Liftoff report projects the split of hydrogen production in future
years between electrolytic and SMR.
---------------------------------------------------------------------------

    Further, multiple utilities are pursuing projects to secure
supplies of electrolyzer-based hydrogen for their power projects. As
mentioned earlier in this proposal, Intermountain Power is working with
partners to develop an integrated hydrogen turbine, a hydrogen
production facility, and a hydrogen storage facility in Delta, Utah.
All three components of the project are under construction and are
scheduled to be operational by 2025, with the turbine combusting 30
percent (by volume) low-GHG hydrogen at startup.\582\ FPL has announced
plans to build 30 GW of excess solar to supply clean hydrogen
production to power its turbines and to sell to other customers.\583\
Entergy has entered into multiple agreements to explore the use of
existing and new renewable generating assets and transmission to supply
zero GHG electricity to developers of hydrogen production plants.\584\
Multiple US utilities are collaborating to develop hydrogen hubs.\585\
---------------------------------------------------------------------------

    \582\ https://www.ipautah.com/ipp-renewed/.
    \583\ https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-for-florida-power-light/.
    \584\ https://www.entergynewsroom.com/news/entergy-texas-new-fortress-energy-partner-advance-hydrogen-economy-in-southeast-texas/
and https://www.entergynewsroom.com/news/entergy-texas-monarch-energy-collaborate-advance-southeast-texas-energy-infrastructure-1323187465/.
    \585\ https://news.duke-energy.com/releases/major-southeast-utilities-establish-hydrogen-hub-coalition.
---------------------------------------------------------------------------

c. Costs
    The fact that existing sources are already planning to combust low-
GHG hydrogen, even in the absence of a regulatory requirement, is an
indication that the costs of co-firing are reasonable.
    The EPA has also developed a more specific description of the
costs, which follows. It incorporates some components of the analysis
of costs of co-firing low-GHG hydrogen for new turbines, as discussed
in section VII.F.3.c.vii(B) of this preamble.
    There are three sets of potential costs associated with
retrofitting combustion turbines to co-fire hydrogen: (1) Capital costs
of retrofitting combustion turbines to have the capability of co-firing
hydrogen; (2) pipeline infrastructure to deliver hydrogen; and (3) the
fuel costs related to production of low-GHG hydrogen. While many
combustion turbines are able to fire lower volume blends of hydrogen
with natural gas, not all have the capacity or on-site infrastructure
necessary to blend higher volumes of hydrogen. The primary costs that
combustion turbines would incur would be the fuel costs for low-GHG
hydrogen, along with limited capital retrofit costs, in order to co-
fire hydrogen at the 30 percent and 96 percent levels that the EPA is
proposing as the BSER.
    One company, Constellation Energy Corporation, has estimated the
costs to retrofit existing plants to co-fire hydrogen and has indicated
that they are reasonable: ``We expect $10-$60/kW in retrofit costs to
achieve 30-60% hydrogen blending by volume at our power plants. At
blend levels in the range of 60-100%, OEMs have suggested pricing of
roughly $100/kW.'' \586\ The EPA estimates that if low-GHG hydrogen is
available at a delivered price of $1/kg,\587\ co-firing 30 percent
hydrogen in a combined cycle EGU operating at a capacity factor of 65
percent would increase the levelized cost of electricity (LCOE) by
$2.9/MWh and a 96 percent co-firing rate would increase the LCOE by
$21/MWh.\588\ Regardless of the level of hydrogen co-firing, the
CO2 abatement cost is $64/ton ($70/metric ton) at the
affected facility.\589\ For an aeroderivative simple cycle combustion
turbine operating at a capacity factor of 40 percent, the EPA estimates
co-firing 30 percent low-GHG hydrogen would increase the LCOE by $4.1/
MWh, and a 96 percent co-firing rate would increase the LCOE by $30/
MWh. At a delivered price of $0.75/kg, the CO2 abatement
costs for co-firing hydrogen would be $32/ton ($35/metric ton). For a
combined cycle EGU, the EPA estimates the LCOE increase would be $1.4/
MWh and $11/MWh for the 30 percent and 96 percent cases, respectively.
For a simple cycle EGU, the EPA estimates the LCOE increase would be
$2.1/MWh and $15/MWh for the 30 percent and 96 percent cases,
respectively.
---------------------------------------------------------------------------

    \586\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units Docket ID No. EPA-HQ-OAR-2022-0289, June 6, 2022).
    \587\ The delivered price includes the purchase cost of the fuel
and its transportation costs and the 45V tax credit.
    \588\ The EIA long-term natural gas price for utilities is
$3.69/MMBtu.
    \589\ The abatement cost of co-firing low-GHG hydrogen is
determined by the relative delivered cost of the low-GHG hydrogen
and natural gas.
---------------------------------------------------------------------------

    The EPA is soliciting comment on what additional costs would be
required to ensure that combustion turbines are able to co-fire between
30 to 96 percent low-GHG hydrogen and if there are efficiency impacts
from co-firing hydrogen. Retrofits to add the capacity to combust
higher volumes of hydrogen could include retrofitting the combustor,
increasing the size of the fuel piping, and upgrades to minimize fuel
leakage, hydrogen storage and blending equipment, upgraded control
systems, modification to the continuous emissions monitoring system,
safety upgrades and leakage detectors, modification of the HRSG to
accept higher temperature exhaust, and NOX control
modifications (e.g., upgraded premix combustion technologies).\590\
According to model plant estimates in EPRI's US-REGEN model, the heat
rate of a hydrogen-fired combustion turbine is 5 percent higher than a
comparable natural gas-fired combustion turbine. Furthermore, for
hydrogen-fired combustion turbines relative to a comparable natural
gas-fired combustion turbine, the capital costs are

approximately $70/kW higher, the fixed operating costs are
approximately $1/year per kW higher, and the non-fuel variable
operating costs are approximately $0.5/MWh higher.\591\ While these
costs are for new combustion turbines, the amounts could be higher for
retrofits to combustion turbines. To the extent it is appropriate to
account for additional costs associated with a hydrogen co-firing BSER
for existing combustion turbines, the EPA is soliciting comment on
whether capital and fixed costs should be increased by 9 percent,
consistent with the NETL estimated retrofit costs of CCS relative to
new combustion turbines.
---------------------------------------------------------------------------

    \590\ Simon, Nima, Retrofitting Gas Turbine Facilities for
Hydrogen Blending. November 2, 2022. https://www.icf.com/insights/energy/retrofitting-gas-turbines-hydrogen-blending.
    \591\ https://us-regen-docs.epri.com/v2021a/assumptions/electricity-generation.html#new-generation-capacity.
---------------------------------------------------------------------------

    The EPA is proposing to determine that the increase in operating
costs from a BSER based on low-GHG hydrogen is reasonable.
d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
    The co-firing of hydrogen in combustion turbines in the amounts
that the EPA proposes as the BSER would not have adverse non-air
quality health and environmental impacts. It would potentially result
in increased production of NOX, but those NOX
emissions can be controlled, as described in sections VII.F.3.c.vii.(A)
and XI.C.2.b.i of this preamble.
    In addition, co-firing hydrogen in the amounts proposed would not
have adverse impacts on energy requirements, including either the
requirements of the combustion turbines to obtain fuel or on the energy
sector more broadly, particularly with respect to reliability. As
discussed in sections VII.F.3.c.vii.(A)-(B) and XI.C.2.b.-c. of this
preamble, combustion turbines can be constructed to co-fire high
volumes of hydrogen in lieu of natural gas, and the EPA expects that
low-GHG hydrogen will be available in sufficient quantities and at
reasonable cost. Any impact on the energy sector would be further
mitigated by the large amounts of existing generation that would not be
subject to requirements in this rule and the projected new capacity in
the base case modeling.
e. Extent of Reductions in CO2 Emissions
    The site-specific reduction in CO2 emissions achieved by
a combustion turbine co-firing hydrogen is dependent on the volume of
hydrogen blended into the fuel system. Due to the lower energy density
by volume of hydrogen compared to natural gas, an affected source that
combusts 30 percent by volume hydrogen with natural gas would achieve
approximately a 12 percent reduction in CO2 emissions versus
firing 100 percent natural gas.\592\ A source combusting 100 percent
hydrogen would have zero CO2 stack emissions because
hydrogen contains no carbon, as previously discussed. A source co-
firing 96 percent by volume hydrogen (approximately 89 percent by heat
input) would achieve an approximate 90 percent CO2 emission
reduction, which is roughly equivalent to the emission reduction
achieved by sources utilizing 90 percent CCS.
---------------------------------------------------------------------------

    \592\ The energy density by volume of hydrogen is lower than
natural gas.
---------------------------------------------------------------------------

f. Promotion of the Development and Implementation of Technology
    Determining co-firing 30 percent (by volume) low-GHG hydrogen by
2032 and co-firing 96 percent (by volume) to be components of the BSER
would generally advance technology development in both the production
of low-GHG hydrogen and the use of hydrogen in combustion turbines, for
the same reasons discussed with respect to new combustion turbines in
section VII.F.3.c.vii.(E) of this preamble.
g. Summary
    The EPA proposes that co-firing 30 percent low-GHG hydrogen by 2032
and 96 percent by 2038 qualify as a BSER pathway for large and
frequently-used existing combustion turbines. For the reasons discussed
above, the EPA proposes that co-firing low-GHG hydrogen on that pathway
is adequately demonstrated in light of the capability of combustion
turbines to co-fire hydrogen and the EPA's reasonable expectation that
adequate quantities of low-GHG hydrogen will be available by 2032 and
2038 and at reasonable cost. Moreover, combusting hydrogen will achieve
reductions because it does not produce GHG emissions and will not have
adverse non-air quality health or environmental impacts or energy
requirements, including on the nationwide energy sector. Primarily
because the production of low-GHG hydrogen generates the fewest GHG
emissions, the EPA proposes that co-firing low-GHG hydrogen, and not
other types of hydrogen, qualify as the ``best'' system of emission
reduction. See section VII.F.3.c.vii(F) of this preamble. The fact that
co-firing low GHG hydrogen creates market demand for, and advances the
development of, low-GHG hydrogen, a fuel that is useful for reducing
emissions in the power sector and other industries, provides further
support for this proposal.
    Similar to new base load combined cycle turbines, the EPA is also
taking comment on an alternative approach in which the BSER for these
units would be based on CCS with 90 percent capture, for the reasons
discussed next, but units could follow a pathway that would enable them
to achieve the same reductions using low-GHG hydrogen.
3. CCS
a. Overview
    The EPA believes that CCS is an effective mitigation measure for
existing combustion turbines and that it would be most cost-effective
for units that are frequently operating. As discussed in section
VII.F.3.b.iii.(A) of this preamble, multiple companies are considering
adding CCS to existing fossil fuel-fired power plants and multiple
companies have performed FEED studies evaluating the feasibility of
installing CCS on an existing combined cycle unit. As also discussed
there, CO2 pipelines are available and their network is
expanding in the U.S., the safety of existing and new supercritical
CO2 pipelines is comprehensively regulated by PHMSA, and
areas without reasonable access to pipelines for geologic sequestration
can transport CO2 to sequestration sites via other
transportation modes. As also discussed there, geologic sequestration
of CO2 is well proven, broadly available throughout the
U.S., and there is a detailed set of regulatory requirements to ensure
the security of sequestered CO2. For these reasons, the EPA
proposes that CCS with 90 percent capture is adequately demonstrated
for existing combustion turbines.
    The EPA further proposes that CCS is cost-reasonable for existing
turbines that are greater than 300 MW and operate at greater than 50
percent capacity. The EPA believes that many existing combined cycle
units are likely to be able to install and operate CCS within the costs
that the EPA found to be reasonable for new stationary combustion
turbines and existing coal-fired steam generating units. Certain parts
of the cost calculation should be much the same as for new sources,
including the costs for transportation and sequestration as well as the
availability of the IRC section 45Q tax credit, although the costs for
retrofitting capture equipment may in some cases be higher. See section
VII.F.3.b.iii.(B) of this preamble. NETL estimates that the capital
cost of CCS retrofits on combined cycle EGUs is 9 percent

higher than for new combined cycle EGUs.\593\ The additional capital
costs increase the LCOE of the retrofit CCS by an additional $1.5/MWh
compared to an installation at a new combined cycle EGU, which is
consistent with control costs that EPA has found to be reasonable in
other rulemakings, as noted in section VII.F.3.b.iii.(B)(5).
---------------------------------------------------------------------------

    \593\ Tommy Schmitt, Sally Homsy, National Energy Technology
Laboratory, Cost and Performance of Retrofitting NGCC Units for
Carbon Capture--Revision 3, March 17, 2023 (DOE/NETL-2023/3848).
---------------------------------------------------------------------------

    The ability to cost-effectively apply CCS was a significant
consideration in the EPA's selection of proposed capacity and
utilization thresholds to determine which existing turbines would be
covered by these proposed emission guidelines. The EPA considered two
primary factors in evaluating an appropriate capacity threshold. The
first is emission reduction potential. As the capacity threshold
decreases a larger amount of the existing fleet is covered and overall
emission reduction potential increases. For instance, at a 500 MW
threshold, only 2 percent of the capacity and 7 percent of the
emissions are covered. The second factor the EPA considered was
capacity to build CCS. In 2030, the EPA projects that approximately 12
GW of coal-fired generation will likely install CCS (including both CCS
being installed to meet requirements of this rule and CCS that EPA
projects would occur even without the requirements proposed here).
There are likely to also be a number of other CCS projects for other
industries developed in the 2023 through 2030 timeframe. Multiple
industries including the ethanol industry and the hydrogen production
sector have announced post combustion CCS projects in response to the
IRA.
    The EPA believes it is reasonable to assume therefore that by 2035
there will be a larger capability to build CCS retrofits than in 2030.
Had the EPA proposed capacity thresholds of 400 MW or 500 MW, they
would have only resulted in the need for a maximum of 12 GW or 6 GW of
CCS capacity respectively by 2035 for existing gas turbines covered by
this proposal, which is less than the CCS capacity the EPA projects in
2030 to meet the existing coal BSER. That would likely mean foregoing
feasible, cost-effective emissions reductions. By contrast, the 300 MW
cutpoint that EPA is proposing would require up to 37 GW of CCS in
2035. While this is approximately 3 times the amount of CCS that the
EPA is projecting for coal-fired units in 2030, the EPA believes that
300 MW is a reasonable threshold primarily because there will be
significant time to deploy the needed infrastructure, a total of eleven
years from the likely finalization of these guidelines. In addition, it
is unlikely that all of the units that EPA projects would be affected
in 2035 would choose to install CCS; some would likely choose to co-
fire low-GHG hydrogen.\594\ For these reasons, the EPA believes that
there will be adequate capability to build enough CCS for the existing
combustion turbine EGUs subject to a CCS BSER at a capacity threshold
of 300 MW, given the amount of time provided.
---------------------------------------------------------------------------

    \594\ Approximately 6 GW of the capacity projected to operate at
a capacity factor of greater than 50 percent in the EPA's modeling
is owned by NextERA who has already announced intentions to convert
much of their combined cycle turbines to co-fire increasing amounts
of hydrogen.
---------------------------------------------------------------------------

    The EPA also considered a capacity threshold of 200 MW and of 100
MW. According to the EPA's projections, a threshold of 200 MW would
affect a total of 85 GW, and a threshold of 100 MW would affect 134 GW
of existing combustion turbine capacity. While the EPA believes that it
is possible that the industry could install that amount of CCS on this
timeline, the EPA believes it is important to gather more information
on the question of how quickly CCS can be deployed and is therefore
taking comment on, but not proposing, a lower capacity threshold of 200
MW or 100 MW, and taking comment on whether it would be feasible to
install CCS and or co-fire hydrogen for the 85 GW or 134 GW of units it
projects would be covered under those thresholds and a capacity factor
of greater than 50 percent.
    Historical rates of emission control technology retrofits at
existing coal-fired power plants, such as flue gas desulfurization
(FGD), indicate that rapid deployments of such technologies in response
to regulatory requirements have proven feasible historically in the
United States and elsewhere. FGD was rapidly deployed in the United
States in response to various regulatory requirements, including the
1971 NSPS addressing SO2 emissions. Although other
compliance options were available, FGD--a wholly new technology--was
installed on 48 GW of coal-fired power plants between 1973 and
1984,\595\ while the number of technology vendors went from 1 to
16.\596\ Similarly, Germany subsequently increased its share of FGD
from 10 to 79 percent in four years.597 598 It should be
noted that as FGD became a more familiar technology, installation rates
accelerated, reaching nearly 30 GW a year in the United States.\599\ A
very rapid ramp up happened after the Clean Air Interstate Rule, for
example, where the installed capacity increased from 131 GW in 2007 to
200 GW in under four years.\600\ There are many differences between FGD
and CCS, but the history of the rapid build-out of FGD generally
supports the EPA's view that companies with the expertise to install
complex emission control equipment can rapidly ramp up capacity in
response to a regulatory driver.
---------------------------------------------------------------------------

    \595\ Van Ewijk, S., McDowall, W. Diffusion of flue gas
desulfurization reveals barriers and opportunities for carbon
capture and storage. Nat Commun 11, 4298, Figure 1 and Source Data
(2020), available at https://doi.org/10.1038/s41467-020-18107-2.
    \596\ Taylor, et al., Regulation as Mother of Innovation, 27 Law
& Pol'y 348, 356 (2005).
    \597\ Van Ewijk, S., McDowall, W. Diffusion of flue gas
desulfurization reveals barriers and opportunities for carbon
capture and storage. Nat Commun 11, 4298 (2020). https://doi.org/10.1038/s41467-020-18107-2.
    \598\ Similarly, in response to regulatory requirements over 100
GW of coal-fired generation installed selective catalytic reduction
(SCR) between 1999 and 2009, ramping from very low levels. Healey,
Scaling and Cost Dynamics of Pollution Control Technologies, at 7,
Figure 3 (2013). https://core.ac.uk/download/pdf/44737055.pdf.
    \599\ Markussan, Scaling up and Deployment of FGD in the US
(CCS--Releasing the Potential) (2012) at v, 24.
    \600\ Electric Power Annual 2015, https://www.eia.gov/electricity/annual/archive/pdf/03482015.pdf.
---------------------------------------------------------------------------

    The EPA seeks comment on the feasibility of setting a threshold of
100 or 200 MW and a 40 percent capacity factor in light of these
examples and other relevant considerations. As further described below,
the EPA further proposes that CCS with 90 percent capture for existing
combustion turbines greater than 300 MW and operating at more than 50
percent capacity meets the other criteria to qualify as the BSER, for
the same reasons as it does for new combustion turbines in the baseload
subcategory:
b. Adequately Demonstrated
    Section VII.F.3.b of this preamble includes discussion of how CCS
with a 90 percent capture rate has been adequately demonstrated and is
technically feasible based on the demonstration of the technology at
existing coal-fired steam generating units and industrial sources in
addition to combustion turbines. Notably, the function, design, and
operation of post-combustion CO2 capture equipment is
similar, although not identical, for both steam generating units and
combustion turbines. As a result, application of CO2 capture
at existing coal-fired steam generating units helps show that it is
adequately demonstrated for combustion turbines as well.

    In the retrofit context, SaskPower's Boundary Dam Unit 3, a 110 MW
lignite-fired unit in Saskatchewan, Canada, has demonstrated
CO2 capture rates of 90 percent using an amine-based post-
combustion capture system retrofitted to the existing steam generating
unit. The capture plant, which began operation in 2014, was the first
full-scale CO2 capture system retrofit on an existing coal-
fired power plant.\601\ Other references detailed in section
VII.F.3.b.iii.(A).(2) provide additional support for the demonstration
of CO2 capture retrofits.
---------------------------------------------------------------------------

    \601\ Giannaris, S., et al., Proceedings of the 15th
International Conference on Greenhouse Gas Control Technologies
(March 15-18, 2021). SaskPower's Boundary Dam Unit 3 Carbon Capture
Facility--The Journey to Achieving Reliability. https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3820191.
---------------------------------------------------------------------------

    Moreover, section VII.F.3.b.iii.(A)(3) of this preamble describes
how CCS has been successfully applied to a combined cycle EGU (the
Bellingham Energy Center in south central Massachusetts) and how
several other projects are in development. Both section
VII.F.3.b.iii.(A)(3) of this preamble and the TSD on GHG Mitigation
Measures--Carbon Capture and Storage for Combustion Turbines discuss
several CCS projects under development involving retrofits to existing
NGCC units.
    In addition to CO2 capture, the CO2 transport
and geologic storage aspects of CCS systems are also adequately
demonstrated, as discussed in section VII.F.3.b and section X.D.1.a of
this preamble and in the GHG Mitigation Measures for Steam Generating
Units TSD. Geologic sequestration potential for CO2 is
widespread and available throughout the U.S. Nearly every State in the
U.S. has or is in close proximity to formations with geologic
sequestration potential, including areas offshore. These areas include
deep saline formation, unmineable coal seams, and oil and gas
reservoirs. Additionally, the U.S. CO2 pipeline network has
steadily expanded (with 5,339 miles in operation in 2021, a 13 percent
increase in CO2 pipeline miles since 2011), and appears
primed to continue expanding, with several major projects recently
announced across the country. Areas without reasonable access to
pipelines for geologic sequestration can transport CO2 to
sequestration sites via other transportation modes such as ship, road
tanker, or rail tank cars.
c. Costs
    The EPA is proposing that the costs of CCS are reasonable for
existing combustion turbines that are large and frequently used. As
further discussed in the Regulatory Impact Analysis and the GHG
Mitigation Measures--Carbon Capture and Storage for Combustion Turbines
TSD, the EPA's approach relies on cost and performance assumptions
consistent with the IPM post-IRA 2022 reference case.\602\ The EPA's
baseline shows that 7 GW of existing natural gas combined cycle
capacity retrofits with CCS in 2030, rising to 10 GW in 2035. The
significant deployment of CCS on combined cycle natural gas EGUs in the
absence of emission standards reinforces the cost reasonableness and
feasibility of the proposed standards.
---------------------------------------------------------------------------

    \602\ These assumptions are detailed at: https://www.epa.gov/system/files/documents/2023-03/Chapter%206%20-%20CO2%20Capture%2C%20Storage%2C%20and%20Transport.pdf.
_____________________________________-

    Section VII.F.3.b.iii.(B) and section X.D.1.a.ii of this preamble
discuss the cost-reasonableness of CCS technology in the context of new
combustion turbines and existing coal-fired steam generating units.
Additionally, a March 2023 NETL report estimates that the capital cost
of CCS retrofits on combined cycle EGUs is 9 percent higher than for
installation of CCS equipment on new greenfield combined cycle
EGUs.\603\ The higher retrofit costs account for the cost premium for
design, construction, and tie-in constraints imposed by existing plant
layout and operation. The additional capital costs increase the LCOE of
the retrofit CCS by an additional $2.2/MWh compared to an installation
at a new combined cycle EGU.\604\ Assuming the same model plant, a 90
percent-capture retrofit amine-based post combustion CCS system
increases the LCOE by $8.6/MWh and has overall CO2 abatement
costs of $26/ton ($28/metric ton). Similar to NETL estimates for
greenfield CCS projects, costs at a specific plant would be expected to
vary somewhat from this estimate, as it does not include site and
plant-specific considerations such as seismic conditions, local labor
costs, or local environmental regulations.
---------------------------------------------------------------------------

    \603\ Cost and Performance of Retrofitting NGCC Units for Carbon
Capture--Revision 3 (DOE/NETL-2023/3848, March 17, 2023). https://www.netl.doe.gov/projects/files/CostandPerformanceofRetrofittingNGCCUnitsforCarbonCaptureRevision3_031723.pdf.
    \604\ These calculations use the NETL F-Class turbine, a service
life of 12 years, an interest rate of 7.0 percent, a natural gas
price of $3.69/MMBtu, a capacity factor of 75 percent, a transport,
storage, and monitoring cost of $10/metric ton, and a 45Q tax credit
of $85/metric ton.
---------------------------------------------------------------------------

d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
    As in the context of new NGCC units and existing coal-fired steam
generating units (discussed in section VII.F.3.b.iii.(C) and section
X.D.1.a.iii of this preamble), the EPA does not expect the use of CCS
at large, frequently used existing combustion turbines to have
unreasonable adverse consequences related to non-air quality health and
environmental impact or to energy requirements.
    Regarding energy requirements, upon retrofitting an NGCC plant with
CCS, a derate in the net plant electrical output will be incurred due
to the parasitic/auxiliary energy demand required to run the CCS
system, as well as steam extraction from the steam cycle to satisfy the
CCS reboiler duty.\605\ As discussed in the TSD on GHG Mitigation
Measures--Carbon Capture and Storage for Combustion Turbines, a recent
NETL report has estimated that the resulting derates for 90 percent
CO2 capture retrofits range from an 11.5 to 11.8 percent
loss of net MWe.
---------------------------------------------------------------------------

    \605\ Cost and Performance of Retrofitting NGCC Units for Carbon
Capture--Revision 3. (DOE/NETL--2023/3848, March 17, 2023). https://www.osti.gov/biblio/1961845.
---------------------------------------------------------------------------

    Despite decreases in efficiency, IRC section 45Q tax credits
provide an incentive for increased generation with full operation of
CCS because the credits are proportional to the amount of captured and
sequestered CO2 emissions and not to the amount of
electricity generated. The EPA is proposing that the energy penalty is
relatively minor compared to the GHG benefits of CCS. The EPA does not
believe that determining CCS to be BSER for large, frequently operated
combustion turbines will cause reliability concerns. This is because of
the limited increase in costs and energy penalty due to CCS, coupled
with the amounts of smaller or lower capacity generation that would not
be subject to these requirements and the projected new capacity in the
base case modeling. For the estimated 37 GW of facilities that would
face requirements under this proposal, if they all installed CCS
retrofit the reduction in available capacity would be approximately 4.3
GW, or less than 1% of the total modeled available natural gas capacity
in 2035. Grid planners, operators, and market participants can address
the potential, marginal impact, through development of a similarly
small increment of accredited capacity, whether from new natural gas
simple cycle turbine

deployment, new energy storage, or new sources of clean energy.
    Regarding non-air quality health and environmental impact, criteria
or hazardous air pollutant emissions would in general be mitigated or
adequately controlled by equipment needed to meet other CAA
requirements, and the EPA's assessment is that the additional cooling
water requirements from CCS at NGCC units are reasonable, as discussed
in section VII.F.3.v.iii.(C). The EPA is committed to working with its
fellow agencies to foster meaningful engagement with communities and
protect communities from pollution. This can be facilitated through the
existing detailed regulatory framework for CCS projects and further
supported through robust and meaningful public engagement early in the
technological deployment process. CCS projects undertaken pursuant to
these emission guidelines will, if the EPA finalizes proposed revisions
to the CAA section 111 implementing regulations,\606\ be subject to
requirements for meaningful engagement as part of the State plan
development process. See section XII.F.1.b of this preamble for
additional details.
---------------------------------------------------------------------------

    \606\ 87 FR 79176, 79190-92 (December 23, 2022).
---------------------------------------------------------------------------

e. Extent of Reductions in CO2 Emissions
    Designating CCS with 90 percent capture as a component of the BSER
for large and frequently-operated combustion turbines prevents large
amounts of CO2 emissions. According to the NETL baseline
report, adding a 90 percent CO2 capture system increases the
EGU's gross heat rate by 7 percent and the unit's net heat rate by 13
percent. Since more fuel would be consumed in the CCS case, the gross
and net emissions rates are reduced by 89.3 percent and 88.7 percent
respectively.
f. Promotion of the Development and Implementation of Technology
    The EPA also considered whether determining CCS to be a component
of the BSER for existing large and frequently operated combustion
turbines will advance the technological development of CCS and
concluded that this factor supports our BSER determination. Combined
with the availability of 45Q tax credits and investments in supporting
CCS infrastructure from the IIJA, this requirement should incentivize
additional use of CCS, which should, in turn, incentivize cost
reductions through the development and use of better performing
solvents or sorbents. While solvent-based CO2 capture has
been adequately demonstrated at the commercial scale, a determination
of the BSER for certain existing combustion turbines (along with new
baseload combustion turbines and long term coal-fired steam generating
units) is the use of CCS will also likely incentivize the deployment of
alternative CO2 capture techniques at scale. Moreover, as
noted above, the cost of CCS has fallen in recent years and is expected
to continue to fall; and further implementation of the technology can
be expected to lead to additional cost reductions, due to added
experience and cost efficiencies through scaling.
    The EPA seeks comment on the feasibility of setting a threshold for
inclusion in the existing combustion turbine segment to be addressed by
the emission guidelines proposed here of 100 or 200 MW and a 40 percent
capacity factor in light of the examples of other historic deployment
of pollution controls and other relevant considerations. DOE recently
released a report discussing the State of carbon management
technology.\607\ In that report, DOE states that with policy support
(either via regulation or incentives) or technology premiums for low-
carbon products (e.g., low embodied carbon steel and concrete) the
scale up of CCS technologies and pipeline and storage infrastructure
would proceed much faster for the power sector than will proceed absent
additional policy support or market demand.\608\ In the report, DOE
states that regulatory developments, in particular, could play a
dramatic role in accelerating the pathways described for industries
with lower-purity CO2 streams such as power plants. The
report states that absent additional incentives, CCS technology for the
power sector is likely to significantly scale between 2030-2040 with
pilot and demonstration technologies occurring now. As detailed in the
report, several incentives have recently become available or been
significantly increased that will accelerate the deployment of CCS for
the power sector. The 45Q tax credit for CCS is a strong incentive, and
DOE is already investing heavily through the Bipartisan Infrastructure
Law at further demonstrating lower-purity CCS technologies such as
those used in the power sector, which will help to decrease costs and
establish repeatable commercial arrangements.
---------------------------------------------------------------------------

    \607\ DOE Carbon Management Demonstration and Deployment
Pathway, April 2023, https://liftoff.energy.gov/
    \608\ The Federal Buy Clean Task Force and the First Mover's
Coalition are both seeking to provide a clear demand signal for low
embodied emissions products.
---------------------------------------------------------------------------

    As the DOE report discusses, CO2 pipelines also need to
be further built out for CCS technologies to scale. CO2
pipelines are the most mature, and often the most cost-effective
CO2 transport technology for high volumes and will likely
form the backbone of CO2 transport. PHMSA reported that
5,339 miles of CO2 pipelines were in operation in 2021.\609\
Analogous historical build out of inter- and intrastate natural gas
transmission pipelines demonstrates that similar levels of
CO2 pipeline deployment are feasible. Data reported by EIA
indicates that from 1997 to 2008 over 25,000 miles of natural gas
transmission pipeline was constructed, averaging over 2,000 miles per
year.\610\ Other analyses indicate that the size of CO2
pipeline network necessary to capture over 1,000 million metric tons
per year of CO2 emissions from large, frequently operated
coal and natural gas EGUs ranges from 20,000 miles to 25,000
miles.\611\ This is in line with the historical maximum deployment of
natural gas transmission pipelines, and also does not account for any
economies of scale from pipeline systems developed for capture from
other non-power CO2 sources.
---------------------------------------------------------------------------

    \609\ U.S. Department of Transportation, Pipeline and Hazardous
Material Safety Administration, ``Hazardous Annual Liquid Data.''
2021. https://www.phmsa.dot.gov/data-and-statistics/pipeline/gas-distribution-gas-gathering-gas-transmission-hazardous-liquids.
    \610\ https://www.eia.gov/naturalgas/pipelines/EIA-NaturalGasPipelineProjects.xlsx.
    \611\ Middleton, Richard and Bennett, Jeffrey and Ellett, Kevin
and Ford, Michael and Johnson, Peter and Middleton, Erin and Ogland-
Hand, Jonathan and Talsma, Carl, Reaching Zero: Pathways to
Decarbonize the US Electricity System with CCS (August 30, 2022).
Proceedings of the 16th Greenhouse Gas Control Technologies
Conference (GHGT-16) 23-24 Oct 2022. https://ssrn.com/abstract=4274085 or http://dx.doi.org/10.2139/ssrn.4274085.
---------------------------------------------------------------------------

D. Areas That the EPA Is Seeking Comment on Related to Existing
Combustion Turbines

    The EPA is seeking comment on four general areas related to
selecting the BSER for existing combustion turbines. First, the EPA is
soliciting comment on general assumptions about potential future
utilization of combustion turbines. Second, the EPA is soliciting
comment on assumptions about the appropriate group of existing
combustion turbine units to be addressed in this rulemaking. Third, the
EPA is requesting comment on the appropriate BSER for those turbines.
Fourth, the EPA is requesting comment

on the timing of BSER requirements for existing combustion turbines.
    The EPA is seeking comment on a number of issues related to how its
consideration of projected future utilization of combined cycles
informed its consideration of a potential BSER for existing combustion
turbines. First, the EPA is taking comment on its projections of how
combustion turbines will operate in the future and the key factors that
influence those changes in operation. While the EPA modeling shows that
there is some increase in emissions from these units in all years
following imposition of CAA section 111 standards on existing coal-
fired steam generating units and new stationary combustion turbines,
that increase is much smaller in the later years. The EPA believes the
magnitude of these trends is significantly impacted by the rate at
which new low emitting generation comes on-line, in part incentivized
by IRA and IIJA. The EPA is taking comment on all aspects of these
assumptions including: the speed at which new low-emitting generation
will come on-line and the impact that it has on likely capacity factors
for combined cycle units (in particular the projection that capacity
factors will grow in the 2028/30 timeframe but decrease in later
years).
    With regard to the size and definition of the category to be
covered in a first rulemaking covering only part of the existing
turbine category, the EPA is also taking comment on how its assumptions
about the potential operation of combustion turbines in future years
coupled with considerations about the availability of infrastructure
should inform which units should be covered in a first rulemaking. More
specifically, the EPA is requesting comment on how to consider the rate
of CCS (and potentially hydrogen) infrastructure development in
determining a BSER that could potentially impact hundreds of sources.
If, for instance, increased renewable generation and storage capacity
were to lead to a smaller number of units operating at capacity factors
of greater than 50 percent, the proposed BSER would not affect as many
units and a smaller size threshold might be possible without expanding
the amount of infrastructure needed. Conversely, if more units were
likely to operate at a higher capacity factor, a higher capacity
threshold might be appropriate. If the number of units likely to be
covered by a 50 percent threshold were sufficiently small, it might be
reasonable to include units in the intermediate category (e.g., units
with capacity factors of between 20 percent and 50 percent) in a first
rulemaking addressing the existing fossil fuel-fired turbine category.
The EPA is also taking comment on a lower capacity factor threshold
(e.g., 40 percent) and a lower capacity threshold (200 MW or 100 MW,
and capacities between 100 and 300 MW). With regards to units with a
capacity factor of greater than 50 percent that are under 300 MW and
units with a capacity factor of 50 percent or less the EPA is taking
comment on the appropriateness of CCS and/or hydrogen as a BSER. With
regards to hydrogen, the EPA is taking comment on the appropriate level
of and timing for hydrogen co-firing. More generally, EPA is requesting
comment on any feasibility issues related to broader CCS deployment
should those thresholds be adjusted such that more coal capacity is
affected, and how such issues could be addressed.
    With regards to the BSER itself, the EPA is soliciting comment on
the applicability of CCS retrofits to existing combustion turbines and
its focus on base load turbines (e.g., those with a capacity factor of
greater than 50 percent). This solicitation includes comment on whether
particular plants would be unable to retrofit CCS, including details of
the circumstances that might make retrofitting with CCS unreasonable or
infeasible.
    The EPA is also taking comment on the role of low-GHG hydrogen as
part of BSER. More specifically, the EPA is requesting comment on the
appropriateness of low-GHG hydrogen as a BSER for combustion turbines
larger than 300 MW with capacity factors of greater than 50 percent.
While, as has been noted earlier in this section, a number of turbines
already exist or are under construction that owners of combustion
turbines have indicated may burn large amounts of hydrogen in a base
load mode, the EPA is also aware that other proponents of low-GHG
hydrogen use in turbines focus on it primarily as an energy storage
device, storing renewable energy to provide electricity in times where
renewable energy was not available. The EPA is interested in the
question of whether, in this case, it would be likely that a combined
cycle turbine burning low-GHG hydrogen would operate near base load,
and whether it be prudent to have an alternative BSER or an alternative
compliance pathway for units combusting low-GHG hydrogen and solicits
comments on these questions. Similar to the NSPS for base load
combustion turbines, the EPA is also taking comment on whether to
finalize both the proposed low-GHG hydrogen BSER and the proposed CCS
with 90 percent capture BSER, or finalize a BSER with a single pathway,
such as based on application of CCS with 90 percent capture, which
could also be met by co-firing with low-GHG hydrogen.
    With regard to the timing for BSER, the EPA is taking comment on a
2035 CCS based BSER standard and whether that standard could reasonably
be applied earlier. Similarly, the EPA is taking comment on the timing
of a low-GHG hydrogen based BSER and whether a 30 percent low-GHG
hydrogen standard could be implemented earlier than 2032, or if low-GHG
hydrogen supply infrastructure development suggests it should be later.
The EPA is taking comment on the same questions with regard to a 96
percent low-GHG hydrogen co-firing BSER in 2038.

E. BSER for Remaining Combustion Turbines

    While the EPA believes that emission guidelines for units covered
in the first rulemaking, proposed above, can achieve important emission
reductions from the most frequently operating combustion turbines, the
EPA believes that limits to infrastructure and capability to build
carbon capture systems or co-fire large amounts of hydrogen caution
against a first rulemaking addressing emissions from existing turbines
covering all combustion turbines. In this section, the EPA discusses
how developing a BSER for units in a second rulemaking could address
units that do not meet the applicability requirements for the first
rulemaking.
    As noted above, the EPA is taking comment on what units should be
part of whatever action the EPA finalizes as a result of the proposal.
Based on the units that the EPA has proposed be included, units that
might remain uncovered include smaller baseload units (e.g., those less
than or equal to 300 MW) and all units operating less than or equal to
a capacity factor of 50 percent. Particularly for the remainder of the
baseload units, the EPA is interested in whether any other units should
have a BSER based on CCS. The EPA is also interested in the timing of
such a requirement recognizing the tensions between an earlier
requirement that would both achieve earlier reductions and the need to
allow time for infrastructure to develop to support growing amounts of
CCS.
    For intermediate turbines, the EPA is taking comment on a BSER
similar to that for new turbines. In particular, the EPA is interested
in comment about an appropriate pathway and timing for a BSER that
would ultimately require 96 percent low-GHG hydrogen by volume.

Finally, for peaking turbines, the EPA is interested in comment about
whether a clean hydrogen BSER would be appropriate, what the timing of
such a requirement should be and whether there should be any phasing.
    The EPA is also interested in any comments related to: potential
changes in operational patterns for turbines, particularly as more
renewables and storage enter the grid. For instance, the EPA is
interested in comments as to whether improvements in energy storage
will reduce reliance on intermediate and peaking turbines. The EPA is
also interested in comments on any potential technology developments
that could impact its determination of BSER. For instance, the EPA is
aware that in addition to electrolyzer based hydrogen and natural gas
based hydrogen, there are other means of hydrogen production receiving
significant attention such as naturally occurring hydrogen, and
solicits comments on whether any of these potential technology
developments should impact the EPA's consideration of the appropriate
BSER for the remaining turbines.

XII. State Plans for Proposed Emission Guidelines for Existing Fossil
Fuel-Fired EGUs

A. Overview

    State plan submissions under these emission guidelines are governed
by the requirements of 40 CFR part 60, subpart Ba (subpart Ba).\612\
The EPA proposed to revise certain aspects of 40 CFR part 60, subpart
Ba, in its December 2022 proposal, ``Adoption and Submittal of State
Plans for Designated Facilities: Implementing Regulations Under Clean
Air Act Section 111(d)'' (proposed subpart Ba).\613\ The Agency intends
to finalize revisions to 40 CFR part 60, subpart Ba, before
promulgating these emission guidelines. Therefore, State plan
development and State plan submissions under these proposed emission
guidelines would be subject to the requirements of subpart Ba as
revised in that future final action, including any changes the EPA
makes to the proposal in response to public comments. To the extent the
EPA is proposing to add to, supersede, or otherwise vary the
requirements of subpart Ba for the purposes of these particular
emission guidelines, those proposals are explicitly addressed in this
section of the preamble. Unless expressly amended or superseded in
these proposed emission guidelines, the provisions of subpart Ba, as
revised by the EPA's forthcoming final rule, would apply.
---------------------------------------------------------------------------

    \612\ 40 CFR 60.20a-60.29a.
    \613\ See 87 FR 79176 (December 23, 2022); see also id., Docket
ID No. EPA-HQ-OAR-2021-0527-0002 (memorandum to docket containing
proposed revisions to 40 CFR part 60, subpart Ba).
---------------------------------------------------------------------------

    This section provides information on several aspects of State plan
development, including compliance deadlines, a presumptive methodology
for establishing standards of performance for affected EGUs, compliance
flexibilities, and State plan components and submission. In sections X
and XI of this preamble, the EPA is soliciting comment on ranges for
dates and values for defining subcategories, BSER, and degrees of
emission limitation; those solicitations for comment extend to the
proposed values and dates discussed in this section of the preamble. In
section XII.B, the EPA proposes and explains its reasoning for
compliance deadlines for affected steam generating units and affected
combustion turbines. In section XII.C, the EPA describes its
requirement that State plans achieve equivalent stringency to the EPA's
BSER. Section XII.D proposes a presumptive methodology for calculating
the standards of performance for affected EGUs based on subcategory as
well as requirements related to invoking RULOF to apply a less
stringent standard of performance than results from the EPA's
presumptive methodology. Section XII.D also describes proposed
requirements for increments of progress for affected EGUs in certain
subcategories and milestones for affected EGUs, as well as testing and
monitoring requirements. In section XII.E, the EPA proposes that States
would be permitted to include trading and averaging as compliance
measures for affected EGUs in their State plans, so long as plans
demonstrate equivalence to the stringency that would result if each
affected EGU was individually achieving its standard of performance.
Finally, section XII.F describes what must be included in State plans,
including plan components specific to these emission guidelines and
requirements for conducting meaningful engagement.
    In this section of the preamble, the term ``affected EGU'' means
any existing fossil fuel-fired steam generating unit or existing fossil
fuel-fired combustion turbine EGU that meets the applicability criteria
described in sections X and XI of this preamble. Affected EGUs would be
covered by the proposed emission guidelines under 40 CFR part 60
subpart UUUUb.

B. Compliance Deadlines

    The EPA is proposing a compliance date of January 1, 2030, for
affected steam generating units. The proposed compliance date for the
CCS combustion turbine subcategory is January 1, 2035. The proposed
compliance dates for the first phase and second phase for the affected
hydrogen co-fired combustion turbine subcategory are January 1, 2032,
and January 1, 2038, respectively. This means that starting on the
applicable compliance date, affected EGUs would be subject to standards
of performance and other State plan requirements under these emission
guidelines and would be required to start demonstrating compliance with
those requirements.
    The EPA is proposing that January 1, 2030, is the soonest that
affected steam generating units could reasonably commence compliance
with standards of performance given the proposed State plan submission
timeline (24 months; see section XII.F.2 of this preamble) and the
amount of time affected EGUs in the long-term and medium-term coal-
fired steam generating unit subcategories will need to install CCS or
natural gas co-firing, respectively. For consistency, the EPA is also
proposing a January 1, 2030, compliance date for imminent- and near-
term coal-fired units as well as the different subcategories of natural
gas- and oil-fired steam generating units.
    However, the EPA recognizes that the BSERs for some subcategories
of affected steam-generating EGUs are routine methods of operation and
maintenance, which do not require the installation of any or
significant control equipment and can thus be applied earlier.\614\
Therefore, the EPA is soliciting comment on compliance dates defined by
the date of approval of the State plan or January 1, 2030, whichever is
earlier, for imminent-term coal-fired steam generating units, near-term
coal-fired steam generating units, and the different subcategories of
natural gas- and oil-fired steam generating units.
---------------------------------------------------------------------------

    \614\ The EPA is also taking comment in section X.D.3.b.ii on
potential BSER options for imminent- and near-term affected coal-
fired steam generating units based on low levels of natural gas co-
firing.
---------------------------------------------------------------------------

    The proposed compliance timeframe for affected steam-generating
EGUs in these proposed emission guidelines is based on the amount of
time the EPA believes is needed to comply with standards of performance
based on implementation of natural gas co-firing or CCS. Each of these
systems would require several years to plan, permit, and construct.
However, as explained further in section XII.F.2 of this preamble, the
EPA is proposing to

adjust the State plan submission deadline so that certain necessary
planning and design steps for natural gas co-firing or CCS
implementation can take place as part of the State plan development
process. That is, we expect that some of the planning and design steps
described below would take place prior to State plan submission. The
EPA believes that coordinating State plan development, submission, and
implementation in this manner reflects how the owners/operators of
affected EGUs and States would actually undertake the steps leading to
ultimate deployment of a control technology and compliance with a
standard of performance.
    The GHG Mitigation Measures for Steam Generating Units TSD
discusses the timeframes for implementation of natural gas co-firing
and CCS at existing coal-fired steam generating EGUs. Based on this
analysis, it is clear that the time needed to design and implement CCS
is an important aspect for setting a compliance date under these
emission guidelines. CCS projects will include planning, design, and
construction of both the carbon capture system and the transport and
storage system; the EPA believes that all of these steps can be
completed within roughly 5 years.\615\
---------------------------------------------------------------------------

    \615\ GHG Mitigation Measures for Steam Generating Units TSD,
chapter 4.7.1. See Table 5 in chapter 4.7.1 for visual
representation of the CCS and co-firing project timelines described
in this section.
---------------------------------------------------------------------------

    Deployment of a carbon capture system starts with a technical and
economic feasibility evaluation, including a Front End Engineering
Design (FEED) study. The owner/operator of an affected EGU would then
proceed to making technical and commercial arrangements, including
arranging project financing and permitting. These initial steps do not
need to be undertaken sequentially and may be completed in 3 years or
less. As noted above, the EPA also believes that at least some of these
project design and development steps, including feasibility evaluations
and FEED studies, can and will be completed prior to State plan
submission. The EPA believes that the commencement of CCS project
implementation activities, including more detailed engineering work and
procurement, construction of the carbon capture system, and startup and
testing, will overlap with the final steps of the initial project
design and development phase. These project implementation steps take
approximately 3 years to complete.
    In addition to planning and implementing a carbon capture system,
the owners/operators of affected EGUs will also have to design and
construct a system for transporting and storing captured
CO2. The necessary steps for implementing transport and
storage of captured CO2 can be undertaken simultaneously
with development of the CO2 capture system, and some of the
steps necessary for transport and storage can additionally overlap with
each other. The EPA thus believes design and implementation of
CO2 transport and storage can be completed within 5 years.
    The EPA believes that the initial phases of planning and design for
CO2 transport and storage, including site characterization
and pipeline feasibility and design activities, can and will occur
prior to State plan submission, i.e., as part of the State plan
development process. First, the owner/operator of an affected EGU would
undertake a feasibility analysis associated with CO2
transport and storage, as well as site characterization and permitting
of potential storage areas. These steps can overlap with each other and
the EPA anticipates that, in total, feasibility analyses, site
characterization, and permitting of potential storage areas will take
2-3 years to complete. The EPA believes there is significant
opportunity to overlap the design and planning phase for CO2
transport and storage with the engineering and construction phase for
transport and storage, which is anticipated to take 2-3 years. Based on
the potential to conduct many of the design, planning, permitting,
engineering, and construction steps, the EPA thus believes that
affected EGUs will need approximately 5 years, from start to finish, to
be ready to implement CO2 transport and storage.
    The EPA expects that implementation of natural gas co-firing
projects for affected coal-fired steam-generating EGUs, including any
necessary construction of natural gas pipelines, can be completed in
approximately 3.5 years. As discussed in the GHG Mitigation Measures
for Steam Generating Units TSD,\616\ any necessary boiler modifications
to accommodate natural gas co-firing can be completed within 3 years.
The process of planning, permitting, and construction for boiler
modifications can occur simultaneously with the steps that owners/
operators of affected EGUs would need to undertake if construction of a
new natural gas pipeline is needed. The time required to develop and
construct natural gas laterals can be broken into three phases:
planning and design; permitting and approval; and construction. It is
reasonable to assume that the planning and design phase can typically
be completed in a matter of months and will often be finalized in less
than a year. The time required to complete the permitting and approval
phase can vary. Based on a review of recent FERC data, the average time
for pipeline projects similar in scope to the projects considered in
this TSD is about 1.5 years and would likely not exceed 4 years. The
EPA notes that these data may not reflect that pipeline projects may be
completed more expeditiously in the presence of a regulatory deadline.
Finally, the actual construction could likely be completed in less than
1 year. Based on a sum of these estimates, the EPA believes that 3.5
years is a reasonable timeframe for pipeline projects.
---------------------------------------------------------------------------

    \616\ GHG Mitigation Measures for Steam Generating Units TSD,
chapters <IP_ADDRESS>, <IP_ADDRESS>, and 4.7.1.
---------------------------------------------------------------------------

    The EPA expects that final emission guidelines will be published in
June 2024 and is proposing a State plan submission deadline that is 24
months from publication, which would be June 2026. The proposed
compliance date for affected steam generating units is January 1, 2030.
The EPA requests comment on whether using a period of 3.5 years after
State plan submission is appropriate for establishing a compliance
deadline for these emission guidelines. As explained above, the EPA is
basing this proposed timeframe on the expectation that some of the
initial evaluation and planning steps for both natural gas co-firing
and CCS would take place as part of State plan development, i.e.,
before the State plan submission deadline. The EPA is also requesting
comment on potential compliance dates between 1.5 and 5.5 years after
State plan submission (i.e., January 1, 2028, to January 1, 2032),
including on the feasibility of completing all the steps to implement
natural gas co-firing and CCS within a shorter or longer timeframe. To
the extent that commenters believe more or less time after State plan
submission is more appropriate than the proposed 3.5 years, the EPA
requests that commenters provide information supporting the provision
of a different compliance date. Additionally, the proposed State plan
submission date and proposed compliance date are based on the EPA's
anticipation that it will publish final emission guidelines for
affected EGUs in June 2024. Should the actual date of publication of
the final emission guidelines differ from this target, the EPA will
adjust the State plan submission and compliance dates accordingly.
    As discussed in section XI.C of this preamble, the EPA is proposing
to subcategorize affected existing,

frequently used combustion turbines that are covered under these
emission guidelines into two subcategories: one subcategory for
affected combustion turbine EGUs that adopt the pathway with a standard
of performance based on CCS, referred to as the ``CCS subcategory'' and
one subcategory for affected combustion turbine EGUs that adopt the
pathway with a standard of performance based on hydrogen co-firing,
referred to as the ``hydrogen co-fired subcategory.'' For affected
combustion turbines in the CCS subcategory, the EPA is proposing a
compliance date of January 1, 2035, which is the soonest the Agency
believes these sources can comply with standards of performance based
on installation and operation of CCS, given the timeframes for planning
and construction of carbon capture and CO2 transport and
storage systems along with other demands on the infrastructure and
resources needed to implement CCS throughout the power sector and the
broader economy. For affected combustion turbines in the hydrogen co-
fired subcategory, the EPA is proposing a two-phase standard of
performance, with a proposed compliance date for the first phase of
January 1, 2032, and for the second phase of January 1, 2038.
    For combustion turbine EGUs in the CCS subcategory, the same
timeframes and considerations discussed for the planning and
construction of CCS for affected coal-fired steam generating units
apply. That is, the EPA expects that the owners or operators of
affected combustion turbines will be able to complete the design,
planning, permitting, engineering, and construction steps for the
carbon capture and transport and storage systems within 5 years. As
with affected coal-fired steam generating units, the EPA believes that
States and owners or operators can and would take several of the
initial steps in the design and planning processes for combustion
turbine EGUs as part of State plan development, i.e., prior to the
proposed State plan submission deadline in approximately June 2026.
    However, as noted in section XI.C of this preamble, the EPA is
projecting approximately 12 GW of coal-fired generation will likely
retrofit with CCS in order to meet the proposed January 1, 2030,
compliance date for affected long-term coal-fired steam generating
units. These and other CCS projects that are likely to be occurring in
response to the IRA may take up a significant amount of the capacity to
plan and build CCS between 2023 and 2030. The EPA anticipates that
additional pipeline capacity will be constructed ahead of January 1,
2030, for CO2 transport as well as for natural gas pipeline
laterals that may be needed for affected coal-fired steam generating
units that will co-fire with natural gas as a control strategy. Due to
these and other overlapping demands on the capacity to design,
construct, and operate carbon systems as well as pipeline systems, the
EPA is proposing to find that a January 1, 2030, compliance date for
affected combustion turbine EGUs in the CCS subcategory, although
feasible for an individual unit, would not be the most reasonable
deadline for all of the units that would need to install CCS.
Therefore, the EPA is proposing to provide a compliance date for
affected combustion turbine EGUs in the CCS subcategory that is 5 years
after the compliance date for long-term coal-fired steam generating
units, or January 1, 2035. The EPA requests comment on its proposed
compliance deadline for combustion turbine EGUs in the CCS subcategory,
including on whether an earlier or later compliance date would be more
reasonable given the time needed to analyze, design, and construct
carbon capture and CO2 transport and storage systems and the
overlapping timeframes for installation of CCS on EGUs under the
proposed CAA section 111(b) standards of performance for new combustion
turbines and on existing coal-fired steam generating units under these
proposed emission guidelines.
    For affected combustion turbine EGUs in the hydrogen co-fired
subcategory, the EPA is proposing a compliance deadline for the first
phase of January 1, 2032. As discussed in sections VII.F.3.c.v and vi
of this preamble, currently the vast majority of hydrogen is not low-
GHG hydrogen. Midstream infrastructure limitations and the adequacy and
availability of hydrogen storage facilities currently present obstacles
and increase prices for delivered low-GHG hydrogen. However, given the
growth in the hydrogen sector and Federal funding for DOE's H2Hubs,
which will explicitly explore and incentivize hydrogen distribution,
the EPA believes hydrogen distribution and storage infrastructure will
not present a barrier to access for new combustion turbines opting to
co-fire 30 percent hydrogen by volume in 2032. Legislative actions
including the IIJA and IRA, utility initiatives, and industrial sector
production and infrastructure projects indicate that sufficient low-GHG
hydrogen and sufficient distribution infrastructure can reasonably be
expected to be available by this time. On this basis, the EPA is
proposing that compliance with the first phase of the standard, which
is based on an affected EGU co-firing 30 percent (by volume) low-GHG
hydrogen, will commence on January 1, 2032.
    The proposed compliance date of January 1, 2038, for the second
phase of the standard of performance for combustion turbine EGUs in the
hydrogen co-fired subcategory, which is based on a proposed BSER of 96
percent (by volume) co-firing low-GHG hydrogen, is also based on an
assessment of when sufficient quantities of such hydrogen will be
available, as well as when turbine vendors are anticipated to have the
equipment necessary for higher percentages of hydrogen co-firing
available. As discussed in section VII.F.3 of this preamble, the EPA
expects that based on technology advances, growing demand for low-GHG
hydrogen, and the hydrogen production tax credits available under IRC
45V(b)(2), there will be continued expansion of the hydrogen production
and transmission network between 2032 and 2038. The EPA also notes
that, based on the current ages of the existing combustion turbine
fleet, the number of units that would be expected to meet their
standards of performance in 2038 by co-firing 96 percent hydrogen (by
volume) is likely to decline. Therefore, the EPA believes it is
reasonable to expect that there will be sufficient low-GHG hydrogen in
2038 to provide the quantities needed for both new and affected
existing combustion turbines in the hydrogen co-fired subcategory to
meet their applicable standards of performance. The EPA requests
comment on this assessment, as well as on whether compliance dates
other that January 1, 2032, and January 1, 2038, would be more
reasonable for the first and second phases of the standards for
affected units in the hydrogen co-fired subcategory, and why.

C. Requirement for State Plans To Maintain Stringency of the EPA's BSER
Determination

    As explained in section V.C of this preamble, CAA section 111(d)(1)
requires the EPA to establish requirements for State plans that, in
turn, must include standards of performance for existing sources. Under
CAA section 111(a)(1), a standard of performance is ``a standard for
emissions of air pollutants which reflects the degree of emission
limitation achievable through the application of the best system of
emission reduction which . . . the Administrator determines has been
adequately demonstrated.'' That is, the

EPA has the responsibility to determine the best system of emission
reduction for a given category or subcategory of sources and to
determine the degree of emission limitation achievable through
application of the BSER to affected sources.\617\ The level of emission
performance required under CAA section 111 is reflected in the EPA's
presumptive standards of performance.
---------------------------------------------------------------------------

    \617\ See, e.g., West Virginia v. EPA, 142 S. Ct. 2587, 2607
(2022) (``In devising emissions limits for power plants, EPA first
`determines' the `best system of emission reduction' that--taking
into account cost, health, and other factors--it finds `has been
adequately demonstrated.' The Agency then quantifies `the degree of
emission limitation achievable' if that best system were applied to
the covered source.'') (internal citations omitted).
---------------------------------------------------------------------------

    States use the EPA's presumptive standards of performance as the
basis for establishing requirements for affected sources in their State
plans. In order for the EPA to find a State plan ``satisfactory,'' that
plan must address each affected source within the State and achieve the
level of emission performance that would result if each affected source
was achieving its presumptive standard of performance, after accounting
for any application of RULOF.\618\ That is, while States have the
discretion to establish the applicable standards of performance for
affected sources in their State plans, the structure and purpose of CAA
section 111 require that those plans achieve equivalent stringency as
applying the EPA's presumptive standards of performance to each of
those sources (again, after accounting for any application of RULOF).
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    \618\ As explained in section XI.D.2 of this preamble, States
may invoke RULOF to apply a less stringent standard of performance
to a particular affected EGU when the state demonstrates that the
EGU cannot reasonably apply the BSER to achieve the degree of
emission limitation determined by the EPA. In this case, the state
plan may not necessarily achieve the same stringency as each source
achieving the EPA's presumptive standards of performance because
affected EGUs for which RULOF has been invoked would have standards
of performance less stringent than the EPA's presumptive standards.
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    The EPA's December 2022 proposed revisions to the CAA section 111
implementing regulations (40 CFR part 60, subpart Ba) would provide
that States are permitted, in appropriate circumstances, to adopt
compliance measures that allow their sources to meet their standards of
performance in the aggregate.\619\ As with the establishment of
standards of performance for affected sources, CAA section 111 requires
that State plans that include such flexibilities for complying with
standards of performance demonstrate equivalent stringency as would be
achieved if each affected source was achieving its standard of
performance.
---------------------------------------------------------------------------

    \619\ 87 FR 79176, 79207-08 (December 23, 2015).
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    The requirement that State plans achieve equivalent stringency to
the EPA's BSER and degree of emission limitation is borne out of the
structure and purpose of CAA section 111, which is to mitigate air
pollution that is reasonably anticipated to endanger public health or
welfare. It achieves this purpose by requiring source categories that
cause or contribute to dangerous air pollution to operate more cleanly.
Unlike the Clean Air Act's NAAQS-based programs, section 111 is not
designed to reach a level of emissions that has been deemed ``safe'' or
``acceptable''; there is no air-quality target that tells States and
sources when emissions have been reduced ``enough.'' Rather, CAA
section 111 requires affected sources to reduce their emissions to the
level that the EPA has determined is achievable through application of
the best system of emission reduction, i.e., to achieve emission
reductions consistent with the applicable presumptive standard of
performance. Consistent with the statutory purpose of requiring
affected sources to operate more cleanly, the EPA typically expresses
presumptive standards of performance as rate-based emission
limitations.
    In the course of complying with a rate-based standard of
performance under a State plan, an affected source may take an action
that removes it from the source category, e.g., by permanently ceasing
operations. In this case, the source is no longer subject to the
emission guidelines. An affected source may also choose to change its
operating characteristics in a way that impacts its overall emissions,
e.g., by changing its utilization; however, the source is still
required to meet its rate-based standard. In either instance, the
changes to one affected source do not implicate the obligations of
other affected sources. Although such changes may reduce emissions from
the source category, they do not absolve the remaining affected EGUs
from the statutory obligation to improve their emission performance
consistent with the level that the EPA has determined is achievable
through application of the BSER. This fundamental statutory requirement
applies regardless of whether a standard of performance is expressed or
implemented as a rate- or mass-based emission limitation, or whether
standards of performance are achieved on a source-specific or aggregate
basis.
    In sum, consistent with the respective roles of the EPA and States
under CAA section 111, States have discretion to establish standards of
performance for affected sources in their State plans, and to provide
flexibilities for affected sources to use in complying with those
standards. However, State plans must demonstrate that they ultimately
provide for equivalent stringency as would be achieved if each affected
source was achieving the applicable presumptive standard of
performance, after accounting for any application of RULOF.

D. Establishing Standards of Performance

    CAA section 111(d)(1)(A) provides that ``each State shall submit to
the Administrator a plan which establishes standards of performance for
any existing source''; that plan must also ``provide[ ] for the
implementation and enforcement of such standards of performance.'' That
is, States must use the BSER and stringency in the EPA's emission
guidelines to establish standards of performance for each existing
affected EGU through a State plan.
    To assist States in developing State plans that achieve the level
of stringency required by the statute, it has been the EPA's
longstanding practice to provide presumptively approvable standards of
performance or a methodology for establishing such standards. For the
purpose of these emission guidelines, the EPA is proposing a
methodology for States to use in establishing presumptively approvable
standards of performance for affected existing EGUs. Per CAA section
111(a)(1), the basis of this methodology is the degree of emission
limitation the EPA has determined is achievable through application of
the BSER to each subcategory. The EPA anticipates and intends for most
States to apply the presumptive standards of performance to affected
EGUs.
    Additionally, CAA section 111(d)(1)(B) permits States to take into
consideration a particular affected EGU's RULOF when applying a
standard of performance to that source. The EPA's proposed revisions to
the CAA section 111 implementing regulations at 40 CFR part 60, subpart
Ba provide that a State would be able to apply a less stringent
standard of performance to an affected EGU when the State can
demonstrate that the source cannot reasonably apply the BSER to achieve
the degree of emission limitation determined by the EPA. Proposed
subpart Ba describes the conditions that would warrant application of a
less stringent RULOF standard under these emission guidelines and how a
RULOF standard

would be determined. Further detail about how the EPA proposes to
implement the RULOF provision in the context of this rulemaking is
provided in section XII.D.2 of this preamble.
    States also have the authority to apply standards of performance to
affected EGUs that are more stringent than the EPA's presumptively
approvable standards of performance.\620\
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    \620\ 40 CFR 60.24a(f). The EPA has proposed to revise this
provision to clarify that it has the obligation and authority to
review and approve state plans that contain the more stringent
requirements. 87 FR 79176, 79204 (December 23, 2022).
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1. Application of Presumptive Standards
    This section of the preamble describes the EPA's approach to
providing presumptive standards of performance for each of the
subcategories of affected EGUs under these emission guidelines,
including establishing baseline emission performance. Under this
proposal, each subcategory with a proposed BSER and degree of emission
limitation would have a corresponding methodology for establishing
presumptively approvable standards of performance (also referred to as
``presumptive standards of performance'' or ``presumptive standards'').
    A State, when establishing standards of performance for affected
EGUs in its plan, would identify each affected EGU in the State and
specify into which subcategory each EGU falls. The EPA is proposing
that the State would then use the corresponding methodology for the
given subcategory to calculate and apply the presumptively approvable
standard of performance for each affected EGU.
    States also have the authority to deviate from the methodology for
presumptively approvable standards, in order to apply a more stringent
standard of performance through increasing the degree of emission
limitation beyond what the EPA has determined to be achievable for
units as a general matter (e.g., a State decides that an EGU in the
medium-term coal-fired subcategory should co-fire 50 percent natural
gas instead of 40 percent). Deviations to increase stringency do not
trigger use of the RULOF mechanism, which requires States to
demonstrate that an affected EGU cannot reasonably apply the BSER to
achieve the degree of emission limitation determination by the
EPA.\621\ The EPA proposes to presume that standards of performance
that are more stringent than the EPA's presumptive standards are
``satisfactory'' for the purposes of CAA section 111(d).
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    \621\ 87 FR 79176, 79199 (December 23, 2022).
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a. Establishing Baseline Emission Performance for Presumptive Standards
    For each subcategory, the proposed methodology to calculate a
standard of performance entails establishing a baseline of
CO2 emissions and corresponding electricity generation for
an affected EGU and then applying the degree of emission limitation
achievable through the application of the BSER (as established in
section X.D and XI.C of this preamble). The methodology for
establishing baseline emission performance for an affected EGU is
identical in each of the subcategories but will result in a value that
is unique to each affected EGU. To establish baseline emission
performance for an affected EGU, the EPA is proposing that a State will
use the CO2 mass emissions and corresponding electricity
generation data for a given affected EGU from any continuous 8-quarter
period from 40 CFR part 75 reporting within the 5 years immediately
prior to the date the final rule is published in the Federal Register.
This proposed period is based on the NSR program's definition of
``baseline actual emissions'' for existing electric steam generating
units. See 40 CFR 52.21(b)(48)(i). Eight quarters of 40 CFR part 75
data corresponds to a 2-year period, but the EPA is proposing 8
quarters of data as that corresponds to quarterly reporting according
to 40 CFR part 75. Functionally, the EPA expects States to utilize the
most representative 8-quarter period of data from the 5 years
immediately preceding the date the final rule is published in the
Federal Register. For the 8 quarters of data, the EPA is proposing that
a State would divide the total CO2 emissions (in the form of
pounds) over that continuous time period by the total gross electricity
generation (in the form of MWh) over that same time period to calculate
baseline CO2 emission performance in lb CO2 per
MWh. As an example, a State establishing baseline emission performance
in the year 2023 would start by evaluating the CO2 emissions
and electricity generation data for each of its affected EGUs for 2018
through 2022 and choosing, for each affected EGU, a continuous 8-
quarter period that it deems to be the best representation of the
operation of that affected EGU. While the EPA will evaluate the choice
of baseline periods chosen by States when reviewing State plan
submissions, the EPA intends to defer to a State's reasonable exercise
of discretion as to which 8-quarter period is representative.
    The EPA is proposing to require the use of 8 quarters during the 5-
year period prior to the date the final rule is published in the
Federal Register as the relevant period for the baseline methodology
for a few reasons. First, each affected EGU has unique operational
characteristics that affect the emission performance of the EGU (load,
geographic location, hours of operation, coal rank, unit size, etc.),
and the EPA believes each affected EGU's emission performance baseline
should be representative of the source-specific conditions of the
affected EGU and how it has typically operated. Additionally, allowing
a State to choose (likely in consultation with the owners or operators
of affected EGUs) the 8-quarter period for assessing baseline
performance can avoid situations in which a prolonged period of
atypical operating conditions would otherwise skew the emissions
baseline. Relatedly, the EPA believes that by using total mass
CO2 emissions and total electric generation for an affected
EGU over an 8-quarter period, any relatively short-term variability of
data due to seasonal operations or periods of startup and shutdown, or
other anomalous conditions, will be averaged into the calculated level
of baseline emission performance. The baseline-setting approach of
using total CO2 mass emissions and total electric generation
over an 8-quarter period also aligns with the reporting and compliance
requirements. The EPA is proposing that compliance would be
demonstrated annually based on the lb CO2/MWh emission rate
derived by dividing the total reported CO2 mass emissions by
the total reported electric generation for an affected EGU during the
compliance year, which is consistent with the expression of the degree
of emission limitation proposed for each subcategory in sections X.D.4,
X.E.2, and XI.C. The EPA believes that using total mass CO2
emissions and total electric generation provides a simple and
streamlined approach for calculating baseline emission performance
without the need to sort and filter non-representative data; any minor
amount of non-representative data will be subsumed and accounted for
through implicit averaging over the course of the 8-quarter period.
Moreover, this approach, by not sorting or filtering the data,
eliminates any need for discretion in assessing whether the data is
appropriate to use.
    The EPA is soliciting comment on the proposed baseline-setting
approach and specifically on the applicability of such an approach for
each of the different subcategories. The EPA is proposing a continuous
8-quarter period to better average out operating variability but

solicits comment on whether a different time period would be more
appropriate for assessing baseline emission performance, as well as on
the 5-year window from which the period for baseline emission
performance is chosen. The EPA also solicits comment on the use of
total mass CO2 emissions and total electric generation over
a consecutive 8-quarter time period as representative and on whether
the EPA's proposed approach is appropriate.
    The EPA believes that using the proposed baseline-setting approach
as the basis for establishing presumptively approvable standards of
performance will provide certainty for States, as well as transparency
and a streamlined process for State plan development. While this
approach is specifically designed to be flexible enough to accommodate
unit-specific circumstances, States retain the ability to deviate from
the methodologies the EPA is proposing for establishing baselines of
emission performance for affected EGUs. The EPA believes that the
instances in which a State may need to use an alternate baseline-
setting methodology will be limited to anticipated changes in
operation, i.e., circumstances in which historical emission performance
is not representative of future emission performance. The EPA is
proposing that States wishing to vary the baseline calculation for an
affected EGU based on anticipated changes in operation, when those
changes result in a less stringent standard of performance, must use
the RULOF mechanism, which is designed to address such contingencies.
b. Presumptive Standards for Steam Generating Units
    As described in section X.C of this preamble, the EPA is proposing
to first subcategorize affected existing steam generating units by fuel
type: coal-fired and oil- or natural gas-fired steam generating units.
The EPA is proposing further subcategorization into four subcategories
for coal-fired steam generating units and seven subcategories for oil-
and natural gas-fired steam generating units. As explained in section
X.C.3, the EPA is proposing that an affected coal-fired steam
generating unit's operating horizon determines the applicable
subcategory in three of the four subcategories; in the case of the
near-term subcategory, the operating horizon and load level establish
applicability.
    The EPA notes that, as explained in section X.C.3 of this preamble,
where the owners or operators of affected coal-fired steam-generating
units have elected to commit to permanently cease operation (and, in
the case of near-term operating horizon units, to limit their capacity
factor) and have also elected to make any such commitments federally
enforceable through inclusion in a State plan, a State may rely on such
commitments to subcategorize coal-fired steam generating units under
these emission guidelines. To be included in a State plan a commitment
to cease operations or to limit capacity factor must be enforceable by
the State, whether through State rule, agreed order, permit, or other
legal instrument.\622\ Upon EPA approval of the State plan, that
commitment will become federally enforceable.
---------------------------------------------------------------------------

    \622\ 40 CFR 60.26a.
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    For affected oil- and natural gas-fired steam generating units,
subcategories are defined by load level and the type of fuel fired, as
well as locality (i.e., continental and non-continental U.S.). There
are four subcategories for oil-fired steam generating units based on
different combinations of load level (base load, intermediate load, and
low load) and locality, and three subcategories for natural gas-fired
steam generating units based on load level (base load, intermediate,
and low).
i. Long-Term Coal-Fired Steam Generating Units
    This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
long-term coal-fired steam generating units. Affected coal-fired steam
generating units that have either (1) Elected to commit to permanently
cease operations on January 1, 2040, or later, or (2) that have not
elected to commit to permanently cease operations as part of the
State's plan submission, fall within this subcategory and have a
proposed BSER of CCS with 90 percent capture and a proposed degree of
emission limitation of 90 percent capture of the mass of CO2
in the flue gas (i.e., the mass of CO2 after the boiler but
before the capture equipment) over an extended period of time and an
88.4 percent reduction in emission rate on a gross basis over an
extended period of time. The EPA is proposing that where States use the
methodology described here to establish standards of performance for an
affected EGU in this subcategory, those established standards would be
presumptively approvable when included in a State plan submission. In
section X of this preamble, for the long-term coal-fired subcategory,
the EPA is soliciting comment on a capture rate of 90 to 95 percent and
a degree of emission limitation defined by a reduction in emission rate
on a gross basis from 75 to 90 percent.
    Establishing a standard of performance for an affected coal-fired
EGU in this subcategory consists of two steps: establishing a source-
specific level of baseline emission performance (as described above);
and applying the level of stringency, based on the application of the
BSER, to that level of baseline emission performance. Implementation of
CCS with a capture rate of 90 precent translates to a level of
stringency of an 88.4 percent reduction in CO2 emission rate
(see section X.D.4.a of this preamble) compared to the baseline level
of emission performance. Using the complement of 88.4 percent (i.e.,
11.6 percent) and multiplying it by the baseline level of emission
performance results in the presumptively approvable standard of
performance. For example, if a long-term coal-fired EGU's level of
baseline emission performance is 2,000 lbs per MWh, it will have a
presumptively approvable standard of performance of 232 lbs per MWh
(2,000 lbs per MWh multiplied by 0.116).
    The EPA is also proposing that affected coal-fired EGUs in the
long-term subcategory comply with federally enforceable increments of
progress, which are described in section XII.D.3.a of this preamble.
    The EPA solicits comments on this proposed methodology for
calculating presumptively approvable standards of performance for long-
term coal-fired steam generating units.
ii. Medium-Term Coal-Fired Steam Generating Units
    This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
medium-term coal-fired steam generating units. Affected coal-fired
steam generating units that have elected to commit to permanently cease
operations after December 31, 2031, and before January 1, 2040, have a
proposed BSER of 40 percent co-firing of natural gas. The EPA is
proposing that where States use the methodology described here to
establish standards of performance for an affected EGU in this
subcategory, those established standards of performance would be
presumptively approvable when included in a State plan submission.
    Establishing a standard of performance for an affected EGU in this
subcategory consists of two steps: establishing a source-specific level
of baseline emission performance (as described earlier in this
preamble); and applying the level of emission reduction

stringency, based on the application of the BSER, to that level of
baseline emission performance. Implementation of natural gas co-firing
at a level of 40 percent of total annual heat input translates to a
level of stringency of a 16 percent reduction in CO2
emissions (see section X.D.4.b of this preamble) compared to the
baseline level of emission performance. Using the complement of 16
percent (i.e., 84 percent) and multiplying it by the baseline level of
emission performance results in the presumptively approvable standard
of performance for the affected EGU. For example, if a medium-term
coal-fired EGU's level of baseline emission performance is 2,000 lbs
per MWh, it will have a presumptively approvable standard of
performance of 1,680 lbs per MWh (2,000 lbs per MWh multiplied by
0.84). In section X of this preamble, for the medium-term coal-fired
subcategory, the EPA is soliciting comment on a natural gas co-firing
level of 30 to 50 percent and a degree of emission limitation from 12
to 20 percent.
    For medium-term coal-fired steam generating units that have an
amount of co-firing that is reflected in the baseline operation, the
EPA is proposing that States account for such preexisting co-firing in
adjusting the degree of emission limitation. If, for example, an EGU
co-fires natural gas at a level of 10 percent of the total annual heat
input during the applicable 8-quarter baseline period, the
corresponding degree of emission limitation would be adjusted to 12
percent (i.e., an additional 30 percent of natural gas by heat input)
to reflect the preexisting level of natural gas co-firing. This results
in a standard of performance based on the degree of emission limitation
achieving an additional 30 percent co-firing beyond the 10 percent that
is accounted for in the baseline. The EPA believes this approach is a
more straightforward mathematical adjustment than adjusting the
baseline to appropriately reflect a preexisting level of co-firing.
However, the EPA solicits comment on whether the adjustment of a
standard of performance based on preexisting levels of natural gas co-
firing should be done through the baseline. To adjust the baseline to
account for preexisting natural gas co-firing, the State would need to
calculate a baseline of emission performance for an EGU that removes
the mass emissions and electric generation that are attributable to the
natural gas portion of the fuel. With this adjusted baseline that
removes the natural gas-fired portion, the presumptive standard of
performance would be calculated by multiplying the adjusted baseline by
the degree of emission limitation factor that reflects 40 percent co-
firing. The EPA is not proposing this methodology, because parsing the
attributable emissions and electric generation associated with natural
gas co-firing from the attributable emissions and electric generation
associated with coal-fired generation requires manipulation of the
emissions and electric generation data. However, the EPA solicits
comment on whether baseline adjustment is more appropriate and also why
that may be so.
    The standard of performance for the medium-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, to qualify for inclusion in the subcategory an
affected coal-fired steam generating unit must have elected to commit
to permanently cease operations prior to January 1, 2040. If a State
decides to rely on such a commitment to place an affected EGU into the
medium-term coal-fired subcategory by making it an enforceable element
of its State plan, the commitment to cease operations will become
federally enforceable upon EPA approval of the plan.
    The EPA is proposing that affected coal-fired EGUs that elect to
commit to dates to permanently cease operations for subcategory
applicability, including EGUs in the medium-term coal-fired
subcategory, have corresponding federally enforceable milestones with
which they must comply. The EPA intends these milestones to assist
affected EGUs in ensuring they are completing the necessary steps to
comply with their State plan and commitments to dates to permanently
cease operations. These milestones are described in detail in section
XII.D.3.b of this preamble. Affected EGUs in this subcategory would
also be required to comply with the federally enforceable increments of
progress described in section XII.D.3.a of this preamble.
    The EPA solicits comment on the proposed methodology for
calculating presumptively approvable standards of performance for
medium-term coal-fired steam generating units, including on the
proposed approach for adjusting a presumptively approvable standard of
performance to accommodate preexisting natural gas co-firing.
iii. Imminent-Term Coal-Fired Steam Generating Units
    This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
imminent-term coal-fired steam generating units. Affected coal-fired
steam generating units that elect to commit to permanently cease
operations before January 1, 2032, have a proposed BSER of routine
methods of operation and maintenance. Therefore, the proposed
presumptively approvable standard of performance is not to exceed the
baseline emission performance of the affected EGU (as described in
section XII.D.1.a of this preamble).
    Unlike the proposed standards of performance for the long-term and
medium-term coal-fired steam generating units, establishing a standard
of performance for an affected EGU in the imminent-term subcategory
consists of just one step. The EPA is proposing that where States use
the methodology described in section XII.D.1.a of this preamble to
establish the baseline level of emission performance for an affected
EGU, the emission rate described by that baseline would constitute the
presumptively approvable standard of performance. This standard of
performance reflects that the proposed BSER for these affected EGUs is
routine methods of operation and maintenance and a degree of emission
limitation equivalent to no increase in emission rate from the baseline
level of emission performance. This also ensures that the affected EGU
will not backslide in its emission performance.
    Although the EPA believes that the baseline performance level
adequately accounts for variability in annual emission rate, the EPA is
also soliciting comment on a methodology for a presumptive standard
above the baseline emission performance. For the imminent-term coal-
fired subcategory, the EPA is soliciting comment on a presumptive
standard that is defined by 0 to 2 standard deviations in annual
emission rate (using the 5-year period of data) above the baseline
emission performance, or that is 0 to 10 percent above the baseline
emission performance.
    Because the EPA is soliciting comment on a potential BSER for this
subcategory based on low levels of natural gas co-firing, as described
in section X.D.3.b.ii, comment is also being solicited on the
presumptively approvable standards for that potential BSER. The BSER is
based on the maximum hourly heat input of natural gas fired in the unit
(MMBtu/hr) relative to the maximum hourly heat input the

unit is capable of (i.e., the nameplate capacity on an MMBtu/hr basis).
The EPA is soliciting comment on the baseline natural gas co-firing
level being determined from the 5 years of data preceding the
publication of the final rule, or based on engineering limitations
(i.e., extent of startup guns or size of pipeline to unit). That
percent of heat input results in percent reductions from the emission
performance baseline equivalent to the percent of heat input times 0.4.
Adjustments relative to current co-firing levels may be accounted for
in a manner consistent with section XII.D.1.b.ii. Alternatively, the
EPA is soliciting comment on a degree of emission limitation on a fuel
heat input basis. For a potential BSER of low levels of natural gas co-
firing, the EPA is therefore also soliciting comment on a presumptively
approvable standard defined on a heat input basis.
    The standard of performance for the imminent-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, to qualify for inclusion in the subcategory an
affected coal-fired EGU must have elected to commit to permanently
cease operations prior to January 1, 2032. If a State decides to rely
on such a commitment to place an affected EGU into the imminent-term
coal-fired subcategory by making it an enforceable element of its State
plan, the commitment to cease operations will become federally
enforceable upon EPA approval of the plan.
    The EPA is also proposing that affected coal-fired steam generating
units that have elected to commit to dates to permanently cease
operations for subcategory applicability, including EGUs in the
imminent-term coal-fired subcategory, have corresponding federally
enforceable milestones with which they must comply. The EPA intends
these milestones to assist affected EGUs in ensuring they are
completing the necessary steps to comply with these dates in their
State plan. These milestones are described in detail in section
XII.D.3.b of this preamble.
    The EPA solicits comment on the proposed methodology for
establishing presumptively approvable standards of performance for
imminent-term coal-fired steam generating units.
iv. Near-Term Coal-Fired Steam Generating Units
    Similar to the proposed approach for establishing presumptively
approvable standards of performance for affected EGUs in the imminent-
term coal-fired subcategory, the EPA is proposing that affected EGUs in
the near-term coal-fired subcategory have a presumptively approvable
standard of performance based on the baseline emission performance of
the affected EGU (as described in section XII.D.1.a of this preamble).
The near-term subcategory includes affected coal-fired steam generating
units that have elected to commit to permanently cease operations after
December 31, 2031, and before January 1, 2035, and that have elected to
adopt an annual capacity factor limitation of 20 percent.
    The EPA is proposing that where States use the methodology
described in section XII.D.1.a of this preamble to establish the
baseline level of emission performance for an affected EGU, the
emission rate described by that baseline would constitute the
presumptively approvable standard of performance. This standard of
performance reflects the proposed BSER of routine methods of operation
and maintenance and a degree of emission limitation equivalent to no
increase in emission rate. This also ensures that the affected EGU will
not backslide in its emission performance.
    For the near-term coal-fired subcategory, the EPA is soliciting
comment on a presumptive standard that is defined by 0 to 2 standard
deviations in annual emission rate (using the 5-year period of data)
above the baseline emission performance, or that is 0 to 10 percent
above the baseline emission performance.
    Because the EPA is soliciting comment on a potential BSER for this
subcategory based on low levels of natural gas co-firing, as described
in section X.D.3.b.ii, comment is also being solicited on the
presumptively approvable standards for that potential BSER. The BSER is
based on the maximum hourly heat input of natural gas fired in the unit
(MMBtu/hr) relative to the maximum hourly heat input the unit is
capable of (i.e., the nameplate capacity on an MMBtu/hr basis). The EPA
is soliciting comment on the baseline natural gas co-firing level being
determined from the 5 years of data preceding the publication of the
final rule, or based on engineering limitations (i.e., extent of
startup guns or size of pipeline to unit). That percent of heat input
results in percent reductions from the emission performance baseline
equivalent to the percent of heat input times 0.4. Adjustments relative
to current co-firing levels may be accounted for in a manner consistent
with section XII.D.1.b.ii. Alternatively, the EPA is soliciting comment
on a degree of emission limitation on a fuel heat input basis. For a
potential BSER of low levels of natural gas co-firing, the EPA is
therefore also soliciting comment on a presumptively approvable
standard defined on a heat input basis.
    The standard of performance for the near-term coal-fired
subcategory is based on the degree of emission limitation that is
achievable through application of the BSER to the affected EGUs in the
subcategory and consists exclusively of the rate-based emission
limitation. However, to qualify for inclusion in the subcategory an
affected coal-fired EGU must have elected to commit to permanently
cease operations after December 31, 2031, and before January 1, 2035,
and must have elected to adopt an annual capacity factor limitation of
20 percent. If a State decides to rely on such commitments to place an
affected EGU into the near-term coal-fired subcategory by making them
enforceable elements of its State plan, the commitments to cease
operations and to limit its capacity factor will become federally
enforceable upon EPA approval of the plan.
    The EPA is also proposing that affected coal-fired EGUs that have
elected to commit to dates to permanently cease operations for
subcategory applicability, including EGUs in the near-term coal-fired
subcategory, have corresponding federally enforceable milestones with
which they must comply. The EPA intends these milestones to assist
affected EGUs in ensuring they are completing the necessary steps to
comply with these dates in their State plan. These milestones are
described in detail in section XII.D.3.b of this preamble.
    The EPA solicits comment on the proposed methodology for
establishing presumptively approvable standards of performance for
near-term coal-fired steam generating units.
v. Natural Gas-Fired Steam Generating Units and Continental Oil-Fired
Steam Generating Units
    This section describes the EPA's proposed methodology for
presumptively approvable standards of performance for affected natural
gas-fired and continental oil-fired steam generating units: low load
natural gas-fired steam generating units, intermediate load natural
gas- fired steam generating units, base load natural gas-fired steam
generating units, low load oil-fired steam generating units,
intermediate load continental oil-fired steam generating units, and
base load continental oil-fired steam

generating units. It does not address non-continental intermediate oil-
fired and non-continental base load oil-fired steam generating units,
which are described in section XII.D.1.b.vi of this preamble. The
proposed definitions of these subcategories are discussed in section
X.C.2 of this preamble. The proposed presumptive standards of
performance are based on degrees of emission limitation that units are
currently achieving, consistent with the proposed BSER of routine
methods of operation and maintenance, which amounts to a proposed
degree of emission limitation of no increase in emission rate.
    Unlike the approach to establishing presumptive standards of
performance for coal-fired EGUs in these proposed emission guidelines,
the EPA is proposing presumptive standards of performance for affected
natural gas-fired and continental oil-fired steam generating units in
lieu of methodologies that States would use to establish presumptive
standards of performance. This is largely because the low variability
in emissions data at intermediate and base load for these units and
relatively consistent performance between these units at those load
levels, as discussed in section X.E of this preamble and detailed in
the Natural Gas- and Oil-fired Steam Generating Unit TSD, allows for
the identification of a generally applicable standard of performance.
    However, for natural gas- or oil-fired steam generating units with
low annual capacity factors, annual emission rates can be high (greater
than 2,500 lb CO2/MWh-gross) and can vary considerably
across units and from year to year. Despite their relatively high
emission rates, though, overall emissions from these units are low.
Based on these considerations, the EPA is not proposing a BSER or that
States establish standards of performance for these units at this time.
However, as noted above, the EPA is soliciting comment on determining a
BSER of uniform fuels for these units. In addition, the EPA is
soliciting comment on a presumptive standard of performance for these
units based on heat input. Specifically, the EPA is soliciting comment
on a range of presumptive standards of performance from 120 to 130 lb
CO2/MMBtu for low load natural gas-fired steam generating
units, and from 160 to 170 lb CO2/MMBtu for low load oil-
fired steam generating units.
    For intermediate load natural gas-fired units (annual capacity
factors greater than or equal to 8 percent and less than 45 percent),
annual emission rates are less than 1,500 lb CO2/MWh-gross
for about 90 percent of the units. Therefore, the EPA is proposing the
presumptive standard of performance of an annual calendar-year emission
rate of 1,500 lb CO2/MWh-gross for these units.
    For base load natural gas-fired units (annual capacity factors
greater than or equal to 45 percent), annual emission rates are less
than 1,300 lb CO2/MWh-gross for about 80 percent of units.
Therefore, the EPA is proposing the presumptive standard of performance
of an annual calendar-year emission rate of 1,300 lb CO2/
MWh-gross for these units.
    In the continental U.S., there are few if any oil-fired steam
generating units that operate with intermediate or high utilization.
Liquid-oil-fired steam generating units with 24-month capacity factors
less than 8 percent do qualify for a work practice standard in lieu of
emission requirements under the Mercury and Air Toxics Standards rule
(MATS) (40 CFR 63, subpart UUUUU). If oil-fired units operated at
higher annual capacities, it is likely they would do so with
substantial amounts of natural gas firing and have emission rates that
are similar to steam generating units that fire only natural gas at
those levels of utilization. There are a few natural gas-fired steam
generating units that are near the threshold for qualifying as oil-
fired units (i.e., firing more than 15 percent oil in a given year) but
that on average fire more than 90 percent of their heat input from
natural gas. Therefore, the EPA is proposing the same presumptive
standards of performance for oil-fired steam generating units as for
natural gas-fired units, noted above.
    The EPA is also taking comment on a range of presumptive standards
of performance for natural gas- and oil-fired steam generating units.
Specifically, the EPA is soliciting comment on standards between (1)
1,400 and 1,600 lb CO2/MWh-gross for intermediate load
natural gas-fired units, (2) 1,250 and 1,400 lb CO2/MWh-
gross for base load natural gas-fired units, (3) 1,400 and 2,000 lb
CO2/MWh-gross for intermediate load oil-fired units, and (4)
1,250 and 1,800 lb CO2/MWh-gross for base load oil-fired
units. The upper end of the ranges for oil-fired units is higher
because of the limited data available for oil-fired units that operate
at those annual capacity factors.
vi. Non-Continental Oil-Fired Steam Generating Units
    The EPA is proposing that for affected EGUs in the non-continental
intermediate oil-fired and non-continental base load oil-fired
subcategory, a presumptively approvable standard of performance would
be based on baseline emission performance, consistent with the EPA's
proposed BSER determination of routine methods of operation and
maintenance and the proposed degree of emission limitation of no
increase in emission rate. The EPA is proposing that where States use
the methodology described in section XII.D.1.a of the preamble to
establish unit-specific baseline levels of emission performance for
affected EGUs in this subcategory, those emission rates would
constitute presumptively approvable standards of performance when
included in a State plan submission. This standard of performance would
ensure no increase in the unit-specific emission rate from the baseline
level of emission performance.
    For the intermediate and base load non-continental oil-fired
subcategory, the EPA is soliciting comment on a presumptive standard
that is defined by 0 to 2 standard deviations in annual emission rate
(using the 5-year period of data) above the baseline emission
performance, or that is 0 to 10 percent above the baseline emission
performance.
    The EPA solicits comment on the proposed methodology for
establishing presumptively approvable standards of performance for non-
continental oil-fired steam generating units in the intermediate and
base load subcategories.
c. Presumptive Standards for Combustion Turbines
    As described in section XI.C, the EPA is proposing to define
affected existing combustion turbines under these emission guidelines
as units with a capacity greater than 300 MW and an annual capacity
factor of greater than 50 percent. Within this set of units, the EPA is
proposing two subcategories based on the type of fuel used: existing
combustion turbines that adopt the pathway with a standard of
performance based on CCS, referred to as the ``CCS subcategory'' and
existing combustion turbines that adopt the pathway with a standard of
performance based on hydrogen co-firing, referred to as the ``hydrogen
co-fired subcategory.'' States, in their State plan submissions, would
be required to assign existing combustion turbine EGUs with capacities
greater than 300 MW and the ability to operate at an annual capacity
factor of greater than 50 percent to one

subcategory or the other.\623\ States would then be required to include
in their plans the presumptive standard of performance corresponding to
the appropriate subcategory for each affected existing combustion
turbine EGU. As discussed in section XII.D.2 of this preamble, States,
in applying a standard of performance to a particular affected existing
combustion turbine EGU, also have discretion to consider that EGU's
remaining useful life and other factors.
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    \623\ As explained in section XI.D of this preamble, the EPA is
soliciting comment on, inter alia, whether to finalize both the CCS
and hydrogen co-fired pathways for existing combustion turbines or
whether to finalize a BSER determination with a single pathway. If
the EPA does not finalize the proposed two-pathway approach, the
state plan requirements for existing combustion turbines in this
section XII of the preamble will be updated accordingly for the
final rule.
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    However, the EPA anticipates that some existing combustion turbine
EGUs that are greater than 300 MW do not intend to operate at an annual
capacity factor of greater than 50 percent starting in 2032 (the first
proposed compliance date for affected existing combustion turbine EGUs
under these emission guidelines). Such an EGU may elect to commit to an
enforceable annual capacity factor limitation of less than or equal to
50 percent. If a State elects to include such an enforceable commitment
in its State plan, the State would not be required to have a standard
of performance for that particular combustion turbine EGU in its plan.
Otherwise, each affected existing combustion turbine that is greater
than 300 MW and that has the ability to operate at an annual capacity
factor of greater than 50 percent must have a subcategory designation
and standard of performance in the State plan.
    The EPA is proposing that States may structure the requirements for
affected combustion turbine EGUs in their State plans so that the
applicable standard of performance must be met for years in which the
unit operates above the 50 percent annual capacity factor threshold.
States and the owners or operators of affected EGUs that have such
contingent standards of performance would be required to ensure that an
affected EGU has complied with its standard of performance for each
calendar year in which it has operated at an annual capacity factor of
greater than 50 percent. The EPA expects that if the owner or operator
of an affected combustion turbine EGU that has a standard of
performance believes there is a chance the EGU will operate at an
annual capacity factor of greater than 50 percent in the upcoming
compliance period, it will plan to meet that standard. Given this
practical reality, the EPA is taking comment on whether it should
require that once an affected existing combustion turbine EGU has
exceeded the 50 percent annual capacity factor threshold and triggered
application of its standard of performance for a given compliance
period, that EGU must continue to meet its standard in subsequent
compliance periods.
i. Carbon Capture and Storage Existing Combustion Turbine Generating
Units
    This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
existing combustion turbine EGUs that adopt the pathway with a standard
of performance based on CCS. Affected EGUs that are assigned to this
subcategory have a proposed BSER of CCS with 90 percent capture and a
proposed degree of emission limitation of 90 percent capture of the
mass of CO2 in the flue gas (i.e., the mass of
CO2 after the turbine but before the capture equipment) over
an extended period of time and an 89 percent reduction in emission rate
on a gross basis over an extended period of time. The EPA is proposing
that where States use the methodology described here to establish
standards of performance for an affected EGU in this subcategory, those
established standards would be presumptively approvable when included
in a State plan submission.
    Establishing a standard of performance for an affected combustion
turbine EGU in this subcategory consists of two steps: establishing a
source-specific level of baseline emission performance (as described
above); and applying the level of stringency, based on the application
of the BSER, to that level of baseline emission performance.
Implementation of CCS with a capture rate of 90 precent translates to a
level of stringency of an 89 percent reduction in CO2
emission rate (see section XI.C of this preamble) compared to the
baseline level of emission performance. Using the complement of 89
percent (i.e., 11 percent) and multiplying it by the baseline level of
emission performance results in the presumptively approvable standard
of performance. For example, if a combustion turbine EGU in this
subcategory has a baseline level of emission performance of 1,000 lbs
per MWh, it will have a presumptively approvable standard of
performance of 110 lbs per MWh (1,000 lbs per MWh multiplied by 0.11).
    The EPA is also proposing that affected combustion turbines in this
subcategory comply with federally enforceable increments of progress,
which are described in section XII.D.3.a of this preamble.
    The EPA solicits comments on this proposed methodology for
calculating presumptively approvable standards of performance for
existing combustion turbines in the CCS subcategory.
ii. Hydrogen Co-Fired Existing Combustion Turbine Generating Units
    This section describes the EPA's proposed methodology for
establishing presumptively approvable standards of performance for
existing combustion turbines that adopt the pathway with a standard of
performance based on hydrogen co-firing. Affected combustion turbine
EGUs in this subcategory have a proposed BSER of hydrogen co-firing
with two phases of stringency. In the first phase, affected EGUs in
this subcategory co-fire hydrogen at a level of 30 percent by volume
with a proposed degree of emission limitation of 12 percent reduction
in emission rate on a gross basis over an extended period of time. In
the second phase, affected EGUs in this subcategory co-fire hydrogen at
a level of 96 percent by volume with a proposed degree of emission
limitation of 88.4 percent reduction in emission rate on a gross basis
over an extended period of time. As described in section XII.B,
compliance with the first phase commences on January 1, 2032, and
compliance with the second phase commences on January 1, 2038. The EPA
is proposing that where States use the methodology described here to
establish standards of performance for this subcategory, those
established standards of performance would be presumptively approvable
when included in a State plan submission.
    Establishing a standard of performance for an affected EGU in this
subcategory consists of three steps: first, establishing a source-
specific level of baseline emission performance (as described earlier
in this preamble); and second, applying the level of emission reduction
stringency for the first phase, based on the application of the first
phase BSER, to that level of baseline emission performance; and third,
applying the level of emission reduction stringency for the second
phase, based on the application of the second phase BSER, to that level
of baseline emission performance.
    Implementation of hydrogen co-firing at a level of 30 percent by
volume translates to a level of stringency of a 12 percent reduction in
CO2 emissions (see

section XI.C of this preamble) compared to the baseline level of
emission performance. Using the complement of 12 percent (i.e., 88
percent) and multiplying it by the baseline level of emission
performance results in the presumptively approvable standard of
performance for the affected EGU. For example, if a combustion turbine
EGU that co-fires 30 percent hydrogen (by volume) has a baseline level
of emission performance of 1,000 lbs per MWh, it will have a
presumptively approvable standard of performance of 880 lbs per MWh
(1,000 lbs per MWh multiplied by 0.88) for the first phase.
    Implementation of hydrogen co-firing at a level of 96 percent by
volume translates to a level of stringency of an 88.4 percent reduction
in CO2 emissions (see section XI.C of this preamble)
compared to the baseline level of emission performance. Using the
complement of 88.4 percent (i.e., 11.6 percent) and multiplying it by
the baseline level of emission performance results in the presumptively
approvable standard of performance for the affected EGU. For example,
if a combustion turbine EGU that co-fires 96 percent hydrogen (by
volume) has a baseline level of emission performance of 1,000 lbs per
MWh, it will have a presumptively approvable standard of performance of
116 lbs per MWh (1,000 lbs per MWh multiplied by 0.116) for the second
phase.
    The EPA is proposing that affected combustion turbine EGUs in this
subcategory that meet their standards of performance using hydrogen co-
firing must co-fire with low-GHG hydrogen. States must make this an
enforceable part of their State plans, as described in further detail
in section XII.F.1.b.i.
    The EPA is also proposing that affected combustion turbines in this
subcategory comply with federally enforceable increments of progress,
which are described in section XII.D.3.a of this preamble.
    The EPA solicits comment on the proposed methodology for
calculating presumptively approvable standards of performance for
existing combustion turbine EGUs in the hydrogen co-fired subcategory.
2. Remaining Useful Life and Other Factors
    Under CAA section 111(d), the EPA is required to promulgate
regulations under which States submit plans applying standards of
performance to affected EGUs. While States establish the standards of
performance, there is a fundamental obligation under CAA section 111(d)
that such standards reflect the degree of emission limitation
achievable through the application of the BSER, as determined by the
EPA.\624\ The EPA identifies this degree of emission limitation as part
of its emission guideline. 40 CFR 60.22a(b)(5). Thus, as described in
section X.D of this preamble, the EPA is providing proposed
methodologies for States to follow in determining and applying
presumptively approvable standards of performance to affected EGUs in
each of the subcategories covered by these emission guidelines.
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    \624\ West Virginia v. EPA, 142 S. Ct. 2587, 2607 (2022) (``In
devising emissions limits for power plants, EPA first `determines'
the `best system of emission reduction' that--taking into account
cost, health, and other factors--it finds `has been adequately
demonstrated.' The Agency then quantifies `the degree of emission
limitation achievable' if that best system were applied to the
covered source.'') (internal citations omitted).
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    While standards of performance must generally reflect the degree of
emission limitation achievable through application of the BSER as
determined by the EPA, CAA section 111(d)(1) also requires that the EPA
regulations permit the States, in applying a standard of performance to
a particular designated facility, to ``take into consideration, among
other factors, the remaining useful life of the existing sources to
which the standard applies.'' The EPA's implementing regulations under
40 CFR 60.24a thus allow a State to consider a particular designated
facility's remaining useful life and other factors in applying to that