engagement early in the technological deployment process. CCS projects
undertaken pursuant to these emission guidelines will, if the EPA
finalizes proposed revisions to the CAA section 111 implementing
regulations,\548\ be subject to requirements for meaningful engagement
as part of the State plan development process. See section XII.F.1.b of
this preamble for additional details.
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    \548\ 87 FR 79176, 79190-92 (December 23, 2022).
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(A) Energy Requirements

    For a steam generating unit with 90 percent amine-based
CO2 capture, parasitic/auxiliary energy demand increases and
the net power output decreases. Amine-based CO2 capture is
an energy-intensive process. In particular, the solvent regeneration
process requires substantial amounts of heat in the form of steam and
CO2 compression requires a large amount of electricity. Heat
and power for the CO2 capture equipment can be provided
either by using the steam and electricity produced by the steam
generating unit or by an auxiliary cogeneration unit. However, any
auxiliary source of heat and power is part of the ``designated
facility,'' along with the steam generating unit. The standards of
performance apply to the designated facility. Thus, any CO2
emissions from the connected auxiliary equipment need to be captured or
they will increase the facility's emission rate.
    Using integrated heat and power can reduce the capacity (i.e., the
amount of electricity that a unit can distribute to the grid) of an
approximately 474 MW-net (501 MW-gross) coal-fired steam generating
unit without CCS to approximately 425 MW-net with CCS and contributes
to a reduction in net efficiency of 23 percent.\549\ For retrofits of
CCS on existing sources, the ductwork for flue gas and piping for heat
integration to overcome potential spatial constraints are a component
of efficiency reduction. The EPA notes that slightly greater efficiency
reductions than in the 2016 NETL retrofit report are assumed for the
BSER cost analyses, as detailed in the GHG Mitigation Measures for
Steam Generating Units TSD, available in the docket. Despite decreases
in efficiency, IRC section 45Q tax credits provide an incentive for
increased generation with full operation of CCS because the credits are
proportional to the amount of captured and sequestered CO2
emissions and not to the amount of electricity generated. The Agency is
proposing that the energy penalty is relatively minor compared to the
GHG benefits of CCS and, therefore, does not disqualify CCS as being
considered the BSER for existing coal-fired steam generating units.
---------------------------------------------------------------------------

    \549\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016.https://www.netl.doe.gov/energy-analysis/details?id=d335ce79-84ee-4a0b-a27b-c1a64edbb866.
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    Additionally, the EPA considered the impacts on the power sector,
on a nationwide and long-term basis, of determining CCS to be the BSER
for long-term coal-fired steam generating units. The EPA is proposing
that designating CCS as the BSER for existing long-term coal-fired
steam generating units would have limited and non-adverse impacts on
the long-term structure of the power sector. Absent the requirements
defined in this action, the EPA projects that 9 GW of coal-fired steam
generating units would apply CCS by 2030 and 35 GW of coal-fired steam
generating units, some without controls, would remain in operation in
2040. Designating CCS to be the BSER for existing long-term coal-fired
steam generating units would likely result in more of the coal-fired
steam generating unit capacity applying CCS. The time available before
the compliance deadline of January 1, 2030, provides for adequate
resource planning, including accounting for the downtime necessary to
install the CO2 capture equipment at long-term coal-fired
steam generating units. While the IRC 45Q tax credit is available,
long-term coal-fired steam generating units are anticipated to run at
base load conditions. Total generation from coal-fired steam generating
units in the other subcategories would gradually decrease over an
extended period of time through 2039, subject to the commitments those
units have chosen to adopt. Any decreases in the amount of generation
from coal-fired steam generating units, whether locally or more
broadly, are compensated for by increased generation from other
sources. Additionally, for the long-term units applying CCS, the EPA is
proposing the increase in the annualized cost of generation for those
units is reasonable. Therefore, the EPA is proposing that there would
be no unreasonable impacts on the reliability of electricity
generation. A broader discussion of reliability impacts of the proposed
actions is available in section XIV.F of this preamble. Finally,
changes in the amount of generation from coal-fired steam generating
units may contribute to additional generation from combined cycle
combustion turbines. Since these EGUs have lower GHG and criteria
pollutant emission rates than existing coal-fired steam generating
units, overall emissions from the power sector would likely decrease.
(B) Non-GHG Emissions
    For amine-based CO2 capture retrofits to coal-fired
steam generating units, decreased efficiency and increased utilization
would otherwise result in increases of non-GHG emissions; however,
importantly, most of those impacts would be mitigated by the flue gas
conditioning required by the CO2 capture process and by
other control equipment that the units already have or may need to
install to meet other CAA requirements. Decreases in efficiency result
in increases in the relative amount of coal combusted per amount of
electricity generated and would otherwise result in increases in the
amount of non-GHG pollutants emitted per amount of electricity
generated. Additionally, increased utilization would otherwise result
in increases in total non-GHG emissions. However, substantial flue gas
conditioning, particularly to remove SO2, is critical to
limiting solvent degradation and maintaining reliable operation of the
capture plant. To achieve the necessary limits on SO2 levels
in the flue gas for the capture process, steam generating units will
need to add an FGD column, if they do not already have one, and may
need an additional polishing column (i.e., quencher). A wet FGD column
and a polishing column will also reduce the emission rate of
particulate matter. Additional improvements in particulate matter
removal may also be necessary to reduce the fouling of other components
(e.g., heat exchangers) of the capture process. NOX
emissions can cause solvent degradation and nitrosamine formation by
chemical absorption of NOX, depending on the chemical
structure of the solvent. The DOE's Carbon Management Pathway report
notes that monitoring and emission controls for such degradation
products are currently part of standard operating procedures for amine-
based CO2 capture systems.\550\

A conventional multistage water or acid wash and mist eliminator at the
exit of the CO2 scrubber is effective at removal of gaseous
amine and amine degradation products (e.g., nitrosamine)
emissions.551 552 NOX levels of the flue gas
required to avoid solvent degradation and nitrosamine formation in the
CO2 scrubber vary. For most units, the requisite limits on
NOX levels to assure that the CO2 capture process
functions properly may be met by the existing NOX combustion
controls, and those units may not need to install SCR for process
purposes. However, most existing coal-fired steam generating units
either already have SCR or will be covered by proposed Federal
Implementation Plan (FIP) requirements regulating interstate transport
of NOX (as an ozone precursors) from EGUs. See 87 FR 20036
(April 6, 2022). For units not otherwise required to have SCR, an
increase in utilization from a CO2 capture retrofit could
result in increased NOX emissions at the source that,
depending on the quantity of the emissions increase, may trigger major
NSR permitting requirements. Under this scenario, the permitting
authority may determine that the NSR permit requires the installation
of SCR for those units, based on applying the requirements of major
NSR. Alternatively, a State could, as part of its State plan, develop
enforceable conditions for a source expected to trigger major NSR that
would effectively limit the unit's ability to increase its emissions in
amounts that would trigger major NSR. Under this scenario, with no
major NSR requirements applying due to the limit on the emissions
increase, the permitting authority may conclude for minor NSR purposes
that installation of SCR is not required for the units. See section
XIII.A of this preamble for additional discussion of the NSR program.
---------------------------------------------------------------------------

    \550\ U.S. Department of Energy (DOE). Pathways to Commercial
Liftoff: Carbon Management. https://liftoff.energy.gov/wp-content/uploads/2023/04/20230424-Liftoff-Carbon-Management-vPUB_update.pdf.
    \551\ Sharma, S., Azzi, M., ``A critical review of existing
strategies for emission control in the monoethanolamine-based carbon
capture process and some recommendations for improved strategies,''
Fuel, 121, 178 (2014).
    \552\ Mertens, J., et al., ``Understanding ethanolamine (MEA)
and ammonia emissions from amine-based post combustion carbon
capture: Lessons learned from field tests,'' Int'l J. of GHG
Control, 13, 72 (2013).
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(C) Water Use and Siting
    Water consumption at the plant increases when applying carbon
capture, due to solvent water makeup and cooling demand. Water
consumption can increase by 36 percent on a gross basis.\553\ A
separate cooling water system dedicated to a CO2 capture
plant may be necessary. However, the amount of water consumption
depends on the design of the cooling system. For example, the cooling
system cited in the CCS feasibility study for SaskPower's Shand Power
station would rely entirely on water condensed from the flue gas and
thus would not require any increase in external water consumption.\554\
Regions with limited water supply may rely on dry or hybrid cooling
systems, although, in areas with adequate water, wet cooling systems
can be more effective.
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    \553\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
    \554\ International CCS Knowledge Centre. The Shand CCS
Feasibility Study Public Report. https://ccsknowledge.com/pub/Publications/Shand_CCS_Feasibility_Study_Public_Report_Nov2018_(2021-05-12).pdf.
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    With respect to siting considerations, CO2 capture
systems have a sizeable physical footprint and a consequent land-use
requirement. The EPA is proposing that the water use and siting
requirements are manageable and therefore the EPA does not expect any
of these considerations to preclude coal-fired power plants generally
from being able to install and operate CCS. However, the EPA is
soliciting comment on these issues.
(D) Transport and Geologic Sequestration
    As noted in section VII.F.3.b.iii of this preamble, PHMSA oversight
of supercritical CO2 pipeline safety protects against
environmental release during transport and UIC Class VI regulations
under the SDWA, in tandem with GHGRP subpart RR requirements, ensure
the protection of USDWs and the security of geologic sequestration.
iv. Extent of Reductions in CO2 Emissions
    CCS can be applied to coal-fired steam generating units at the
source and reduce the CO2 emission rate by 90 percent or
more. Increased steam and power demand have a small impact on the
reduction in emission rate that occurs with 90 percent capture.
According to the 2016 NETL Retrofit report, 90 percent capture will
result in emission rates that are 88.4 percent lower on a lb/MWh-gross
basis and 87.1 percent lower on a lb/MWh-net basis compared to units
without capture.\555\ After capture, CO2 can be transported
and securely sequestered.\556\ Although steam generating units with
CO2 capture will have an incentive to operate at higher
utilization because the cost to install the CCS system is largely fixed
and the IRC section 45Q tax credit increases based on the amount of
CO2 captured and sequestered, any increase in utilization
will be far outweighed by the substantial reductions in emission rate.
---------------------------------------------------------------------------

    \555\ DOE/NETL-2016/1796. ``Eliminating the Derate of Carbon
Capture Retrofits.'' May 31, 2016. https://www.netl.doe.gov/energy-analysis/details?id=e818549c-a565-4cbc-94db-442a1c2a70a9.
    \556\ Intergovernmental Panel on Climate Change. (2005). Special
Report on Carbon Dioxide Capture and Storage.
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v. Technology Advancement
    The EPA considered the potential impact of designating CCS as the
BSER for long-term coal-fired steam generating units on technology
advancement, and the EPA is proposing that designating CCS as the BSER
will provide for meaningful advancement of CCS technology, for many of
the same reasons as noted in section VII.F.3.b.iii(F) of this preamble.
vi. Comparison With 2015 NSPS for Newly Constructed Coal-Fired EGUs
    In the 2015 NSPS, the EPA determined that the BSER for newly
constructed coal-fired EGUs was based on CCS with 16-23 percent
capture, based on the type of coal combusted, and consequently, the EPA
promulgated standards of performance of 1,400 lb CO2/MWh-g. 80 FR 64512
(Table 1), 64513 (October 23, 2015). The EPA made those determinations
based on the costs of CCS at the time of that rulemaking. In general,
those costs were significantly higher than at present, due to recent
technology cost declines as well as related policies, including the IRC
section 45Q tax credit for CCS, which was not available at that time
for purposes of consideration during the development of the NSPS. Id.
at 64562 (Table 8). Based on of these higher costs, the EPA determined
that 16-23 percent capture qualified as the BSER, and not a
significantly higher percentage of capture. Given the substantial
differences in the cost of CCS during the time of the 2015 NSPS and the
present time, the capture percentage of the 2015 NSPS necessarily
differed from the capture percentage in this proposal, and, by the same
token, the associated degree of emission limitation and resulting
standards of performance necessarily differ as well.
b. Natural Gas Co-Firing
    The EPA also evaluated natural gas co-firing at 40 percent of the
heat input as the potential BSER for long-term coal-fired steam
generating units. Because

the EPA is proposing natural gas co-firing as the BSER for medium-term
units, details that are common to medium-term and long-term units are
discussed in section X.D.2.b of the preamble. Based on the discussion
therein, the EPA is proposing that natural gas co-firing is adequately
demonstrated and that the non-air quality health and environmental
effects and energy requirements are not unreasonable. The costs of
natural gas co-firing for a long-term unit may also be reasonable. For
example, for a representative unit with a 10-year amortization period,
the cost of reductions is $53/ton of CO2. Finally, while 40
percent natural gas co-firing achieves unit-level emission rate
reductions of 16 percent, those reductions are less than CCS with 90
percent capture. Therefore, because CCS achieves more reductions at the
unit level and is proposed as cost reasonable for long-term units, the
EPA is not proposing natural gas co-firing as the BSER for long-term
coal-fired steam generating units.
c. Conclusion
    The EPA proposes that CCS at a capture rate of 90 percent is the
BSER for long-term coal-fired steam generating units because CCS is
adequately demonstrated, as indicated by the facts that it has been
operated at scale and is widely applicable to sources and that there
are vast sequestration opportunities across the continental U.S.
Additionally, accounting for recent technology cost declines as well as
policies including the tax credit under IRC section 45Q, the costs for
CCS are reasonable. Moreover, any adverse non-air quality health and
environmental impacts and energy requirements of CCS, including impacts
on the power sector on a nationwide basis, are limited and are
outweighed by the benefits of the significant GHG emission reductions
at reasonable cost. In contrast, co-firing 40 percent natural gas would
achieve far fewer emission reductions without improving the cost
effectiveness of the control strategy. These considerations provide the
basis for proposing CCS as the best of the systems of emission
reduction for long-term coal-fired power plants. In addition,
determining CCS as the BSER promotes this useful control technology.
Although the EPA believes that long-lived coal-fired power plants will
generally be able to implement and operate CCS within the cost
parameters calculated as part of the BSER analysis, and therefore that
they would be able to meet a standard of performance based on CCS with
90 percent capture, the EPA solicits comment on whether particular
plants would be unable to do so, including details of the circumstances
that might make retrofitting with CCS unreasonable or infeasible.
2. Medium-Term Coal-Fired Steam Generating Units
    In this section of the preamble, the EPA evaluates CCS and natural
gas co-firing as potential BSER for medium-term coal-fired steam
generating units.
    In section X.D.1.a of this preamble, the EPA evaluated CCS with 90
percent capture of CO2 as the BSER for long-term coal-fired
steam generating units. Much of this evaluation is relevant for medium-
term units. However, because they have shorter operating horizons and,
as a result, a shorter period for amortization and for collecting the
IRC section 45Q tax credits, CCS would be less cost effective for those
units. Therefore, the EPA is not proposing CCS as BSER for medium-term
coal-fired steam generating units.
    Instead, the EPA is proposing that 40 percent natural gas co-firing
on a heat input basis is the BSER for medium-term coal-fired steam
generating units. Co-firing 40 percent natural gas, on an annual
average heat input basis, results in a 16 percent reduction in
CO2 emission rate. The technology has been adequately
demonstrated, can be implemented at reasonable cost, does not have
adverse non-air quality health and environmental impacts or energy
requirements, and achieves meaningful reductions in CO2
emissions. Co-firing also advances useful control technology and has
acceptable national and long-term impacts on the energy sector, which
provide additional, although not essential, support for treating it as
the BSER.
a. CCS
    In this section of the preamble, the EPA evaluates the use of CCS
as the BSER for existing medium-term coal-fired steam generating units.
This evaluation is much the same as the evaluation for long-term units,
with the important difference of costs.
    For long-term units, as discussed earlier in this preamble, the
EPA's analysis used to evaluate the reasonableness of CCS costs employs
a 12-year amortization period, which is consistent with the period of
time during which the IRC section 45Q tax credit can be claimed.
However, existing coal-fired steam generating units that have elected
to commit to permanently cease operations prior to 2040--ones in the
medium-term subcategory, as well as in the near-term, and imminent-term
subcategories--would have a shorter period to amortize capital costs
and also would not be able to fully utilize the IRC section 45Q tax
credit. As a result, for these sources, the cost effectiveness of CCS
is less favorable. As noted in section X.D.1.a.ii(C) of this preamble,
for a 70 percent annual capacity factor and a 7-year amortization
period, costs for the reference unit are $39/ton of CO2
reduced and $34/MWh. This $/MWh generation cost is less favorable
relative to the representative cost ($/MWh) for wet FGD, the costs for
which are detailed in section VII.F.3.b.iii(B)(5). Due to the higher
incremental cost of generation, the EPA is not proposing CCS as the
BSER for medium-term coal-fired steam generating units.
    While the EPA is not proposing CCS as BSER for the proposed
subcategory of medium-term units, the EPA is taking comment on the
operating horizon (i.e., between 8 and 10 years, instead of the
proposed 10-year operating horizon) that most appropriately defines the
threshold date between medium-term and long-term units and the EPA is
also taking comment on the level of costs of CCS that should be
considered reasonable.
b. Natural Gas Co-Firing
    In this section of the preamble, the EPA evaluates natural gas co-
firing as potential BSER for medium-term coal-fired steam generating
units. Considerations that are common to the proposed subcategories of
existing coal-fired steam generating units are discussed in section
X.D.1.a of the preamble, in addition to considerations that are
specific to medium-term units.
    For a coal-fired steam generating unit, the substitution of natural
gas for some of the coal, so that the unit fires a combination of coal
and natural gas, is known as ``natural gas co-firing.'' The EPA is
proposing natural gas co-firing at a level of 40 percent of annual heat
input as BSER for medium-term coal-fired steam generating units.
i. Adequately Demonstrated
    The EPA is proposing to find that natural gas co-firing at the
level of 40 percent of annual heat input is adequately demonstrated for
coal-fired steam generating units. Many existing coal-fired steam
generating units already use some amount of natural gas, and several
have co-fired at relatively high levels at or above 40 percent of heat
input in recent years.
(A) Boiler Modifications
    Most existing coal-fired steam generating units can be modified to
co-fire natural gas in any desired proportion with coal, up to 100
percent

natural gas. Generally, the modification of existing boilers to enable
or increase natural gas firing typically involves the installation of
new gas burners and related boiler modifications, including, for
example, new fuel supply lines and modifications to existing air ducts.
The introduction of natural gas as a fuel can reduce boiler efficiency
slightly, due in large part to the relatively high hydrogen content of
natural gas. However, since the reduction in coal can result in reduced
auxiliary power demand, the overall impact on net heat rate can range
from a 2 percent increase to a 2 percent decrease.
    It is common practice for steam generating units to have the
capability to burn multiple fuels onsite, and of the 565 coal-fired
steam generating units operating at the end of 2021, 249 of them
reported consuming natural gas as a fuel or startup source. Coal-fired
steam generating units often use natural gas or oil as a startup fuel,
to warm the units up before running them at full capacity with coal.
While startup fuels are generally used at low levels (up to roughly 1
percent of capacity on an annual average basis), some coal-fired steam
generating units have co-fired natural gas at considerably higher
shares. Based on hourly reported CO2 emission rates from the
start of 2015 through the end of 2020, 29 coal-fired steam generating
units co-fired with natural gas at rates at or above 60 percent of
capacity on an hourly basis.\557\ The capability of those units on an
hourly basis is indicative of the extent of boiler burner modifications
and sizing and capacity of natural gas pipelines to those units, and
implies that those units are technically capable of co-firing at least
60 percent natural gas on a heat input basis on average over the course
of an extended period (e.g., a year). Additionally, during that same
2015 through 2020 period, 29 coal-fired steam generating units co-fired
natural gas at over 40 percent on an annual heat input basis. Because
of the number of units that have demonstrated co-firing above 40
percent of heat input, the EPA is proposing that co-firing at 40
percent is adequately demonstrated. A more detailed discussion of the
record of natural gas co-firing, including current trends, at coal-
fired steam generating units is included in the GHG Mitigation Measures
for Steam Generating Units TSD.
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    \557\ U.S. Environmental Protection Agency (EPA). ``Power Sector
Emissions Data.'' Washington, DC: Office of Atmospheric Protection,
Clean Air Markets Division. Available from EPA's Air Markets Program
Data website: https://campd.epa.gov.
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(B) Natural Gas Pipeline Development
    In addition to any potential boiler modifications, the supply of
natural gas is necessary to enable co-firing at existing coal-fired
steam boilers. As discussed in the previous section, many plants
already have at least some access to natural gas. In order to increase
natural gas access beyond current levels, many will find it necessary
to construct natural gas supply pipelines.
    The U.S. natural gas pipeline network consists of approximately 3
million miles of pipelines that connect natural gas production with
consumers of natural gas. To increase natural gas consumption at a
coal-fired boiler without sufficient existing natural gas access, it is
necessary to connect the facility to the natural gas pipeline
transmission network via the construction of a lateral pipeline. The
cost of doing so is a function of the total necessary pipeline capacity
(which is characterized by the length, size, and number of laterals)
and the location of the plant relative to the existing pipeline
transmission network. The EPA estimated the costs associated with
developing new lateral pipeline capacity sufficient to meet 60 percent
of the net summer capacity at each coal-fired steam generating unit. As
discussed in the GHG Mitigation Measures for Steam Generating Units
TSD, the EPA estimates that this lateral capacity would be sufficient
to enable each unit to achieve 40 percent natural gas co-firing on an
annual average basis.
    The EPA considered the availability of the upstream natural gas
pipeline capacity to satisfy the assumed co-firing demand implied by
these new laterals. This analysis included pipeline development at all
EGUs that could be included in this subcategory. The EPA's assessment
reviewed the reasonableness of each assumed new lateral by determining
whether the peak gas capacity of that lateral could be satisfied
without modification of the transmission pipeline systems to which it
is assumed to be connected. This analysis found that most, if not all,
existing pipeline systems are currently able to meet the peak needs
implied by these new laterals in aggregate, assuming that each existing
coal-fired unit in the analysis co-fired with natural gas at a level
implied by these new laterals, or 60 percent of net summer generating
capacity. While this is a reasonable assumption for the analysis to
support this mitigation measure in the BSER context, it is also a
conservative assumption that overstates the amount of natural gas co-
firing expected under the proposed rule.
    The maximum amount of pipeline capacity, if all coal-fired steam
capacity in the medium-term subcategory implemented the proposed BSER
by co-firing 40 percent natural gas, would be a fraction of the
pipeline capacity constructed recently. The EPA estimates that this
maximum total capacity would be about 17.3 billion cubic feet per day,
which would require almost 4,000 miles of pipeline costing roughly
$13.3 billion. Over 5 years, this maximum total incremental pipeline
capacity would amount to 800 miles per year and approximately $2.7
billion per year in capital expenditures, on average. By comparison,
based on data collected by EIA, the total annual mileage of natural gas
pipelines constructed over the 2017-2021 period ranged from
approximately 1,000 to 2,500 miles per year, with a total capacity of
10 to 25 billion cubic feet per day. This represents an estimated
annual investment of up to nearly $15 billion. These historical annual
values are much higher than the maximum annual values that could be
expected under this proposed BSER measure--which, as noted above,
represent a conservative estimate that overstates the amount of co-
firing that the EPA projects would occur under this proposed rule.
    These conservatively high estimates of pipeline requirements also
compare favorably to industry projections of future pipeline capacity
additions. Based on a review of a 2018 industry report, titled ``North
America Midstream Infrastructure through 2035: Significant Development
Continues,'' investment in midstream infrastructure development is
expected to average about $37 billion per year through 2035, which is
lower than historical levels. Approximately $10 to $20 billion annually
is expected to be invested in natural gas pipelines through 2035. This
report also projects that an average of over 1,400 miles of new natural
gas pipeline will be built through 2035, which is similar to the
approximately 1,670 miles that were built on average from 2013 to 2017.
These values are considerably greater than the average annual
expenditure of $2.7 billion on 800 miles per year of new pipeline
construction that would be necessary for the entire operational fleet
of coal-fired steam generating units to co-fire with natural gas. The
actual pipeline investment for this subcategory would be substantially
lower.
ii. Costs
    The capital costs associated with the addition of new gas burners
and other necessary boiler modifications depend on the extent to which
the current boiler is already able to co-fire with some

natural gas and on the amount of gas co-firing desired. The EPA
estimates that, on average, the total capital cost associated with
modifying existing boilers to operate at up to 100 percent of heat
input using natural gas is approximately $52/kW. These costs could be
higher or lower, depending on the equipment that is already installed
and the expected impact on heat rate or steam temperature.
    While fixed O&M (FOM) costs can potentially decrease as a result of
decreasing the amount of coal consumed, it is common for plants to
maintain operation of one coal pulverizer at all times, which is
necessary for maintaining several coal burners in continuous service.
In this case, coal handling equipment would be required to operate
continuously and therefore natural gas co-firing would have limited
effect on reducing the coal-related FOM costs. Although, as noted,
coal-related FOM costs have the potential to decrease, the EPA does not
anticipate a significant increase in impact on FOM costs related to co-
firing with natural gas.
    In addition to capital and FOM cost impacts, any additional natural
gas co-firing would result in incremental costs related to the
differential in fuel cost, taking into consideration the difference in
delivered coal and gas prices, as well as any potential impact on the
overall net heat rate. The EPA's post-IRA 2022 reference case projects
that in 2030, the average delivered price of coal will be $1.47/MMBtu
and the average delivered price of natural gas will be $2.53/MMBtu.
Thus, assuming the same level of generation and no impact on heat rate,
the additional fuel cost would be above $1/MMBtu on average in 2030.
The total additional fuel cost could increase or decrease depending on
the potential impact on net heat rate. An increase in net heat rate,
for example, would result in more fuel required to produce a given
amount of generation and thus additional cost. In the GHG Mitigation
Measures for Steam Generating Units TSD, the EPA's cost estimates
assume a 1 percent increase in net heat rate.
    Finally, for plants without sufficient access to natural gas, it is
also necessary to construct new natural gas pipelines (``laterals'').
Pipeline costs are typically expressed in terms of dollars per inch of
pipeline diameter per mile of pipeline distance (i.e., dollars per
inch-mile), reflecting the fact that costs increase with larger
diameters and longer pipelines. On average, the cost for lateral
development within the contiguous U.S. is approximately $280,000 per
inch-mile (2019$), which can vary based on site-specific factors. The
total pipeline cost for each coal-fired steam generating unit is a
function of this cost, as well as a function of the necessary pipeline
capacity and the location of the plant relative to the existing
pipeline transmission network. The pipeline capacity required depends
on the amount of co-firing desired as well as on the desired level of
generation--a higher degree of co-firing while operating at full load
would require more pipeline capacity than a lower degree of co-firing
while operating at partial load. It is reasonable to assume that most
plant owners would develop sufficient pipeline capacity to deliver the
maximum amount of desired gas use in any moment, enabling higher levels
of co-firing during periods of lower fuel price differentials. Once the
necessary pipeline capacity is determined, the total lateral cost can
be estimated by considering the location of each plant relative to the
existing natural gas transmission pipelines as well as the available
excess capacity of each of those existing pipelines. For purposes of
the cost reasonableness estimates as follows, the EPA assumes pipeline
costs of $92/kW, which is the median value of all unit-level pipeline
cost estimates, as explained in the GHG Mitigation Measures for Steam
Generating Units TSD. The range in costs reflects a range in the
amortization period of the capital costs over 6 to 10 years, which is
consistent with the amount of time over which the units in the medium-
term subcategory could be operational.
    The EPA sums the natural gas co-firing costs as follows: For a
typical base load coal-fired steam generating unit in 2030, the EPA
estimates that the cost of co-firing with 40 percent natural gas on an
annual average basis is approximately $53 to $66/ton CO2
reduced, or $9 to $12/MWh, respective to amortization periods of 10 to
6 years. This estimate is based on the characteristics of a typical
coal-fired unit in 2021 (400 MW capacity and an average heat rate of
10,500 Btu/kWh) operating at a typical capacity factor of about 50
percent, and it assumes a pipeline cost of $92/kW, as discussed earlier
in this preamble.
    Based on the coal-fired steam generating units that existed in 2021
and that do not have known plans to cease operations or convert to gas
by 2030, and assuming that each of those units continues to operate at
the same level in 2030 as it operated in 2017-2021, on average, the EPA
estimates that the weighted average cost of co-firing with 40 percent
natural gas on an annual average basis is approximately $64 to $78/ton
CO2 reduced, or $11 to $14/MWh. The $/ton cost estimate is
lower than average for approximately 82 GW, and the $/MWh cost estimate
is lower than average for 86 GW (about 69 percent and 72 percent,
respectively, of the relevant coal fleet). These estimates and all
underlying assumptions are explained in detail in the GHG Mitigation
Measures for Steam Generating Units TSD.
    As was described in section X.D.1 of this preamble, the EPA has
compared the estimated costs discussed in section X.D.2 of this
preamble to costs that coal-fired steam generating units have incurred
to install controls that reduce other air pollutants, such as
SO2. Compared to the representative costs of controls
detailed in section VII.F.3.b.iii(B)(5) of this preamble (i.e.,
emission control costs on EGUs of $10.60 to $29/MWh and the costs in
the 2016 NSPS regulating GHGs for the Crude Oil and Natural Gas source
category of $98/ton of CO2e reduced (80 FR 56627; September
18, 2015)), both estimates of annualized costs of natural gas co-firing
(approximately $53-$66/ton or $9-$12/MWh for a typical unit and $64-
$78/ton or $11-$14/MWh on average)) are comparable or lower. The range
of cost effectiveness estimates presented in this section is lower than
previously estimated by the EPA in the proposed CPP, for several
reasons. Since then, the expected difference between coal and gas
prices has decreased significantly, from over $3/MMBtu to about $1/
MMBtu in this proposal. Additionally, a recent analysis performed by
Sargent and Lundy for the EPA supports a considerably lower capital
cost for modifying existing boilers to co-fire with natural gas. The
EPA also recently conducted a highly detailed facility-level analysis
of natural gas pipeline costs, the median value of which is slightly
lower than the value used by the EPA previously to approximate the cost
of co-firing at a representative unit.
    Based on the cost analysis presented in this section, the EPA is
proposing that the costs of natural gas co-firing are reasonable for
the medium-term coal-fired steam generating unit subcategory.
iii. Non-Air Quality Health and Environmental Impact and Energy
Requirements
    Natural gas co-firing for steam generating units is not expected to
have any significant adverse consequences related to non-air quality
health and environmental impacts or energy requirements.

(A) Non-GHG Emissions
    Non-GHG emissions are reduced when steam generating units co-fire
with natural gas because less coal is combusted. SO2,
PM2.5, acid gas, mercury and other hazardous air pollutant
emissions that result from coal combustion are reduced proportionally
to the amount of natural gas consumed, i.e., under this proposal, by 40
percent. Natural gas combustion does produce NOX emissions,
but in lesser amounts than from coal-firing. However, the magnitude of
this reduction is dependent on the combustion system modifications that
are implemented to facilitate natural gas co-firing.
    Additionally, sufficient regulations exist related to natural gas
pipelines and transport that assure natural gas can be safely
transported with minimal risk of environmental release. PHMSA develops
and enforces regulations for the safe, reliable, and environmentally
sound operation of the nation's 2.6 million mile pipeline
transportation system. Recently, PHMSA finalized a rule that will
improve the safety and strengthen the environmental protection of more
than 300,000 miles of onshore gas transmission pipelines.\558\ PHMSA
also recently promulgated a rule covering natural gas
transmission,\559\ as well as a rule that significantly expanded the
scope of safety and reporting requirements for more than 400,000 miles
of previously unregulated gas gathering lines.\560\ Additionally, FERC
oversees the development of new natural gas pipelines.
---------------------------------------------------------------------------

    \558\ Pipeline Safety: Safety of Gas Transmission Pipelines:
Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments (87
FR 52224; August 24, 2022).
    \559\ Pipeline Safety: Safety of Gas Transmission Pipelines:
MAOP Reconfirmation, Expansion of Assessment Requirements, and Other
Related Amendments (84 FR 52180; October 1, 2019).
    \560\ Pipeline Safety: Safety of Gas Gathering Pipelines:
Extension of Reporting Requirements, Regulation of Large, High-
Pressure Lines, and Other Related Amendments (86 FR 63266; November
15, 2021).
---------------------------------------------------------------------------

(B) Energy Requirements
    The introduction of natural gas co-firing will cause steam boilers
to be slightly less efficient due to the high hydrogen content of
natural gas. Co-firing at levels between 20 percent and 100 percent can
be expected to decrease boiler efficiency between 1 percent and 5
percent. However, despite the decrease in boiler efficiency, the
overall net output efficiency of a steam generating unit that switches
from coal- to natural gas-firing may change only slightly, in either a
positive or negative direction. Since co-firing reduces coal
consumption, the auxiliary power demand related to coal handling and
emissions controls typically decreases as well. While a site-specific
analysis would be required to determine the overall net impact of these
countervailing factors, generally the effect of co-firing on net unit
heat rate can vary within approximately plus or minus 2 percent.
    The EPA previously determined in the ACE Rule (84 FR 32520 at
32545; July 8, 2019) that ``co-firing natural gas in coal-fired utility
boilers is not the best or most efficient use of natural gas and [. .
.] can lead to less efficient operation of utility boilers.'' That
determination was informed by the more limited supply of natural gas,
and the larger amount of coal-fired EGU capacity and generation, in
2019. Since that determination, the expected supply of natural gas has
expanded considerably, and the capacity and generation of the existing
coal-fired fleet has decreased, reducing the total mass of natural gas
that might be required for sources to implement this measure.
Additionally, the natural gas co-firing measure is now being proposed
for a medium-term coal-fired steam generating unit subcategory, a group
of units that will operate at most for 10 years following the
compliance date, which would further reduce the total amount of
required natural gas.
    Furthermore, regarding the efficient operation of boilers, the ACE
determination was based on the observation that ``co-firing can
negatively impact a unit's heat rate (efficiency) due to the high
hydrogen content of natural gas and the resulting production of water
as a combustion by-product.'' That finding does not consider the fact
that the effect of co-firing on net unit heat rate can vary within
approximately plus or minus 2 percent, and therefore the net impact on
overall utility boiler efficiency for each steam generating unit is
uncertain.
    For all of these reasons, the EPA is proposing that natural gas co-
firing at medium-term coal-fired steam generating units does not result
in any significant adverse consequences related to energy requirements.
    Additionally, the EPA considered longer term impacts on the energy
sector, and the EPA is proposing these impacts are reasonable.
Designating natural gas co-firing as the BSER for medium-term coal-
fired steam generating units would not have significant adverse impacts
on the structure of the energy sector. Steam generating units that
currently are coal-fired would be able to remain primarily coal-fired.
The replacement of some coal with natural gas as fuel in these sources
would not have significant adverse effects on the price of natural gas
or the price of electricity.
iv. Extent of Reductions in CO2 Emissions
    One of the primary benefits of natural gas co-firing is emission
reduction. CO2 emissions are reduced by approximately 4
percent for every additional 10 percent of co-firing. When shifting
from 100 percent coal to 60 percent coal and 40 percent natural gas,
CO2 stack emissions are reduced by approximately 16 percent.
Non-CO2 emissions are reduced as well, as noted earlier in
this preamble.
v. Technology Advancement
    Natural gas co-firing is already well-established and widely used
by coal-fired steam boiler generating units. As a result, this proposed
rule is not likely to lead to technological advances or cost reductions
in the components of natural gas co-firing, including modifications to
boilers and pipeline construction. However, greater use of natural gas
co-firing may lead to improvements in the efficiency of conducting
natural gas co-firing and operating the associated equipment.
c. Conclusion
    The EPA proposes that natural gas co-firing at 40 percent of heat
input is the BSER for medium-term coal-fired steam generating units
because natural gas co-firing is adequately demonstrated, as indicated
by the facts that it has been operated at scale and is widely
applicable to sources. Additionally, the costs for natural gas co-
firing are reasonable. Moreover, any adverse non-air quality health and
environmental impacts and energy requirements of natural gas co-firing
are limited and are outweighed by the benefits of the emission
reductions at reasonable cost. In contrast, CCS, although achieving
greater emission reductions, would be less cost-effective, in general,
for the proposed subcategory of medium-term units.
    While the EPA is not proposing CCS as BSER for the proposed
subcategory definition of medium-term units, the EPA is taking comment
on the operating horizons that define the threshold date between
medium-term and long-term units (i.e., between 8 and 10 years, instead
of the proposed 10-year operating horizon) and on what amount of costs
should be considered reasonable.

3. Imminent-Term and Near-Term Coal-Fired Steam Generating Units
    In this section of the preamble, the EPA evaluates CCS, natural gas
co-firing, low levels of natural gas co-firing, and routine methods of
operation and maintenance as the BSER for imminent-term and near-term
coal-fired steam generating units. Primarily because of the effect of a
short operating horizon on the cost of controls for these units, the
EPA proposes routine methods of operation and maintenance as the BSER.
a. CCS
    As noted in section X.D.2.a of this preamble, the EPA is not
proposing CCS for medium-term units due to $/MWh costs being less
favorable based on the appropriate cost metrics. Because of the shorter
operating horizons for imminent-term and near-term coal-fired steam
generating units, CCS is less cost favorable for them than for medium-
term units. Therefore, the EPA is not proposing CCS as BSER for
imminent-term or near-term coal-fired steam generating units.
Additional details of cost values for amortization periods
representative of imminent-term and near-term units are available in
the GHG Mitigation Measures for Steam Generating Units TSD.
b. Natural Gas Co-Firing
i. Natural Gas Co-Firing at 40 Percent
    Much of the discussion of natural gas co-firing in section X.D.2.b
of this preamble for medium-term units is relevant for imminent-term
and near-term units, except that natural gas co-firing is less cost
effective for the latter units because of their short operating
horizons, particularly on a $/ton of CO2 reduced basis. For
a 2-year amortization period, annualized costs for the representative
unit are $130/ton of CO2 reduced and $23/MWh of generation.
Therefore, the EPA is not proposing natural gas co-firing as BSER for
imminent-term or near-term units. Additional details of cost are
available in the GHG Mitigation Measures for Steam Generating Units
TSD.
ii. Natural Gas Co-Firing at Low Levels of Heat Input
    Although higher levels of natural gas co-firing may be less cost
effective for imminent-term and near-term units, it is possible that
lower levels of natural gas co-firing may be cost reasonable. Many
units have demonstrated the ability to co-fire with natural gas over
short periods of time and operating with those same levels of natural
gas co-firing over longer periods of time (i.e., annually) may achieve
emission reductions. A low level of natural gas co-firing (up to 10
percent of annual heat input) is adequately demonstrated and may be
broadly achievable, may achieve reductions in GHG emissions, may be of
reasonable cost, and is unlikely to cause unreasonable adverse non-air
quality health and environmental impacts or result in substantial
energy requirements. Therefore, the EPA is soliciting comment on low
levels of natural gas co-firing as a potential component of the BSER
for imminent-term and near-term coal-fired steam generating units.
    The EPA recognizes that different coal-fired units may be already
capable of different natural gas co-firing rates (as discussed in
section X.D.2.b.i of this preamble) and is therefore soliciting comment
on defining a potential BSER on the basis of the maximum hourly heat
input of natural gas fired in the unit (MMBtu/hr) relative to the
maximum hourly heat input the unit is capable of (i.e., the nameplate
capacity on an MMBtu/hr basis). Alternatively, the EPA is soliciting
comment on a fixed value of annual heat input percentage that
represents a low level of natural gas co-firing, as well as the
definition of a low level of natural gas co-firing that is based on the
characteristics of an existing facility (e.g., the capacity of the
existing pipeline). The EPA is also soliciting comment on a degree of
emission limitation resulting from low levels of natural gas co-firing,
as detailed in section X.D.4.c of this preamble.
(1) Adequately Demonstrated
    For many of the same reasons stated in section X.D.2.b.i of this
preamble for natural gas co-firing at higher levels, natural gas co-
firing at low levels is adequately demonstrated. The EPA also
identified that 369 of the 565 EGUs operating at the end of 2021 have
either reported natural gas as a fuel source, are located at a plant
with a natural gas generator, and/or are located at a plant with a
natural gas pipeline connection. A large percentage of the existing
fleet of coal-fired steam generating units would therefore likely be
able to co-fire natural gas at low levels without having to make boiler
modifications or build additional pipelines.
(2) Costs
    The costs of low levels of natural gas co-firing may be reasonable
because low levels of natural gas co-firing likely require little, if
any, capital investment. Additionally, the relatively small increase in
natural gas fuel use would only result in a modest increase in total
fuel cost.
(3) Non-Air Quality Health and Environmental Impact and Energy
Requirements
    For many of the same reasons stated in section X.D.2.b.iii of this
preamble, low levels of natural gas co-firing are unlikely to cause
unreasonable adverse non-air quality health and environmental impacts
or result in substantial energy requirements. Furthermore, low levels
of natural gas co-firing may require only limited construction of
additional infrastructure as existing pipeline laterals to the units
should be of sufficient size to achieve low levels of natural gas co-
firing.
(4) Extent of Reductions in CO2 Emissions
    The emission reductions achieved at the unit from low levels of
natural gas co-firing of 1 to 10 percent may be relatively low at
around 0.4 to 4 percent, respectively. However, these are likely on
average greater than the emission reductions that could be achievable
by other technologies, such as HRI. Furthermore, because the efficiency
of the unit is not increased as with HRI, the unit likely does not move
up in dispatch order, and it is likely the unit would not be subject to
the rebound effect. See section X.D.5 of this preamble for a discussion
of HRI.
(5) Technology Advancement
    Low levels of natural gas co-firing do not advance useful control
technology, for reasons similar to those discussed in section X.D.2.b.v
of this preamble.
c. Routine Methods of Operation and Maintenance
    For the imminent-term and near-term coal-fired steam generating
units, the EPA is proposing that the BSER is routine methods of
operation and maintenance already occurring at the unit, so as to
maintain the current unit-specific CO2 emission rates
(expressed as lb CO2/MWh).
    Routine methods of operation and maintenance are adequately
demonstrated because units already operate by those methods. They will
not result in additional costs from any controls, and will not create
adverse non-air quality health and environmental impacts or energy
requirements. They will not achieve CO2 emission reductions
at the unit level relative to current performance, but they can prevent
worsening of emission rates over time. Although they do not advance
useful control technology, they do not have adverse impacts on the
energy sector from a nationwide or long-term perspective.

4. Degree of Emission Limitation
    Under CAA section 111(d), once the EPA determines the BSER, it must
determine the ``degree of emission limitation'' achievable by the
application of the BSER. States then determine standards of performance
and include them in the State plans, based on the specified degree of
emission limitation. Proposed presumptive standards of performance are
detailed in section XII.D of this preamble. There is substantial
variation in emission rates among coal-fired steam generating units--
the range is, approximately, from 1,700 lb CO2/MWh-gross to
2,500 lb CO2/MWh-gross--which makes it challenging to
determine a single, uniform emission limit. Accordingly, for each of
the four subcategories of coal-fired steam generating units, the EPA is
proposing to determine the degree of emission limitation by a
percentage change in emission rate, as follows:
a. Long-Term Coal-Fired Steam Generating Units
    As discussed earlier in this preamble, the EPA is proposing the
BSER for long-term coal-fired steam generating units as ``full-
capture'' CCS, defined as 90 percent capture of the CO2 in
the flue gas. The degree of emission limitation achievable by applying
this BSER can be determined on a rate basis. A capture rate of 90
percent results in reductions in the emission rate of 88.4 percent on a
lb CO2/MWh-gross basis, and this reduction in emission rate
can be observed over an extended period (e.g., an annual calendar-year
basis). Therefore, the EPA is proposing that the degree of emission
limitation for long-term units is an 88.4 percent reduction in emission
rate on a lb CO2/MWh-gross basis over an extended period
(e.g., an annual calendar-year basis).
    As noted in section X.D.1.a of this preamble, new CO2
capture retrofits on existing coal-fired steam generating units may
achieve capture rates greater than 90 percent, and the EPA is taking
comment on a range of capture rates that may be achievable. As noted in
section VII.F.3.b.iii(A)(2) of this preamble, the operating
availability (i.e., the amount of time a process operates relative to
the amount of time it planned to operate) of industrial processes is
usually less than 100 percent. Assuming that CO2 capture
achieves 90 percent capture when available to operate, that CCS is
available to operate 90 percent of the time the coal-fired steam
generating unit is operating, and that the steam generating unit
operates the same whether or not CCS is available to operate, total
emission reductions would be 81 percent. Higher levels of emission
reduction could occur for higher capture rates coupled with higher
levels of operating availability relative to operation of the steam
generating unit. If the steam generating unit were not permitted to
operate when CCS was unavailable, there may be local reliability
consequences, and the EPA is soliciting comment on how to balance these
issues. Additionally, the EPA is soliciting comment on a range of the
degree of emission limitation achievable, in the form of a reduction in
emission rate of 75 to 90 percent when determined over an extended
period (e.g., an annual calendar-year basis).
b. Medium-Term Coal-Fired Steam Generating Units
    As discussed earlier in this preamble, the BSER for medium-term
coal-fired steam generating units is 40 percent natural gas co-firing.
The application of 40 percent natural gas co-firing results in
reductions in the emission rate of 16 percent. Therefore, the degree of
emission limitation for these units is a 16 percent reduction in
emission rate on a lb CO2/MWh-gross basis over an extended
period (e.g., an annual calendar-year basis).
c. Imminent-Term and Near-Term Coal-Fired Steam Generating Units
    As discussed above, the BSER for imminent-term and near-term coal-
fired steam generating units is routine methods of operation and
maintenance. Application of this BSER results in no increase in
emission rate. Thus, the degree of emission limitation corresponding to
the application of the BSER is no increase in emission rate on a lb
CO2/MWh-gross basis over an extended period (e.g., an annual
calendar-year basis).
    Because the EPA is soliciting comment on low levels of natural gas
co-firing as a potential BSER for imminent-term and near-term units,
the EPA is also soliciting comment on the degree of emission limitation
that may be achievable by application of low levels of natural gas co-
firing. The EPA is soliciting comment on degrees of emission limitation
defined by reductions in emission rate on a lb CO2/MWh-gross
basis that are equal to the percent of heat input times 0.4, the
percent of reduction in emission rate that may be achieved for each
percent of natural gas heat input. For example, for natural gas co-
firing at 1 to 10 percent, this results in a degree of emission
limitation of 0.4 to 4 percent reduction in emission rate on a lb
CO2/MWh-gross basis (over an extended period of time). More
specifically, the EPA solicits comment on the degree of emission
limitation based on the calculation method defined in the preceding
text up to a 4 percent reduction in emission rate (lb CO2/
MWh-gross) over an extended period of time. Alternatively, as the EPA
is also soliciting comment on a fixed percent of low levels of natural
gas co-firing, the EPA is additionally soliciting comment on a fixed
degree of emission limitation based on the same calculation method.
Because the reductions in GHG emissions from low levels of natural gas
co-firing are relatively low and may be challenging to measure, the EPA
is also soliciting comment on a degree of emission limitation defined
on a percent of heat input basis, although the EPA also recognizes that
measurement of fuel flow may also have challenges.
5. Other Emission Reduction Measures
a. Heat Rate Improvements
    Heat rate is a measure of efficiency that is commonly used in the
power sector. The heat rate is the amount of energy input, measured in
Btu, required to generate one kWh of electricity. The lower an EGU's
heat rate, the more efficiently it operates. As a result, an EGU with a
lower heat rate will consume less fuel and emit lower amounts of
CO2 and other air pollutants per kWh generated as compared
to a less efficient unit. HRI measures include a variety of technology
upgrades and operating practices that may achieve CO2
emission rate reductions of 0.1 to 5 percent for individual EGUs. The
EPA considered HRI to be part of the BSER in the CPP and to be the BSER
in the ACE Rule. However, the reductions that may be achieved by HRI
are small relative to the reductions from natural gas co-firing and
CCS. Also, some facilities that apply HRI would, as a result of their
increased efficiency, increase their utilization and therefore increase
their CO2 emissions (as well as emissions of other air
pollutants), a phenomenon that the EPA has termed the ``rebound
effect.'' Therefore, the EPA is not proposing HRI as a part of BSER.
i. CO2 Reductions From HRI in Prior Rulemakings
    In the CPP, the EPA quantified emission reductions achievable
through heat rate improvements on a regional basis by an analysis of
historical emission rate data, taking into consideration operating load
and ambient temperature. The Agency concluded that EGUs can achieve on
average a 4.3 percent improvement in the Eastern Interconnection, a 2.1

percent improvement in the Western Interconnection, and a 2.3 percent
improvement in the Texas Interconnection. See 80 FR 64789 (October 23,
2015). The Agency then applied all three of the building blocks to 2012
baseline data and quantified, in the form of CO2 emission
rates, the reductions achievable in each interconnection in 2030, and
then selected the least stringent as a national performance rate. Id.
at 64811-19. The EPA noted that building block 1 measures could not by
themselves constitute the BSER because the quantity of emission
reductions achieved would be too small and because of the potential for
an increase in emissions due to increased utilization (i.e., the
``rebound effect'').
    A description of the ACE Rule is detailed in section IX of this
preamble.
ii. Updated CO2 Reductions From HRI
    The HRI measures include improvements to the boiler island (e.g.,
neural network system, intelligent sootblower system), improvements to
the steam turbine (e.g., turbine overhaul and upgrade), and other
equipment upgrades (e.g., variable frequency drives). Some regular
practices that may recover degradation in heat rate to recent levels--
but that do not result in upgrades in heat rate over recent design
levels and are therefore not HRI measures--include practices such as
in-kind replacements and regular surface cleaning (e.g., descaling,
fouling removal). Specific details of the HRI measures are described in
the GHG Mitigation Measures for Steam Generating Units TSD and an
updated 2023 Sargent and Lundy HRI report (Heat Rate Improvement Method
Costs and Limitations Memo), available in the docket. Most HRI upgrade
measures achieve reductions in heat rate of less than 1 percent. In
general, the 2023 Sargent and Lundy HRI report, which updates the 2009
Sargent and Lundy HRI report, shows that HRI achieve less reductions
than indicated in the 2009 report, and shows that several HRI either
have limited applicability or have already been applied at many units.
Steam path overhaul and upgrade may achieve reductions up to 5.15
percent, with the average being around 1.5 percent. Different
combinations of HRI measures do not necessarily result in cumulative
reductions in emission rate (e.g., intelligent sootblowing systems
combined with neural network systems). Some of the HRI measures (e.g.,
variable frequency drives) only impact heat rate on a net generation
basis by reducing the parasitic load on the unit and would thereby not
be observable for emission rates measured on a gross basis. Assuming
many of the HRI measures could be applied to the same unit, adding
together the upper range of some of the HRI percentages could yield an
emission rate reduction of around 5 percent. However, the reductions
that the fleet could achieve on average are likely much smaller. As
noted, the 2023 Sargent and Lundy HRI report notes that, in many cases,
units have already applied HRI upgrades or that those upgrades would
not be applicable to all units. The unit level reductions in emission
rate from HRI are small relative to CCS or natural gas co-firing. In
the CPP and ACE Rule, the EPA viewed CCS and natural gas co-firing as
too costly to qualify as the BSER; those costs have fallen since those
rules and, as a result, CCS and natural gas co-firing do qualify as the
BSER for the long-term and medium-term subcategories, respectively.
iii. Potential for Rebound in CO2 Emissions
    Reductions achieved on a rate basis from HRI may not result in
overall emission reductions and could instead cause a ``rebound
effect'' from increased utilization. A rebound effect would occur
where, because of an improvement in its heat rate, a steam generating
unit experiences a reduction in variable operating costs that makes the
unit more competitive relative to other EGUs and consequently raises
the unit's output. The increase in the unit's CO2 emissions
associated with the increase in output would offset the reduction in
the unit's CO2 emissions caused by the decrease in its heat
rate and rate of CO2 emissions per unit of output. The
extent of the offset would depend on the extent to which the unit's
generation increased. The CPP did not consider HRI to be BSER on its
own, in part because of the potential for a rebound effect. Analysis
for the ACE Rule, where HRI was the entire BSER, observed a rebound
effect for certain sources in some cases. In this action, where
different subcategories of units are proposed to be subject to
different BSER measures, steam generating units in a hypothetical
subcategory with HRI as BSER could experience a rebound effect. Because
of this potential for perverse GHG emission outcomes resulting from
deployment of HRI at certain steam generating units, coupled with the
relatively minor overall GHG emission reductions that would be expected
from this measure, the EPA is not proposing HRI as the BSER for any
subcategory of existing coal-fired steam generating units.

E. Natural Gas-Fired and Oil-Fired Steam Generating Units

    In this section of the preamble, the EPA is addressing natural gas-
and oil-fired steam generating units. The EPA is proposing the BSER and
degree of emission limitation achievable by application of the BSER for
those units and identifying the associated emission rates that States
may apply to these units. For the reasons described here, the EPA is
proposing subcategories based on load level (i.e., annual capacity
factor), specifically, units that are base load, intermediate load, and
low load. At this time, the EPA is not proposing requirements for low
load units but is taking comment on a BSER of lower emitting fuels for
those units. The EPA is proposing routine methods of operation and
maintenance as BSER for intermediate and base load units. Applying that
BSER would not achieve emission reductions but would prevent increases
in emission rates. The EPA is proposing presumptive standards of
performance that differ between intermediate and base load units due to
their differences in operation, as detailed in section XII.D.1.b.v of
this preamble. The EPA is also proposing a separate subcategory for
non-continental oil-fired steam generating units, which operate
differently from continental units, with presumptive standards of
performance detailed in section XII.D.1.b.vi of this preamble.
    Natural gas- and oil-fired steam generating units combust natural
gas or distillate fuel oil or residual fuel oil in a boiler to produce
steam for a turbine that drives a generator to create electricity. In
non-continental areas, existing natural gas- and oil-fired steam
generating units may provide base load power, but in the continental
U.S., most existing units operate in a load-following manner. There are
approximately 200 natural gas-fired steam generating units and fewer
than 30 oil-fired steam generating units in operation in the
continental U.S. Fuel costs and inefficiency relative to other
technologies (e.g., combustion turbines) result in operation at lower
annual capacity factors for most units. Based on data reported to EIA
and CAMD for the contiguous U.S., for natural gas-fired steam
generating units in 2019, the average annual capacity factor was less
than 15 percent and 90 percent of units had annual capacity factors
less than 35 percent. For oil-fired steam generating units in 2019, no
units had annual capacity factors above 8 percent. Additionally, their
load-following method of operation results in frequent cycling and a
greater proportion of time

spent at low hourly capacities, when generation is less efficient.
Furthermore, because startup times for most boilers are usually long,
natural gas steam generating units may operate in standby mode between
periods of peak demand. Operating in standby mode requires combusting
fuel to keep the boiler warm, and this further reduces the efficiency
of natural gas combustion.
    Unlike coal-fired steam generating units, the CO2
emission rates of oil- and natural gas-fired steam generating units
that have similar annual capacity factors do not vary considerably
between units. This is partly due to the more uniform qualities (e.g.,
carbon content) of the fuel used. However, the emission rates for units
that have different annual capacity factors do vary considerably, as
detailed in the Natural Gas- and Oil-fired Steam Generating Unit TSD.
Low annual capacity factor units cycle frequently, have a greater
proportion of CO2 emissions that may be attributed to
startup, and have a greater proportion of generation at inefficient
hourly capacities. Intermediate annual capacity factor units operate
more often at higher hourly capacities, where CO2 emission
rates are lower. High annual capacity factor units operate still more
at base load conditions, where units are more efficient and
CO2 emission rates are lower. Based on these performance
differences between these load levels, the EPA is, in general,
proposing to divide natural gas- and oil-fired steam generating units
into three subcategories each--low load, intermediate load, and base
load--as specified in section X.C.2 of this preamble: ``low'' load is
defined by annual capacity factors less than 8 percent,
``intermediate'' load is defined by annual capacity factors greater
than or equal to 8 percent and less than 45 percent, and ``base'' load
is defined by annual capacity factors greater than 45 percent.
1. Options Considered for BSER
    The EPA has considered various methods for controlling
CO2 emissions from natural gas- and oil-fired steam
generating units to determine whether they meet the criteria for BSER.
Co-firing natural gas cannot be the BSER for these units because
natural gas- and oil-fired steam generating units already fire large
proportions of natural gas. Most natural gas-fired steam generating
units fire more than 90 percent natural gas on a heat input basis, and
any oil-fired steam generating units that would potentially operate
above an annual capacity factor of around 15 percent would combust
natural gas as a large proportion of their fuel as well. Nor is CCS a
candidate for BSER. The utilization of most gas-fired units, and likely
all oil-fired units, is relatively low, and as a result, the amount of
CO2 available to be captured is low. However, the capture
equipment would still need to be sized for the nameplate capacity of
the unit. Therefore, the capital and operating costs of CCS would be
high relative to the amount of CO2 available to be captured.
Additionally, again due to lower utilization, the amount of IRC section
45Q tax credits that owner/operators could claim would be low. Because
of the relatively high costs and the relatively low cumulative emission
reduction potential for these natural gas- and oil-fired steam
generating units, the EPA is not proposing CCS as the BSER for them.
    The EPA has reviewed other possible controls but is not proposing
any of them as the BSER for natural gas- and oil-fired units either.
Co-firing hydrogen in a boiler is technically possible, but, for the
same reasons discussed in section VII of this preamble, the only
hydrogen that could be considered for the BSER would be low-GHG
hydrogen, and there is limited availability of that hydrogen now and in
the near future. Additionally, for natural gas-fired steam generating
units, setting a future standard based on hydrogen would have limited
GHG reduction benefits given the low utilization of natural gas- and
oil-fired steam generating units. Lastly, HRI for these types of units
would face many of the same issues as for coal-fired steam generating
units; in particular, HRI could result in a rebound effect that would
increase emissions.
    However, the EPA recognizes that natural gas- and oil-fired steam
generating units could possibly, over time, operate more, in response
to other changes in the power sector. Additionally, some coal-fired
steam generating units have converted to 100 percent natural gas-fired,
and it is possible that more may do so in the future. Moreover, in part
because the fleet continues to age, the plants may operate with
degrading emission rates. In light of these possibilities, identifying
the BSER and degrees of emission limitation for these sources would be
useful to provide clarity and prevent backsliding in GHG performance.
Therefore, the EPA is proposing BSER for intermediate and base load
natural gas- and oil-fired steam generating units to be routine methods
of operation and maintenance, such that the sources could maintain the
emission rates (on a lb/MWh-gross basis) currently maintained by the
majority of the fleet across discrete ranges of annual capacity factor.
The EPA is proposing this BSER for intermediate load and base load
natural gas- and oil-fired steam generating units, regardless of the
operating horizon of the unit.
    A BSER based on routine methods of operation and maintenance is
adequately demonstrated because units already operate with those
practices. There are no or negligible additional costs because there is
no additional technology that units are required to apply and there is
no change in operation or maintenance that units must perform.
Similarly, there are no adverse non-air quality health and
environmental impacts or adverse impacts on energy requirements. Nor do
they have adverse impacts on the energy sector from a nationwide or
long-term perspective. The EPA's initial modeling, which supports this
proposed rule, indicates that by 2040, a number of natural gas-fired
steam generating units have remained in operation since 2030, although
at reduced annual capacity factors. There are no CO2
reductions that may be achieved at the unit level, but applying the
BSER should preclude increases in emission rates. Routine methods of
operation and maintenance do not advance useful control technology, but
this point is not significant enough to offset their benefits.
    The EPA is also taking comment on, but not proposing, a BSER of
lower emitting fuels for low load natural gas- and oil-fired steam
generating units. As noted earlier in this preamble, non-coal fossil
fuels combusted in utility boilers typically include natural gas,
distillate fuel oil (i.e., fuel oil No. 1 and No. 2), and residual fuel
oil (i.e., fuel oil No. 5 and No. 6). The EPA previously established
heat-input based fuel composition as BSER in the 2015 NSPS (termed
``clean fuels'' in that rulemaking) for new non-base load natural gas-
and multi-fuel-fired stationary combustion turbines (80 FR 64615-17;
October 23, 2015), and the EPA is similarly proposing lower emitting
fuels as BSER for new low load combustion turbines as described in
section VII of this preamble. For low load natural gas- and oil-fired
steam generating units, the high variability in emission rates
associated with the variability of load at the lower-load levels limits
the benefits of a BSER based on routine maintenance and operation. That
is because the high variability in emission rates would make it
challenging to determine an emission rate (i.e., on a lb
CO2/MWh-gross basis) that could serve as the presumptive
standard of performance that would reflect application of a BSER of
routine operation and maintenance.

On the other hand, for those units, a BSER of ``uniform fuels'' and an
associated presumptive standard of performance based on a heat input
basis, as described in section XII.D of this preamble, may be
reasonable. The EPA is soliciting comment on the fuel types that would
constitute ``uniform fuels'' specific to low load natural gas- and oil-
fired steam generating units.
2. Degree of Emission Limitation
    As discussed above, because the proposed BSER for base load and
intermediate load natural gas- and oil-fired steam generating plants is
routine operation and maintenance, which the units are, by definition,
already employing, the degree of emission limitation by application of
this BSER is no increase in emission rate on a lb CO2/MWh-
gross basis over an extended period of time (e.g., an annual calendar
year).

F. Summary

    The EPA has evaluated options for BSER for GHG emissions for fossil
fuel-fired steam generating units. The EPA is proposing
subcategorization of steam generating units by the type of fossil fuel
fired in the unit, and, for each fuel type, further levels of
subcategorization. For each subcategory, the EPA is proposing a BSER
and resulting degree of emission limitation achievable by application
of that BSER, as summarized in table 5, with presumptively approvable
standards of performance for use in State plan development (see section
XII of this preamble for details) included for completeness. For coal-
fired steam generating units that plan to operate in the long-term, the
EPA is proposing a BSER of CCS with 90 percent capture of
CO2. In response to industry stakeholder input and
recognizing that the cost effectiveness of controls depends on a unit's
expected operating time horizon, which dictates the amortization period
for the capital costs of the controls, the EPA is proposing other BSER
for coal-fired units with shorter operating horizons while taking
comment on what dates most appropriately define the thresholds between
these different subcategories. For the different subcategories of
natural gas- and oil-fired units, the EPA is proposing BSERs based on
routine methods of operation and maintenance. The EPA solicits comment
on the proposed BSER and degrees of emission limitation, as well as the
proposed subcategorization, including the potential to remove the
imminent-term subcategory and include units with earlier commitments to
permanently cease operations in either the near-term or medium-term
subcategory. It is noted that for imminent-term and near-term coal-
fired steam generating units, the EPA is also soliciting comment on
potential BSERs based on co-firing low levels of natural gas.
---------------------------------------------------------------------------

    \561\ Presumptive standards of performance are discussed in
detail in section XII of the preamble. While States establish
standards of performance for sources the EPA provides presumptively
approvable standards of performance based on the degree of emission
limitation achievable through application of the BSER for each
subcategory. Inclusion in this table is for completeness.

                         Table 5--Summary of Proposed BSER, Subcategories, and Degrees of Emission Limitation for Affected EGUs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Presumptively       Ranges in values on
           Affected EGUs             Subcategory definition           BSER             Degree of emission    approvable standard      which the EPA is
                                                                                limitation        of performance \561\    soliciting comment
--------------------------------------------------------------------------------------------------------------------------------------------------------
Long-term existing coal-fired steam  Coal-fired steam        CCS with 90 percent     88.4 percent           88.4 percent           The achievable
 generating units.                    generating units that   capture of CO2.         reduction in           reduction in annual    capture rate from 90
                                      have not elected to                             emission rate (lb      emission rate (lb      to 95 percent or
                                      commit to permanently                           CO2/MWh-gross).        CO2/MWh-gross) from    greater and the
                                      cease operations by                                                    the unit-specific      achievable degree of
                                      January 1, 2040.                                                       baseline.              emission limitation
                                                                                defined by a
                                                                                reduction in
                                                                                emission rate from
                                                                                75 to 90 percent.
Medium-term existing coal-fired      Coal-fired steam        Natural gas co-firing   A 16 percent           A 16 percent           The percent of
 steam generating units.              generating units that   at 40 percent of the    reduction in           reduction in annual    natural gas co-
                                      have elected to         heat input to the       emission rate (lb      emission rate (lb      firing from 30 to 50
                                      commit to permanently   unit.                   CO2/MWh-gross).        CO2/MWh-gross) from    percent and the
                                      cease operations                                                       the unit-specific      degree of emission
                                      after December 31,                                                     baseline.              limitation from 12
                                      2031, and before                                                                              to 20 percent.
                                      January 1, 2040, and
                                      that are not near-
                                      term units.
Near-term existing coal-fired steam  Coal-fired steam        Routine methods of      No increase in         An emission rate       The presumptive
 generating units.                    generating units that   operation.              emission rate (lb      limit (lb CO2/MWh-     standard: 0 to 2
                                      have elected to                                 CO2/MWh-gross).        gross) defined by      standard deviations
                                      commit to permanently                                                  the unit-specific      in annual emission
                                      cease operations                                                       baseline.              rate above or 0 to
                                      after December 31,                                                                            10 percent above the
                                      2031, and before                                                                              unit-specific
                                      January 1, 2035, and                                                                          baseline.
                                      commit to adopt an
                                      annual capacity
                                      factor limit of 20
                                      percent.
Imminent-term existing coal-fired    Coal-fired steam        Routine methods of      No increase in         An emission rate       The presumptive
 steam generating units.              generating units that   operation.              emission rate (lb      limit (lb CO2/MWh-     standard: 0 to 2
                                      have elected to                                 CO2/MWh-gross).        gross) defined by      standard deviations
                                      commit to permanently                                                  the unit-specific      in annual emission
                                      cease operations                                                       baseline.              rate above or 0 to
                                      before January 1,                                                                             10 percent above the
                                      2032.                                                                                unit-specific
                                                                                baseline.

Base load continental existing oil-  Oil-fired steam         Routine methods of      No increase in         An annual emission     The threshold between
 fired steam generating units.        generating units with   operation and           emission rate (lb      rate limit of 1,300    intermediate and
                                      an annual capacity      maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      base load from 40 to
                                      factor greater than                                                                           50 percent annual
                                      or equal to 45                                                                                capacity factor; the
                                      percent.                                                                                degree of emission
                                                                                limitation from
                                                                                1,250 lb CO2/MWh-
                                                                                gross to 1,800 lb
                                                                                CO2/MWh-gross.
Intermediate load continental        Oil-fired steam         Routine methods of      No increase in         An annual emission     The degree of
 existing oil-fired steam             generating units with   operation and           emission rate (lb      rate limit of 1,500    emission limitation
 generating units.                    an annual capacity      maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      from 1,400 lb CO2/
                                      factor greater than                                                                           MWh-gross to 2,000
                                      or equal to 8 percent                                                                         lb CO2/MWh-gross.
                                      and less than 45
                                      percent.
Low load (continental and non-       Oil-fired steam         None proposed.........  .....................  .....................  The threshold between
 continental) existing oil-fired      generating units with                                                                         low and intermediate
 steam generating units.              an annual capacity                                                                            load from 5 to 20
                                      factor less than 8                                                                            percent annual
                                      percent.                                                                                capacity factor.
Intermediate and base load non-      Non-continental oil-    Routine methods of      No increase in         An emission rate       The presumptive
 continental existing oil-fired       fired steam             operation and           emission rate (lb      limit (lb CO2/MWh-     standard: 0 to 2
 steam generating units.              generating units with   maintenance.            CO2/MWh-gross).        gross) defined by      standard deviations
                                      an annual capacity                                                     the unit-specific      in annual emission
                                      factor greater than                                                    baseline.              rate above or 0 to
                                      or equal to 8 percent.                                                                        10 percent above the
                                                                                unit-specific
                                                                                baseline.
Base load existing natural gas-      Natural gas-fired       Routine methods of      No increase in         An annual emission     The threshold between
 fired steam generating units.        steam generating        operation and           emission rate (lb      rate limit of 1,300    intermediate and
                                      units with an annual    maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      base load from 40 to
                                      capacity factor                                                                               50 percent annual
                                      greater than or equal                                                                         capacity factor; The
                                      to 45 percent.                                                                                acceptable standard
                                                                                from 1,250 lb CO2/
                                                                                MWh-gross to 1,400
                                                                                lb CO2/MWh-gross.
Intermediate load existing natural   Natural gas-fired       Routine methods of      No increase in         An annual emission     The acceptable
 gas-fired steam generating units.    steam generating        operation and           emission rate (lb      rate limit of 1,500    standard from 1,400
                                      units with an annual    maintenance.            CO2/MWh-gross).        lb CO2/MWh-gross.      lb CO2/MWh-gross to
                                      capacity factor                                                                               1,600 lb CO2/MWh-
                                      greater than or equal                                                                         gross.
                                      to 8 percent and less
                                      than 45 percent.
Low load existing natural gas-fired  Natural gas-fired       None proposed.........  .....................  .....................  The threshold between
 steam generating units.              steam generating                                                                              low and intermediate
                                      units with an annual                                                                          load from 5 to 20
                                      capacity factor less                                                                          percent annual
                                      than 8 percent.                                                                               capacity factor.
--------------------------------------------------------------------------------------------------------------------------------------------------------

XI. Proposed Regulatory Approach for Emission Guidelines for Existing
Fossil Fuel-fired Stationary Combustion Turbines

A. Overview

    Because the EPA has established NSPS for GHG emissions from new
fossil fuel-fired stationary combustion turbines under CAA section
111(b), it has an obligation to also establish emission guidelines for
GHG emissions from existing fossil-fuel fired stationary combustion
turbines under CAA section 111(d). Existing fossil fuel-fired
stationary combustion turbines already represent a significant share of
GHG emissions from EGUs and are quickly becoming the largest source of
GHG emissions from the power sector. As other fossil fuel-fired EGUs
reduce utilization or retire, at least some of this generation may
shift to the existing combustion turbine fleet with significant GHG
emission implications, particularly if the latter is not subject to
limits on GHG emissions. For these reasons, the EPA intends to
discharge its obligation to prescribe emission guidelines for these
sources as expeditiously as practicable. In this document, the EPA is
proposing emission guidelines for certain existing fossil fuel-fired
stationary combustion turbines and soliciting comment on approaches
that could be used to establish emission guidelines for the remaining
units in the fleet.
    In considering how to address this problem, the EPA believes there
are at least two key factors to consider. The first is that determining
the BSER and issuing emission guidelines covering these units sooner
rather than later is important to address the GHG emissions from this
growing portion of the inventory. The second is related to the size of
the affected fleet and the implications for the feasibility and timing
of implementing potential candidates for BSER. As discussed later in
this section, there are at least three technologies that could be
applied to reduce GHGs from existing combustion turbines (CCS, hydrogen
co-firing, and heat rate improvements), all of which are available
today and are being pursued to at least some degree by owners and
operators of these sources. Although the EPA believes that these
technologies are available and adequately demonstrated at the level of
individual existing combustion turbines, emission guidelines for these
sources must also consider how much of the fleet could reasonably
implement

one or more of these potential BSER approaches in a given time frame.
    Furthermore, the EPA is aware that grid operators and power
companies currently rely on existing fossil fuel-fired combustion
turbines as a flexible and readily dispatchable resource that plays a
key role in fulfilling resource adequacy and operational reliability
needs. Although advancements in energy storage and accelerated
development and deployment of zero-emitting resources may diminish
reliance on existing fossil fuel-fired combustion turbines for
reliability purposes over time, it is imperative that emission
guidelines for these sources not impair the reliability of the bulk
power system. For these reasons, the EPA believes that it is important
that a BSER determination and associated emission guidelines for
existing fossil fuel-fired combustion turbines rely on GHG control
options that can be feasibly and cost-effectively implemented at a
scale commensurate with the size of the regulated fleet, and provide
sufficient operational flexibility and lead time to allow for smooth
implementation of the GHG emission limitations that preserves system
reliability.
    Given the large size of the existing combustion turbine fleet and
the lead time required to develop CCS and hydrogen-related
infrastructure, the EPA believes the BSER for this category entails
significant lead time for application of CCS or low-GHG hydrogen co-
firing. As a result, the EPA is planning to break the existing
combustion turbine category into two segments, and is focusing this
proposal on the largest and most frequently operated (e.g., base load)
existing combustion turbines that have the highest GHG emissions on an
annual basis. For these large and frequently operated existing
combustion turbines, the EPA is proposing to determine that the BSER
consists of either application of CCS by 2035, or application of low-
GHG hydrogen co-firing beginning in 2032, based on an evaluation of the
statutory BSER criteria that mirrors EPA's evaluation of the BSER for
new base load combustion turbines. This focused approach will limit GHG
emissions from the highest-emitting existing natural gas combustion
turbines, while allowing sufficient lead time for application of CCS or
low-GHG hydrogen co-firing and limiting the amount of affected capacity
to a degree that is consistent with the availability of these two GHG
mitigation technologies. The EPA intends to undertake a separate
rulemaking as expeditiously as practicable that addresses emissions
from the remaining combustion turbines.
    In this document, the EPA is soliciting comment on both the scope
of these proposed emission guidelines (in other words, the
applicability thresholds that would determine which existing combustion
turbines are in the first segment) as well as the BSER for units
covered in this rulemaking. In section XII of this preamble, the EPA is
also taking comment on the associated State plan requirements
associated with the BSER for existing fossil fuel-fired turbines.
    As described in more detail below, the EPA is proposing to
determine that the BSER for large and frequently operated existing
stationary combustion turbines is the same as for the proposed second
phase of requirements for new base load combustion turbines.
Accordingly, the EPA is proposing emission guidelines for these
existing stationary combustion turbines that would require either that
these sources achieve a degree of emission limitation consistent with
the use of CCS by 2035, or achieve a degree of emission limitation
reflecting the utilization of 30 percent low-GHG hydrogen by volume by
2032 (increasing to 96 percent low-GHG hydrogen by volume by 2038).
    The EPA believes that it is important to stagger CCS requirements
for existing coal-fired units and new and existing fossil fuel-fired
turbines to allow time for both deployment of CCS infrastructure and to
accommodate increased demand for specialized engineering and
construction labor needed to build CCS equipment. The EPA also believes
that because coal-fired units emit more CO2/MWh, that to the
extent that there are limitations to the amount of CCS that can be
installed by 2030 it makes sense to focus a CCS BSER on those coal-
fired units first. A 2035 compliance timeframe would allow for
staggering of resources needed to install CCS while still allowing
existing turbines to take advantage of the IRC section 45Q tax credits
to make CCS controls more cost-effective or to use hydrogen, produced
at facilities eligible for the 45V tax credits, making hydrogen co-
firing more cost effective.\562\ In the rest of this section, the EPA
proposes regulations for the first segment and solicits comment on
specific elements of the approach. This section also briefly discusses
what BSER might look like for units in the second rulemaking, and
requests comments that could inform the development of a rulemaking
defining BSER, degrees of emission limitation, compliance deadlines and
other elements of an emission guideline for those units at a later
date.
---------------------------------------------------------------------------

    \562\ CCS projects that commence construction as late as
December 31, 2032 can qualify for the 45Q tax credit.
---------------------------------------------------------------------------

    As explained in more detail later in this section, the EPA is
proposing that the first segment it would cover would be units greater
than 300 MW with an annual capacity factor of greater than 50 percent.
The EPA projects that 37 GW of capacity would meet these criteria in
2035, representing 14 percent of the projected existing combustion
turbine capacity and 23 percent of the projected generation from
existing combustion turbines in 2035. As is explained further below,
the EPA is proposing this capacity factor and capacity threshold after
weighing the quantity of emissions from these units and considerations
about the feasibility of installing significant amounts of CCS and/or
hydrogen co-firing. In short, these units offer the best opportunity to
achieve significant emissions reduction consistent with what the EPA
believes these technologies will be capable of on a national scale.
Similar to its proposal for new base load turbines, the EPA is
proposing that BSER for those existing sources be both pathways, that
is CCS with 90 percent capture in 2035 and clean hydrogen combusting 30
percent by volume in 2032 and 96 percent by volume in 2038.
Alternatively, as with the proposal for new base load turbines, the EPA
is taking comment on whether to finalize a BSER with a single pathway
based on application of CCS with 90 percent capture, which could also
be met by co-firing with low-GHG hydrogen as a compliance option, or
vice-versa. The EPA is also taking comment on whether the compliance
date should begin earlier, including as early as 2030.\563\
---------------------------------------------------------------------------

    \563\ If we finalize one of these variations, the state plan
requirements may change accordingly.
---------------------------------------------------------------------------

    The EPA has promulgated several prior rulemakings under both CAA
section 111(b) and section 111(d) that provide the regulated sector
with lead time to accommodate the time needed to deploy control
technology. Section VII.F.3.a of this preamble discusses, in the
section 111(b) context, precedent for rulemakings that provide such
lead time. For additional examples under CAA section 111(d), see 70 FR
28606, 28619 (May 18, 2005) (establishing emission guidelines for
electric utility steam generating units, with a 13-year compliance
timeframe for a second control phase); 61 FR 9905, 9919 (March 12,
1996) (establishing emission guidelines for municipal solid waste
landfills, with a 2.5-year compliance

timeframe); 62 FR 48348, 48381 (September 15, 1997) (establishing
emission guidelines for hospital/medical/infectious waste incinerators,
with up to 3 years after State plan approval for facilities to install
control equipment). Section XI.B provides background information
concerning the composition of the current fossil fuel-fired stationary
combustion turbine fleet and how it is expected to change in the near
future. In section XI.C, the EPA proposes an approach for units covered
in this rulemaking and in section XI.D, the EPA summarizes the key
topics for which we are soliciting comment relative to existing
combustion turbines. Finally, section XI.E, outlines a potential
approach for units covered in a second rulemaking

B. The Existing Stationary Combustion Turbine Fleet

    In 2021, existing combustion turbines represented 37 percent of the
GHG emissions from the power sector and 40 percent of the generation
from the power sector. In the EPA's updated baseline projections for
the power sector, they represent 74 percent of the GHG emissions and 25
percent of the generation in 2035. In EPA's modeling of the 2035
control case, in which both existing fossil fuel-fired EGUs and new
stationary combustion turbine EGUs are subject to the emissions
limitations proposed in this action but existing combustion turbine
EGUs are left uncontrolled, load shifting from those two categories of
sources to the existing combustion turbines results in an increase in
the share of the emissions from existing combustion turbines (including
combined cycle and simple cycle combustion turbines) to 82 percent
while their share of generation remains 25 percent. Moreover, in that
control case, existing combined cycle combustion turbines are
responsible for 71 percent of the CO2 emissions from the
power sector.
    In the EPA's modeling in support of these rules, we see two trends
that are important relative to existing combustion turbines. First, the
EPA's analysis of the reference case (which includes the impacts of IRA
without considering the GHG limitation requirements proposed in these
rules) projects a long-term decline in generation and emissions from
existing combustion turbines relative to current generation and
emissions. In this reference case, combined cycle generation falls in
each model run year from 2028 through 2050, and it falls by more than
50 percent between 2030 and 2045. Generation from existing simple cycle
combustion turbines is projected to peak in 2030 before declining by
more than 70 percent by 2045. While generation falls from turbines,
this is primarily caused by declining capacity factors, not through
retirements.
    Historical data shows a wide range of variation in both the heat
rate and the GHG emission rates among both existing combined cycle
combustion turbines and existing simple cycle combustion turbines. The
GHG emission rates for existing combined cycle units range from as low
as 644 lb CO2/MWh-gross to as high as 1,891 lb
CO2/MWh-gross, and annual capacity factors range from as low
as 1 percent to as high as 85 percent. While there is some correlation
between units with low-GHG emission rates (e.g., more efficient units)
and utilization, some low efficiency combined cycle units have
historically operated at very high capacity factors. For instance, two
of the highest operating units (at 85 percent capacity utilization)
have GHG emission rates of nearly 1,200 lb/MWh-gross.
C. BSER for Base Load Turbines Over 300 MW
    As noted earlier, the EPA is adopting an approach in which existing
combustion turbines would be regulated in two segments. The proposed
emission guidelines presented in this document focus on the first
segment, which comprises the base load units (e.g., those operated at
capacity factors of greater than 50 percent) over 300 MW. The EPA
intends to undertake a separate rulemaking to address the second
segment, comprising the remainder of the existing fossil fuel-fired
stationary combustion fleet, as expeditiously as practicable.
    Because the first segment would be focused on the largest most
frequently used units, the EPA is proposing that the BSER for these
units would be CCS or a BSER based upon burning low-GHG hydrogen. As is
the case for new base load combustion turbines, each of these sets of
controls is adequately demonstrated, of reasonable cost, and consistent
with the other criteria to qualify as the BSER.
    Because the second segment would include both smaller more
frequently used units and less frequently used units, in that action,
the EPA anticipates considering a broader range of technologies
including heat rate improvements. This approach recognizes the
imperatives (the urgent need to reduce greenhouse gases), the
opportunities (including the availability of IRC section 45Q tax
credits incentivizing CCS installation as long as sources commence
construction by January 1, 2033), and the need for infrastructure for
CCS and co-firing low-GHG hydrogen to be deployed at a broader scale if
these BSER technologies are to be deployed broadly at smaller and less
frequently operated existing combustion turbines.
    The EPA is proposing emission guidelines for units with a capacity
factor greater than 50 percent and a capacity of greater than 300 MW,
but is also taking comment on whether that capacity factor threshold or
capacity threshold should be lower (for instance 40 percent for the
capacity factor and 200 MW or 100 MW for the capacity). The EPA is
proposing that 300 MW is the appropriate threshold for applicability
because it focuses on the units with the highest emissions where CCS is
likely to be most cost effective. As an important first step towards
abating emissions from the existing turbine fleet and recognizing that
at least some project developers are considering the use of clean
hydrogen in base load turbines \564\ and recognizing that there are
likely limits to the clean hydrogen supply in the mid-term, the EPA
believes that it is appropriate to also propose a clean hydrogen BSER
for the same set of units. Table 6 provides information from IPM
detailing the amount of capacity and generation from the 2035 IPM
projected control case that would be covered under various capacity
thresholds.
---------------------------------------------------------------------------

    \564\ As one developer notes, ``the plant will be capable of
supporting a balanced and diverse power generation portfolio in the
future; from energy storage capable of accommodating seasonal
fluctuations from renewable energy, to cost effective, dispatchable
intermediate and baseload power.'' https://www.longridgeenergy.com/news/2020-10-13-long-ridge-energy-terminal-partners-with-new-fortress-energy-and-ge-to-transition-power-plant-to-zero-carbon-hydrogen.

    Table 6--Key Characteristics for Baseload Combined Cycle Units of
                           Various Capacities
------------------------------------------------------------------------
                                                 Percentage   Percentage
 NGCC units projected to run at a                 of total     of total
 capacity factor of greater than     Capacity       NGCC         NGCC
50 percent and at a capacity size      (GW)       capacity    generation
           greater than                             (%)          (%)
------------------------------------------------------------------------
100 MW...........................          134           49           78
200 MW...........................           85           31           51
300 MW...........................           37           14           23
400 MW...........................           12            4           10
500 MW...........................            6            2            7
------------------------------------------------------------------------

    The EPA believes this approach would ensure that GHG emissions
limitations are implemented first at the subset of existing fossil
fuel-fired combustion turbines that contributes the most to GHG
emissions, and where the benefits of implementing GHG controls would be
greatest.
    The EPA believes there are three sets of controls that could
potentially qualify as the BSER for the group of large and frequently-
operated combustion turbines covered in the first rulemaking. Those
controls are heat rate/efficiency improvements, co-firing low-GHG
hydrogen, and use of CCS. We discuss each of these below, and in the
course of each discussion explain why we are proposing that the
following controls qualify as the BSER: co-firing with low-GHG hydrogen
in the amounts of 30 percent (by volume) by 2032 and 96 percent (by
volume) by 2038, and the use of CCS with 90 percent capture by 2035.
1. Heat-Rate Improvements
    The EPA believes that heat rate improvements for existing
combustion turbines are broadly applicable today. Heat rate/efficiency
improvements can be divided into two types. The first type involves
smaller scale improvements to existing combustion turbines. The second
type involves more comprehensive upgrades of the combustion turbines.
    Smaller scale efficiency improvements can include measures such as
inlet fogging and inlet cooling. Both of these techniques can achieve
about 2 percent improvements in heat rate. Inlet chilling costs
approximately $19/kW and is also accompanied by a capacity increase of
11 percent. Inlet fogging is approximately $0.93/kW and is accompanied
by a capacity increase of 6 percent.\565\ These small-scale efficiency
improvements would likely result in an average 2 percent improvement in
the heat rate of affected existing combustion turbines.
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    \565\ https://www.andovertechnology.com/wp-content/uploads/2021/03/C_18_EDF_FINAL.pdf.
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    More comprehensive efficiency upgrades to combustion turbines are
also possible. An upgrade to the combustion turbine can result in a
heat rate improvement of 3.0 percent and a capacity increase of 13
percent for $172/kW, while an upgrade to the steam turbine can result
in a heat rate improvement of 3.2 percent with a capacity increase of 3
percent for $130/kW. These more comprehensive efficiency improvements
would likely result in an average efficiency improvement of 6 percent
for affected existing stationary combustion turbines. The EPA is not
proposing HRI improvements for units greater than 300 MW because they
achieve significantly less emission reductions than either CCS or co-
firing hydrogen, but believes that some units may choose to make these
upgrades as part of their response to installing CCS and/or co-firing
hydrogen. The EPA is taking comment on whether HRI should be considered
BSER (or a component of BSER) for combined cycle units with a capacity
factor of greater than 50 percent and a capacity of less than 300 MW as
part of this initial rulemaking.
2. Co-Firing Low-GHG Hydrogen
a. Overview
    The EPA is proposing that for existing combined cycle combustion
turbines that operate at capacity factors of greater than 50 percent
and that are greater than 300 MW, co-firing 30 percent low-GHG hydrogen
by 2032 and 96 percent by 2038 qualifies as the BSER, for largely the
same reasons that apply to new combined cycle turbines, as discussed in
section VII.F.3.c.vii of this preamble. Co-firing hydrogen at these
levels is adequately demonstrated, as indicated by announced plans of
manufacturers and generators to undertake retrofit projects for
hydrogen co-firing. These plans also indicate that the costs of
retrofitting are reasonable. The analysis concerning the costs of low-
GHG hydrogen for existing turbines is comparable to the analysis for
new turbines. See section VII.F.3.c.vii.(B) of this preamble. Co-firing
with low-GHG hydrogen at existing turbines also has comparable non-air
quality environmental impacts and energy requirements, and comparable
emissions reductions as co-firing with low-GHG hydrogen at new
turbines. See sections VII.F.3.c.vii.(C)-(D) of this preamble. For
these reasons, the EPA is proposing that co-firing with low-GHG
hydrogen qualifies as the BSER. The fact that doing so will also
advance the development and deployment of this low-emitting technology
further supports this proposal.
b. Adequately Demonstrated
    Co-firing with low-GHG hydrogen is feasible in combustion turbines
that are currently being produced. Manufacturers have developed
retrofits to allow existing combustion turbines to combust up to 100
percent hydrogen, and some companies have announced plans to retrofit
their existing turbines to combust hydrogen. In section VII.F.3.c of
this preamble, the EPA proposes co-firing of low-GHG hydrogen as BSER
for certain new base load combustion turbines. A number of the examples
that the EPA cites as evidence that companies are developing combined
cycle turbines to co-fire hydrogen either are existing turbines that
companies are planning to retrofit to burn hydrogen or are already
under construction, and would, therefore, be classified as existing
turbines under this rule. Because new combined cycle turbines that
operate at capacity factors of greater than 50 percent are similar to
existing combined cycle turbines that operate at capacity factors of
greater than 50 percent, the EPA is proposing a similar BSER pathway
for existing combustion turbines, based upon co-firing 30 percent (by
volume) low-GHG hydrogen in 2032 and ramping up thereafter to 96
percent (by volume) low-GHG hydrogen in 2038.
    There are two key questions related to whether co-firing low-GHG
hydrogen in existing combustion turbines is

adequately demonstrated. The first question is whether existing
combustion turbines are capable of co-firing significant amounts of
hydrogen and/or if they can be retrofitted to do so. The second
question is whether there will be an adequate supply of low-GHG
hydrogen. These points are discussed below.
i. Capability of Existing Turbines To Co-Fire Hydrogen
    There are at least three lines of evidence that demonstrate that
co-firing low-GHG hydrogen in existing turbines is possible today (with
a number of them already able to fire 100 percent hydrogen) and that by
approximately 2030, many additional turbine models will have the
capability to co-fire 100 percent hydrogen. First, information from
turbine vendors indicates that they already have significant experience
in operating turbines with hydrogen; some of their existing turbine
models can co-fire hydrogen; and/or they are currently engaged in
projects to upgrade existing turbines to co-fire hydrogen. Second, test
burns have been completed on several existing utility turbines. Third,
several utilities have indicated plans to retrofit existing turbines to
co-fire hydrogen.
    Existing turbine vendors including GE, Mitsubishi, and Siemens have
indicated that their turbines can currently co-fire some amounts of
hydrogen; and, they have plans to expand those capabilities. GE has
indicated that most of their product line can currently be configured
to co-fire significant amounts of hydrogen.\566\ Siemens is currently
offering retrofit packages for many of its existing turbines that will
allow them to combust up to 75 percent hydrogen.\567\ Mitsubishi also
offers retrofit packages that could allow for up to 100 percent firing
of hydrogen.\568\
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    \566\ https://www.ge.com/gas-power/future-of-energy/hydrogen-fueled-gas-turbines?utm_campaign=h2&utm_medium=cpc&utm_source=google&utm_content=eta&utm_term=Ge%20gas%20turbine%20hydrogen&gad=1&gclid=EAIaIQobChMIqMaL6IXG_gIVhsjjBx2gPgb-EAAYASAAEgK61PD_BwE and https://www.ge.com/content/dam/gepower-new/global/en_US/downloads/gas-new-site/future-of-energy/hydrogen-overview.pdf.
    \567\ https://assets.siemens-energy.com/siemens/assets/api/uuid:66b2b6a3-7cdc-404d-9ab0-ddcfbe4adf02/hydrogenflyer.pdf?ste_sid=81945e06dd4f27fd626614f9b954e3f4.
    \568\ https://solutions.mhi.com/clean-fuels/hydrogen-gas-turbine/.
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    Section VII.F.3.c.vii(A) of this preamble includes discussion of
how retrofitting existing turbines to co-fire with increasing amounts
of hydrogen is adequately demonstrated. Several turbines currently in
operation have the capability to co-fire hydrogen up to 30 percent
without modifications. Other existing turbine models would need
modifications to enable co-firing between 50 and 100 percent.
    Moreover, several existing combined cycle turbines have
demonstrated the ability to co-fire some amounts of hydrogen. The Long
Ridge Energy Terminal tested 5 percent hydrogen co-firing at the 485-MW
combined cycle plant on a GE HA-class (GE 7HA.02) in 2022. The turbine
is designed to enable a transition to 100 percent hydrogen fuel. This
example is particularly salient given the large capacity of the unit.
No modifications should be required for this turbine model, which has
been available since 2017, to operate with between 5 and 20 percent
hydrogen co-firing. Higher hydrogen co-firing concentrations will
require some modification.\569\
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    \569\ https://www.powermag.com/first-hydrogen-burn-at-long-ridge-ha-class-gas-turbine-marks-triumph-for-ge/.
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    Southern Company has also demonstrated hydrogen co-firing on a
Mitsubishi, M501G turbine. The demonstration involved co-firing 20
percent hydrogen (by volume), was successful at both full and partial
load, and demonstrated compliance with emissions requirements without
impacting maintenance intervals.\570\ Other test burns have
demonstrated the ability to fire up to 80 percent hydrogen without
emissions excursions.\571\
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    \570\ https://www.powermag.com/southern-co-gas-fired-demonstration-validates-20-hydrogen-fuel-blend/.
    \571\ https://www.ccj-online.com/real-world-experience-firing-hydrogen-natural-gas-mixtures/.
---------------------------------------------------------------------------

    Several utilities are exploring the use of hydrogen in their
existing turbine fleet. For example, Constellation Energy, which owns a
fleet of 23 gas-fired turbines with a combined total capacity of 8.6
GW, asserts that retrofitting existing turbines to co-fire hydrogen is
technically feasible with existing turbine models: ``Based on our
assessments, retrofits using available technology can allow hydrogen
blending at 50-100 percent by volume in select generators. These
retrofits, which include burner and additional balance-of-plant
modifications, allow for more substantial CO2 emissions
reductions.'' \572\ Florida Power and Light (FPL) intends to convert 16
GW of existing turbine capacity to run on 100 percent hydrogen by
2045.\573\ They are currently developing a 25 MW electrolyzer project
at the Cavendish Energy Center.\574\
---------------------------------------------------------------------------

    \572\ Constellation Energy Corporation's Comments on EPA Draft
White Paper: Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units.
    \573\ https://cleanenergy.org/blog/nextera-sets-goal-to-decarbonize-proposes-big-transition-for-florida-power-light/.
    \574\ https://dailyenergyinsider.com/news/34040-florida-power-light-taps-cummins-for-its-green-hydrogen-facility/.
---------------------------------------------------------------------------

    One concern with hydrogen co-firing is that, because it burns at a
higher temperature, it has the potential to generate more thermal NOx.
The most commonly used NOX combustion control for base load
combined cycle turbines is dry low NOX (DLN) combustion.
Even though the ability to co-fire hydrogen in combustion turbines that
are using DLN combustors to reduce emissions of NOX is
currently more limited, all major combustion turbine manufacturers have
developed DLN combustors for utility EGUs that can co-fire
hydrogen.\575\ Moreover, the major combustion turbine manufacturers are
designing combustion turbines that will be capable of combusting 100
percent hydrogen by approximately 2030, with DLN designs that assure
acceptable levels of NOX emissions.576 577
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    \575\ Siemens Energy (2021). Overcoming technical challenges of
hydrogen power plants for the energy transition. NS Energy. https://www.nsenergybusiness.com/news/overcoming-technical-challenges-of-hydrogen-power-plants-for-energy-transition/.
    \576\ Simon, F. (2021). GE eyes 100% hydrogen-fueled power
plants by 2030. https://www.euractiv.com/section/energy/news/ge-eyes-100-hydrogen-fuelled-power-plants-by-2030/.
    \577\ Patel, S. (2020). Siemens' Roadmap to 100% Hydrogen Gas
Turbines. https://www.powermag.com/siemens-roadmap-to-100-hydrogen-gas-turbines/.
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ii. Availability of Low-GHG Hydrogen
    The EPA is proposing that the BSER for existing combustion turbines
includes co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and
96 percent (by volume) by 2038. The EPA is proposing to define low-GHG
hydrogen as hydrogen that is produced with overall carbon emissions of
less than 0.45 kg CO2e/kgH2 from well-to-gate. Electrolytic
hydrogen produced using zero-carbon emitting energy sources is the most
likely, but not the only, form of hydrogen anticipated to meet this
proposed definition.\578\
---------------------------------------------------------------------------

    \578\ DOE, Pathways to Commercial Liftoff: Clean Hydrogen (March
2023).
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    Suitable volumes of low-GHG hydrogen are expected to be produced by
the 2032 and 2038 timeframes to satisfy the demand driven by this
proposed rule. As referenced throughout this proposal, DOE's clean
hydrogen production estimates are 10 MMT annually of clean hydrogen by
2030, and 20 MMT annually by 2040. There is reason to believe actual
produced

low-GHG hydrogen will exceed those levels. Announced clean hydrogen
production projects total 12 MMT annually for 2030.\579\ In fact,
hydrogen production could outpace DOE's projections if demand markets
across sectors, including the power sector, grow rapidly and emerge
simultaneously with cost declines across the value chain.\580\ Over
time, the emergence of the self-sustaining low-GHG hydrogen markets are
predicted to be established as demand for low-GHG solidifies and
anchors the market, ensuring low-GHG production even after the PTC
sunsets. Given the magnitude of the PTC for low-GHG hydrogen, $3/kg,
electrolytic hydrogen production is expected to accelerate, accounting
for between 70 and 95 percent of hydrogen production in 2030, and
between 30 and 50 percent in 2040.\581\
---------------------------------------------------------------------------

    \579\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 8 of the
Liftoff Report represents compiled clean hydrogen projects with
aggregated 2030 production exceeding 12 MMT annually.
    \580\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 13 presents
modeling of hydrogen production volumes under various scenarios,
including projections of 20MMT in 2030, and 42 MMT in 2040 based on
high end of ranges for end use demand which assumes additional ramp
up in policy support for decarbonization--which is consistent with
this proposal to reduce emissions from the power sector, as well as
EPA's proposed Greenhouse Gas Emissions Standards for Heavy-Duty
Vehicle.
    \581\ DOE Pathways to Commercial Liftoff: Clean Hydrogen, March
2023. https://liftoff.energy.gov/wp-content/uploads/2023/03/20230320-Liftoff-Clean-H2-vPUB-0329-update.pdf. Figure 14 of the