design heat input capacity)
greater than 260 GJ/hr (250 MMBtu/hr) heat input of fossil fuel (either
alone or in combination with any other fuel).
Sec. 60.5850b What EGUs are excluded from being affected EGUs?
EGUs that are excluded from being affected EGUs are:
(a) New or reconstructed steam generating units that are subject to
subpart TTTT of this part as a result of commencing construction after
the subpart TTTT applicability date;
(b) Modified natural gas- or oil-fired steam generating units that
are subject to subpart TTTT of this part as a result of commencing
modification after the subpart TTTT applicability date;
(c) Modified coal-fired steam generating units that are subject to
subpart TTTTa of this part as a result of commencing modification after
the subpart TTTTa applicability date;
(d) EGUs subject to a federally enforceable permit limiting net-
electric sales to one-third or less of their potential electric output
or 219,000 MWh or less on an annual basis and annual net-electric sales
have never exceeded one-third or less of their potential electric
output or 219,000 MWh;
(e) Non-fossil fuel units (i.e., units that are capable of deriving
at least 50 percent of heat input from non-fossil fuel at the base load
rating) that are subject to a federally enforceable permit limiting
fossil fuel use to 10 percent or less of the annual capacity factor;
(f) CHP units that are subject to a federally enforceable permit
limiting annual net-electric sales to no more than either 219,000 MWh
or the product of the design efficiency and the potential electric
output, whichever is greater;
(g) Units that serve a generator along with other EGUs, where the
effective generation capacity (determined based on a prorated output of
the base load rating of each EGU) is 25 MW or less;
(h) Municipal waste combustor units subject to 40 CFR part 60,
subpart Eb;
(i) Commercial or industrial solid waste incineration units that
are subject to 40 CFR part 60, subpart CCCC; or
(j) EGUs that derive greater than 50 percent of the heat input from
an industrial process that does not produce any electrical or
mechanical output or useful thermal output that is used outside the
affected EGU.
(k) Existing coal-fired steam generating units that have
demonstrated that they plan to permanently cease operations before
January 1, 2032, pursuant to Sec. 60.5740b(a)(9)(ii).
Recordkeeping and Reporting Requirements
Sec. 60.5860b What applicable monitoring, recordkeeping, and
reporting requirements do I need to include in my State plan for
affected EGUs?
(a) Your State plan must include monitoring for affected EGUs that
is no less stringent than what is described in (a)(1) through (9) of
this section.
(1) The owner or operator of an affected EGU (or group of affected
EGUs that share a monitored common stack) that is required to meet
standards of performance must prepare a monitoring plan in accordance
with the applicable provisions in 40 CFR 75.53(g) and (h), unless such
a plan is already in place under another program that requires
CO2 mass emissions to be monitored and reported according to
40 CFR part 75.
(2) For rate-based standards of performance, only ``valid operating
hours,'', i.e., full or partial unit (or stack) operating hours for
which:
(i) ``Valid data'' (as defined in Sec. 60.5880b) are obtained for
all of the parameters used to determine the hourly CO2 mass
emissions (lbs). For the purposes of this subpart, substitute data
recorded under part 75 of this chapter are not considered to be valid
data; data obtained from flow monitoring bias adjustments are not
considered to be valid data; and data provided or not provided from
monitoring instruments that have not met the required frequency for
relative accuracy audit testing are not considered to be valid data and
(ii) The corresponding hourly gross energy output value is also
valid data (Note: For operating hours with no useful output, zero is
considered to be a valid value).
(3) For rate-based standards of performance, the owner or operator
of an affected EGU must measure and report the hourly CO2
mass emissions (lbs) from each affected unit using the procedures in
paragraphs (a)(3)(i) through (vi) of this section, except as otherwise
provided in paragraph (a)(4) of this section.
(i) The owner or operator of an affected EGU must install, certify,
operate, maintain, and calibrate a CO2 continuous emissions
monitoring system (CEMS) to directly measure and record CO2
concentrations in the affected EGU exhaust gases emitted to the
atmosphere and an exhaust gas flow rate monitoring system according to
40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of
CO2 concentration, provided that the affected EGU does not
use carbon separation (e.g., carbon capture and storage (CCS)), the
owner or operator of an affected EGU may use data from a certified
oxygen (O2) monitor to calculate hourly average
CO2 concentrations, in accordance with 40 CFR
75.10(a)(3)(iii). However, when an O2 monitor is used this
way, it only quantifies the combustion CO2; therefore, if
the EGU is equipped with emission controls that produce non-combustion
CO2 (e.g., from sorbent injection), this additional
CO2 must be accounted for, in accordance with section 3 of
appendix G to part 75 of this chapter. If CO2 concentration
is measured on a dry basis, the owner or operator of the affected EGU
must also install, certify, operate, maintain, and calibrate a
continuous moisture monitoring system, according to 40 CFR 75.11(b).
Alternatively, the owner or operator of an affected EGU may either use
an appropriate fuel-specific default moisture value from 40 CFR
75.11(b) or submit a petition to the Administrator under 40 CFR 75.66
for a site-specific default moisture value.
(ii) For each ``valid operating hour'' (as defined in paragraph
(a)(2) of this section), calculate the hourly CO2 mass
emission rate (tons/hr), either from Equation F-11 in appendix F to 40
CFR part 75 (if CO2 concentration is measured on a wet
basis), or by following the procedure in section 4.2 of appendix F to
40 CFR part 75 (if CO2
[[Page 40058]]
concentration is measured on a dry basis).
(iii) Next, multiply each hourly CO2 mass emission rate
by the EGU or stack operating time in hours (as defined in 40 CFR
72.2), to convert it to tons of CO2. Multiply the result by
2,000 lbs/ton to convert it to lbs.
(iv) The hourly CO2 tons/hr values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under 40 CFR 75.57(e) and must be reported
electronically under 40 CFR 75.64(a)(6), if required by a State plan.
The owner or operator must use these data, or equivalent data, to
calculate the hourly CO2 mass emissions.
(v) Sum all of the hourly CO2 mass emissions values from
paragraph (a)(3)(ii) of this section.
(vi) For each continuous monitoring system used to determine the
CO2 mass emissions from an affected EGU, the monitoring
system must meet the applicable certification and quality assurance
procedures in 40 CFR 75.20 and appendices A and B to 40 CFR part.
(4) The owner or operator of an affected EGU that exclusively
combusts liquid fuel and/or gaseous fuel may, as an alternative to
complying with paragraph (a)(3) of this section, determine the hourly
CO2 mass emissions according to paragraphs (a)(4)(i) through
(a)(4)(vi) of this section.
(i) Implement the applicable procedures in appendix D to part 75 of
this chapter to determine hourly EGU heat input rates (MMBtu/hr), based
on hourly measurements of fuel flow rate and periodic determinations of
the gross calorific value (GCV) of each fuel combusted. The fuel flow
meter(s) used to measure the hourly fuel flow rates must meet the
applicable certification and quality-assurance requirements in sections
2.1.5 and 2.1.6 of appendix D to 40 CFR part 75 (except for qualifying
commercial billing meters). The fuel GCV must be determined in
accordance with section 2.2 or 2.3 of appendix D to 40 CFR part 75, as
applicable.
(ii) For each measured hourly heat input rate, use Equation G-4 in
appendix G to 40 CFR part 75 to calculate the hourly CO2
mass emission rate (tons/hr).
(iii) For each ``valid operating hour'' (as defined in paragraph
(a)(2) of this section), multiply the hourly tons/hr CO2
mass emission rate from paragraph (a)(4)(ii) of this section by the EGU
or stack operating time in hours (as defined in 40 CFR 72.2), to
convert it to tons of CO2. Then, multiply the result by
2,000 lbs/ton to convert it to lbs.
(iv) The hourly CO2 tons/hr values and EGU (or stack)
operating times used to calculate CO2 mass emissions are
required to be recorded under 40 CFR 75.57(e) and must be reported
electronically under 40 CFR 75.64(a)(6), if required by a State plan.
You must use these data, or equivalent data, to calculate the hourly
CO2 mass emissions.
(v) Sum all of the hourly CO2 mass emissions values (lb)
from paragraph (a)(4)(iii) of this section.
(vi) The owner or operator of an affected EGU may determine site-
specific carbon-based F-factors (Fc) using Equation F-7b in
section 3.3.6 of appendix F to 40 CFR part 75 and may use these
Fc values in the emissions calculations instead of using the
default Fc values in the Equation G-4 nomenclature.
(5) For rate-based standards, the owner or operator of an affected
EGU (or group of affected units that share a monitored common stack)
must install, calibrate, maintain, and operate a sufficient number of
watt meters to continuously measure and record on an hourly basis gross
electric output. Measurements must be performed using 0.2 accuracy
class electricity metering instrumentation and calibration procedures
as specified under ANSI No. C12.20-2010 (incorporated by reference, see
Sec. 60.17). Further, the owner or operator of an affected EGU that is
a combined heat and power facility must install, calibrate, maintain,
and operate equipment to continuously measure and record on an hourly
basis useful thermal output and, if applicable, mechanical output,
which are used with gross electric output to determine gross energy
output. The owner or operator must use the following procedures to
calculate gross energy output, as appropriate for the type of affected
EGU(s).
(i) Determine Pgross/net the hourly gross or net energy
output in MWh. For rate-based standards, perform this calculation only
for valid operating hours (as defined in paragraph (a)(2) of this
section). For mass-based standards, perform this calculation for all
unit (or stack) operating hours, i.e., full or partial hours in which
any fuel is combusted.
(ii) If there is no net electrical output, but there is mechanical
or useful thermal output, either for a particular valid operating hour
(for rate-based applications), or for a particular operating hour (for
mass-based applications), the owner or operator of the affected EGU
must still determine the net energy output for that hour.
(iii) For rate-based applications, if there is no (i.e., zero)
gross electrical, mechanical, or useful thermal output for a particular
valid operating hour, that hour must be used in the compliance
determination. For hours or partial hours where the gross electric
output is equal to or less than the auxiliary loads, net electric
output shall be counted as zero for this calculation.
(iv) Calculate Pgross/net for your affected EGU (or
group of affected EGUs that share a monitored common stack) using the
following equation. All terms in the equation must be expressed in
units of MWh. To convert each hourly gross or net energy output value
reported under 40 CFR part 75 to MWh, multiply by the corresponding EGU
or stack operating time.
Equation 1 to Paragraph (a)(5)(iv)
[GRAPHIC] [TIFF OMITTED] TR09MY24.062
Where:
PGROSS/NET = Gross or net energy output of your affected
EGU for each valid operating hour (as defined in 60.5860b(a)(2)) in
MWh.
(PE)ST = Electric energy output plus mechanical energy
output (if any) of steam turbines in MWh.
(PE)CT = Electric energy output plus mechanical energy
output (if any) of stationary combustion turbine(s) in MWh.
(PE)IE = Electric energy output plus mechanical energy
output (if any) of your affected egu's integrated equipment that
provides electricity or mechanical energy to the affected EGU or
auxiliary equipment in MWh.
(PE)A = Electric energy used for any auxiliary loads in
MWh.
(PT)PS = Useful thermal output of steam (measured
relative to SATP conditions, as applicable) that is used for
applications that do not generate additional electricity, produce
mechanical energy output, or enhance the performance of the affected
EGU. This is calculated using the equation specified in paragraph
(a)(5)(V) of this section in MWh.
[[Page 40059]]
(PT)HR = Non-steam useful thermal output (measured
relative to SATP conditions, as applicable) from heat recovery that
is used for applications other than steam generation or performance
enhancement of the affected EGU in MWh.
(PT)IE = Useful thermal output (relative to SATP
conditions, as applicable) from any integrated equipment is used for
applications that do not generate additional steam, electricity,
produce mechanical energy output, or enhance the performance of the
affected EGU in MWh.
TDF = Electric transmission and distribution factor of 0.95 for a
combined heat and power affected egu where at least on an annual
basis 20.0 percent of the total gross or net energy output consists
of electric or direct mechanical output and 20.0 percent of the
total gross or net energy output consist of useful thermal output on
a 12-operating month rolling average basis, or 1.0 for all other
affected EGUs.
(v) If applicable to your affected EGU (for example, for combined
heat and power), you must calculate (Pt)PS using the
following equation:
Equation 2 to Paragraph (a)(5)(v)
[GRAPHIC] [TIFF OMITTED] TR09MY24.063
Where:
QM = Measured steam flow in kilograms (KG) (or pounds
(LBS)) for the operating hour.
H = Enthalpy of the steam at measured temperature and pressure
(relative to SATP conditions or the energy in the condensate return
line, as applicable) in joules per kilogram (J/KG) (or BTU/LB).
CF = Conversion factor of 3.6 x 10\9\ J/MWH or 3.413 x 10\6\ BTU/
MWh.
(vi) For rate-based standards, sum all of the values of
Pgross/net for the valid operating hours (as defined in
paragraph (a)(2) of this section). Then, divide the total
CO2 mass emissions for the valid operating hours from
paragraph (a)(3)(v) or (a)(4)(v) of this section, as applicable, by the
sum of the Pgross/net values for the valid operating hours
to determine the CO2 emissions rate (lb/gross or net MWh).
(6) In accordance with Sec. 60.13(g), if two or more affected EGUs
implementing the continuous emissions monitoring provisions in
paragraph (a)(3) of this section share a common exhaust gas stack and
are subject to the same emissions standard, the owner or operator may
monitor the hourly CO2 mass emissions at the common stack in
lieu of monitoring each EGU separately. If an owner or operator of an
affected EGU chooses this option, the hourly gross or net electric
output for the common stack must be the sum of the hourly gross or net
electric output of the individual affected EGUs and the operating time
must be expressed as ``stack operating hours'' (as defined in 40 CFR
72.2).
(7) In accordance with Sec. 60.13(g), if the exhaust gases from an
affected EGU implementing the continuous emissions monitoring
provisions in paragraph (a)(3) of this section are emitted to the
atmosphere through multiple stacks (or if the exhaust gases are routed
to a common stack through multiple ducts and you elect to monitor in
the ducts), the hourly CO2 mass emissions and the ``stack
operating time'' (as defined in 40 CFR 72.2) at each stack or duct must
be monitored separately. In this case, the owner or operator of an
affected EGU must determine compliance with an applicable emissions
standard by summing the CO2 mass emissions measured at the
individual stacks or ducts and dividing by the gross or net energy
output for the affected EGU.
(8) Consistent with Sec. 60.5775b, if two or more affected EGUs
serve a common electric generator, you must apportion the combined
hourly gross or net energy output to the individual affected EGUs
according to the fraction of the total steam load contributed by each
EGU. Alternatively, if the EGUs are identical, you may apportion the
combined hourly gross or net electrical load to the individual EGUs
according to the fraction of the total heat input contributed by each
EGU.
(9) The owner or operator of an affected EGU must measure and
report monthly fuel usage for each affected source subject to standards
of performance with the information in paragraphs (a)(9)(i) through
(iii) of this section:
(i) The calendar month during which the fuel was used;
(ii) Each type of fuel used during the calendar month of the
compliance period; and
(iii) Quantity of each type of fuel combusted in each calendar
month in the compliance period with units of measure.
(b) Your State plan must require the owner or operator of each
affected EGU covered by your State plan to maintain the records, for at
least 5 years following the date of each occurrence, measurement,
maintenance, corrective action, report, or record.
(1) The owner or operator of an affected EGU must maintain each
record on site for at least 2 years after the date of each occurrence,
measurement, maintenance, corrective action, report, or record,
whichever is latest, according to Sec. 60.7. The owner or operator of
an affected EGU may maintain the records off site and electronically
for the remaining year(s).
(2) The owner or operator of an affected EGU must keep all of the
following records, in a form suitable and readily available for
expeditious review:
(i) All documents, data files, and calculations and methods used to
demonstrate compliance with an affected EGU's standard of performance
under Sec. 60.5775b.
(ii) Copies of all reports submitted to the State under paragraph
(b) of this section.
(iii) Data that are required to be recorded by 40 CFR part 75
subpart F.
(c) Your State plan must require the owner or operator of an
affected EGU covered by your State plan to include in a report
submitted to you the information in paragraphs (c)(1) through (3) of
this section.
(1) Owners or operators of an affected EGU must include in the
report all hourly CO2 emissions, for each affected EGU (or
group of affected EGUs that share a monitored common stack).
(2) For rate-based standards, each report must include:
(i) The hourly CO2 mass emission rate values (tons/hr)
and unit (or stack) operating times, (as monitored and reported
according to part 75 of this chapter), for each valid operating hour;
(ii) The gross or net electric output and the gross or net energy
output (Pgross/net) values for each valid operating hour;
(iii) The calculated CO2 mass emissions (lb) for each
valid operating hour;
(iv) The sum of the hourly gross or net energy output values and
the sum of the
[[Page 40060]]
hourly CO2 mass emissions values, for all of the valid
operating hours; and
(v) The calculated CO2 mass emission rate (lbs/gross or
net MWh).
(3) For each affected EGU the report must also include the
applicable standard of performance and demonstration that it met the
standard of performance. An owner or operator must also include in the
report the affected EGU's calculated emission performance as a
CO2 emission rate in units of the standard of performance.
(d) The owner or operator of an affected EGU must follow any
additional requirements for monitoring, recordkeeping and reporting in
a State plan that are required under Sec. 60.5740b if applicable.
(e) If an affected EGU captures CO2 to meet the
applicable standard of performance, the owner or operator must report
in accordance with the requirements of 40 CFR part 98 subpart PP and
either:
(1) Report in accordance with the requirements of 40 CFR part 98,
subpart RR, or subpart VV, if injection occurs on-site;
(2) Transfer the captured CO2 to a facility that reports
in accordance with the requirements of 40 CFR part 98, subpart RR, or
subpart VV, if injection occurs off-site; or
(3) Transfer the captured CO2 to a facility that has
received an innovative technology waiver from the EPA pursuant to
paragraph (f) of this section.
(f) Any person may request the Administrator to issue a waiver of
the requirement that captured CO2 from an affected EGU be
transferred to a facility reporting under 40 CFR part 98, subpart RR,
or subpart VV. To receive a waiver, the applicant must demonstrate to
the Administrator that its technology will store captured
CO2 as effectively as geologic sequestration, and that the
proposed technology will not cause or contribute to an unreasonable
risk to public health, welfare, or safety. In making this
determination, the Administrator shall consider (among other factors)
operating history of the technology, whether the technology will
increase emissions or other releases of any pollutant other than
CO2, and permanence of the CO2 storage. The
Administrator may test the system or require the applicant to perform
any tests considered by the Administrator to be necessary to show the
technology's effectiveness, safety, and ability to store captured
CO2 without release. The Administrator may grant conditional
approval of a technology, with the approval conditioned on monitoring
and reporting of operations. The Administrator may also withdraw
approval of the waiver on evidence of releases of CO2 or
other pollutants. The Administrator will provide notice to the public
of any application under this provision and provide public notice of
any proposed action on a petition before the Administrator takes final
action.
Sec. 60.5865b What are my recordkeeping requirements?
(a) You must keep records of all information relied upon in support
of any demonstration of State plan components, State plan requirements,
supporting documentation, and the status of meeting the State plan
requirements defined in the State plan.
(b) You must keep records of all data submitted by the owner or
operator of each affected EGU that are used to determine compliance
with each affected EGU emissions standard or requirements in an
approved State plan, consistent with the affected EGU requirements
listed in Sec. 60.5860b.
(c) If your State has a requirement for all hourly CO2
emissions and gross generation or heat input information to be used to
calculate compliance with an annual emissions standard for affected
EGUs, any information that is submitted by the owners or operators of
affected EGUs to the EPA electronically pursuant to requirements in 40
CFR part 75 meets the recordkeeping requirement of this section and you
are not required to keep records of information that would be in
duplicate of paragraph (b) of this section.
(d) You must keep records for a minimum of 10 years from the date
the record is used to determine compliance with an emissions standard
or State plan requirement. Each record must be in a form suitable and
readily available for expeditious review.
(e) If your State plan includes provisions for the compliance date
extension, described in Sec. 60.5740b(a)(11), you must keep records of
the information required in Sec. 60.5740b(a)(11)(i) from affected EGUs
that use the compliance date extension.
(f) If your State plan includes provisions for the short-term
reliability mechanism, as described in Sec. 60.5740b(a)(12), you must
keep records of the information required in Sec. 60.5740b(a)(12)(iii)
from affected EGUs that use the short-term reliability mechanism.
(g) If your State plan includes provisions for the reliability
assurance mechanism, described in Sec. 60.5740b(a)(13), you must keep
records of the information required in Sec. 60.5740b(a)(13)(vi) from
affected EGUs that use the reliability assurance mechanism.
Sec. 60.5870b What are my reporting and notification requirements?
(a) In lieu of the annual report required under Sec. 60.25(e) and
(f), you must report the information in paragraph (b) of this section.
(b) You must submit an annual report to the EPA that must include
the information in paragraphs (b)(1) through (10) of this section. For
each calendar year reporting period the report must be submitted by
March 1 of the following year.
(1) The report must include the emissions performance achieved by
each affected EGU during the reporting period and identification of
whether each affected EGU is in compliance with its standard of
performance during the compliance period, as specified in the State
plan.
(2) The report must include, for each affected EGU, a comparison of
the CO2 standard of performance in the State plan versus the
actual CO2 emission performance achieved.
(3) The report must include, for each affected EGU, the sum of the
CO2 emissions, the sum of the gross energy output, and the
sum of the heat input for each fuel type.
(4) Enforcement actions initiated against affected EGUs during the
reporting period, under any standard of performance or compliance
schedule of the State plan.
(5) Identification of the achievement of any increment of progress
required by the applicable State plan during the reporting period.
(6) Identification of designated facilities that have ceased
operation during the reporting period.
(7) Submission of emission inventory data as described in paragraph
(a) of this section for designated facilities that were not in
operation at the time of State plan development but began operation
during the reporting period.
(8) Submission of additional data as necessary to update the
information submitted under paragraph (a) of this section or in
previous progress reports.
(9) Submission of copies of technical reports on all performance
testing on designated facilities conducted under paragraph (b)(2) of
this section, complete with concurrently recorded process data.
(10) The report must include all other required information, as
specified in your State plan according to Sec. 60.5740b.
(c) If you include provisions for the compliance date extension,
described in Sec. 60.5740b(a)(11), in your State plan, you must report
to the EPA the information listed in Sec. 60.5740b(a)(11)(i).
[[Page 40061]]
(d) If you include provisions for the short-term reliability
mechanism, described in Sec. 60.5740b(a)(12), in your State plan, you
must report to the EPA the following information for each event, listed
in Sec. 60.5740b(a)(12)(iii).
(e) If you include provisions for the reliability assurance
mechanism, described in Sec. 60.5740b(a)(13) in your State plan, you
must report to the EPA the information listed in Sec.
60.5740b(a)(13)(vi).
Sec. 60.5875b How do I submit information required by these emission
guidelines to the EPA?
(a) You must submit to the EPA the information required by these
emission guidelines following the procedures in paragraphs (b) through
(e) of this section.
(b) All State plan submittals, supporting materials that are part
of a State plan submittal, any State plan revisions, and all State
reports required to be submitted to the EPA by the State plan must be
reported through the EPA's State Plan Electronic Collection System
(SPeCS). SPeCS is a web accessible electronic system accessed at the
EPA's Central Data Exchange (CDX) (http://www.epa.gov/cdx/). States
that claim that a State plan submittal or supporting documentation
includes confidential business information (CBI) must submit that
information on a compact disc, flash drive, or other commonly used
electronic storage media to the EPA. The electronic media must be
clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office,
Attention: State and Local Programs Group, MD C539-01, 4930 Old Page
Rd., Durham, NC 27703.
(c) Only a submittal by the Governor or the Governor's designee by
an electronic submission through SPeCS shall be considered an official
submittal to the EPA under this subpart. If the Governor wishes to
designate another responsible official the authority to submit a State
plan, the EPA must be notified via letter from the Governor prior to
the May 11, 2026, deadline for State plan submittal so that the
official will have the ability to submit the initial or final State
plan submittal in the SPeCS. If the Governor has previously delegated
authority to make CAA submittals on the Governor's behalf, a State may
submit documentation of the delegation in lieu of a letter from the
Governor. The letter or documentation must identify the designee to
whom authority is being designated and must include the name and
contact information for the designee and also identify the State plan
preparers who will need access to SPeCS. A State may also submit the
names of the State plan preparers via a separate letter prior to the
designation letter from the Governor in order to expedite the State
plan administrative process. Required contact information for the
designee and preparers includes the person's title, organization, and
email address.
(d) The submission of the information by the authorized official
must be in a non-editable format. In addition to the non-editable
version all State plan components designated as federally enforceable
must also be submitted in an editable version. Following initial State
plan approval, States must provide the EPA with an editable copy of any
submitted revision to existing approved federally enforceable State
plan components, including State plan backstop measures. The editable
copy of any such submitted State plan revision must indicate the
changes made at the State level, if any, to the existing approved
federally enforceable State plan components, using a mechanism such as
redline/strikethrough. These changes are not part of the State plan
until formal approval by the EPA.
(e) You must provide the EPA with non-editable and editable copies
of any submitted revision to existing approved federally enforceable
State plan components. The editable copy of any such submitted State
plan revision must indicate the changes made at the State level, if
any, to the existing approved federally enforceable State plan
components, using a mechanism such as redline/strikethrough. These
changes are not part of the State plan until formal approval by the
EPA.
Sec. 60.5876b What are the recordkeeping and reporting requirements
for EGUs that have committed to permanently cease operations by January
1, 2032?
(a) If you are the owner or operator of an EGU that has committed
to permanently cease operations by January 1, 2032, you must maintain
records for and submit the reports listed in paragraphs (a)(1) through
(3) of this section according to the electronic reporting requirements
in paragraph (b) of this section.
(1) Five years before any planned date to permanently cease
operations or by the date upon which the State plan is submitted,
whichever is later, the owner or operator of the EGU must submit an
initial report to the EPA that includes the information in paragraphs
(a)(1)(i) and (ii) of this section.
(i) A summary of the process steps required for the EGU to
permanently cease operation by the date included in the State plan,
including the approximate timing and duration of each step and any
notification requirements associated with deactivation of the unit.
These process steps may include, e.g., initial notice to the relevant
reliability authority of the deactivation date and submittal of an
official retirement filing (or equivalent filing) made to the EGU's
relevant reliability authority.
(ii) Supporting regulatory documents, which include those listed in
paragraphs (a)(1)(ii)(A) through (G) of this section:
(A) Correspondence and official filings with the relevant regional
RTO, Independent System Operator, Balancing Authority, PUC, or other
applicable authority;
(B) Any deactivation-related reliability assessments conducted by
the RTO or Independent System Operator;
(C) Any filings pertaining to the affected EGU with the SEC or
notices to investors, including but not limited to references in forms
10-K and 10-Q, in which plans for the EGU are mentioned;
(D) Any integrated resource plans and PUC orders approving the
EGU's deactivation;
(E) Any reliability analyses developed by the RTO, Independent
System Operator, or relevant reliability authority in response to the
EGU's deactivation notification;
(F) Any notification from a relevant reliability authority that the
EGU may be needed for reliability purposes notwithstanding the EGU's
intent to deactivate; and
(G) Any notification to or from an RTO, Independent System
Operator, or relevant reliability authority altering the timing of
deactivation of the EGU.
(2) For each of the remaining years prior to the date by which an
EGU has committed to permanently cease operations, the owner or
operator of the EGU must submit an annual status report to the EPA that
includes the information listed in paragraphs (a)(2)(i) and (ii) of
this section:
(i) Progress on each of the identified process steps identified in
the initial report as described in paragraph (a)(1)(i) of this section;
and
(ii) Supporting regulatory documents, including correspondence and
official filings with the relevant RTO, Independent System Operator,
Balancing Authority, PUC, or other applicable authority to demonstrate
progress toward all steps described in paragraph (a)(1)(i) of this
section.
(3) The owner or operator must submit a final report to the EPA no
later than 6 months following its committed closure date. This report
must document any actions that the EGU has taken subsequent to ceasing
operation to
[[Page 40062]]
ensure that such cessation is permanent, including any regulatory
filings with applicable authorities or decommissioning plans.
(b) Beginning November 12, 2024, if you are the owner or operator
of an EGU that has committed to permanently cease operations by January
1, 2032, you must submit all the information required in paragraph (a)
of this section in a Permanent Cessation of Operation report in PDF
format following the procedures specified in paragraph (c) of this
section.
(c) If you are required to submit notifications or reports
following the procedure specified in this paragraph (c), you must
submit notifications or reports to the EPA via the Compliance and
Emissions Data Reporting Interface (CEDRI), which can be accessed
through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).
The EPA will make all the information submitted through CEDRI available
to the public without further notice to you. Do not use CEDRI to submit
information you claim as CBI. Although we do not expect persons to
assert a claim of CBI, if you wish to assert a CBI claim for some of
the information in the report or notification, you must submit a
complete file in the format specified in this subpart, including
information claimed to be CBI, to the EPA following the procedures in
paragraphs (c)(1) and (2) of this section. Clearly mark the part or all
of the information that you claim to be CBI. Information not marked as
CBI may be authorized for public release without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 CFR part 2. All CBI claims must be
asserted at the time of submission. Anything submitted using CEDRI
cannot later be claimed CBI. Furthermore, under CAA section 114(c),
emissions data is not entitled to confidential treatment, and the EPA
is required to make emissions data available to the public. Thus,
emissions data will not be protected as CBI and will be made publicly
available. You must submit the same file submitted to the CBI office
with the CBI omitted to the EPA via the EPA's CDX as described earlier
in this paragraph (c).
(1) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings and be flagged to the attention of the Emission Guidelines for
Greenhouse Gas Emissions for Electric Utility Generating Units Sector
Lead. If assistance is needed with submitting large electronic files
that exceed the file size limit for email attachments, and if you do
not have your own file sharing service, please email [email protected]
to request a file transfer link.
(2) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109
T.W. Alexander Drive P.O. Box 12055, RTP, NC 27711. All other files
should also be sent to the attention of the Greenhouse Gas Emissions
for Electric Utility Generating Units Sector Lead. The mailed CBI
material should be double wrapped and clearly marked. Any CBI markings
should not show through the outer envelope.
(d) Any records required to be maintained by this subpart that are
submitted electronically via the EPA's CEDRI may be maintained in
electronic format. This ability to maintain electronic copies does not
affect the requirement for facilities to make records, data, and
reports available upon request to a delegated air agency or the EPA as
part of an on-site compliance evaluation.
(e) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for
failure to timely comply with that reporting requirement. To assert a
claim of EPA system outage, you must meet the requirements outlined in
paragraphs (e)(1) through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time
beginning five business days prior to the date that the submission is
due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(5) You must provide to the Administrator a written description
identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(6) The decision to accept the claim of EPA system outage and allow
an extension to the reporting deadline is solely within the discretion
of the Administrator.
(7) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(f) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, you may assert a claim of force majeure for
failure to timely comply with that reporting requirement. To assert a
claim of force majeure, you must meet the requirements outlined in
paragraphs(f)(1) through (5) of this section.
(1) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning five business days prior
to the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the affected facility,
its contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large scale power outage).
(2) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(4) The decision to accept the claim of force majeure and allow an
extension
[[Page 40063]]
to the reporting deadline is solely within the discretion of the
Administrator.
(5) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
(g) Alternatives to any electronic reporting required by this
subpart must be approved by the Administrator.
Definitions
Sec. [thinsp]60.5880b What definitions apply to this subpart?
As used in this subpart, all terms not defined herein will have the
meaning given them in the Clean Air Act and in subparts A, Ba, TTTT,
and TTTTa, of this part.
Affected electric generating unit or Affected EGU means a steam
generating unit that meets the relevant applicability conditions in
section Sec. 60.5845b.
Annual capacity factor means the ratio between the actual heat
input to an EGU during a calendar year and the potential heat input to
the EGU had it been operated for 8,760 hours during a calendar year at
the base load rating.
Base load rating means the maximum amount of heat input (fuel) that
an EGU can combust on a steady-state basis, as determined by the
physical design and characteristics of the EGU at ISO conditions, as
defined below. For a stationary combustion turbine or IGCC, base load
rating includes the heat input from duct burners.
Coal-fired steam generating unit means an electric utility steam
generating unit or IGCC unit that meets the definition of ``fossil
fuel-fired'' and that burns coal for more than 10.0 percent of the
average annual heat input during any continuous 3-calendar-year period
after December 31, 2029, or for more than 15.0 percent of the annual
heat input during any one calendar year after December 31, 2029, or
that retains the capability to fire coal after December 31, 2029.
Combined cycle unit means a stationary combustion turbine from
which the heat from the turbine exhaust gases is recovered by a heat
recovery steam generating unit to generate additional electricity.
Combined heat and power unit or CHP unit, (also known as
``cogeneration'') means an electric generating unit that uses a steam-
generating unit or stationary combustion turbine to simultaneously
produce both electric (or mechanical) and useful thermal output from
the same primary energy source.
Compliance period means an annual (calendar year) period for an
affected EGU to comply with a standard of performance.
Derate means a decrease in the available capacity of an electric
generating unit, due to a system or equipment modification or to
discounting a portion of a generating unit's capacity for planning
purposes.
Fossil fuel means natural gas, petroleum, coal, and any form of
solid fuel, liquid fuel, or gaseous fuel derived from such material for
the purpose of creating useful heat.
Gross energy output means:
(1) For stationary combustion turbines and IGCC, the gross electric
or direct mechanical output from both the EGU (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expander(s)) plus 100 percent of the useful thermal output.
(2) For steam generating units, the gross electric or mechanical
output from the affected EGU(s) (including, but not limited to, output
from steam turbine(s), combustion turbine(s), and gas expander(s))
minus any electricity used to power the feedwater pumps plus 100
percent of the useful thermal output;
(3) For combined heat and power facilities where at least 20.0
percent of the total gross energy output consists of useful thermal
output on a 12-operating-month rolling average basis, the gross
electric or mechanical output from the affected EGU (including, but not
limited to, output from steam turbine(s), combustion turbine(s), and
gas expander(s)) minus any electricity used to power the feedwater
pumps (the electric auxiliary load of boiler feedwater pumps is not
applicable to IGCC facilities), that difference divided by 0.95, plus
100 percent of the useful thermal output.
Heat recovery steam generating unit (HRSG) means a unit in which
hot exhaust gases from the combustion turbine engine are routed in
order to extract heat from the gases and generate useful output. Heat
recovery steam generating units can be used with or without duct
burners.
Integrated gasification combined cycle facility or IGCC means a
combined cycle facility that is designed to burn fuels containing 50
percent (by heat input) or more solid-derived fuel not meeting the
definition of natural gas plus any integrated equipment that provides
electricity or useful thermal output to either the affected facility or
auxiliary equipment. The Administrator may waive the 50 percent solid-
derived fuel requirement during periods of the gasification system
construction, startup and commissioning, shutdown, or repair. No solid
fuel is directly burned in the unit during operation.
ISO conditions means 288 Kelvin (15 [deg]C, 59 [deg]F), 60 percent
relative humidity and 101.3 kilopascals (14.69 psi, 1 atm) pressure.
Mechanical output means the useful mechanical energy that is not
used to operate the affected facility, generate electricity and/or
thermal output, or to enhance the performance of the affected facility.
Mechanical energy measured in horsepower hour must be converted into
MWh by multiplying it by 745.7 then dividing by 1,000,000.
Nameplate capacity means, starting from the initial installation,
the maximum electrical generating output that a generator, prime mover,
or other electric power production equipment under specific conditions
designated by the manufacturer is capable of producing (in MWe, rounded
to the nearest tenth) on a steady-state basis and during continuous
operation (when not restricted by seasonal or other deratings) as of
such installation as specified by the manufacturer of the equipment, or
starting from the completion of any subsequent physical change
resulting in an increase in the maximum electrical generating output
that the equipment is capable of producing on a steady-state basis and
during continuous operation (when not restricted by seasonal or other
deratings), such increased maximum amount (in MWe, rounded to the
nearest tenth) as of such completion as specified by the person
conducting the physical change.
Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. Finally,
natural gas does not include the following gaseous fuels: Landfill gas,
digester gas, refinery gas, sour gas, blast furnace gas, coal-derived
gas, producer gas, coke oven gas, or any gaseous fuel produced in a
process which might result in highly variable CO2 content or
heating value.
Natural gas-fired steam generating unit means an electric utility
steam generating unit meeting the definition of ``fossil fuel-fired,''
that is not a coal-fired or oil-fired steam generating unit, that no
longer retains the capability to fire coal after December 31, 2029, and
that burns natural gas for more than 10.0 percent of the average annual
heat input during any continuous 3-calendar-year period after December
31, 2029, or for more than 15.0 percent of the annual
[[Page 40064]]
heat input during any calendar year after December 31, 2029.
Net electric output means the amount of gross generation the
generator(s) produce (including, but not limited to, output from steam
turbine(s), combustion turbine(s), and gas expander(s)), as measured at
the generator terminals, less the electricity used to operate the plant
(i.e., auxiliary loads); such uses include fuel handling equipment,
pumps, fans, pollution control equipment, other electricity needs, and
transformer losses as measured at the transmission side of the step up
transformer (e.g., the point of sale).
Net energy output means:
(1) The net electric or mechanical output from the affected
facility, plus 100 percent of the useful thermal output measured
relative to standard ambient temperature and pressure conditions that
is not used to generate additional electric or mechanical output or to
enhance the performance of the unit (e.g., steam delivered to an
industrial process for a heating application).
(2) For combined heat and power facilities where at least 20.0
percent of the total gross or net energy output consists of electric or
direct mechanical output and at least 20.0 percent of the total gross
or net energy output consists of useful thermal output on a 12-
operating month rolling average basis, the net electric or mechanical
output from the affected EGU divided by 0.95, plus 100 percent of the
useful thermal output; (e.g., steam delivered to an industrial process
for a heating application).
Oil-fired steam generating unit means an electric utility steam
generating unit meeting the definition of ``fossil fuel-fired'' that is
not a coal-fired steam generating unit, that no longer retains the
capability to fire coal after December 31, 2029, and that burns oil for
more than 10.0 percent of the average annual heat input during any
continuous 3-calendar-year period after December 31, 2029, or for more
than 15.0 percent of the annual heat input during any one calendar year
after December 31, 2029.
Standard ambient temperature and pressure (SATP) conditions means
298.15 Kelvin (25 [deg]C, 77 [deg]F) and 100.0 kilopascals (14.504 psi,
0.987 atm) pressure. The enthalpy of water at SATP conditions is 50
Btu/lb.
State agent means an entity acting on behalf of the State, with the
legal authority of the State.
Stationary combustion turbine means all equipment including, but
not limited to, the turbine engine, the fuel, air, lubrication and
exhaust gas systems, control systems (except emissions control
equipment), heat recovery system, fuel compressor, heater, and/or pump,
post-combustion emission control technology, and any ancillary
components and sub-components comprising any simple cycle stationary
combustion turbine, any combined cycle combustion turbine, and any
combined heat and power combustion turbine based system plus any
integrated equipment that provides electricity or useful thermal output
to the combustion turbine engine, heat recovery system, or auxiliary
equipment. Stationary means that the combustion turbine is not self-
propelled or intended to be propelled while performing its function. It
may, however, be mounted on a vehicle for portability. A stationary
combustion turbine that burns any solid fuel directly is considered a
steam generating unit.
Steam generating unit means any furnace, boiler, or other device
used for combusting fuel and producing steam (nuclear steam generators
are not included) plus any integrated equipment that provides
electricity or useful thermal output to the affected facility or
auxiliary equipment.
System Emergency means periods when the Reliability Coordinator has
declared an Energy Emergency Alert level 2 or 3 as defined by NERC
Reliability Standard EOP-011-2, or its successor.
Uprate means an increase in available electric generating unit
power capacity due to a system or equipment modification.
Useful thermal output means the thermal energy made available for
use in any heating application (e.g., steam delivered to an industrial
process for a heating application, including thermal cooling
applications) that is not used for electric generation, mechanical
output at the affected EGU, to directly enhance the performance of the
affected EGU (e.g., economizer output is not useful thermal output, but
thermal energy used to reduce fuel moisture is considered useful
thermal output), or to supply energy to a pollution control device at
the affected EGU. Useful thermal output for affected EGU(s) with no
condensate return (or other thermal energy input to the affected
EGU(s)) or where measuring the energy in the condensate (or other
thermal energy input to the affected EGU(s)) would not meaningfully
impact the emission rate calculation is measured against the energy in
the thermal output at SATP conditions. Affected EGU(s) with meaningful
energy in the condensate return (or other thermal energy input to the
affected EGU) must measure the energy in the condensate and subtract
that energy relative to SATP conditions from the measured thermal
output.
Valid data means quality-assured data generated by continuous
monitoring systems that are installed, operated, and maintained
according to 40 CFR part 75. For CEMS, the initial certification
requirements in 40 CFR 75.20 and appendix A to 40 CFR part 75 must be
met before quality-assured data are reported under this subpart; for
on-going quality assurance, the daily, quarterly, and semiannual/annual
test requirements in sections 2.1, 2.2, and 2.3 of appendix B to 40 CFR
part 75 must be met and the data validation criteria in sections 2.1.4,
2.2.3, and 2.3.2 of appendix B to 40 CFR part 75 apply. For fuel flow
meters, the initial certification requirements in section 2.1.5 of
appendix D to 40 CFR part 75 must be met before quality-assured data
are reported under this subpart (except for qualifying commercial
billing meters under section 2.1.4.2 of appendix D), and for on-going
quality assurance, the provisions in section 2.1.6 of appendix D to 40
CFR part 75 apply (except for qualifying commercial billing meters).
Waste-to-Energy means a process or unit (e.g., solid waste
incineration unit) that recovers energy from the conversion or
combustion of waste stream materials, such as municipal solid waste, to
generate electricity and/or heat.
[FR Doc. 2024-09233 Filed 5-8-24; 8:45 am]
BILLING CODE 6560-50-P