which the EPA establishes a single CCS-based second phase standard for
base load combustion turbines, along with a second phase standard for
intermediate load combustion turbines that is based on low-GHG hydrogen
as a component of the BSER, would align with this potential scenario.
In addition, if an owner or operator of a new combustion turbine does
seek to utilize low-GHG hydrogen for base load generation, a single
CCS-based second phase standard for base load combustion turbines would
not preclude owners and operators from utilizing low-GHG hydrogen as a
means of compliance. Owners/operators could also comply with a CCS-
based standard by co-firing 96 percent (by volume) low-GHG hydrogen
from the outset of the second phase--rather than the proposed approach
that would delay requirements for this level of co-firing until 2038.
2. Co-Firing Low-GHG Hydrogen as BSER for Intermediate Load Combined
Cycle and Simple Cycle Subcategories
    The EPA is also soliciting comment on subcategorizing intermediate
load combustion turbines into an intermediate load combined cycle
subcategory and an intermediate load simple cycle subcategory. The BSER
for both subcategories would be two components: (1) Highly efficient
generation (either combined cycle technology or simple cycle
technology, respectively) and (2) co-firing 30 percent (by volume) low-
GHG hydrogen, with the first component applying when the source
commences operation and the second component applying in the year 2032.
Dividing the intermediate load subcategory into these two subcategories
would assure that intermediate load combined cycle turbines would have
a more stringent standard of performance--that is, expressed in a lower
lb CO2/MWh--than intermediate load simple cycle turbines.
3. Integrated Onsite Generation and Energy Storage
    Integrated equipment is currently included as part of the affected
facility and the EPA is soliciting comment on the best approach to
recognizing the

environmental benefits of onsite integrated non-emitting generation and
energy storage. The EPA is proposing regulatory text to clarify that
the output from integrated renewables is included as output when
determining the NSPS emissions rate. The EPA is also proposing that the
output from the integrated renewable generation is not included when
determining the net electric sales for applicability purposes. In the
alternative, the EPA is soliciting comment on whether instead of
exempting the generation from the integrated renewables from counting
toward electric sales, the potential output from the integrated
renewables would be included when determining the design efficiency of
the facility. Since the design efficiency is used when determining the
electric sales threshold this would increase the allowable electric
sales for subcategorization purposes. Including the integrated
renewables when determining the design efficiency of the affected
facility would have the impact of increasing the operational
flexibility of owners/operators of intermediate load combustion
turbines. Renewables typically have much lower 12-operating month
capacity factors than the intermediate electric sales threshold so
could allow the turbine engine itself to operate at a higher capacity
factor while still being considered an intermediate load EGU.
Conversely, if the integrated renewables operate at a 12-operating
month capacity factor of greater than 20 percent that would reduce the
ability of a peaking turbine engine to operate while still remaining in
the low load subcategory. However, even if a combustion turbine engine
itself were to operate at a capacity factor of less than 20 percent and
become categorized as an intermediate load combustion turbine when the
output form the integrated renewables are considered, the output from
the integrated renewables could lower the emissions rate such that the
affected facility would be in compliance with the intermediate load
standard of performance.
    For integrated energy storage technologies, the EPA is soliciting
comment on including the rated output of the energy storage when
determining the design efficiency of the affected facility. Similar to
integrated renewables, this would increase the flexibility of owner/
operators to operate at higher capacity factors while remaining in the
low and intermediate load subcategories. The EPA is not proposing that
the output from the energy storage be considered in either determining
the NSPS emissions rate or as net electric sales for subcategorization
applicability purposes. While additional energy storage will allow for
integration of additional variable renewable generation, the energy
storage devices could be charged using grid supplied electricity that
is generated from other types of generation. Therefore, this is not
necessarily stored low-GHG electricity.
4. Definition of System Emergency
    40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60,
subpart TTTTa) include a provision that electricity sold during hours
of operation when a unit is called upon to operate due to a system
emergency is not counted toward the percentage electric sales
subcategorization threshold.\515\ The EPA concluded that this exclusion
is necessary to provide flexibility, to maintain system reliability,
and to minimize overall costs to the sector (80 FR 64612; October 23,
2015). Some in the regulated community have informed the Agency that
additional clarification on a system emergency would need to be
determined and documented for compliance purposes. The intent is that
the local grid operator would determine which EGUs are essential to
maintain grid reliability. The EPA is soliciting comments on amending
the definition of system emergency to clarify how it would be
implemented. The current text is any abnormal system condition that the
RTO, Independent System Operators (ISO) or control area Administrator
determines requires immediate automatic or manual action to prevent or
limit loss of transmission facilities or generators that could
adversely affect the reliability of the power system and therefore call
for maximum generation resources to operate in the affected area, or
for the specific affected EGU to operate to avert loss of load.
---------------------------------------------------------------------------

    \515\ Electricity sold by units that are not called upon to
operate due to a system emergency (e.g., units already operating
when the system emergency is declared) is counted toward the
percentage electric sales threshold.
---------------------------------------------------------------------------

5. Definition of Natural Gas
    40 CFR part 60, subpart TTTT (and the proposed 40 CFR part 60,
subpart TTTTa) include a definition of natural gas. Natural gas is a
fluid mixture of hydrocarbons (e.g., methane, ethane, or propane),
composed of at least 70 percent methane by volume or that has a gross
calorific value between 35 and 41 megajoules (MJ) per dry standard
cubic meter (950 and 1,100 Btu per dry standard cubic foot), that
maintains a gaseous state under ISO conditions. Finally, natural gas
does not include the following gaseous fuels: Landfill gas, digester
gas, refinery gas, sour gas, blast furnace gas, coal-derived gas,
producer gas, coke oven gas, or any gaseous fuel produced in a process
which might result in highly variable CO2 content or heating
value. The EPA is soliciting comment on if the exclusions for specific
gases such as landfill gas, etc. are necessary of if they should be
deleted. If landfill gas, coal-derived gas, or other gases are
processed to meet the methane and heating value content of pipeline
quality natural gas they could be mixed into the pipeline network and
it is the intent that this mixture be considered natural gas for the
purposes of 40 CFR part 60, subpart TTTT and the proposed 40 CFR part
60, subpart TTTTa.
6. Summary of Solicitation of Comment on BSER Variations
    This section summarizes the variations on the subcategories and on
BSER for combustion turbines on which the EPA is soliciting comment. It
is intended to highlight certain aspects of the proposal the Agency is
soliciting comment on and is not intended to cover all aspects of the
proposal.
    For the low load subcategory, the EPA is soliciting comment on:
     An electric sales threshold of between 15 to 25 percent
for all combustion turbines regardless of the specific design
efficiency.
     An electric sales threshold based on three quarters of the
design efficiency of the combustion turbine. This would result in
electric sales thresholds of 18 to 22 percent for simple cycle turbines
and 26 to 31 percent for combined cycle turbines.
     Applying a second component of BSER, co-firing 30 percent
(by volume) low-GHG hydrogen by 2032.
    For the intermediate load subcategory, the EPA is soliciting
comment on:
     An efficiency-based standard of performance of between
1,000 to 1,200 lb CO2/MWh-gross.
     The use of steam injection as part of the first BSER
component.
     An electric sales threshold based on 94 percent of the
design efficiency. This would result in electric sales thresholds of 29
to 35 percent for simple cycle turbines and 40 to 49 percent for
combined cycle turbines.
     A hydrogen co-firing range of 30 to 50 percent by volume
as the second component of the BSER.
     Beginning implementation of the second component of the
BSER (i.e., hydrogen co-firing) as early as 2030.
     The second component of the BSER would establish separate
subcategories

for simple and combined cycle intermediate load combustion turbines,
both based on co-firing low-GHG hydrogen.
     Adding a third phase standard based on higher levels of
low-GHG hydrogen co-firing by 2038.
    For the base load subcategory, the EPA is soliciting comment on:
     An efficiency-based standard of performance of between 730
to 800 lb CO2/MWh-gross for large combustion turbines.
     An efficiency-based standard of performance of between 850
to 900 lb CO2/MWh-gross for small combustion turbines.
     Beginning implementation of the second component of the
BSER (i.e., CCS or hydrogen co-firing) as early as 2030.
     Beginning implementation of the third component of the co-
firing low-GHG hydrogen-based BSER earlier than 2038.
     Whether the third component of the hydrogen BSER should be
96 percent by volume or a lower volume--note that if it is a lower
volume that raises issues as to whether the BSER would be appropriate
if EPA found that a CCS BSER of 90% for NGCCs was generally applicable
     A hydrogen co-firing range of 30 to 50 percent as the
second component of the BSER for combustion turbines co-firing
hydrogen.
     A single standard based on either a CCS-based BSER or a
co-firing low-GHG-hydrogen based BSER for all base load combustion
turbines.
     A carbon capture rate of 90 to 95 percent as the second
component of the CCS-based BSER.

O. Compliance Dates

    The EPA is proposing that affected sources that commenced
construction or reconstruction after May 23, 2023, would need to meet
the requirements of 40 CFR part 60, subpart TTTTa upon startup of the
new or reconstructed affected facility or the effective date of the
final rule, whichever is later. This proposed compliance schedule is
consistent with the requirements in section 111 of the CAA.

VIII. Requirements for New, Modified, and Reconstructed Fossil Fuel-
Fired Steam Generating Units

A. 2018 NSPS Proposal

    The EPA promulgated NSPS for GHG emissions from fossil fuel-fired
steam generating units in 2015. 80 FR 64510 (October 23, 2015). As
discussed in section V.B.2 of this preamble, on December 20, 2018, the
EPA proposed amendments that would revise the determination of the BSER
for control of GHG emissions from newly constructed coal-fired steam
generating units in 40 CFR part 60, subpart TTTT (83 FR 65424; December
20, 2018). The EPA is not reopening for comment or soliciting comment
on the 2018 NSPS Proposal, and intends to further address it in a
separate action.
1. Additional Amendments
    The EPA is proposing multiple less significant amendments. These
amendments would be either strictly editorial and would not change any
of the requirements of 40 CFR part 60, subpart TTTT or are intended to
add additional compliance flexibility. The proposed amendments would
also be incorporated into the proposed subpart TTTTa. For additional
information on these amendments, see the redline strikeout version of
the rule showing the proposed amendments. First, the EPA is proposing
editorial amendments to define acronyms the first time they are used in
the regulatory text. Second, the EPA is proposing to add International
System of Units (SI) equivalent for owners/operators of stationary
combustion turbines complying with a heat input-based standard. Third,
the EPA is proposing to fix errors in the current 40 CFR part 60,
subpart TTTT regulatory text referring to part 63 instead of part 60.
Fourth, as a practical matter owners/operators of stationary combustion
turbines subject to the heat input-based standard of performance need
to maintain records of electric sales to demonstrate that they are not
subject to the output-based standard of performance. Therefore, the EPA
is proposing to add a specific requirement that owner/operators
maintain records of electric sales to demonstrate they did not sell
electricity above the threshold that would trigger the output-based
standard. Next, the EPA is proposing to update the ANSI, ASME, and ASTM
test methods to include more recent versions of the test methods.
Finally, the EPA is proposing to add additional compliance
flexibilities for EGUs either serving a common electric generator or
using a common stack. Specifically, for EGUs serving a common electric
generator, the EPA is soliciting comment on whether the Administrator
should be able to approve alternate methods for determining energy
output. For EGUs using a common stack, the EPA is soliciting comment on
whether specific procedures should be added for apportioning the
emissions and/or if the Administrator should be able to approve site-
specific alternate procedures.

B. Eight-Year Review of NSPS for Fossil Fuel-Fired Steam Generating
Units

1. New Construction and Reconstruction
    The EPA promulgated NSPS for GHG emissions from fossil fuel-fired
steam generating units in 2015. As noted in section IV.F, the EPA is
not aware of any plans by any companies to undertake new construction
of a new fossil fuel-fired steam generating unit, or to undertake a
reconstruction of an existing fossil fuel-fired steam generating unit,
that would be subject to the 2015 NSPS for steam generating units.
Accordingly, the EPA does not consider it necessary, nor a good use of
agency resources, to review the NSPS for new construction or
reconstruction. See ``New Source Performance Standards (NSPS) Review:
Advanced notice of proposed rulemaking,'' 76 FR 65653, 65658 (October
24, 2011) (suggesting it may not be necessary for the EPA to review an
NSPS when no new construction, modification, or reconstruction is
expected in the source category). Should events change and the EPA
learns that companies plan to undertake construction of a new fossil
fuel-fired steam generating unit or reconstruction of an existing
fossil fuel-fired steam generating unit, the EPA would consider
reviewing these standards.
2. Modifications
    In the 2015 NSPS, the EPA issued final standards for a steam
generating unit that implements a ``large modification,'' defined as a
physical change, or change in the method of operation, that results in
an increase in hourly CO2 emissions of more than 10 percent
when compared to the source's highest hourly emissions in the previous
5 years. Such a modified steam generating unit is required to meet a
unit-specific CO2 emission limit determined by that unit's
best demonstrated historical performance (in the years from 2002 to the
time of the modification). The 2015 NSPS did not include standards for
a steam generating unit that implements a ``small modification,''
defined as a change that results in an increase in hourly
CO2 emissions of less than or equal to 10 percent when
compared to the source's highest hourly emissions in the previous 5
years. 80 FR 64514 (October 23, 2015).
    In the 2015 NSPS, the EPA explained its basis for promulgating this
rule as follows. The EPA has historically been notified of only a
limited number of NSPS modifications involving fossil steam generating
units and therefore predicted that very few of these units

would trigger the modification provisions and be subject to the
proposed standards. Given the limited information that we have about
past modifications, the agency has concluded that it lacks sufficient
information to establish standards of performance for all types of
modifications at steam generating units at this time. Instead, the EPA
has determined that it is appropriate to establish standards of
performance at this time for larger modifications, such as major
facility upgrades involving, for example, the refurbishing or
replacement of steam turbines and other equipment upgrades that result
in substantial increases in a unit's hourly CO2 emissions
rate. The agency has determined, based on its review of public comments
and other publicly available information, that it has adequate
information regarding the types of modifications that could result in
large increases in hourly CO2 emissions, as well as on the
types of measures available to control emissions from sources that
undergo such modifications, and on the costs and effectiveness of such
control measures, upon which to establish standards of performance for
modifications with large emissions increases at this time. Id. at
64597-98. The EPA is not reopening any aspect of these determinations
concerning modifications in the 2015 NSPS, except, as noted below, for
the BSER and associated requirements for large modifications.
    Because the EPA has not promulgated a NSPS for small modifications,
any existing steam generating unit that undertakes a change that
increases its hourly CO2 emissions rate by 10 percent or
less would continue to be treated as an existing source that is subject
to the CAA section 111(d) requirements being proposed today.
    With respect to large modifications, we explained in the 2015 NSPS
that they are rare, but there is record evidence indicating that they
may occur. Id. at 64598. Because the EPA is proposing requirements for
existing sources that are, on their face, more stringent than the
requirements for large modifications, the EPA believes it is
appropriate to review and revise the latter requirements to minimize
the anomalous incentive that an existing source could have to undertake
a large modification for the purpose of avoiding the more stringent
requirements that it would be subject to if it remained an existing
source. Accordingly, the EPA is proposing to revise the BSER for large
modifications to mirror the BSER for the subcategory of coal-fired
steam generating units that plan to operate past December 31, 2039,
that is, the use of CCS with 90 percent capture of CO2. The
EPA believes that it is reasonable to assume that any existing source
that invests in a physical change or change in the method of operation
that would qualify as a large modification expects to continue to
operate past 2039. Accordingly, the EPA proposes that CCS with 90
percent capture qualifies as the BSER for such a source for the same
reasons that it qualifies as the BSER for existing sources that plan to
operate past December 31, 2039. The EPA discusses these reasons in
section X.D.1.a. The EPA is proposing to determine that CCS with 90
percent capture qualifies as the BSER for large modifications, and not
the controls determined to be the BSER in the 2015 NSPS, due to the
recent reductions in the cost of CCS. The EPA does not believe there
are any considerations relative to a source undertaking a large
modification that point towards a control system other than CCS with 90
percent capture qualifying as the BSER. The Agency solicits comment on
this issue.
    By the same token, the EPA is proposing that the degree of emission
limitation associated with CCS with 90 percent capture is an 88.4
percent reduction in emission rate (lb CO2/MWh-gross basis),
the same as proposed for existing sources with CCS with 90 percent
capture. See section X.D.1.a.iv. Based on this degree of emission
limitation, the EPA is proposing that the standard of performance for
steam generating units that undertake large modifications after the
date of publication of this proposal is a unit-specific emission limit
determined by an 88.4 percent reduction in the unit's best historical
annual CO2 emission rate (from 2002 to the date of the
modification). The EPA is proposing that an owner/operator of a
modified steam generating unit comply with the proposed emissions rate
upon startup of the modified affected facility or the effective date of
the final rule, whichever is later. The EPA is proposing the same
testing, monitoring, and reporting requirements as are currently in 40
CFR part 60, subpart TTTT.

C. Projects Under Development

    Finally, during the 2015 NSPS rulemaking, the EPA identified the
Plant Washington project in Georgia and the Holcomb 2 project in Kansas
as EGU ``projects under development'' based on representations by
developers that the projects had commenced construction prior to the
proposal of the 2015 NSPS and, thus, would not be new sources subject
to the final NSPS (80 FR 64542-43; October 23, 2015). The EPA did not
set a performance standard at the time but committed to doing so if new
information about the projects became available. These projects were
never constructed and are no longer expected to be constructed.
    The Plant Washington project was to be an 850-MW supercritical
coal-fired EGU. The Environmental Protection Division (EPD) of the
Georgia Department of Natural Resources issued air and water permits
for the project in 2010 and issued amended permits in
2014.516 517 518 In 2016, developers filed a request with
the EPD to extend the construction commencement deadline specified in
the amended permit, but the director of the EPD denied the request,
effectively canceling the approval of the construction permit and
revoking the plant's amended air quality permit.\519\
---------------------------------------------------------------------------

    \516\ https://www.gpb.org/news/2010/07/26/judge-rejects-coal-plant-permits.
    \517\ https://www.southernenvironment.org/press-release/court-rules-ga-failed-to-set-safe-limits-on-pollutants-from-coal-plant/.
    \518\ https://permitsearch.gaepd.org/permit.aspx?id=PDF-OP-22139.
    \519\ https://www.southernenvironment.org/wp-content/uploads/legacy/words_docs/EPD_Plant_Washington_Denial_Letter.pdf.
---------------------------------------------------------------------------

    The Holcomb 2 project was intended to be a single 895-MW coal-fired
EGU and received permits in 2009 (after earlier proposals sought
approval for development of more than one unit). In 2020, after
developers announced they would no longer pursue the Holcomb 2
expansion project, the air permits were allowed to expire, effectively
canceling the project.
    For these reasons, the EPA is proposing to remove these projects
under the applicability exclusions in subpart TTTT.

IX. Proposed ACE Rule Repeal

    The EPA is proposing to repeal the ACE Rule. A general summary of
the ACE Rule, including its regulatory and judicial history, is
included in section V.B of this preamble. The repeal of the ACE Rule is
intended to stand alone and be severable from the other aspects of this
rule. The EPA proposes to repeal the ACE Rule on three grounds that
together, and each independently, justify the rule's repeal. First, as
a policy matter, the EPA believes that the suite of heat rate
improvements (HRI) the ACE Rule selected as the BSER should be
reexamined and are no longer an appropriate BSER for existing coal-
fired EGUs. The EPA concludes that the suite of HRI set forth in the
ACE Rule provide

negligible CO2 reductions at best and, in many cases, could
increase CO2 emissions because of the rebound effect, as
explained in section X.D.5.a. These concerns taken together, along with
new evidence, and the EPA's experience in implementing the ACE Rule,
cast doubt on the ACE Rule's minimal projected emission reductions and
increase the likelihood that the ACE Rule could make CO2
pollution worse. As a result, the EPA has determined it is appropriate
to repeal the rule, and to reevaluate whether other technologies
constitute the BSER.
    Second, the ACE Rule rejected CCS and natural gas co-firing as the
BSER for reasons that no longer apply. This rule should be repealed so
that EPA may determine the BSER based on evaluating all the candidate
technologies. Since the ACE Rule was promulgated, changes in the power
industry, developments in the costs of controls, and new Federal
subsidies have made these other technologies more broadly available and
less expensive. The EPA is now proposing that these technologies are
the BSER for certain subcategories of sources, as described in section
X of this preamble.
    Third, the EPA concludes that the ACE Rule conflicted with CAA
section 111 and the EPA's implementing regulations because it did not
specifically identify the BSER or the ``degree of emission limitation
achievable though application of the [BSER],'' but set forth an
indeterminate range of values. Thus, the rule did not provide the
States with adequate guidance on the degree of emission limitation that
must be reflected in the standards of performance so that a State plan
would be approvable by the EPA. Along with this, the ACE Rule also
improperly departed from the statutory framework of CAA section 111(d)
by categorically precluding States from allowing their sources to
comply with standards of performance by trading or averaging. Properly
construed, CAA section 111(d) gives States discretion to provide
sources with certain compliance flexibilities, including trading or
averaging in appropriate circumstances so long as the other
requirements of section 111 are met as described below.

A. Summary of Selected Features of the ACE Rule

    The ACE Rule determined that the BSER for coal-fired EGUs was a
``list of `candidate technologies,' '' consisting of seven types of the
``most impactful HRI technologies, equipment upgrades, and best
operating and maintenance practices,'' (84 FR 32536; July 8, 2019),
including, among others, ``Boiler Feed Pumps'' and ``Redesign/Replace
Economizer.'' Id. at 32537 (table 1). The rule provided a range of
improvements in heat rate that each of the seven ``candidate
technologies'' could achieve if applied to coal-fired EGUs of different
capacities. For six of the technologies, the expected level of
improvement in heat rate ranged from 0.1-0.4 percent to 1.0-2.9
percent, and for the seventh technology, ``Improved Operating and
Maintenance (O&M) Practices,'' the range was ``0 to >2%.'' Id. The ACE
Rule explained that States must review each of their designated
facilities, on either a source-by-source or group-of-sources basis, and
``evaluate the applicability of each of the candidate technologies.''
Id. at 32550. States were to use the list of HRI technologies ``as
guidance but will be expected to conduct unit-specific evaluations of
HRI potential, technical feasibility, and applicability for each of the
BSER candidate technologies.'' Id. at 32538.
    The ACE Rule emphasized that States had ``inherent flexibility'' in
undertaking this task with ``a wide range of potential outcomes.'' Id.
at 32542. The ACE Rule provided that States could conclude that it was
not appropriate to apply some technologies. Id. at 32550. Moreover, if
a State did decide to apply a particular technology to a particular
source, the State could determine the level of heat rate improvement
from the technology to be anywhere within the range that the EPA had
identified for that technology, or even outside that range. Id. at
32551. The ACE Rule stated that after the State evaluated the
technologies and calculated the amount of HRI in this way, it should
determine the standard of performance that the source could achieve,
Id. at 32550, and then adjust that standard further based on the
application of source-specific factors such as remaining useful life.
Id. at 32551.
    The ACE Rule then identified the process by which States had to
take these actions. States must ``evaluat[e] each'' of the seven
candidate technologies and provide a summary, which ``include[s] an
evaluation of the . . . degree of emission limitation achievable
through application of the technologies.'' Id. at 32580. Then, the
State must provide a variety of information about each power plant,
including, the plant's ``annual generation,'' ``CO2
emissions,'' ``[f]uel use, fuel price, and carbon content,''
``operation and maintenance costs,'' ``[h]eat rates,'' ``[e]lectric
generating capacity,'' and the ``timeline for implementation,'' among
other information. Id. at 32581. The EPA explained that the purpose of
this data was to allow the Agency to ``adequately and appropriately
review the plan to determine whether it is satisfactory.'' Id. at
32558.
    The ACE Rule projected a very low level of overall emission
reduction if States generally applied the set of candidate technologies
to their sources. The rule was projected to achieve a less-than-1-
percent reduction in power-sector CO2 emissions by
2030.\520\ Further, the EPA also projected that it would increase
CO2 emissions from power plants in 15 States and the
District of Columbia because of the ``rebound effect'' as sources
implemented HRI measures and became more efficient. This phenomenon is
explained in more detail in section X.D.5.a.\521\
---------------------------------------------------------------------------

    \520\ ACE Rule RIA 3-11, table 3-3.
    \521\ The rebound effect becomes evident by comparing the
results of the ACE Rule IPM runs for the 2018 reference case, EPA,
IPM State-Level Emissions: EPAv6 November 2018 Reference Case, EPA-
HQ-OAR-2017-0355-26720, and for the ``Illustrative ACE Scenario. IPM
State-Level Emissions: Illustrative ACE Scenario, EPA-HQ-OAR-2017-
0355-26724.
---------------------------------------------------------------------------

    The ACE Rule considered several other control measures as the BSER,
including co-firing with natural gas and CCS, but rejected them. The
ACE Rule rejected co-firing with natural gas primarily on grounds that
it was too costly in general, and especially for sources that have
limited or no access to natural gas. 84 FR 32545 (July 8, 2019). The
rule also concluded that generating electricity by co-firing natural
gas in a utility boiler would be an inefficient use of the gas when
compared to combusting it in a combustion turbine. Id. The ACE Rule
rejected CCS on grounds that it was too costly. Id. at 32548. The rule
identified the high capital and operating costs of CCS and noted the
fact that the IRC 45Q tax credit, as it then applied, would provide
only limited benefit to sources. Id. at 32548-49.
    In addition, the ACE Rule interpreted CAA section 111 to preclude
States from allowing their sources to trade or average to demonstrate
compliance with their standards of performance. Id. at 32556-57.

B. Developments Undermining ACE Rule's Projected Emission Reductions

    The EPA's first basis for proposing to repeal the ACE Rule is that
there is doubt that the rule would achieve even the limited emissions
reductions projected at the time of promulgation if it were implemented
now, and implementation could increase CO2

emissions instead. Thus, the EPA concludes that as a matter of the
Agency's policy judgment it is appropriate to repeal the rule and
evaluate whether other technologies qualify as the BSER given new
factual developments. This action is consistent with the Supreme
Court's instruction in FCC v. Fox Television Stations, Inc., 556 U.S.
502 (2009), where the Supreme Court explained that an agency issuing a
new policy ``need not demonstrate to a court's satisfaction that the
reasons for the new policy are better than the reasons for the old
one.'' Instead, ``it suffices that the new policy is permissible under
the statute, that there are good reasons for it, and that the agency
believes it to be better, which the conscious change of course
adequately indicates.'' Id. at 514-16 (emphasis in original; citation
omitted).
    Two factors, taken together, undermine the ACE Rule's projected
emission reductions and create the risk that implementation of the ACE
Rule could increase--rather than reduce--CO2 emissions from
coal-fired EGUs. First, HRI technologies achieve only limited GHG
emission reductions. The ACE Rule projected that if States generally
applied the set of candidate technologies to their sources, the rule
would achieve a less-than-1-percent reduction in power-sector
CO2 emissions by 2030.\522\ The EPA now doubts that even
these minimal reductions would be achieved. The ACE Rule's projected
benefits were premised in part on a 2009 technical report by Sargent &
Lundy that evaluated the effects of HRI technologies. In 2023, Sargent
& Lundy issued an updated report which details that the HRI selected as
the BSER in the ACE Rule would bring fewer emissions reductions than
estimated in 2009. The 2023 report concludes that, with few exceptions,
HRI technologies are less effective at reducing CO2
emissions than assumed in 2009. And most sources had already optimized
application of HRIs, and so there are fewer opportunities to reduce
emissions than previously anticipated.
---------------------------------------------------------------------------

    \522\ ACE Rule RIA 3-11, table 3-3.
---------------------------------------------------------------------------

    Second, for a subset of sources, HRI are likely to cause a rebound
effect leading to an increase in GHG emissions for those sources for
the reasons explained in section X.D.5.a. The estimate of the rebound
effect was quite pronounced in the ACE Rule's own analysis--the rule
projected that it would increase CO2 emissions from power
plants in 15 States and the District of Columbia. Specifically, the EPA
prepared modeling projections to understand the impacts of the ACE
Rule. These projections assumed that, consistent with the rule, sources
would impose a small degree of efficiency improvements. The modeling
showed that the rule would not result in absolute emissions reductions
across all affected sources, and some would instead increase absolute
emissions. See EPA, IPM State-Level Emissions: EPAv6 November 2018
Reference Case, EPA-HQ-OAR-2017-0355-26720 (providing ACE reference
case); IPM State-Level Emissions: Illustrative ACE Scenario, EPA-HQ-
OAR-2017-0355-26724 (providing illustrative scenario).
    Despite the fact that the ACE Rule was projected to increase
emissions in many States, these States were nevertheless obligated
under the rule to assemble detailed State plans that evaluated
available technologies and the performance of each existing coal-fired
power plant, as described in section IX.A of this preamble. For
example, the State was required to analyze the plant's ``annual
generation,'' ``CO2 emissions,'' ``[f]uel use, fuel price,
and carbon content,'' ``operation and maintenance costs,'' ``[h]eat
rates,'' ``[e]lectric generating capacity,'' and the ``timeline for
implementation,'' among other information. 84 FR 32581 (July 8, 2019).
This evaluation and the imposition of standards of performance was
mandated even though the State plan would lead to an increase rather
than decrease CO2 emissions.
    In this context, the data undermining the ACE Rule's limited,
projected emission reductions along with the risk that implementation
of the rule could increase CO2 pollution raises doubts that
the HRI satisfies the statutory criteria to constitute the BSER for
this category of sources. The core element of the BSER analysis is
whether the emission reduction technology selected reduces emissions.
See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 441 (D.C. Cir.
1973) (noting ``counter productive environmental effects'' questioned
whether the BSER selected was in fact the ``best'').
    The EPA's experience in implementing the ACE Rule reinforces these
concerns. After the ACE Rule was promulgated, one State drafted a State
plan that set forth a standard of performance that allowed the affected
source to increase its emission rate. The draft partial plan would have
applied to one source, the Longview Power, LLC facility, and would have
established a standard of performance, based on the State's
consideration of the ``candidate technologies,'' that was higher (i.e.,
less stringent) than the source's historical emission rate. Thus, the
draft plan would not have achieved any emission reductions from the
source, and instead would have allowed the source to increase its
emissions, if it was finalized.\523\
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    \523\ West Virginia CAA Sec.  111(d) Partial Plan for Greenhouse
Gas Emissions from Existing Electric Utility Generating Units
(EGUs), https://dep.wv.gov/daq/publicnoticeandcomment/Documents/Proposed%20WV%20ACE%20State%20Partial%20Plan.pdf.
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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 EPA to
propose that HRI are not the BSER for coal-fired power plants.
    Along with changes in the anticipated reductions from HRI, it makes
sense for the EPA to reexamine the BSER because the costs of two
control measures, co-firing with natural gas and CCS, have fallen
substantially for sources with longer-term operating horizons such that
the EPA may determine that these measures satisfy the requirements for
the BSER for the source categories identified below. As noted, the ACE
Rule rejected natural gas co-firing as the BSER on grounds that it was
too costly and would lead to inefficient use of natural gas. But as
discussed in section X.D.2.b.ii of this preamble, the costs of natural
gas co-firing have substantially decreased, and the EPA is proposing
that the costs of co-firing 40 percent by volume natural gas are
reasonable for existing coal-fired EGUs in the medium-term subcategory,
i.e., units that plan to operate during, in general, the 2032 to 2040
period. In addition, the changed circumstances, including that natural
gas is available in greater amounts, and there are fewer coal-fired
EGUs, mitigates the concerns the ACE Rule identified about inefficient
use of natural gas. See section X.D.2.b.iii(B).
    Similarly, the ACE Rule rejected CCS as the BSER on grounds that it
was too costly. But as discussed in section X.D.1.b.ii of this
preamble, the costs of CCS have substantially declined, partly because
of developments in the technology that have lowered capital costs, and
partly because the IRA extended and increased the IRC section 45Q tax
credit so that it defrays a higher

portion of the costs of CCS. Accordingly, for coal-fired EGUs that will
continue to operate past 2040, the EPA is proposing that the costs of
CCS, which have fallen to approximately $7-$12/MWh, are reasonable.
    The reductions from these two technologies are substantial. For
long-term coal-fired steam generating units, the BSER of 90 percent
capture CCS results in substantial CO2 emissions reductions
amounting to emission rates that are 88.4 percent lower on a lb/MWh-
gross basis and 87.1 percent lower on a lb/MWh-net basis compared to
units without capture, as described in section X.D.4 of this preamble.
And for the BSER for medium-term units, 40 percent natural gas co-
firing achieves reductions of 16 percent, as described in section
X.D.2.b.iv of this preamble.
    Given the availability of more effective, cost-reasonable
technology, the EPA concludes that HRIs are not the BSER for all coal-
fired EGUs.
    The EPA is thus proposing to adopt a new policy and change its
regulatory scheme for coal-fired power plants. As discussed in section
X.C.3 of this preamble, the EPA is proposing to subcategorize coal-
fired power plants according to the time that they will continue to
operate. For sources in the imminent-term and near-term subcategories--
which include sources that, in general, have federally enforceable
commitments to permanently cease operations by 2032 or 2035,
respectively--the EPA is proposing that the BSER is routine methods of
operation and maintenance, with associated presumptive standards of
performance that do not permit an increased emission rate and are not
anticipated to have a rebound effect; and the EPA is soliciting comment
on whether co-firing some amount of natural gas should be part of the
BSER. For sources in the medium-term subcategory--which includes
sources that are not in the other subcategories and that have a
federally enforceable commitment to permanently cease operations by
2040--the EPA is proposing that the BSER is co-firing 40 percent by
volume natural gas. The EPA concludes this control measure is
appropriate because it achieves substantial reductions at reasonable
cost. In addition, the EPA believes that because a large supply of
natural gas is available, devoting part of this supply for fuel for a
coal-fired steam generating unit in place of a percentage of the coal
burned at the unit is an appropriate use of natural gas and will not
adversely impact the energy system, as described in section
X.D.2.b.iii(B) of this preamble.
    For sources in the long-term subcategory--which includes sources
that do not have a federally enforceable commitment to permanently
cease operations by 2040--the EPA is proposing that the BSER is CCS
with 90 percent capture of CO2. The EPA believes that this
control measure is appropriate because it achieves substantial
reductions at reasonable cost, as described in section X.D.1.c of this
preamble.
    The EPA is not proposing HRI as the BSER for any coal-fired EGUs.
As discussed in section X.D.5.a, the EPA does not consider HRIs an
appropriate BSER for the imminent-term and near-term subcategories
because these technologies would achieve few, if any, emissions
reductions and may increase emissions due to the rebound effect. The
EPA is proposing to reject HRI as the BSER for the medium-term and
long-term subcategories because HRI could also lead to a rebound
effect. Most importantly, changed circumstances show that co-firing
natural gas and CCS are available at reasonable cost, and will achieve
more GHG emissions reductions. Accordingly, the EPA believes that HRI
do not qualify as the BSER for any coal-fired EGUs, and that other
approaches meet the statutory standard. For these reasons, the EPA
proposes to repeal the ACE Rule.

D. Insufficiently Precise Degree of Emission Limitation Achievable From
Application of the BSER

    The third independent reason why the EPA is proposing to repeal the
ACE Rule is that the rule did not identify with sufficient specificity
the BSER or the degree of emission limitation achievable through the
application of the BSER. Thus, States lacked adequate guidance on the
BSER they should consider and level of emission reduction that the
standards of performance must achieve. The ACE Rule determined the BSER
to be a suite of HRI ``candidate technologies,'' but did not identify
with specificity the degree of emission limitation States should apply
in developing standards of performance for their sources. As a result,
the ACE Rule conflicted with CAA section 111 and the implementing
regulations, and thus failed to provide States adequate guidance so
that they could ensure that their State plans were satisfactory and
approvable by the EPA.
    CAA section 111 and the EPA's long-standing implementing
regulations establish a clear process for the EPA and States to
regulate emissions of certain air pollutants from existing sources.
``The statute directs EPA to (1) `determine[ ],' taking into account
various factors, the `best system of emission reduction which . . . has
been adequately demonstrated,' (2) ascertain the `degree of emission
limitation achievable through the application' of that system, and (3)
impose an emissions limit on new stationary sources that `reflects'
that amount.'' West Virginia v. EPA, 142 S. Ct. 2587, 2601 (2022)
(quoting 42 U.S.C. 7411(d)). Further, ``[a]lthough the States set the
actual rules governing existing power plants, EPA itself still retains
the primary regulatory role in Section 111(d) . . . [and] decides the
amount of pollution reduction that must ultimately be achieved.'' Id.
at 2602.
    Once the EPA makes these determinations, the State must establish
``standards of performance'' for its sources that are based on the
degree of emission limitation that the EPA determines in the emissions
guidelines. CAA section 111(a)(1) makes this clear through its
definition of ``standard of performance'' as ``a standard for emissions
of air pollutants which reflects the degree of emission limitation
achievable through the application of the [BSER].'' After the EPA
determines the BSER, 40 CFR 60.22(b)(5), and the degree of emission
limitation achievable from application of the BSER, ``the States then
submit plans containing the emissions restrictions that they intend to
adopt and enforce in order not to exceed the permissible level of
pollution established by EPA.'' 142 S. Ct. at 2602 (citing 40 CFR
60.23, 60.24; 42 U.S.C. 7411(d)(1)).
    The EPA then reviews the plan and approves it if the standards of
performance are ``satisfactory,'' under CAA section 111(d)(2)(A). The
EPA's long-standing implementing regulations make clear that the EPA's
basis for determining whether the plan is ``satisfactory'' includes
that the plan must contain ``emission standards . . . no less stringent
than the corresponding emission guideline(s).'' 40 CFR 60.24(c). The
EPA's revised implementing regulations contain the same requirement. 40
CFR 60.24a(c). In addition, under CAA section 111(d)(1), in ``applying
a standard of performance to any particular source'' a State may
consider, ``among other factors, the remaining useful life of the
existing source to which such standard applies.'' This is also known as
the RULOF provision and is discussed in section XII.D.2.
    In the ACE Rule, the EPA recognized that the CAA required it to
determine the BSER and identify the degree of emission limitation
achievable through application of the BSER. 84 FR 32537

(July 8, 2019). But the rule did not make those determinations. Rather,
the ACE Rule described the BSER as a list of ``candidate
technologies.'' And the rule described the degree of emission
limitation achievable by application of the BSER as ranges of
reductions from the HRI technologies. The rule thus shifted the
responsibility for determining the BSER and degree of emission
limitation achievable from the EPA to the States. Accordingly, the ACE
Rule did not meet the CAA section 111 requirement that the EPA
determine the BSER or the degree of emission limitation from
application of the BSER.
    As described above, the ACE Rule identified the HRI in the form of
a list of seven ``candidate technologies,'' accompanied by a wide range
of percentage improvements to heat rate that these technologies could
provide. Indeed, for one of them, improved O&M practices (that is,
operation and management practices), the range was ``0 to >2%'', which
is effectively unbounded. 84 FR 32537 (table 1) (July 8, 2019). The ACE
Rule was clear that this list was simply the starting point for a State
to calculate the standards of performance for its sources. That is, the
seven sets of technologies were ``candidate[s]'' that the State could,
but was not required to, apply and if the State did choose to apply one
or more of them, the State could do so in a manner that yielded any
percentage of heat rate improvement within the range that the EPA
identified, or even outside that range, if the State chose. Thus, as a
practical matter, the ACE Rule did not determine the BSER or any degree
of emission limitation from application of the BSER, and so States had
no guidance on how to craft approvable State plans. In this way, EPA
effectively abdicated its responsibilities, and directed each State to
determine for its sources what the BSER would be (that is, which HRI
technologies should be applied to the source and with what intensity),
and, based on that, what the degree of emission limitation achievable
by application of the BSER. See 84 FR 32537-38 (July 8, 2019).
    The only constraints that the ACE Rule imposed on the States were
procedural ones, and those did not give the EPA any benchmark to
determine whether a plan could be approved or give the States any
certainty on whether their plan would be approved. As noted above, when
a State submitted its plan, it needed to show that it evaluated each
candidate technology for each source or group of sources, explain how
it determined the degree of emission limitation achievable, and include
data about the sources. But because the ACE Rule did not identify a
BSER or include a degree of emission limitation that the standards must
reflect, the States lacked specific guidance on how to craft adequate
standards of performance, and the EPA had no benchmark against which to
evaluate whether a State's submission was ``satisfactory'' under CAA
section 111(d)(2)(A). Thus, the EPA's review of State plans was
essentially a standardless exercise, notwithstanding the Agency's
longstanding view that it was ``essential'' that ``EPA review . . .
[state] plans for their substantive adequacy.'' 40 FR 53342-43
(November 17, 1975). In 1975, the EPA explained that it was not
appropriate to limit its review based ``solely on procedural criteria''
because otherwise ``states could set extremely lenient standards . . .
so long as EPA's procedural requirements were met.'' Id. at 53343.
    Finally, the ACE Rule's approach to determining the BSER and degree
of emission limitation departed from prior emission guidelines under
CAA section 111(d), in which the EPA included a numeric degree of
emission limitation. See, e.g., 42 FR 55796, 55797 (October 18, 1977)
(limiting emission rate of acid mist from sulfuric acid plants to 0.25
grams per kilogram of acid); 44 FR 29828, 29829 (May 22, 1979)
(limiting concentrations of total reduced sulfur from most of the
subcategories of kraft pulp mills, such as digester systems and lime
kilns, to 5, 20, or 25 ppm over 12-hour averages); 61 FR 9905, 9919
(March 12, 1996) (limiting concentration of non-methane organic
compounds from solid waste landfills to 20 parts per million by volume
or 98-percent reduction). In the ACE Rule, the EPA did not grapple with
this change in position as required by FCC v. Fox Television Stations,
Inc., 556 U.S. 502 (2009), or explain why it was appropriate to provide
a boundless degree of emission limitation achievable in this context.
    For this reason, the EPA proposes to repeal the ACE Rule. Its
failure to determine the BSER and the associated degree of emission
limitation achievable from application of the BSER deviated from CAA
section 111 and the implementing regulations. Without these
determinations, the ACE Rule lacked any benchmark that would guide the
States in developing their State plans, and by which the EPA could
determine whether those State plans were satisfactory.

E. ACE Rule's Preclusion of Emissions Trading or Averaging

    While not an independent basis for repeal, the ACE Rule also
interpreted CAA section 111(d) to bar States from allowing emissions
trading or averaging among their sources in all cases, which further
shows that the ACE Rule misconstrued section 111(d) and the appropriate
roles for the EPA and for the States. A trading program might allocate
allowances authorizing a particular level of emissions; a facility
would not need to reduce its emissions so long as it traded for
sufficient allowances. And an averaging program, for example, might
require a group of facilities to reduce their average emissions to a
particular level. So long as some facilities reduced their emissions
sufficiently below that level, it would not be necessary for every
facility to reduce its emissions. Cf. Chevron U.S.A., Inc. v. Natural
Res. Def. Council, Inc., 467 U.S. 837, 863 n.37 (1984) (explaining the
` ``bubble' or `netting' concept). CAA section 111(d) accords States
discretion in developing State plans, and allows States to include
compliance flexibilities like trading or averaging in circumstances the
EPA has determined are appropriate, as long as the plan achieves
equivalent emissions reductions to the EPA's emission guidelines. The
ACE Rule's legal interpretation that CAA section 111(d) always
precludes the State from adopting those flexibilities was incorrect.
    Under CAA section 111, EPA promulgates emission guidelines that
identify the degree of emission limitation achievable through the
application of the BSER as determined by the Administrator. Each State
must then ``submit to the Administrator a plan'' to achieve the degree
of emission limitation identified by EPA. 42 U.S.C. 7411(d)(a). That
plan must ``establish[ ] standards of performance for any existing
source'' that emits certain air pollutants, and also ``provide[ ] for
the implementation and enforcement of such standards of performance.''
Under CAA section 111(a)(1), a ``standard of performance'' is defined
as ``a standard for emissions of air pollutants which reflects the
degree of emission limitation achievable through the application of the
[BSER].'' Although such standards of performance must ``reflect[ ] the
degree of emission limitation achievable through the application of the
[BSER],'' 42 U.S.C. 7411(a)(1), States need not compel regulated
sources to adopt the particular components of the BSER itself.
    The ACE Rule interpreted CAA section 111(a)(1) and (d) to preclude
States from allowing their sources to trade or average to demonstrate
compliance with their standards of performance. 84 FR 32556-57 (July 8,

2019). The ACE Rule based this interpretation on its view that CAA
section 111 limits the type of ``system'' that the EPA may select as
the BSER to ``measures that apply at and to an individual source and
reduce emissions from that source.'' Id. at 32523-24. The ACE Rule also
concluded that the compliance measures the States include in their
plans ``should correspond with the approach used to set the standard in
the first place,'' and therefore must also be limited to measures that
apply at and to an individual source and reduce emissions from that
source. Id. at 32556.
    In its recently published notice of proposed rulemaking to amend
the CAA section 111(d) implementing regulations, the EPA has proposed
to determine that the ACE Rule's legal interpretation as to the type of
``system'' that may be selected as a BSER, and the universal
prohibition of trading and averaging, was incorrect. ``Implementing
Regulations under 40 CFR part 60 Subpart Ba Adoption and Submittal of
State Plans for Designated Facilities: Proposed Rule,'' 87 FR 79176,
79207-79208 (December 23, 2022). As discussed in that document, no
provision in CAA section 111(d), by its terms, precludes States from
having flexibility in determining which measures will best achieve
compliance with the EPA's emission guidelines.
    Specifically, the plain language of section 111(d) does not
affirmatively bar States from considering averaging and trading as a
compliance measure where appropriate for a particular emission
guideline. Under section 111(d)(1), States must ``establish[ ],''
``implement[ ],'' and ``enforce[ ]'' ``standards of performance for any
existing source.'' A State plan that specifies what each existing
source must do to satisfy plan requirements is naturally characterized
as establishing ``standards of performance for [each] existing
source,'' even if measures like trading and averaging are identified as
potential means of compliance. Trading and averaging programs may be
appropriate as a policy matter as well because, in some circumstances,
they can help to ensure that costs are reasonable by enabling market
force to identify the facilities whose emissions can be reduced most
cost-effectively. Nothing in the text of section 111 precludes States
from considering a source's acquisition of allowances in implementing
and enforcing a standard of performance for that particular source, so
long as the State plan achieves the required level of emission
reductions.
    Further supporting this statutory interpretation, section 111(d)
requires a ``procedure similar to that provided by Section 7410.''
Consideration of the section 110 framework reinforces the absence of
any mandate that States consider only compliance measures that apply at
and to an individual source. ``States have `wide discretion' in
formulating their plans'' under section 110. Alaska Dep't of Envtl.
Conservation v. EPA, 540 U.S. 461, 470 (2004) (citation omitted); see
Union Elec. Co. v. EPA, 427 U.S. 246, 269 (1976) (``Congress plainly
left with the States, so long as the national standards were met, the
power to deter-mine which sources would be burdened by regulation and
to what extent.''); Train v. Natural Res. Def. Council, Inc., 421 U.S.
60, 79 (1975) (``[S]o long as the ultimate effect of a State's choice
of emission limitations is compliance with the national standards for
ambient air, the State is at liberty to adopt whatever mix of emission
limitations it deems best suited to its particular situation.'').
Exercising that discretion, States have included measures that do not
apply at or to a source in their section 1410 plans. For example,
States have employed NOX and SO2 trading programs
to comply with section 7410(a)(2)(D)(i)(I), the ``Good Neighbor
Provision.'' Section 110 thus does not distinguish between measures
that do or don't apply at or to a source for compliance, and there is
no sound reason to read section 111's comparably broad language
differently.
    Such flexibility is consistent with the framework of cooperative
federalism that CAA section 111(d) establishes, which vests States with
substantial discretion. As the U.S. Supreme Court has explained, CAA
section 111(d) ``envisions extensive cooperation between federal and
state authorities, generally permitting each State to take the first
cut at determining how best to achieve EPA emissions standards within
its domain.'' American Elec. Power Co. v. Connecticut, 564 U.S. 410,
428 (2011) (citations omitted).
    To be sure, as discussed above, EPA retains an important role in
reviewing State plans for adequacy. Under 111(d), each State must
``submit to the Administrator a plan'' to achieve the degree of
emission limitation identified by EPA. That plan must ``establish[ ]
standards of performance for any existing source for [the] air
pollutant'' and also ``provide[ ] for the implementation and
enforcement of such standards of performance.'' Id. If a State elects
not to submit a plan, or submits a plan that EPA does not find
``satisfactory,'' EPA must promulgate a plan that establishes Federal
standards of performance for the State's existing sources. 42 U.S.C.
7411(d)(2)(A). Thus, the flexibility that CAA section 111(d) grants to
States in adopting measures for their State plans is not unfettered. As
the Supreme Court stated in West Virginia, ``The Agency, not the
States, decides the amount of pollution reduction that must ultimately
be achieved.'' 142 S. Ct. at 2602. State plans then must contain
``emissions restrictions that they intend to adopt and enforce in order
not to exceed the permissible level of pollution established by EPA.''
Id. Thus, EPA bears the burden of ensuring that the permissible level
of pollution is not exceeded by any State plan. When a compliance
flexibility compromises the ability of the State plan to achieve the
necessary emission reductions, then the EPA may reasonably preclude
reliance on such measures, or otherwise conclude that the State plan is
not satisfactory.
    Thus, the EPA proposed to disagree with the ACE Rule's conclusion
that State plan compliance measures must always apply at and to an
individual source and reduce emissions of that source. As noted in
section V.B.6, the U.S. Supreme Court in West Virginia v. EPA, 142 S.
Ct. 2587 (2022), did not address the scope of the States' compliance
flexibilities in developing State plans. The Court also declined to
address whether CAA section 111 limits the type of ``system'' the EPA
may consider to measures that apply substantially at and to an
individual source. See id. at 2615.
    For these reasons, in its notice of proposed rulemaking to amend
the CAA section 111(d) implementing regulations, EPA proposes to
interpret CAA section 111 as permitting each State to adopt measures
that allow its sources to meet their emissions limits in the aggregate,
when the EPA determines, in any particular emission guideline, that it
is appropriate to do so, given, inter alia, the pollution, sources, and
standards of performance at issue. Thus, it is the EPA's proposed
position that CAA 111(d) authorizes the EPA to approve State plans
under particular emission guidelines that achieve the requisite
emission limitation through the aggregate reductions from those
sources, including through trading or averaging where appropriate for a
particular emission guideline and consistent with the intended
environmental outcomes of the guideline. As discussed in section XII.E,
the EPA is proposing to allow trading and averaging under the proposed
emission guidelines and requesting comment on whether and how such
compliance mechanisms could be

implemented to ensure equivalency with the emission reductions that
would be achieved if each affected source was achieving its applicable
standard of performance.
    The ACE Rule's flawed legal interpretation that CAA section 111(d)
universally precludes States from emissions trading is incorrect and
adds to EPA's rationale for proposing to repeal the rule.

X. Proposed Regulatory Approach for Existing Fossil Fuel-Fired Steam
Generating Units

A. Overview

    In this section of the preamble, the EPA explains the basis for its
proposed emission guidelines for GHG emissions from existing fossil
fuel-fired steam generating units for States' use in plan development.
This includes proposing different subcategories of designated
facilities, the BSER for each subcategory, and the degree of emission
limitation achievable by application of each proposed BSER. The EPA is
proposing subcategories for steam generating units based on the type
and amount of fossil fuel (i.e., coal, oil, and natural gas) fired in
the unit.
    For existing coal-fired steam generating units that plan to operate
in the long-term, the EPA is proposing CCS with 90 percent capture as
BSER, based on a review of emission control technologies detailed
further in this section of the preamble and accompanying TSDs,
available in the docket. The EPA is soliciting comment on a range of
maximum capture rates (90 to 95 percent or greater) and, to potentially
account for the amount of time the capture equipment operates relative
to operation of the steam generating unit, a slightly lower achievable
degree of emission limitation (75 to 90 percent reduction in average
annual emission rate, defined in terms of pounds of CO2 per
unit of generation).
    During the EPA's engagement with stakeholders to inform this
proposed rule, industry stakeholders noted that many coal-fired sources
have plans to permanently cease operation in the coming years, and that
GHG control technologies might not be cost reasonable for those units
operating on shorter timeframes. These stakeholders recommended that
the emission guidelines account for industry plans for permanently
ceasing operation of coal-fired steam generating units by establishing
a ``subcategory pathway'' with less stringent requirements.
    Consistent with this stakeholder input, the EPA proposes to provide
subcategories for coal-fired steam generating units planning to
permanently cease operations in the 2030s. The EPA recognizes that the
cost reasonableness of GHG control technology options differ depending
on a coal-fired steam generating unit's expected operating time
horizon. Accordingly, the EPA is proposing to divide the subcategory
for coal-fired units into additional subcategories based on operating
horizon (i.e., dates for electing to permanently cease operation) and,
for one of those subcategories, load level (i.e., annual capacity
factor), with a separate BSER and degree of emission limitation
corresponding to each subcategory. For long-term coal-fired units, the
EPA is proposing that CCS satisfies the BSER criteria, as noted above.
For medium-term units, the EPA is proposing natural gas co-firing at 40
percent of annual heat input as BSER. The EPA is soliciting comment on
the percent of natural gas co-firing from 30 to 50 percent and the
degree of emission limitation defined by a reduction in emission rate
from 12 to 20 percent. For imminent-term and near-term coal-fired steam
generating units, the EPA is proposing a BSER of routine methods of
operation and maintenance. Because of differences in performance
between units, the EPA is proposing to determine the associated degree
of emission limitation as no increase in emission rate. For imminent-
term and near-term coal-fired steam generating units, the EPA is also
soliciting comment on a potential BSER based on low levels of natural
gas co-firing.
    For natural gas- and oil-fired steam generating units, the EPA is
proposing a BSER of routine methods of operation and maintenance and a
degree of emission limitation of no increase in emission rate. Further,
the EPA is proposing to divide subcategories for oil- and natural gas-
fired units based on capacity and, in some cases, geographic location.
Because natural gas- and oil-fired steam generating units with similar
annual capacity factors perform similarly to one another, the EPA is
proposing presumptive standards of performance of 1,300 lb
CO2/MWh-gross for base load units (i.e., those with annual
capacity factors greater than 45 percent) and 1,500 lb CO2/
MWh-gross for intermediate load units (i.e., those with annual capacity
factors between 8 and 45 percent). Because natural gas- and oil-fired
steam generating units with low load have large variations in emission
rate, the EPA is not proposing a BSER or degree of emission limitation
for those units in this action. However, the EPA is soliciting comment
on a potential BSER of ``uniform fuels'' and degree of emission
limitation defined on a heat input basis by 120 to 130 lb
CO2/MMBtu for low load natural gas-fired steam generating
units and 150 to 170 lb CO2/MMBtu for low load oil-fired
steam generating units. Also, because non-continental oil-fired steam
generating units operate at intermediate and base load, and because
there are relatively few of those units for which to define a limit on
a fleet-wide basis, the EPA is proposing a degree of emission
limitation for those units of no increase in emission rate and
presumptive standards based on unit-specific emission rates, as
detailed in section XII of this preamble. The EPA is soliciting comment
on ranges of annual capacity factors to define the thresholds between
the load levels and ranges in the degrees of emission limitation, as
specified in section X.E of this preamble.
    It should be noted that the EPA is proposing a compliance date of
January 1, 2030, as discussed in section XII of this preamble on State
plan development.
    The remainder of this section is organized into the following
subsections. Subsection B describes the proposed applicability
requirements for existing steam generating units. Subsection C provides
the explanation for the proposed subcategories. Subsection D contains,
for coal-fired steam generating units, a summary of the systems
considered for the BSER, detailed discussion of the systems and other
options considered, and explanation and justification for the
determination of BSER and degree of emission limitation. Subsection E
contains, for natural gas- and oil-fired steam generating units, a
summary of the systems considered for the BSER, detailed discussion of
the systems and other options considered, and explanation and
justification for the determination of BSER and degree of emission
limitation.

B. Applicability Requirements for Existing Fossil Fuel-Fired Steam
Generating Units

    For the emission guidelines, the EPA is proposing that a designated
facility \524\ is any fossil fuel-fired electric utility steam
generating unit (i.e., utility boiler or IGCC unit) that: (1) Was in
operation or had commenced construction on or

before January 8, 2014; \525\ (2) serves a generator capable of selling
greater than 25 MW to a utility power distribution system; and (3) has
a base load rating greater than 260 GJ/h (250 MMBtu/h) heat input of
fossil fuel (either alone or in combination with any other fuel).
Consistent with the implementing regulations, the term ``designated
facility'' is used throughout this preamble to refer to the sources
affected by these emission guidelines.\526\ For this action, consistent
with prior CAA section 111 rulemakings concerning EGUs, the term
``designated facility'' refers to a single EGU that is affected by
these emission guidelines. The rationale for this proposal concerning
applicability is the same as that for 40 CFR part 60, subpart TTTT (80
FR 64543-44; October 23, 2015). The EPA incorporates that discussion by
reference here.
---------------------------------------------------------------------------

    \524\ The term ``designated facility'' means ``any existing
facility . . . which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
    \525\ Under CAA section 111, the determination of whether a
source is a new source or an existing source (and thus potentially a
designated facility) is based on the date that the EPA proposes to
establish standards of performance for new sources.
    \526\ The EPA recognizes, however, that the word ``facility'' is
often understood colloquially to refer to a single power plant,
which may have one or more EGUs co-located within the plant's
boundaries.
---------------------------------------------------------------------------

    Section 111(a)(6) of the CAA defines an ``existing source'' as
``any stationary source other than a new source.'' Therefore, the
emission guidelines would not apply to any EGUs that are new after
January 8, 2014, or reconstructed after June 18, 2014, the
applicability dates of 40 CFR part 60, subpart TTTT. Moreover, because
the EPA is now proposing revised standards of performance for coal-
fired steam generating units that undertake a modification, a modified
source would be considered ``new,'' and therefore not subject to these
emission guidelines, if the modification occurs after the date this
proposal is published in the Federal Register. Any source that has
modified prior to that date would be considered an existing source that
is subject to these emission guidelines.
    In addition, the EPA is proposing to include in the applicability
requirements of the emission guidelines the same exemptions as
discussed for 40 CFR part 60, subpart TTTT in section VII.E.1 of this
preamble. Designated EGUs that may be excluded from a State plan are:
(1) Units that are subject to 40 CFR part 60, subpart TTTT, as a result
of commencing a qualifying modification or reconstruction; (2) steam
generating units subject to a federally enforceable permit limiting
net-electric sales to one-third or less of their potential electric
output or 219,000 MWh or less on an annual basis and annual net-
electric sales have never exceeded one-third or less of their potential
electric output or 219,000 MWh; (3) non-fossil fuel units (i.e., units
that are capable of deriving at least 50 percent of heat input from
non-fossil fuel at the base load rating) that are subject to a
federally enforceable permit limiting fossil fuel use to 10 percent or
less of the annual capacity factor; (4) CHP units that are subject to a
federally enforceable permit limiting annual net-electric sales to no
more than either 219,000 MWh or the product of the design efficiency
and the potential electric output, whichever is greater; (5) units that
serve a generator along with other steam generating unit(s), where the
effective generation capacity (determined based on a prorated output of
the base load rating of each steam generating unit) is 25 MW or less;
(6) municipal waste combustor units subject to 40 CFR part 60, subpart
Eb; (7) commercial or industrial solid waste incineration units that
are subject to 40 CFR part 60, subpart CCCC; or (8) EGUs that derive
greater than 50 percent of the heat input from an industrial process
that does not produce any electrical or mechanical output or useful
thermal output that is used outside the affected EGU. The EPA solicits
comment on the proposed definition of ``designated facility'' and
applicability exemptions for fossil fuel-fired steam generating units.
    The exemptions listed above at (4), (5), (6), and (7) are among the
current exemptions at 40 CFR 60.5509(b), as discussed in section
VII.E.1 of this preamble. The exemptions listed above at (2), (3), and
(8) are exemptions the EPA is proposing to revise for 40 CFR part 60,
subpart TTTT, and the rationale for proposing the exemptions is in
section VII.E.1 of this preamble. For consistency with the
applicability requirements in 40 CFR part 60, subpart TTTT, we are
proposing these same exemptions for the applicability of the emission
guidelines.
    The EPA is, in general, proposing the same emission guidelines for
fossil fuel-fired steam generating units in non-continental areas
(i.e., Hawaii, the Virgin Islands, Guam, American Samoa, the
Commonwealth of Puerto Rico, and the Northern Mariana Islands) and non-
contiguous areas (non-continental areas and Alaska) as the EPA is
proposing for comparable units in the contiguous 48 States. However,
units in non-continental and non-contiguous areas operate on small,
isolated electric grids, may operate differently from units in the
contiguous 48 States, and may have limited access to certain components
of the proposed BSER due to their uniquely isolated geography or
infrastructure. Therefore, the EPA is soliciting comment on the
proposed BSER and degrees of emission limitation for units in non-
continental and non-contiguous areas, and the EPA is soliciting comment
on whether those units in non-continental and non-contiguous areas
should be subject to different, if any, requirements.
    The EPA notes that existing IGCC units are included in the proposed
applicability requirements and that, in section X.C.1 of this preamble,
the EPA is proposing to include those units in the subcategory of coal-
fired steam generating units. IGCC units gasify coal or solid fossil
fuel (e.g., pet coke) to produce syngas (a mixture of carbon monoxide
and hydrogen), and either burn the syngas directly in a combined cycle
unit or use a catalyst for water-gas shift (WGS) to produce a pre-
combustion gas stream with a higher concentration of CO2 and
hydrogen, which can be burned in a hydrogen turbine combined cycle
unit. As described in section X.D of this preamble, the proposed BSER
for coal-fired steam generating units includes co-firing natural gas
and CCS, depending on their operating horizon. The few IGCC units that
now operate in the U.S. either burn natural gas exclusively--and as
such operate as natural gas combined cycle units--or in amounts near to
the 40 percent level of the natural gas co-firing BSER. Additionally,
IGCC units are suitable for pre-combustion CO2 capture.
Because the CO2 concentration in the pre-combustion gas,
after WGS, is high relative to coal-combustion flue gas, pre-combustion
CO2 capture for IGCC units can be performed using either an
amine-based capture process or a physical absorption capture process.
For these reasons, the EPA is not proposing to distinguish IGCC units
from other coal-fired steam generating EGUs, so that the BSER of co-
firing for medium-term coal-fired units and CCS for long-term coal-
fired units apply to IGCC units.\527\
---------------------------------------------------------------------------

    \527\ For additional details on pre-combustion CO2
capture, please see the GHG Mitigation Measures for Steam Generating
Units TSD.
---------------------------------------------------------------------------

C. Subcategorization of Fossil Fuel-Fired Steam Generating Units

    Steam generating units can have a broad range of technical and
operational differences. Based on these differences, they may be
subcategorized, and different BSER and degrees of emission limitation
may be applicable to different subcategories. Subcategorizing allows
for determining the most appropriate

control requirements for a given class of steam generating unit.
Therefore, the EPA is proposing subcategories for steam generating
units based on fossil fuel type, operating horizon and load level, and
is proposing different BSER and degrees of emission limitation for
those different subcategories. The EPA notes that in section XII.B of
this preamble comment is solicited on the compliance deadline (i.e.,
January 1, 2030), for imminent-term and near-term coal-fired steam
generating units, and different subcategories of natural gas- and oil-
fired steam generating units.
1. Subcategorization by Fossil Fuel Type
    In this action, the EPA is proposing definitions for subcategories
of existing fossil fuel-fired steam generating units based on the type
and amount of fossil fuel used in the unit. The subcategory definitions
proposed for these emission guidelines are based on the definitions in
40 CFR part 63, subpart UUUUU, and using the fossil fuel definitions in
40 CFR part 60, subpart TTTT.
    A coal-fired steam generating unit is an electric utility steam
generating unit or IGCC unit that meets the definition of ``fossil
fuel-fired'' and that burns coal for more than 10.0 percent of the
average annual heat input during the 3 calendar years prior to the
proposed compliance deadline (i.e., January 1, 2030), or for more than
15.0 percent of the annual heat input during any one of those calendar
years, or that retains the capability to fire coal after December 31,
2029.
    An oil-fired steam generating unit is an electric utility steam
generating unit meeting the definition of ``fossil fuel-fired'' that is
not a coal-fired steam generating unit and that burns oil for more than
10.0 percent of the average annual heat input during the 3 calendar
years prior to the proposed compliance deadline (i.e., January 1,
2030), or for more than 15.0 percent of the annual heat input during
any one of those calendar years, and that no longer retains the
capability to fire coal after December 31, 2029.
    A natural gas-fired steam generating unit is an electric utility
steam generating unit meeting the definition of ``fossil fuel-fired''
that is not a coal-fired or oil-fired steam generating unit and that
burns natural gas for more than 10.0 percent of the average annual heat
input during the 3 calendar years prior to the proposed compliance
deadline (i.e., January 1, 2030), or for more than 15.0 percent of the
annual heat input during any one of those calendar years, and that no
longer retains the capability to fire coal after December 31, 2029.
2. Subcategorization of Natural Gas- and Oil-Fired Steam Generating
Units by Load Level
    The EPA is also proposing additional subcategories for oil-fired
and natural gas-fired steam generating units, based on load levels:
``low'' load, defined by annual capacity factors less than 8 percent;
``intermediate'' load, defined by annual capacity factors greater than
or equal to 8 percent and less than 45 percent; and ``base'' load,
defined by annual capacity factors greater than or equal to 45 percent.
In addition, the EPA is soliciting comment on a range from 5 to 20
percent to define the threshold value between low and intermediate load
and a range from 40 to 50 percent to define the threshold value between
intermediate and base load. Because non-continental oil-fired units may
operate differently, the EPA is proposing a separate subcategory for
intermediate and base load non-continental oil-fired units. The
rationale for the proposed load thresholds and other subcategories is
detailed in the description of the BSER for oil- and natural gas-fired
steam generating units in section X.E of this preamble.
3. Subcategorization of Coal-Fired Steam Generating Units by Operating
Horizon and Load Level
    The EPA is proposing CCS with 90 percent capture as BSER for
existing coal-fired steam generating units that will operate in the
long-term (i.e., those that intend to operate on or after January 1,
2040), as detailed in section X.D of this preamble. CCS is adequately
demonstrated at coal-fired steam generating units, is cost reasonable,
achieves meaningful reductions in GHG emissions, and meets the other
criteria for the BSER. The EPA is soliciting comment on a range of
maximum capture rates (90 to 95 percent or greater) and, to potentially
account for the amount of time the capture equipment operates relative
to operation of the steam generating unit, a slightly lower achievable
degree of emission limitation (75 to 90 percent reduction in average
annual emission rate, defined in terms of pounds of CO2 per
unit of generation).
    During the EPA's engagement with stakeholders to inform this
proposed rule, industry commenters to the pre-proposal docket noted
that many sources have plans to permanently cease operation in the
coming years, and that GHG control technologies might not be cost
reasonable for those units operating on shorter timeframes. Further,
industry stakeholders recommended that the emission guidelines account
for industry plans for permanently ceasing operation of coal-fired
steam generating units by establishing a ``subcategory pathway.''
Specifically, industry stakeholders requested that, ``[The] EPA should
provide a subcategory pathway for units to decommission/repower into
the early 2030s, which would include enforceable shutdown obligations,
as part of an approach to existing unit guidelines.'' The stakeholders
cited, as a precedent, the EPA's creation of--

    targeted subcategories for unit closures in other contexts, most
notably the cessation of coal subcategory in the 2020 Clean Water
Act (CWA) steam electric effluent guidelines . . . that allows for
decommissioning/repowering by December 31, 2028. This subcategory
allows those facilities that have already filed closure commitments
to continue on a path to decommission/repower these assets without
installing additional control equipment that could extend the lives
of these units to support cost recovery.

    EPA-HQ-OAR-2022-0723-0024. In subsequent comment, industry
stakeholders reiterated that, ``[The] EPA should proactively include a
subcategory that allows for units to opt-in to a federally enforceable
retirement commitment as part of compliance with regulations for
existing sources under CAA section 111(d).'' EPA-HQ-OAR-2022-0723-0038.
Thus, industry stakeholders recommended that EPA allow existing sources
that are on a path to near term retirement to continue on that path
without having to install additional control equipment.
    The proposed emission guidelines are aligned with this
recommendation. Many fossil fuel-fired steam generating units have
plans to cease operations, are part of utilities with commitments to
net zero power by certain dates, or are in States or localities with
commitments to net zero power by certain dates. Over one-third of
existing coal-fired steam generating capacity has planned to cease
operation by 2032, and approximately half of the capacity has planned
to cease operations by 2040.\528\ These plans are part of the industry
trend, described in section IV.F and IV.I, in which owners and
operators of the nation's coal fleet, much of it aging, are replacing
their units with natural gas combustion turbines and, increasingly,
renewable energy.
---------------------------------------------------------------------------

    \528\ See the Power Sector Trends TSD.
---------------------------------------------------------------------------

    As industry stakeholders have pointed out, in previous rulemakings,
the EPA has allowed coal-fired EGUs with plans to voluntarily cease
operations in the near future to continue with their plans without
having to install pollution control equipment. In addition to the 2020
CWA steam electric

effluent guidelines these stakeholders cite, the EPA has also approved
regional haze State implementation plans in which coal-fired EGUs that
voluntarily committed to cease operations by a certain date were not
subject to more stringent controls.\529\
---------------------------------------------------------------------------

    \529\ See, e.g., 76 FR 12651, 12660-63 (March 8, 2011) (best
available retrofit technology requirements for Oregon source based
on enforceable retirement that were to be made federally enforceable
in state implementation plan).
---------------------------------------------------------------------------

    The EPA proposes to take the approach requested by industry
stakeholders in this rulemaking. The EPA recognizes that the cost
reasonableness of GHG control technology options differ depending on a
coal-fired steam generating unit's expected operating time horizon.
Certain technologies that are cost reasonable for EGUs that intend to
operate for the long term are less cost reasonable for EGUs with
shorter operating horizons because of shorter amortization periods and,
for CCS, less time to utilize the IRC section 45Q tax credit.
    Accordingly, the EPA is proposing to divide the subcategory for
coal-fired units into additional subcategories based on operating
horizon (i.e., dates for electing to permanently cease operation) and,
for one of those subcategories, load level (i.e., annual capacity
factor), with a separate BSER and degree of emission limitation
corresponding to each subcategory. Coal-fired steam generating units
would be able to opt into these subcategories if they elect to commit
to permanently ceasing operations by a certain date (and, in the case
of one subcategory, elect to commit to an annual capacity factor
limitation), and also elect to make such commitments federally
enforceable and continuing by including them in the State plan.
    Specifically, the EPA is proposing four subcategories for steam
generating units by operating horizon (i.e., enforceable commitments to
permanently cease operations) and, in one case, by load level (i.e.,
annual capacity factor) as well. ``Imminent-term'' steam generating
units are those that (1) Have elected to commit to permanently cease
operations prior to January 1, 2032, and (2) elect to make that
commitment federally enforceable and continuing by having it included
in the State plan.\530\ ``Near-term'' steam generating units are those
that (1) Have elected to commit to permanently cease operations by
December 31, 2034, as well as to adopt an annual capacity factor limit
of 20 percent, and (2) elect to make both conditions federally
enforceable and continuing by having them included in the State plan.
``Medium-term'' steam generating units are those that (1) Operate after
December 31, 2031, (2) have elected to commit to permanently cease
operations prior to January 1, 2040, (3) elect to make that commitment
federally enforceable and continuing by having it included in the State
plan, and (4) do not meet the definition of near-term units. ``Long-
term'' steam generating units are those that have not elected to commit
to permanently cease operations prior to January 1, 2040. Details
regarding the implementation of subcategories in State plans are
available in section XII.D of this preamble.
---------------------------------------------------------------------------

    \530\ Operating conditions that are within the control of a
source must, under a range of CAA programs, be made federally
enforceable in order for a source to rely on them as the basis for a
less stringent standard. See, e.g., 76 FR 12651, 12660-63 (March 8,
2011) (best available retrofit technology requirements for Oregon
source based on enforceable retirement that were to be made
federally enforceable in state implementation plan); Guidance on
Regional Haze State Implementation Plans for the Second
Implementation Period at 34, EPA-457/B-19-003, August 2019 (to the
extent a state relies on an enforceable shutdown date for a
reasonable progress determination, that measure would need to be
included in the SIP and/or be federally enforceable); 84 FR 32520,
32558 (July 8, 2019) (to the extent a state relies on a source's
retirement date for a standard of performance under 111(d), that
date must be included in the state plan and will thus be made
federally enforceable); 87 FR 79176, 79200-01 (December 23, 2022)
(proposed revisions to CAA section 111(d) implementing regulations
would require States to include operating conditions, including
retirements, in their state plans whenever the state seeks to rely
on that operating condition as the basis for a less stringent
standard).
---------------------------------------------------------------------------

    The EPA is proposing the imminent-term subcategory based on a 2-
year operating horizon from the proposed compliance deadline (January
1, 2030, see section XII.B for additional details). This proposed
subcategory is designed to accommodate units with operating horizons
short enough that no additional CO2 control measures would
be cost reasonable. The EPA is proposing the near-term subcategory to
provide an alternative option for units that intend to operate for a
slightly longer horizon but as peaking units, i.e., that intend to run
at lower load levels. The load level of 20 percent for the near-term
subcategory is based on spreading an average 2 years of generation
(i.e., 50 percent in each year, a typical load level) that would occur
under the imminent-term subcategory over the 5-year operating horizon
of the near-term subcategory. The EPA also solicits comment on whether
the existence of the near-term subcategory makes the imminent-term
subcategory unnecessary. More specifically, the EPA requests comment on
the potential to remove the imminent-term subcategory, which as
proposed includes coal-fired steam generating units that have elected
to commit to permanently cease operations prior to January 1, 2032. The
EPA is considering an option in which these units would instead be
included in the near-term subcategory (units that have elected to
commit to permanently cease operations before January 1, 2035 and
commit to adopt an annual capacity factor limit of 20 percent) or the
medium-term subcategory (units that have elected to commit to
permanently cease operations before January 1, 2040 and that are not
near-term units). The EPA further requests comment on an alternative,
modified approach for units in the imminent-term subcategory that could
take into account how units intending to cease operations operate in
practice in the period leading up to such cessation. For instance, in
their last few years of operation, those units may operate less than
they have historically operated, lowering their total CO2
mass emissions, but at the same time raising their emission rate
(because lower utilization may result in lower efficiency). The EPA
solicits comment on whether it would be appropriate for the imminent-
term units' standards of performance to reflect the reduced utilization
and higher emission rates through the use of an annual mass emission
limitation. Such a limitation would account for lower utilization, but
also allow greater flexibility with regard to hourly emission rate.
    The EPA is proposing the 10-year operating horizon (i.e., January
1, 2040) as the threshold between medium-term and long-term
subcategories because long-term units will have a longer amortization
period and may be better able to fully utilize the IRC section 45Q tax
credit. For the analysis of BSER costs of CCS for long-term units, the
EPA assumes a 12-year amortization period as this is commensurate with
the time period the IRC section 45Q tax credit would be available.
Based on the cost analysis performed under that assumption, the EPA is
proposing the costs of CCS for long-term coal-fired units are
reasonable, as detailed in section X.D.1.a.ii of this preamble. To
support the 10-year operating horizon threshold, the costs for a 10-
year amortization period are shown here. For a 10-year amortization
period, assuming a 50 percent capacity factor, costs of CCS for a
representative unit are $31/ton of CO2 reduced or $27/MWh of
generation. Assuming a 70 percent capacity factor, costs of CCS for a
representative unit are $6/ton of CO2

reduced or $5/MWh of generation. For the population of units planning
to operate on or after January 1, 2030, the fleet average costs
assuming a 50 percent capacity factor are $24/ton of CO2
reduced or $22/MWh. For the population of units planning to operate on
or after January 1, 2030, the fleet average costs assuming a 70 percent
capacity factor are -$3/ton of CO2 reduced or -$2/MWh. Costs
vary depending on capacity factor assumptions, but are in either case
generally comparable to the costs detailed in section
VII.F.3.b.iii(B)(5) of this preamble of other controls on EGUs ($10.60
to $29.00/MWh) and less than the costs in the 2016 NSPS regulating GHGs
for the Crude Oil and Natural Gas source category of $98/ton of
CO2e reduced (80 FR 56627; September 18, 2015). The EPA is
soliciting comment on the dates and load levels used to define the
coal-fired subcategories and is seeking data and analysis on the impact
of those alternative dates and load levels on the compliance
requirements. As noted in section X.D.1.a.ii(C) of this preamble, the
costs for CCS may be reasonable for units with amortization periods as
short as 8 years. Therefore, the EPA is specifically soliciting comment
on an operating horizon of between 8 and 10 years (i.e., January 1,
2038, to January 1, 2040) to define the date for the threshold between
medium-term and long-term coal-fired steam generating units.
4. Legal Basis for Subcategorization
    As noted in section V of this preamble, the EPA has broad authority
under CAA section 111(d) to identify subcategories. As also noted in
section V, the EPA's authority to ``distinguish among classes, types,
and sizes within categories,'' as provided under CAA section 111(b)(2)
and as we interpret CAA section 111(d) to provide as well, generally
allows the Agency to place types of sources into subcategories when
they have characteristics that are relevant to the controls that the
EPA may determine to be the BSER for those sources. One element of the
BSER is cost reasonableness. See CAA section 111(d)(1) (requiring the
EPA, in setting the BSER, to ``tak[e] into account the cost of
achieving such reduction''). As noted in section V, the EPA's long-
standing regulations under CAA section 111(d) explicitly recognize that
subcategorizing may be appropriate for sources based on the ``costs of
control.'' \531\ Subcategorizing on the basis of operating horizon is
consistent with a central characteristic of the coal-fired power
industry that is relevant for determining the cost reasonableness of
control requirements: A large percentage of the industry has announced,
or is expected to announce, dates for ceasing operation, and the fact
that many coal-fired steam generating units intend to cease operation
affects what controls are ``best'' for different subcategories. Whether
the costs of control are reasonable depends in part on the period of
time over which the affected sources can amortize those costs. Sources
that have shorter operating horizons will have less time to amortize
capital costs and the controls will thereby be less cost-effective and
therefore may not qualify as the BSER.\532\
---------------------------------------------------------------------------

    \531\ 40 CFR 60.22(b)(5), 60.22a(b)(5).
    \532\ Steam Electric Reconsideration Rule, 85 FR 64650, 64679
(October 13, 2020) (distinguishes between EGUs retiring before 2028
and EGUs remaining in operation after that time).
---------------------------------------------------------------------------

    In addition, subcategorizing by length of period of continued
operation is similar to two other bases for subcategorization on which
the EPA has relied in prior rules, each of which implicates the cost
reasonableness of controls: The first is load level, noted in section
X.C of this preamble. For example, in the 2015 NSPS, the EPA divided
new natural gas-fired combustion turbines into the subcategories of
base load and non-base load. 80 FR 64510, 64602 (table 15) (October 23,
2015). The EPA did so because the control technologies that were
``best''-including consideration of feasibility and cost-
reasonableness--depended on how much the unit operated. The load level,
which relates to the amount of product produced on a yearly or other
basis, bears similarity to a limit on a period of continued operation,
which concerns the amount of time remaining to produce the product. In
both cases, certain technologies may not be cost reasonable because of
the capacity to produce product--i.e., because the costs are spread
over less product produced.
    The second is fuel type, as also noted in section X.C of this
preamble. The 2015 NSPS provides an example of this type of
subcategorization as well. There, the EPA divided new combustion
turbines into subcategories on the basis of type of fuel combusted. Id.
Subcategorizing on the basis of the type of fuel combusted may be
appropriate when different controls have different costs, depending on
the type of fuel, so that the cost-reasonableness of the control
depends on the type of fuel. In that way, it is similar to
subcategorizing by operating horizon because in both cases, the
subcategory is based upon the cost reasonableness of controls.
Subcategorizing by fuel type presents an additional analogy to the
present case of subcategorizing on the basis of the length of time when
the source will continue to operate because this timeframe is
tantamount to the length of time when the source will continue to
combust the fuel. Subcategorizing on this basis may be appropriate when
different controls for a particular fuel have different costs,
depending on the length of time when the fuel will continue to be
combusted, so that the cost-reasonableness of controls depends on that
timeframe. Some prior EPA rules for coal-fired sources have made
explicit the link between length of time for continued operation and
type of fuel combusted by codifying federally enforceable retirement
dates as the dates by which the source must ``cease burning coal.''
\533\
---------------------------------------------------------------------------

    \533\ See 79 FR 5031, 5192 (January 30, 2014) (explaining that
``[t]he construction permit issued by Wyoming requires Naughton Unit
3 to cease burning coal by December 31, 2017 and to be retrofitted
to natural gas as its fuel source by June 30, 2018'' (emphasis
added)).
---------------------------------------------------------------------------

    It should be noted that subcategorizing on the basis of operating
horizon does not preclude a State from considering RULOF in applying a
standard of performance to a particular source. EPA's authority to set
BSER for a source category (including subcategories) and a State's
authority to invoke RULOF for individual sources within a category or
subcategory are distinct. EPA's statutory obligation is to determine a
generally applicable BSER for a source category, and where that source
category encompasses different classes, types, or sizes of sources, to
set generally applicable BSERs for subcategories accounting for those
differences. By contrast, States' authority to invoke RULOF is premised
on the State's ability to take into account the characteristics of a
particular source that may differ from the assumptions EPA made in
determining BSER generally. As noted above, the EPA is proposing these
subcategories in response to requests by power sector representatives
that this rule accommodate the fact that there is a class of sources
that plans to voluntarily cease operations in the near term. Although
the EPA has designed the subcategories to accommodate those requests, a
particular source may still present source-specific considerations--
whether related to its remaining useful life or other factors--that the
State may consider relevant for the application of that particular
source's standard of performance, and that the State should

address as described in section XII.D.2 of this preamble.

D. Determination of BSER for Coal-Fired Steam Generating Units

    The EPA evaluated two primary control technologies as potentially
representing the BSER for existing coal-fired steam generating units:
CCS and natural gas co-firing. This section of the preamble discusses
each of these alternatives, based on the criteria described in section
V.C of this preamble.
    The EPA is proposing CCS with 90 percent capture as BSER for long-
term coal-fired steam generating units, that is, ones that are expected
to continue to operate past 2039, because CCS can achieve an
appropriate amount of emission reductions and satisfies the other BSER
criteria. Because CCS is less cost reasonable for EGUs that do not plan
to operate in the long term, the EPA is proposing other measures as
BSER for the other subcategories of existing coal-fired steam
generating units.
    Specifically, for medium-term units, that is, ones that have
elected to commit to permanently cease operations after December 31,
2031, and before January 1, 2040, and are not near-term units, the EPA
is proposing a BSER of 40 percent natural gas co-firing on a heat input
basis. However, the EPA is taking comment on the operating horizon
(i.e., between 8 and 10 years, instead of the proposed 10-year
operating horizon) that defines the threshold date between medium-term
and long-term coal-fired steam generating units, and it is possible
that the costs of CCS may be considered reasonable for some portion of
the units that may be covered by the medium-term subcategory as
proposed.
    For imminent-term and near-term units, that is, ones that have
elected to commit to permanently cease operations before January 1,
2032, and between December 31, 2031, and January 1, 2035, coupled with
an annual capacity factor limit, respectively, the EPA is proposing a
BSER of routine methods of operation and maintenance that maintain
current emission rates. The EPA is also soliciting comment on a
potential BSER based on low levels of natural gas co-firing for
imminent- and near-term units.
1. Long-Term Coal-Fired Steam Generating Units
    In this section of the preamble, the EPA evaluates CCS and natural
gas co-firing as potential BSER for long-term coal-fired steam
generating units.
    The EPA is proposing CCS with 90 percent capture of CO2
at the stack as BSER for long-term coal-fired steam generating units.
The Agency is taking comment on the range of the amount of capture of
CO2 from 90 to 95 percent or greater. CCS achieves
substantial reductions in emissions and can capture and permanently
sequester more than 90 percent of CO2 emitted by coal-fired
steam generating units. The technology is adequately demonstrated, as
indicated by the facts that it has been operated at scale and is widely
applicable to sources, and there are vast sequestration opportunities
across the continental U.S. Additionally, the costs for CCS are
reasonable, in light of recent technology cost declines and policies
including the tax credit under IRC section 45Q. Moreover, the non-air
quality health and environmental impacts and energy requirements of CCS
are not unreasonably adverse. These factors provide the basis for
proposing CCS as BSER for these sources. In addition, determining CCS
as the BSER promotes this useful GHG emission control technology.
    The EPA also evaluated natural gas co-firing at 40 percent of heat
input as a potential BSER for long-term coal-fired steam generating
units. While the unit level emission rate reductions of 16 percent
achieved by 40 percent natural gas co-firing are reasonable, those
reductions are substantially less than CCS with 90 percent capture of
CO2. Therefore, because CCS achieves more reductions at the
unit level and is cost reasonable, the EPA is not proposing natural gas
co-firing as the BSER for these units.
a. CCS
    In this section of the preamble, the EPA evaluates the use of CCS
as the BSER for existing long-term coal-fired steam generating units.
This section incorporates by reference the parts of section
VII.F.3.b.iii of this preamble that discuss the aspects of CCS that are
common to new combustion turbines and existing steam generating units.
This section also discusses additional aspects of CCS that are relevant
for existing steam generating units and, in particular, long-term
units.
i. Adequately Demonstrated
    The EPA is proposing that CCS is technically feasible and has been
adequately demonstrated, based on the utilization of the technology at
existing coal-fired steam generating units and industrial sources in
addition to combustion turbines. While the EPA would propose that CCS
is adequately demonstrated on those bases alone, this determination is
further corroborated by EPAct05-assisted projects.
    The fundamental CCS technology has been in existence for decades,
and the industry has extensive experience with and knowledge about it.
Indeed, even without the requirements proposed here, the EPA projects
that 9 GW of coal-fired steam generating units would apply CCS by 2030.
Thus, the EPA will explain how existing and planned fossil fuel-fired
electric power plants and other industrial projects that have installed
or expect to install some or all of the components of CCS technology
support the EPA's proposed determination that CCS is adequately
demonstrated for existing coal-fired power plants, and the EPA will
explain how EPAct05-assisted projects support that proposed
determination, consistent with the legal interpretation of the EPAct05
in section VII.F.3.b.iii(A) of this preamble.
(A) CO2 Capture Technology
    The technology of CO2 capture, in general, is detailed
in accompanying TSDs (available in the docket) and in section
VII.F.3.b.iii of this preamble. As noted there, solvent-based (i.e.,
amine-based) post-combustion CO2 capture is the technology
that is most applicable at existing coal-fired steam generating units.
Technology considerations specific to existing coal-fired steam
generating units, including energy demands, non-GHG emissions, and
water use and siting, are discussed in section X.D.1.a.iii of this
preamble. As detailed in section VII.F.3.b.iii(A) of this preamble, the
CO2 capture component of CCS has been demonstrated at
existing coal-fired steam generating units, industrial processes, and
existing combustion turbines. In particular, SaskPower's Boundary Dam
Unit 3 has demonstrated capture rates of 90 percent of the
CO2 in flue gas using solvent-based post-combustion capture
retrofitted to existing coal-fired steam generating units. While the
EPA would propose that the CO2 capture component of CCS is
adequately demonstrated on the basis of Boundary Dam Unit 3 alone,
CO2 capture has been further demonstrated at other coal-
fired steam generating units (CO2 capture from slipstreams
of AES's Warrior Run and Shady Point) and industrial processes (e.g.,
Quest CO2 capture project), detailed descriptions of which
are provided in section VII.F.3.b.iii(A)(2) of this preamble. The core
technology of CO2 capture applied to combustion turbines is
similar to that of coal-fired steam generating units (i.e., both may
use amine solvent-based methods); therefore the demonstration of
CO2 capture at combustion turbines (e.g., the Bellingham,
Massachusetts,

combined cycle unit), as detailed in section VII.F.3.b.iii(A)(3) of
this preamble, provide additional support for the adequate
demonstration of CO2 capture for coal-fired steam generating
units. Finally, EPAct05-assisted CO2 capture projects (e.g.,
Petra Nova) further corroborate the adequate demonstration of
CO2 capture.
(B) CO2 Transport
    As discussed in section VII.F.3.b.iii of this preamble,
CO2 pipelines are available and their network is expanding
in the U.S., and the safety of existing and new supercritical
CO2 pipelines is comprehensively regulated by PHMSA.\534\
Other modes of CO2 transportation also exist.
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    \534\ PHMSA additionally initiated a rulemaking in 2022 to
develop and implement new measures to strengthen its safety
oversight of CO2 pipelines following investigation into a
CO2 pipeline failure in Satartia, Mississippi in 2020.
For more information, see: https://www.phmsa.dot.gov/news/phmsa-announces-new-safety-measures-protect-americans-carbon-dioxide-pipeline-failures.
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    Based on data from DOE/NETL studies of storage resources, 77
percent of existing coal-fired steam generating units that have planned
operation during or after 2030 are within 80 km (50 miles) of potential
saline sequestration sites, and another 5 percent are within 100 km (62
miles) of potential sequestration sites.\535\ Additionally, of the
coal-fired steam generating units with planned operation during or
after 2030, 90 percent are located within 100 km of one or more types
of sequestration formations, including deep saline, unmineable coal
seams, and oil and gas reservoirs. This distance is consistent with the
distances referenced in studies that form the basis for transport cost
estimates in this proposal.536 537 As noted in section
VII.F.3.b.iii(A)(5) of this preamble, areas without reasonable access
to pipelines for geologic sequestration can transport CO2 to
sequestration sites via other transportation modes such as ship, road
tanker, or rail tank cars.
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    \535\ Sequestration potential as it relates to distance from
existing resources is a key part of the EPA's regular power sector
modeling development, using data from DOE/NETL studies. For details
please see Chapter 6 of the IPM documentation available at: https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
    \536\ The pipeline diameter was sized for this to be achieved
without the need for recompression stages along the pipeline length.
    \537\ Note that the determination that the BSER has been
adequately demonstrated does not require that every source in the
long-term coal-fired steam generating unit subcategory be within 100
km of CO2 storage.
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(C) Geologic Sequestration of CO2
    Geologic sequestration (i.e., the long-term containment of a
CO2 stream in subsurface geologic formations) is well proven
and broadly available throughout the U.S. Geologic sequestration is
based on a demonstrated understanding of the processes that affect the
fate of CO2 in the subsurface. As discussed in section
VII.F.3.a.iii of this preamble, there have been numerous instances of
geologic sequestration in the U.S. and overseas, and the U.S. has
developed a detailed set of regulatory requirements to ensure the
security of sequestered CO2. This regulatory framework
includes the UIC Class VI well regulations, which are under the
authority of SDWA, and the GHGRP, under the authority of the CAA.
    Geologic sequestration potential for CO2 is widespread
and available throughout the U.S. Through an availability analysis of
sequestration potential in the U.S. based on resources from the DOE,
the USGS, and the EPA, the EPA found that there are 43 States with
access to, or are within 100 km from, onshore or offshore storage in
deep saline formations, unmineable coal seams, and depleted oil and gas
reservoirs.
    Sequestration potential as it relates to distance from existing
resources is a key part of the EPA's regular power sector modeling
development, using data from DOE/NETL studies.\538\ These data show
that of the coal-fired steam generating units with planned operation
during or after 2030, 60 percent are located within the boundary of a
saline reservoir, 77 percent are located within 40 miles (80 km) of the
boundary of a saline reservoir, and 82 percent are located within 62
miles (100 km) of a saline reservoir. Additionally, of the coal-fired
steam generating units with planned operation during or after 2030, 90
percent are located within 100 km of any of the considered formations,
including deep saline, unmineable coal seams, and oil and gas
reservoirs.539 540 As noted in section VII.F.3.b.iii(A)(5)
of this preamble, areas without reasonable access to pipelines for
geologic sequestration can transport CO2 to sequestration
sites via other transportation modes such as ship, road tanker, or rail
tank cars.
---------------------------------------------------------------------------

    \538\ For details, please see Chapter 6 of the IPM
documentation. https://www.epa.gov/system/files/documents/2021-09/chapter-6-co2-capture-storage-and-transport.pdf.
    \539\ The distance of 100 km is consistent with the assumptions
underlying the NETL cost estimates for transporting CO2
by pipeline.
    \540\ Note that the determination that the BSER has been
adequately demonstrated does not require that every source in the
long-term coal-fired steam generating unit subcategory be within 100
km of CO2 storage.
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ii. Costs
    The EPA has analyzed the costs of CCS for existing coal-fired long-
term sources, including costs for CO2 capture, transport,
and sequestration. The EPA is proposing that this analysis demonstrates
that the costs of CCS for these sources are reasonable. The EPA also
evaluated costs assuming a higher capacity factor of 70 percent
(resulting in lower costs) and different amortization periods, as
discussed in section X.D.1.a.ii(C) of this preamble. The EPA is
soliciting comment on the assumptions in the cost analysis,
particularly with respect to the capacity factor assumption. As
elsewhere in this section of the preamble, costs are presented in 2019
dollars.
    The EPA assessed costs of CCS for a reference unit as well as the
average cost for the fleet of coal-fired steam generating units with
planned operation during or after 2030. The reference unit, which
represents an average unit in the fleet, has a 400 MW-gross nameplate
capacity and a 10,000 Btu/kWh heat rate. Applying CCS to the reference
unit with a 12-year amortization period and assuming a 50 percent
annual capacity factor--a typical value for the fleet--results in
annualized total costs that can be expressed as an abatement cost of
$14/ton of CO2 reduced and an incremental cost of
electricity of $12/MWh. Included in these estimates is the EPA's
assessment that the transport and storage costs are roughly $30/ton, on
average for the reference unit. For the fleet of coal-fired steam
generating units with planned operation during or after 2030, and
assuming a 12-year amortization period and 50 percent annual capacity
factor and including source specific transport and storage costs, the
average total costs of CCS are $8/ton of CO2 reduced and $7/
MWh. These total costs also account for the IRC section 45Q tax credit,
a detailed discussion of which is provided in section
VII.F.3.b.iii(B)(3) of this preamble. Compared to the representative
costs of controls detailed in section VII.F.3.b.iii(B)(5) of this
preamble (i.e., emission control costs on EGUs of $10.60 to $29/MWh and
the costs in the 2016 NSPS regulating GHGs for the Crude Oil and
Natural Gas source category of $98/ton of CO2e reduced (80
FR 56627; September 18, 2015)) the costs for CCS on long-term coal-
fired steam generating units are similar or better. Based on all of
these analyses, the EPA is proposing that for the purposes of the BSER
analysis, CCS is cost reasonable for long-term coal-fired steam
generating units. The EPA also evaluated costs of CCS under

various other assumptions of amortization period and annual capacity
factor. Finally, it is noted that these CCS costs are lower than those
in prior rulemakings due to the IRC section 45Q tax credit and
reductions in the cost of the technology.
(A) CO2 Capture Costs at Existing Coal-Fired Steam
Generating Units
    A variety of sources provide information for the cost of CCS
systems, and they generally agree around a range of cost. The EPA has
relied heavily on information recently developed by NETL, in the U.S.
Department of Energy, in particular, ``Cost and Performance Baseline
for Fossil Energy Plants,'' \541\ and the ``Pulverized Coal Carbon
Capture Retrofit Database.'' \542\ In addition, the EPA developed an
independent engineering cost assessment for CCS retrofits, with support
from Sargent and Lundy.\543\
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    \541\ https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
    \542\ https://netl.doe.gov/energy-analysis/details?id=69db8281-593f-4b2e-ac68-061b17574fb8.
    \543\ Detailed cost information, assessment of technology
options, and demonstration of cost reasonableness can be found in
the GHG Mitigation Measures for Steam Generating Units TSD.
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(B) CO2 Transport and Sequestration Costs
    As discussed in section VII.F.3.b.iii of this preamble, NETL's
``Quality Guidelines for Energy System Studies; Carbon Dioxide
Transport and Sequestration Costs in NETL Studies'' is one of the more
comprehensive sources of information on CO2 transport and
storage costs available. The Quality Guidelines provide an estimation
of transport costs for a single point-to-point pipeline. Estimated
costs reflect pipeline capital costs, related capital expenditures, and
operations and maintenance costs.\544\ These Quality Guidelines also
provide an estimate of sequestration costs reflecting the cost of site
screening and evaluation, permitting and construction costs, the cost
of injection wells, the cost of injection equipment, operation and
maintenance costs, pore volume acquisition expense, and long-term
liability protection. NETL's Quality Guidelines model costs for a given
cumulative storage potential.\545\
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    \544\ Grant, T., et al. ``Quality Guidelines for Energy System
Studies; Carbon Dioxide Transport and Storage Costs in NETL
Studies.'' National Energy Technology Laboratory. 2019. https://www.netl.doe.gov/energy-analysis/details?id=3743.
    \545\ Details on CO2 transportation and sequestration
costs can be found in the GHG Mitigation Measures for Steam
Generating Units TSD.
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(C) Amortization Period and Annual Capacity Factor
    In the EPA's cost analysis for long-term coal-fired steam
generating units, the EPA assumes a 12-year amortization period and a
50 percent annual capacity factor. The 12-year amortization period is
consistent with the period of time during which the IRC section 45Q tax
credit can be claimed and the 50 percent annual capacity factor is
consistent with the historical fleet average. However, increases in
utilization are likely to occur for units that apply CCS due to the
incentives provided by the IRC section 45Q tax credit. Therefore, the
EPA also assessed the costs for CCS retrofitted to existing coal-fired
steam generating units assuming a 70 percent annual capacity factor.
For a 70 percent annual capacity factor and a 12-year amortization
period, the costs for the reference unit are negative at -$8/ton of
CO2 reduced and -$7/MWh. The negative costs indicate that
the value of the 45Q tax credit more than offsets the costs to install
and operate CCS. For either capacity factor assumption, the $/MWh costs
are comparable to or less than the costs for other controls ($10.60-
$29.00/MWh) which are detailed in section VII.F.3.b.iii(B)(5) of this
preamble.
    As noted in section X.C.3 of this preamble, the EPA is also taking
comment on the operating horizon that defines the threshold date
between the definition of medium-term and long-term coal-fired steam
generating units, specifically an operating horizon between 8 and 10
years (i.e., January 1, 2038 to January 1, 2040), instead of the
proposed 10-year operating horizon. For a 70 percent annual capacity
factor and an 8-year amortization period, annualized costs of applying
CCS for the reference unit are $24/ton of CO2 reduced and
$21/MWh, and it is possible that the cost of generation may be
reasonable relative to the representative cost for wet FGD. However,
CCS may be less cost favorable for units with shorter amortization
periods. For a 70 percent annual capacity factor and a 7-year
amortization period, costs for the reference unit are $39/ton of
CO2 reduced and $34/MWh. Additional details of the cost
analysis are available in the GHG Mitigation Measures for Steam
Generating Units TSD.
(D) Comparison to Costs for CCS in Prior Rulemakings
    In the CPP and ACE Rule, the EPA determined that CCS did not
qualify as the BSER due to cost considerations. Two key developments
have led the EPA to reevaluate this conclusion: the costs of CCS
technology have fallen and the extension and increase in the IRC
section 45Q tax credit, as included in the IRA, in effect provide a
significant stream of revenue for sequestered CO2 emissions.
The CPP and ACE Rule relied on a 2015 NETL report estimating the cost
of CCS. NETL has issued updated reports to incorporate the latest
information available, most recently in 2022, which show cost
reductions. The 2015 report estimated incremental levelized cost of CCS
at a new pulverized coal facility relative to a new facility without
CCS at $74/MWh (2022$),\546\ while the 2022 report estimated
incremental levelized cost at $44/MWh (2022$).\547\ Additionally, the
IRA increased the IRC section 45Q tax credit from $50/metric ton to
$85/metric ton (and, in the case of EOR or certain industrial uses,
from $35/metric ton to $60/metric ton), assuming prevailing wage and
apprenticeship conditions are met. The IRA also enhanced the realized
value of the tax credit through the direct pay and transferability
monetization options described in section IV.E.1. The combination of
lower costs and higher tax credits significantly improves the cost
effectiveness of CCS for purposes of determining whether it qualifies
as the BSER.
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    \546\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 3
(July 2015). https://www.netl.doe.gov/projects/files/CostandPerformanceBaselineforFossilEnergyPlantsVolume1aBitCoalPCandNaturalGastoElectRev3_070615.pdf.
    \547\ Cost And Performance Baseline for Fossil Energy Plants
Volume 1: Bituminous Coal and Natural Gas to Electricity, Rev. 4A
(October 2022). https://netl.doe.gov/projects/files/CostAndPerformanceBaselineForFossilEnergyPlantsVolume1BituminousCoalAndNaturalGasToElectricity_101422.pdf.
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iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
    CCS for steam generating units is not expected to have unreasonable
adverse consequences related to non-air quality health and
environmental impacts or energy requirements. The EPA has considered
non-GHG emissions impacts, the water use impacts, the transport and
sequestration of captured CO2, and energy requirements
resulting from CCS. Because the non-air quality health and
environmental impacts are closely related to the energy requirements,
the latter are discussed first.
    As noted in section VII.F.3.b.iii(C) of this preamble, stakeholders
have shared with the EPA concerns about the safety of CCS projects and
concerns that their communities may bear a

disproportionate environmental burden associated with CCS projects. The
EPA is committed to working with its fellow agencies to foster
meaningful engagement with communities and protect communities from
pollution through the responsible deployment of CCS. This can be
facilitated through the existing detailed regulatory framework for CCS
projects and further supported through robust and meaningful public