for the next tier of credit, which is for hydrogen produced with a GHG
emissions rate between 1.5 and 0.45 kg CO2e/kg
H2, from well-to-gate, IRC section 45V(b)(2)(C); and four
and five times higher than the amount for the next two tiers of credit,
respectively. IRC section 45V(b)(2)(B), (A). With these provisions,
Congress indicated its judgement as to what constitutes the lowest-GHG
hydrogen production, and its intention to incentivize production of
that type of hydrogen. Congress's views inform the EPA's proposal to
define low-GHG hydrogen for purposes the BSER for this CAA section 111
rulemaking consistent with IRC section 45V(b)(2)(D).
    It should be noted that the EPA is not proposing that the ``clean
hydrogen'' definition in section 822 of the IIJA is appropriate for the
EPA's regulatory purposes. This definition is designed for a non-
regulatory purpose. It sets out a non-binding goal, not a standard or a
regulatory definition, intended for use in development of the DOE's
CHPS and funding programs to promote promising new hydrogen
technologies.
    For the reasons discussed above, co-firing low-GHG hydrogen
qualifies as the BSER because it is adequately demonstrated, is of
reasonable cost, does not have adverse non-air quality health or
environmental impacts or energy requirements--in fact, it offers
potential benefits to the energy sector--and reduces GHG emissions. The
fact that this control promotes the advancement of hydrogen co-firing
in combustion turbines provides additional support for proposing it as
part of the BSER. Finally, Congress's direction to choose the ``best''
system of emissions reduction and principles of reasoned decision-
making dictate that the standard should be based on burning low-GHG
hydrogen, and not using other forms of hydrogen.
4. Other Options for BSER
    The EPA considered several other systems of emission reduction as
candidates for the BSER for combustion turbines, but is not proposing
them as the BSER. They include CHP and the hybrid power plant, as
discussed below.
a. Combined Heat and Power (CHP)
    CHP, also known as cogeneration, is the simultaneous production of
electricity and/or mechanical energy and useful thermal output from a
single fuel. CHP requires less fuel to produce a given energy output,
and because less fuel is burned to produce each unit of energy output,
CHP has lower emission rates and can be more economic than

separate electric and thermal generation. However, a critical
requirement for a CHP facility is that it primarily generates thermal
output and generates electricity as a byproduct and must therefore be
physically close to a thermal host that can consistently accept the
useful thermal output. It can be particularly difficult to locate a
thermal host with sufficiently large thermal demands such that the
useful thermal output would impact the emissions rate. The refining,
chemical manufacturing, pulp and paper, food processing, and district
energy systems tend to have large thermal demands. However, the thermal
demand at these facilities is generally only sufficient to support a
smaller EGU, approximately a maximum of several hundred MW. This would
limit the geographically available locations where new generation could
be constructed in addition to limiting its size. Furthermore, even if a
sufficiently large thermal host were in close proximity, the owner/
operator of the EGU would be required to rely on the continued
operation of the thermal host for the life of the EGU. If the thermal
host were to shut down, the EGU could be unable to comply with the
standard of performance. This reality would likely result in difficulty
in securing funding for the construction of the EGU and could also lead
the thermal host to demand discount pricing for the delivered useful
thermal output. For these reasons, the EPA is not proposing CHP as the
BSER.
b. Hybrid Power Plant
    Hybrid power plants combine two or more forms of energy input into
a single facility with an integrated mix of complementary generation
methods. While there are multiple types of hybrid power plants, the
most relevant type for this proposal is the integration of solar energy
(e.g., concentrating solar thermal) with a fossil fuel-fired EGU. Both
coal-fired and NGCC EGUs have operated using the integration of
concentrating solar thermal energy for use in boiler feed water
heating, preheating makeup water, and/or producing steam for use in the
steam turbine or to power the boiler feed pumps.
    One of the benefits of integrating solar thermal with a fossil
fuel-fired EGU is the lower capital and operation and maintenance (O&M)
costs of the solar thermal technology. This is due to the ability to
use equipment (e.g., HRSG, steam turbine, condenser, etc.) already
included at the fossil fuel-fired EGU. Another advantage is the
improved electrical generation efficiency of the non-emitting
generation. For example, solar thermal often produces steam at
relatively low temperatures and pressures, and the conversion of the
thermal energy in the steam to electricity is relatively low. In a
hybrid power plant, the lower quality steam is heated to higher
temperatures and pressures in the boiler (or HSRG) prior to expansion
in the steam turbine, where it produces electricity. Upgrading the
relatively low-grade steam produced by the solar thermal facility in
the boiler improves the relative conversion efficiencies of the solar
thermal to electricity process. The primary incremental costs of the
non-emitting generation in a hybrid power plant are the costs of the
mirrors, additional piping, and a steam turbine that is 10 to 20
percent larger than that in a comparable fossil-only EGU to accommodate
the additional steam load during sunny hours. A drawback of integrating
solar thermal is that the larger steam turbine will operate at part
loads and reduced efficiency when no steam is provided from the solar
thermal panels (i.e., the night and cloudy weather). This limits the
amount of solar thermal that can be integrated into the steam cycle at
a fossil fuel-fired EGU.
    In the 2018 Annual Energy Outlook,\468\ the levelized cost of
concentrated solar power (CSP) without transmission costs or tax
credits is $161/MWh. Integrating solar thermal into a fossil fuel-fired
EGU reduces the capital cost and O&M expenses of the CSP portion by 25
and 67 percent compared to a stand-alone CSP EGU respectively.\469\
This results in an effective LCOE for the integrated CSP of $104/MWh.
Assuming the integrated CSP is sized to provide 10 percent of the
maximum steam turbine output and the relative capacity factors of a
NGCC and the CSP (those capacity factors are 65 and 25 percent,
respectively) the overall annual generation due to the concentrating
solar thermal would be 3 percent of the hybrid EGU output. This would
result in a three percent reduction in the overall CO2
emissions and a one percent increase in the LCOE, without accounting
for any reduction in the steam turbine efficiency. However, these costs
do not account for potential reductions in the steam turbine efficiency
due to being oversized relative to a non-hybrid EGU. A 2011 technical
report by the National Renewable Energy Laboratory (NREL) cited
analyses indicating solar-augmentation of fossil power stations is not
cost-effective, although likely less expensive and containing less
project risk than a stand-alone solar thermal plant. Similarly, while
commenters stated that solar augmentation has been successfully
integrated at coal-fired plants to improve overall unit efficiency,
commenters did not provide any new information on costs or indicate
that such augmentation is cost-effective. The EPA is soliciting comment
on updated costs for hybrid power plants and if the use of hybrid power
plants could be incorporated as part of the BSER for base load
combustion turbines.
---------------------------------------------------------------------------

    \468\ EIA, Annual Energy Outlook 2018, February 6, 2018. https://www.eia.gov/outlooks/aeo/.
    \469\ B. Alqahtani and D. Pati[ntilde]o-Echeverri, Duke
University, Nicholas School of the Environment, ``Integrated Solar
Combined Cycle Power Plants: Paving the Way for Thermal Solar,''
Applied Energy 169:927-936 (2016).
---------------------------------------------------------------------------

    In addition, solar thermal facilities require locations with
abundant sunshine and significant land area in order to collect the
thermal energy. Existing concentrated solar power projects in the U.S.
are primarily located in California, Arizona, and Nevada with smaller
projects in Florida, Hawaii, Utah, and Colorado. NREL's 2011 technical
report on the solar-augment potential of fossil-fired power plants
examined regions of the U.S. with ``good solar resource as defined by
their direct normal insolation (DNI)'' and identified sixteen States as
meeting that criterion: Alabama, Arizona, California, Colorado,
Florida, Georgia, Louisiana, Mississippi, Nevada, New Mexico, North
Carolina, Oklahoma, South Carolina, Tennessee, Texas, and Utah. The
technical report explained that annual average DNI has a significant
effect on the performance of a solar-augmented fossil plant, with
higher average DNI translating into the ability of a hybrid power plant
to produce more steam for augmenting the plant. The technical report
used a points-based system and assigned the most points for high solar
resource values. An examination of a NREL-generated DNI map of the U.S.
reveals that States with the highest DNI values are located in the
southwestern U.S., with only portions of Arizona, California, Nevada,
New Mexico, and Texas (plus Hawaii) having solar resources that would
have been assigned the highest points by the NREL technical report (7
kWh/m2/day or greater).
    The EPA is not proposing hybrid power plants as the BSER because of
gaps in the EPA's knowledge about costs, and concerns about the cost-
effectiveness of the technology, as noted above.
5. Subcategories
    Stationary combustion turbines are defined in the 2015 NSPS to
include

both simple cycle and combined cycle EGUs. In addition, 40 CFR part 60,
subpart TTTT includes three subcategories for combustion turbines--
natural gas-fired base load EGUs, natural gas-fired non-base load EGUs,
and multi-fuel-fired EGUs. Base load EGUs are those that sell
electricity in excess of the site-specific electric sales threshold to
an electric distribution network on both a 12-operating-month and 3-
year rolling average basis. Non-base load EGUs are those that sell
electricity at or less than the site-specific electric sales threshold
to an electric distribution network on both a 12-operating-month and 3-
year rolling average basis. Multi-fuel-fired EGUs combust 10 percent or
more (by heat input) of fuels not meeting the definition of natural gas
on a 12-operating-month rolling average basis.
a. Legal Basis for Subcategorization
    As noted in section V.C.1, CAA section 111(b)(2) provides that the
EPA ``may distinguish among classes, types, and sizes within categories
of new sources for the purpose of establishing . . . standards [of
performance].'' The D.C. Circuit has held that the EPA has broad
discretion in determining whether and how to subcategorize under CAA
section 111(b)(2). Lignite Energy Council, 198 F3d at 933. As also
noted in section V.C.1, in prior CAA section 111 rules, the EPA has
subcategorized on numerous bases, including, among other things, fuel
type and load.
b. Electric Sales Subcategorization (Low, Intermediate, and Base Load
Combustion Turbines)
    As noted earlier, in the 2015 NSPS, the EPA established separate
standards for natural gas-fired base load and non-base load stationary
combustion turbines. The electric sales threshold distinguishing the
two subcategories is based on the design efficiency of individual
combustion turbines. A combustion turbine qualifies as a non-base load
turbine, and is thus subject to a less stringent standard of
performance, if it has net electric sales equal to or less than the
design efficiency of the turbine (not to exceed 50 percent) multiplied
by the potential electric output (80 FR 64601; October 23, 2015). If
the net electric sales exceed that level on both a 12-operating month
and 3 calendar year basis, then the combustion turbine is in the base
load combustion subcategory and is subject to a more stringent standard
of performance. Subcategory applicability can change on a month-to-
month basis since applicability is determined each operating month. For
additional discussion on this approach, see the 2015 NSPS (80 FR 64609-
12; October 23, 2015). The 2015 NSPS non-base load subcategory is broad
and includes combustion turbines that assure grid reliability by
providing electricity during periods of peak electric demand. These
peaking turbines tend to have low annual capacity factors and sell a
small amount of their potential electric output. The non-base load
subcategory in the 2015 NSPS also includes combustion turbines that
operate at intermediate annual capacity factors but are not considered
base load EGUs. These intermediate load EGUs provide a variety of
services, including providing dispatchable power to support variable
generation from renewable sources of electricity. The need for this
service has been expanding as the amount of electricity from wind and
solar continues to grow. In the 2015 NSPS, the EPA determined the BSER
for the non-base load subcategory to be the use of lower emitting fuels
(e.g., natural gas and Nos. 1 and 2 fuel oils). In 2015, the EPA
explained that efficient generation did not qualify as the BSER due in
part to the challenge of determining an achievable output-based
CO2 emissions rate for all combustion turbines in this
subcategory.
    In this action, the EPA is proposing changes to the subcategories
in 40 CFR part 60, subpart TTTTa that will be applicable to sources
that commence construction or reconstruction after the date of this
proposed rulemaking. First, the Agency is proposing the definition of
design efficiency so that the heat input calculation of an EGU is based
on the higher heating value (HHV) of the fuel instead of the lower
heating value (LHV), as explained immediately below. It is important to
note that this would have the effect of lowering the electric sales
threshold. In addition, the EPA is proposing to further divide the non-
base load subcategory into separate intermediate and low load
subcategories.
i. Higher Heating Value as the Basis for Calculation of the Design
Efficiency
    The heat rate is the amount of energy used by an EGU to generate
one kWh of electricity and is often provided in units of Btu/kWh. As
the thermal efficiency of a combustion turbine EGU is increased, less
fuel is burned per kWh generated and there is a corresponding decrease
in emissions of CO2 and other air pollutants. The electric
energy output as a fraction of the fuel energy input expressed as a
percentage is a common practice for reporting the unit's efficiency.
The greater the output of electric energy for a given amount of fuel
energy input, the higher the efficiency of the electric generation
process. Lower heat rates are associated with more efficient power
generating plants.
    Efficiency can be calculated using the HHV or the LHV of the fuel.
The HHV is the heating value directly determined by calorimetric
measurement of the fuel in the laboratory. The LHV is calculated using
a formula to account for the moisture in the combustion gas (i.e.,
subtracting the energy required to vaporize the water in the flue gas)
and is a lower value than the HHV. Consequently, the HHV efficiency for
a given EGU is always lower than the corresponding LHV efficiency
because the reported heat input for the HHV is larger. For U.S.
pipeline natural gas, the HHV heating value is approximately 10 percent
higher than the corresponding LHV heating value and varies slightly
based on the actual constituent composition of the natural gas.\470\
The EPA default is to reference all technologies on a HHV basis,\471\
and the Agency is proposing to base the heat input calculation of an
EGU on HHV for purposes of the definition of design efficiency.
However, it should be recognized that manufacturers of combustion
turbines typically use the LHV to express the efficiency of combustion
turbines.\472\
---------------------------------------------------------------------------

    \470\ The HHV of natural gas is 1.108 times the LHV of natural
gas. Therefore, the HHV efficiency is equal to the LHV efficiency
divided by 1.108. For example, an EGU with a LHV efficiency of 59.4
percent is equal to a HHV efficiency of 53.6 percent. The HHV/LHV
ratio is dependent on the composition of the natural gas (i.e., the
percentage of each chemical species (e.g., methane, ethane, propane,
etc.)) within the pipeline and will slightly move the ratio.
    \471\ Natural gas is also sold on a HHV basis.
    \472\ European plants tend to report thermal efficiency based on
the LHV of the fuel rather than the HHV for both combustion turbines
and steam generating EGUs. In the U.S., boiler efficiency is
typically reported on a HHV basis.
---------------------------------------------------------------------------

    Similarly, the electric energy output for an EGU can be expressed
as either of two measured values. One value relates to the amount of
total electric power generated by the EGU, or gross output. However, a
portion of this electricity must be used by the EGU facility to operate
the unit, including compressors, pumps, fans, electric motors, and
pollution control equipment. This within-facility electrical demand,
often referred to as the parasitic load or auxiliary load, reduces the
amount of power that can be delivered to the transmission grid for
distribution and sale to customers. Consequently, electric energy
output may also be expressed in terms of net

output, which reflects the EGU gross output minus its parasitic
load.\473\
---------------------------------------------------------------------------

    \473\ It is important to note that net output values reflect the
net output delivered to the electric grid and not the net output
delivered to the end user. Electricity is lost as it is transmitted
from the point of generation to the end user and these ``line
loses'' increase the farther the power is transmitted. 40 CFR part
60, subpart TTTT provides a way to account for the environmental
benefit of reduced line losses by crediting CHP EGUs, which are
typically located close to large electric load centers. See 40 CFR
60.5540(a)(5)(i) and the definitions of gross energy output and net
energy output in 40 CFR 60.5580.
---------------------------------------------------------------------------

    When using efficiency to compare the effectiveness of different
combustion turbine EGU configurations and the applicable GHG emissions
control technologies, it is important to ensure that all efficiencies
are calculated using the same type of heating value (i.e., HHV or LHV)
and the same basis of electric energy output (i.e., MWh-gross or MWh-
net). Most emissions data are available on a gross output basis and the
EPA is proposing output-based standards based on gross output. However,
to recognize the superior environmental benefit of minimizing
auxiliary/parasitic loads, the Agency is proposing to include optional
equivalent standards on a net output basis. To convert from gross to
net-output based standards, the EPA used a 1 percent auxiliary load for
simple cycle turbines, a 2 percent auxiliary load for combined cycle
turbines, and a 7 percent auxiliary load for combined cycle EGUs using
90 percent CCS.
ii. Lowering the Threshold Between the Base Load and Non-Base Load
Subcategories
    The subpart TTTT distinction between a base load and non-base load
combustion turbine is determined by the unit's actual electric sales
relative to its potential electric sales, assuming the EGU is operated
continuously (i.e., percent electric sales). Specifically, stationary
combustion turbines are categorized as non-base load and are
subsequently subject to a less stringent standard of performance, if
they have net electric sales equal to or less than their design
efficiency (not to exceed 50 percent) multiplied by their potential
electric output (80 FR 64601; October 23, 2015). Because the electric
sales threshold is based in part on the design efficiency of the EGU,
more efficient combustion turbine EGUs can sell a higher percentage of
their potential electric output while remaining in the non-base load
subcategory. This approach recognizes both the environmental benefit of
combustion turbines with higher design efficiencies and provides
flexibility to the regulated community. In the 2015 NSPS, it was
unclear how often high-efficiency simple cycle EGUs would be called
upon to support increased generation from variable renewable generating
resources. Therefore, the Agency determined it was appropriate to
provide maximum flexibility to the regulated community. To do this, the
Agency based the numeric value of the design efficiency, which is used
to calculate the electric sales threshold, on the LHV efficiency. This
had the impact of allowing combustion turbines to sell a greater share
of their potential electric output while remaining in the non-base load
subcategory.
    For the reasons noted below, the EPA is proposing in 40 CFR part
60, subpart TTTTa that the design efficiency be based on the HHV
efficiency instead of LHV efficiency and that the 50 percent maximum
and 33 percent minimum restriction not be included. When determining
the potential electric output used in calculating the electric sales
threshold in 40 CFR part 60, subpart TTTT, design efficiencies of
greater than 50 percent are reduced to 50 percent and design
efficiencies of less than 33 percent are increased to 33 percent for
determining electric sales threshold subcategorization criteria. The 50
percent criterion was established to limit non-base load EGUs from
selling greater than 55 percent of their potential electric sales.\474\
The 33 percent criterion is included to be consistent with
applicability thresholds in the electric utility criteria pollutant
NSPS (40 CFR part 60, subpart Da). Neither of those criteria are
appropriate for 40 CFR part 60, subpart TTTTa, and the EPA is not
proposing that they be used to determine the electric sales threshold.
By basing the electric sales threshold on the HHV design efficiency,
the 50 percent restriction is no longer appropriate because currently
available combined cycle designs operating as intermediate load
combustion turbines would be limited to selling 55 percent of their
potential electric output. If this restriction were maintained, it
would reduce the regulatory incentive for manufacturers to invest in
programs to develop higher efficiency combustion turbines. The EPA is
also proposing to eliminate the 33 percent minimum design efficiency in
the calculation of the potential electric output. The EPA is unaware of
any new combustion turbines with design efficiencies of less than 33
percent; and this will likely have no cost or emissions impact.
However, this provides assurance that new combustion turbines will
maximize design efficiencies. Because of this relationship between the
electric sales threshold and the design efficiency of an individual
EGU, the proposed definition of design efficiency would have the effect
of lowering the electric sales threshold between the base load and non-
base load subcategories. For combined cycle EGUs, the current base load
electric sales threshold is 55 percent. Proposing the definition of the
design efficiency to be based on HHV would make the base load electric
sales threshold for combined cycle EGUs between 46 and 55 percent.\475\
The current electric sales threshold for simple cycle turbines (i.e.,
non-base load) peaks in a range of 40 to 49 percent of potential
electric sales. Under the proposed definition, simple cycle turbines
would be able to sell no more than between 33 and 40 percent of their
potential electric output without moving into the base load
subcategory. A design efficiency definition based on the HHV will have
the effect of decreasing the electric sales threshold in relative terms
by 19 percent and absolute terms by 7 to 9 percent.\476\ The EPA is
soliciting comment on whether the intermediate/base load electric sales
threshold should be reduced further. The EPA is considering a range
that would lower the base load electric sales threshold for simple
cycle combustion turbines to between 29 to 35 percent (depending on the
design efficiency) and to between 40 to 49 percent for combined cycle
combustion turbines (depending on the design efficiency). This would be
equivalent to reducing the design efficiency by 6 percent (e.g.,
multiplying by 0.94) when determining the electric sales threshold.
---------------------------------------------------------------------------

    \474\ While the design efficiency is capped at 50 percent on a
LHV basis, the base load rating (maximum heat input of the
combustion turbine) is on a HHV basis. This mixture of LHV and HHV
results in the electric sales threshold being 11 percent higher than
the design efficiency. The design efficiency of all new combined
cycle EGUs exceed 50 percent on a LHV basis.
    \475\ The electric sales threshold for combined cycle EGUs with
the highest design efficiencies would remain at 55 percent.
    \476\ The design efficiency appears twice in the equation used
to determine the electric sales threshold. Amending the design
efficiency to use the HHV numeric value results in a larger
reduction in the electric sales threshold than the difference
between the HHV and LHV design efficiency.
---------------------------------------------------------------------------

    The EPA determined that proposing to lower the electric sales
threshold is appropriate for new combustion turbines because, as will
be discussed later, the first component of BSER for both intermediate
load and base load turbines is based on highly efficient generation.
Combined cycle units are significantly more efficient than simple cycle
turbines; and therefore, in general,

the EPA should be focusing its determination of the BSER for base load
units on that more efficient technology. In the 2015 NSPS, the EPA used
a higher sales threshold because of the argument that less efficient
simple cycle turbine technology served a unique role that could not be
served by more efficient combined cycle technology. At the time, the
EPA determined that a BSER based exclusively on that more efficient
technology could exclude the building of simple cycle turbines that are
needed to maintain electric reliability. With improvements to the ramp
rates for combined cycle units and with integrated renewable/energy
storage projects becoming more common, these less efficient simple
cycle turbines are no longer the only technology that can serve this
purpose. Further, as EGUs operate more, they have more hours of steady
state operation relative to hours of startup/cycling. Amending the
electric sales threshold would result in GHG reductions by assuring
that the most efficient generating and lowest emitting combustion
turbine technology is used for each subcategory. Therefore, the
proposed change to calculate the design efficiency on a HHV basis will
result in additional emission reductions at reasonable costs.
    Based on EIA 2022 model plants, combined cycle EGUs have a lower
levelized cost of electricity (LCOE) at capacity factors above
approximately 40 percent compared to simple cycle EGUs operating at the
same capacity factors. This supports the proposed base load electric
threshold of 40 percent for simple cycle turbines because it would be
cost effective for owners/operators of simple cycle turbines to add
heat recovery if they elected to operate their unit as a base load
unit. Furthermore, based on an analysis of monthly emission rates,
recently constructed combined cycle EGUs maintain a 12-operating-month
emissions rates at 12-operating-month capacity factors of less than 55
percent (the base load electric sales threshold in subpart TTTT)
relative to operation at higher capacity factors. Therefore, the base
load subcategory operating range could be expanded in subpart TTTTa
without impacting the stringency of the numeric standard. However, at
12-operating-month capacity factors of less than approximately 50
percent, emission rates of combined cycle EGUs increase relative to
operation at a higher capacity factor. It takes longer for a HRSG to
begin producing steam that can be used to generate additional
electricity than the time it takes a combustion engine to reach full
power. Under operating conditions with a significant number of starts
and stops, typical of intermediate and especially low load combustion
turbines, there may not be enough time for the HRSG to generate steam
that can be used for additional electrical generation. To maximize
overall efficiency, combined cycle EGUs often use combustion turbine
engines that are less efficient than the most efficient simple cycle
combustion turbine engines. Under operating conditions with frequent
starts and stops where the HRSG does not have sufficient time to begin
generating additional electricity, a combined cycle EGU may be no more
efficient than a highly efficient simple cycle EGU. Above capacity
factors of approximately 40 percent, the average run time per start for
combined cycle EGUs tends to increase significantly and the HRSG would
be available to contribute additional electric generation. For more
information on the impact of capacity factors on the emission rates of
combined cycle EGUs see the Efficient Generation at Combustion Turbine
Electric Generating Units TSD, which is available in the rulemaking
docket.
    After the 2015 NSPS was finalized, some stakeholders expressed
concerns about the approach for distinguishing between base load and
non-base load turbines. They posited a scenario in which increased
utilization of wind and solar resources, combined with low natural gas
prices, would create the need for certain types of simple cycle
turbines to operate for longer time periods than had been contemplated
when the 2015 NSPS was being developed. Specifically, stakeholders have
claimed that in some regional electricity markets with large amounts of
variable renewable generation, some of the most efficient new simple
cycle turbines--aeroderivative turbines--could be called on to operate
at capacity factors greater than their design efficiency. However, if
those new simple cycle turbines were to operate at those higher
capacity factors, they would become subject to the more stringent
standard of performance for base load turbines. As a result, according
to these stakeholders, the new aeroderivative turbines would have to
curtail their generation and instead, less-efficient existing turbines
would be called upon to run by the regional grid operators, which would
result in overall higher emissions. The EPA evaluated the operation of
simple cycle turbines in areas of the country with relatively large
amounts of variable renewable generation and did not find a strong
correlation between the percentage of generation from the renewable
sources and the 12-operating-month capacity factors of simple cycle
turbines. In addition, the vast majority of simple cycle turbines that
commenced operation between 2010 and 2016 (the most recent simple cycle
combustion turbines not subject to 40 CFR part 60, subpart TTTT) have
operated well below the base load electric sales threshold in 40 CRF
part 60, subpart TTTT. Therefore, the Agency does not believe that the
concerns expressed by stakeholders necessitates any revisions to the
regulatory scheme. In fact, as noted above, the EPA is proposing that
the electric sales threshold can be lowered without impairing the
availability of simple cycle turbines where needed, including to
support the integration of variable generation. The EPA believes that
the proposed threshold is not overly restrictive since a simple cycle
turbine could operate on average for more than 8 hours a day.
iii. Low and Intermediate Load Subcategories
    The EPA is proposing in 40 CFR part 60, subpart TTTTa to create a
low load subcategory to include combustion turbines that operate only
during periods of peak electric demand (i.e., peaking units) which
would be separate from the intermediate load subcategory. Low load
combustion turbines also provide ramping capability and other ancillary
serves to support grid reliability. The EPA evaluated the operation of
recently constructed simple cycle turbines to understand how they
operate and to determine at what electric sales level or capacity
factor their emissions rate is relatively steady. (Note that for
purposes of this discussion, we use the terms ``electric sales'' and
``capacity factor'' interchangeably.) Peaking units only operate for
short periods of time and potentially at relatively low duty
cycles.\477\ This type of operation reduces the efficiency and
increases the emissions rate, regardless of the design efficiency of
the combustion turbine or how it is maintained. For this reason, it is
difficult to establish a reasonable output-based standard of
performance for peaking units.
---------------------------------------------------------------------------

    \477\ The duty cycle is the average operating capacity factor.
For example, if an EGU operates at 75 percent of the fully rated
capacity, the duty cycle would be 75 percent regardless of how often
the EGU actually operates. The capacity factor is a measure of how
much an EGU is operated relative to how much it could potentially
have been operated.
---------------------------------------------------------------------------

    To determine the electric sales threshold--that is, to distinguish

between the intermediate load and low load subcategories--the EPA
evaluated capacity factor electric sales thresholds of 10 percent, 15
percent, 20 percent, and 25 percent. The EPA found the 10 percent level
problematic for two reasons. First, simple cycle combustion turbines
operating at that level or lower have highly variable emission rates,
and therefore it would be difficult for the EPA to establish a
meaningful output-based standard of performance. In addition, only one-
third of simple cycle turbines that have commenced operation since 2015
have maintained 12-operating-month capacity factors of less than 10
percent. Therefore, setting the threshold at this level would bring
most new simple cycle turbines into the intermediate load subcategory,
which would subject them to a more stringent emission rate which is
only achievable for simple cycle combustion turbines operating at
higher capacity factors. This could create a situation where simple
cycle turbines might not be able to comply with the intermediate load
standard of performance while operating at the low end of the
intermediate load capacity factor subcategorization criteria.
    Importantly, based on the EPA's review of hourly emissions data,
above a 15 percent capacity factor, GHG emission rates for many simple
cycle combustion turbines begin to stabilize, see the Simple Cycle
Stationary Combustion Turbine EGUs TSD, which is available in the
rulemaking docket. At higher capacity factors, more time is typically
spent at steady state operation rather than ramping up and down; and,
emission rates tend to be lower while in steady state operation.
Approximately 60 percent of recently constructed simple cycle turbines
have maintained 12-operating-month capacity factors of 15 percent or
less while two-thirds of recently constructed simple cycle turbines
have operated at capacity factors of 20 percent or less; and, the
emission rates clearly stabilize for the majority of simple cycle
turbines operating at capacity factors of greater than 20 percent.
Nearly 80 percent of recently constructed simple cycle turbines
maintain maximum 12-operating-month capacity factors of 25 percent or
less. Based on this information, the EPA is proposing the low load
electric sales threshold--again, the dividing line to distinguish
between the intermediate- and low-load subcategories--to be 20 percent
and is soliciting comment on a range of 15 to 25 percent. The EPA is
also soliciting comment on whether the low load electric sales
threshold should be determined by a site-specific threshold based on
three quarters of the design efficiency of the combustion turbine.\478\
Under this approach, simple cycle combustion turbines selling less than
18 to 22 percent of their potential electric output (depending on the
design efficiency) would still be considered low load combustion
turbines. This ``sliding scale'' electric sales threshold approach is
similar to the approach the EPA used in the 2015 NSPS to recognize the
environmental benefit of installing the most efficient combustion
turbines for low load applications. Using this approach, combined cycle
EGUs would be able to sell between 26 to 31 percent of their potential
electric output while still being considered low load combustion
turbines.
---------------------------------------------------------------------------

    \478\ The calculation used to determine the electric sales
threshold includes both the design efficiency and the base load
rating. Since the base load rating stays the same when adjusting the
numeric value of the design efficiency for applicability purposes,
adjustments to the design efficiency has twice the impact.
Specifically, using three quarters of the design efficiency reduces
the electric sales threshold by half.
---------------------------------------------------------------------------

    Placing low load and intermediate load combustion turbines into
separate subcategories is consistent with how these units are operated
and how emissions from these units can be quantified and controlled.
Consistent with the 2015 NSPS, the BSER analysis for base load
combustion turbine EGUs assumes the use of combined cycle technology
and the BSER analysis for intermediate and low load combustion turbine
EGUs assumes the use of simple cycle technology. However, the Agency
notes that combined cycle EGUs can elect to operate at lower levels of
electric sales and be classified as intermediate or peaking EGUs. In
this case, owners/operators of combined cycle EGUs would be required to
comply with the standards of performance for intermediate or peaking
EGUs.
c. Multi-Fuel-Fired Combustion Turbines
    40 CFR part 60, subpart TTTT subcategorizes multi-fuel-fired
combustion turbines as EGUs that combust 10 percent or more of fuels
not meeting the definition of natural gas on a 12-operating-month
rolling average basis. The BSER for this subcategory is the use of
lower emitting fuels with a corresponding heat input-based standard of
performance of 120 to 160 lb CO2/MMBtu, depending on the
fuel, for newly constructed and reconstructed multi-fuel-fired
stationary combustion turbines.\479\ Lower emitting fuels for these
units include natural gas, ethylene, propane, naphtha, jet fuel
kerosene, Nos. 1 and 2 fuel oils, biodiesel, and landfill gas. The
definition of natural gas in 40 CFR part 60, subpart TTTT includes fuel
that maintains a gaseous state at ISO conditions, is composed of 70
percent by volume or more methane, and has a heating value of between
35 and 41 megajoules (MJ) per dry standard cubic meter (dscm, m\3\)
(950 and 1,100 British thermal units (Btu) per dry standard cubic
foot). Natural gas typically contains 95 percent methane and has a
heating value of 1,050 Btu/lb.\480\ A potential issue with the multi-
fuel subcategory is that owners/operators of simple cycle turbines can
elect to burn 10 percent non-natural gas fuels, such as Nos. 1 or 2
fuel oil, and thereby remain in that subcategory, regardless of their
electric sales. As a result, they would remain subject to the less
stringent standard that applies to multi-fuel-fired sources, the lower
emitting fuels standard. This could allow less efficient combustion
turbine designs to operate as base load units without having to improve
efficiency and could allow EGUs to avoid the need for efficient design
or best operating and maintenance practices. These potential
circumventions would result in higher GHG emissions.
---------------------------------------------------------------------------

    \479\ Combustion turbines co-firing natural gas with other fuels
must determine fuel-based site-specific standards at the end of each
operating month. The site-specific standards depend on the amount of
co-fired natural gas. 80 FR 64616 (October 23, 2015).
    \480\ Note that 40 CFR part 60, subpart TTTT combustion turbines
co-firing 25 percent hydrogen by volume could be subcategorized as
multi-fuel-fired EGUs because the percent methane by volume could
fall below 70 percent, the heating value could fall below 35 MJ/Sm3,
and 10 percent of the heat input could be coming from a fuel not
meeting the definition of natural gas.
---------------------------------------------------------------------------

    To avoid these concerns, the EPA is proposing to eliminate the
multi-fuel subcategory for low, intermediate, and base load combustion
turbines in 40 CFR part 60, subpart TTTTa. This would mean that new
multi-fuel-fired turbines that commence construction or reconstruction
after the date of this proposal will fall within a particular
subcategory depending on their level of electric sales. The EPA also
proposes that the performance standards for each subcategory be
adjusted appropriately for multi-fuel-fired turbines to reflect the
application of the BSER for the subcategories to turbines burning fuels
with higher GHG emission rates than natural gas. To be consistent with
the definition of lower emitting fuels in the 2015 Rule, the maximum
allowable heat input-based emissions rate would be 160 lb
CO2/MMBtu. For example, a standard of performance based on
efficient generation would be 33 percent

higher for a fuel oil-fired combustion turbine compared to a natural
gas-fired combustion turbine. This would assure that the BSER, in this
case efficient generation, is applied, while at the same time
accounting for the use of multiple fuels. As explained in section
VII.F, in the second phase of the NSPS, the EPA is proposing to further
subcategorize base load combustion turbines based on whether the
combustion turbine is combusting hydrogen. During the first phase of
the NSPS, all base load combustion turbines would be in a single
subcategory. Table 2 summarizes the proposed electric sales
subcategories for combustion turbines.

   Table 2--Proposed Sales Thresholds for Subcategories of Combustion
                              Turbine EGUs
------------------------------------------------------------------------
                                    Electric sales threshold (percent of
            Subcategory                   potential electric sales)
------------------------------------------------------------------------
Low Load..........................  <=20 percent.
Intermediate Load.................  >20 percent and <=site-specific
                                     value determined based on the
                                     design efficiency of the affected
                                     facility.
                                     Between ~ 33 to 40 percent
                                     for simple cycle combustion
                                     turbines.
                                     Between ~ 45 to 55 percent
                                     for combined cycle combustion
                                     turbines.
Base Load.........................  >Site-specific value determined
                                     based on the design efficiency of
                                     the affected facility.
                                     Between ~ 33 to 40 percent
                                     for simple cycle combustion
                                     turbines.
                                     Between ~ 45 to 55 percent
                                     for combined cycle combustion
                                     turbines.
------------------------------------------------------------------------

G. Proposed Standards of Performance

    Once the EPA has determined that a particular system or technology
represents BSER, the CAA authorizes the Administrator to establish
standards of performance for new units that reflect the degree of
emission limitation achievable through the application of that BSER. As
noted above, the EPA proposes that because the technology for reducing
GHG emissions from combustion turbines is advancing rapidly, a multi-
phase set of standards of performance, which reflect a multi-component
BSER, is appropriate for base load and intermediate load combustion
turbines. Under this approach, for the first phase of the standards,
which applies as of the effective date the final rule, the BSER is
highly efficient generation for both base load and intermediate load
combustion turbines. During this phase, owners/operators of EGUs will
be subject to a numeric standard of performance that is representative
of the performance of the best performing EGUs in the subcategory. For
the second phase of the standards, beginning in 2032 and 2035
respectively, the BSER for base load turbines includes either 30
percent low-GHG hydrogen co-firing or 90 percent capture CCS, and
beginning in 2032 the BSER for intermediate load EGUs includes 30
percent low-GHG hydrogen co-firing. The affected EGUs would be subject
to either an emissions rate that reflects continued use of highly
efficient generation coupled with CCS, or one that reflects continued
use of highly efficient generation coupled with co-firing low-GHG
hydrogen. For the third phase of the standards, beginning in 2038 for
base load turbines that began co-firing 30 percent low-GHG hydrogen in
2032, the BSER includes co-firing 96 percent low-GHG hydrogen. In
addition, the EPA is proposing a single component BSER, applicable from
the date of proposal, for low load combustion turbines.
1. Phase-1 Standards
    The first component of the BSER is the use of highly efficient
combined cycle technology for base load EGUs in combination with the
best operating and maintenance practices, the use of highly efficient
simple cycle technology in combination with the best operating and
maintenance practices for intermediate load EGUs, and the use of lower
emitting fuels for low load EGUs.
    For new and reconstructed natural gas-fired base load combustion
turbine EGUs, the EPA proposes to find that the most efficient
available combined cycle technology--which qualifies as the BSER for
base load combustion turbines--supports a standard of 770 lb
CO2/MWh-gross for large natural gas-fired EGUs (i.e., those
with a nameplate heat input greater than 2,000 MMBtu/h) and 900 lb
CO2/MWh-gross for natural gas-fired small EGUs (i.e., those
with a nameplate base load rating of 250 MMBtu/h). The proposed
standard of performance for natural gas-fired base load EGUs with base
load ratings between 250 MMBtu/h and 2,000 MMBtu/h would be between 900
and 770 lb CO2/MWh-gross and be determined based on the base
load rating of the combustion turbine.\481\ The EPA proposes to find
that the most efficient available simple cycle technology--which
qualifies as the BSER for intermediate load combustion turbines--
supports a standard of 1,150 lb CO2/MWh-gross for natural
gas-fired EGUs. For new and reconstructed low load combustion turbines,
the EPA proposes to find that the use of lower emitting fuels--which
qualifies as the BSER--supports a standard that ranges from 120 lb
CO2/MMBtu to 160 lb CO2/MMBtu depending on the
fuel burned. The EPA proposes these standards to apply at all times and
compliance to be determined on a 12-operating-month rolling average
basis.
---------------------------------------------------------------------------

    \481\ A new small natural gas-fired base load EGU would
determine the facility emissions rate by taking the difference in
the base load rating and 250 MMBtu/h, multiplying that number by
0.0743 lb CO2/(MW * MMBtu), and subtracting that number
from 900 lb CO2/MWh-gross. The emissions rate for a NGCC
EGU with a base load rating of 1,000 MMBtu/h is 900 lb
CO2/MWh-gross minus 750 MMBtu/h (1,000 MMBtu/h-250 MMBtu/
h) times 0.0743 lb CO2/(MW * MMBtu), which results in an
emissions rate of 844 lb CO2/MWh-gross.
---------------------------------------------------------------------------

    The EPA has determined that these standards of performance are
achievable specifically for natural gas-fired base load and
intermediate load combustion turbine EGUs. However, combustion turbine
EGUs burn a variety of fuels, including fuel oil during natural gas
curtailments. Owners/operators of combustion turbines burning fuels
other than natural gas would not necessarily be able to comply with the
proposed standards for base load and intermediate load natural gas-
fired combustion turbines using highly efficient generation. Therefore,
the Agency is proposing that owners/operators of combustion turbines
burning fuels other than natural gas may elect to use the ratio of the
heat input-based emissions rate of the specific fuel(s) burned to the
heat input-based emissions rate of natural gas to determine a site-
specific standard of performance for the operating period. For example,
the NSPS emissions rate for a large base load combustion turbine
burning 100 percent distillate oil during the 12-operaitng month period
would be 1,070 lb CO2/MWh-gross.\482\
---------------------------------------------------------------------------

    \482\ The heat input-based emission rates of natural gas and
distillate oil are 117 and 163 lb CO2/MMBtu,
respectively. The ratio of the heat input-based emission rates
(1.39) is multiplied by the natural gas-fired standard of
performance (770 lb CO2/MWh) to get the applicable
emissions rate (1,070 lb CO2/MWh).

---------------------------------------------------------------------------

    To determine what emission rates are currently achieved by existing
high-efficiency combined cycle EGUs and simple cycle EGUs, the EPA
reviewed 12-operating-month generation and CO2 emissions
data from 2015 through 2021 for all combined and simple cycle EGUs that
submitted continuous emissions monitoring system (CEMS) data to the
EPA's emissions collection and monitoring plan system (ECMPS). The data
were sorted by the lowest maximum 12-operating-month emissions rate for
each unit to identify long-term emission rates on a lb CO2/
MWh-gross basis that have been demonstrated by the existing combined
cycle and simple cycle EGU fleets. Since an NSPS is a never-to-exceed
standard, the EPA is proposing that use of long-term data are more
appropriate than shorter term data in determining an achievable
standard. These long-term averages account for degradation and variable
operating conditions, and the EGUs should be able to maintain their
current emission rates, as long as the units are properly maintained.
While annual emission rates indicate a particular standard is
achievable for certain EGUs in the short term, they are not necessarily
representative of emission rates that can be maintained over an
extended period using highly efficient generating technology in
combination with best operating and maintenance practices.
    To determine the 12-operating-month average emissions rate that is
achievable by application of the BSER, the EPA calculated 12-month
CO2 emission rates by dividing the sum of the CO2
emissions by the sum of the gross electrical energy output over the
same period. The EPA did this separately for combined cycle EGUs and
simple cycle EGUs to determine the emissions rate for the base load and
intermediate load subcategories, respectively.
    For base load combustion turbines, the EPA evaluated three emission
rates: 730, 770, and 800 lb CO2/MWh-gross. An emissions rate
of 730 lb CO2/MWh-gross has been demonstrated by a single
combined cycle facility--the Okeechobee Clean Energy Center. This
facility is a large 3-on-1 combined cycle EGU that commenced operation
in 2019 and uses a recirculating cooling tower for the steam cycle.
Each turbine is rated at 380 MW and the three HRSGs feed a single steam
turbine of 550 MW. The EPA is not proposing to use the emissions rate
of this EGU to determine the standard of performance, for multiple
reasons. The Okeechobee Clean Energy Center uses a 3-on-1 multi-shaft
configuration but, many combined cycle EGUs use a 1-on-1 configuration.
Combined cycle EGUs using a 1-on-1 configuration can be designed such
that both the combustion turbine and steam turbine are arranged on one
shaft and drive the same generator. This configuration has potential
capital cost and maintenance costs savings and a smaller plant
footprint that can be particularly important for combustion turbines
enclosed in a building. In addition, a single shaft configuration has
higher net efficiencies when operated at part load than a multi-shaft
configuration. Basing the standard of performance on the performance of
multi-shaft combined cycle EGUs could limit the ability of owners/
operators to construct new combined cycle EGUs in space-constrained
areas (typically urban areas \483\) and combined cycle EGUs with the
best performance when operated as intermediate load EGUs.\484\ Either
of these outcomes could result in greater overall emissions from the
power sector. An advantage of multi-shaft (2-on-1 and 3-on-1)
configurations is that the turbine engine can be installed initially
and run as a simple cycle EGU, with the HRSG and steam turbines added
at a later date, all of which allows for more flexibility for the
regulated community. In addition, a single large steam turbine can
generate electricity more efficiently than multiple smaller steam
turbines, increasing the overall efficiency of comparably sized
combined cycle EGUs. According to Gas Turbine World 2021, multi-shaft
combined cycle EGUs have design efficiencies that are 0.7 percent
higher than single shaft combined cycle EGUs using the same turbine
engine.\485\
---------------------------------------------------------------------------

    \483\ Generating electricity closer to electricity demand can
reduce stress on the electric grid, reducing line losses and freeing
up transmission capacity to support additional generation from
variable renewable sources. Further, combined cycle EGUs located in
urban areas could be designed as CHP EGUs, which have potential
environmental and economic benefits.
    \484\ Power sector modeling projects that combined cycle EGUs
will operate at lower capacity factors in the future. Combined cycle
EGUs with lower base load efficiencies, but higher part load
efficiencies could have lower overall emission rates.
    \485\ According to the data in Gas Turbine World 2021, while
there is a design efficiency advantage of going from a 1-on-1
configuration to a 2-on-1 configuration (assuming the same turbine
engine) there is no efficiency advantage of 3-on-1 configurations
compared to 2-on-1 configurations.
---------------------------------------------------------------------------

    The efficiency of the Rankine cycle (i.e., HRSG plus the steam
turbine) is determined in part by the ability to cool the working fluid
(e.g., steam) after it has been expanded through the turbine. All else
equal, the lower the temperature that can be achieved, the more
efficient the Rankine cycle. The Okeechobee Clean Energy Center used a
recirculating cooling system, which can achieve lower temperatures than
EGUs using dry cooling systems and therefore would be more efficient
and have a lower emissions rate. However dry cooling systems have lower
water requirements and therefore could be the preferred technology in
arid regions or in areas where water requirements could have
significant ecological impacts. Therefore, the EPA proposes that the
efficient generation standard for base load EGUs should account for the
use of dry cooling.
    Finally, the Okeechobee Clean Energy Center is a relatively new EGU
and full efficiency degradation might not be accounted for in the
emissions analysis. Therefore, the EPA is not proposing that an
emissions rate of 730 lb CO2/MWh-gross is an appropriate
nationwide standard. However, the EPA is soliciting comment on whether
the use of alternate working fluid, such as supercritical
CO2, or other potential efficiency improvements would make
this emissions rate an appropriate standard of performance for base
load combustion turbines.
    An emissions rate of 770 lb CO2/MWh-gross has been
demonstrated by 14 percent of recently constructed combined cycle EGUs.
These turbines include combined cycle EGUs using 1-on-1 configurations
and dry cooling, are manufactured by multiple companies, and have long-
term emissions data that fully account for potential degradation in
efficiency. One of the best performing large combined cycle EGUs that
has maintained an emissions rate of 770 lb CO2/MWh-gross is
the Dresden plant, located in Ohio.\486\ This 2-on-1 combined cycle
facility, uses a recirculating cooling tower, and has maintained an
emissions rate of 765 lb CO2/MWh-gross, measured over 12
operating months with 99 percent confidence. The turbine engines are
rated at 2,250 MMBtu/h, which demonstrates that the standard of 770 lb
CO2/MWh-gross is achievable at a heat input rating of 2,000
MMBtu/h. In addition, while a 2-on-1 configuration and a cooling tower
are more efficient than a 1-on-1 configuration and dry cooling, the
Dresden Energy Facility does not use the most efficient combined cycle
design currently available. Multiple more efficient designs have been
developed since the

Dresden Energy Facility commenced operation a decade ago that more than
offset these efficiency losses. Therefore, the EPA proposes that while
the Dresden combined cycle EGUs uses a 2-on-1 configuration with a
cooling tower, it demonstrates that an emissions rate of 770 lb
CO2/MWh-gross is achievable for all new large combined cycle
EGUs. For additional information on the EPA analysis of emission rates
for high efficiency base load combined cycle EGUs, see the Efficient
Generation at Combustion Turbine Electric Generating Units TSD, which
is available in the rulemaking docket.
---------------------------------------------------------------------------

    \486\ The Dresden Energy Facility is listed as being located in
Muskingum County, Ohio, as being owned by the Appalachian Power
Company, as having commenced commercial operation in late 2011. The
facility ID (ORISPL) is 55350 1A and 1B.
---------------------------------------------------------------------------

    The EPA is not proposing an emissions rate of 800 lb
CO2/MWh-gross because it does not represent the most
efficient combined cycle EGUs designs. Nearly half of recently
constructed combined cycle EGUs have maintained an emissions rate of
800 lb CO2/MWh-gross. However, the EPA is soliciting comment
on whether this higher emissions rate is appropriate on grounds that it
would increase flexibility and reduce costs to the regulated community
by allowing more available designs to operate as base load combustion
turbines.
    With respect to small combined cycle combustion turbines, the best
performing unit is the Holland Energy Park facility in Holland,
Michigan, which commenced operation in 2017 and uses a 2-on-1
configuration and a cooling tower.\487\ The 50 MW turbine engines have
individual heat input ratings of 590 MMBtu/h and serve a single 45 MW
steam turbine. The facility has maintained a 12-operating month, 99
percent confidence emissions rate of 870 lb CO2/MWh-gross.
This long-term data accounts for degradation and variable operating
conditions and demonstrates that a base load combustion turbine EGU
with a turbine rated at 250 MMBtu/h should be able to maintain an
emissions rate of 900 lb CO2/MWh-gross.\488\ In addition,
there is a commercially available HRSG that uses supercritical
CO2 instead of steam as the working fluid. This HRSG would
be significantly more efficient than the HRSG that uses dual pressure
steam, which is common for small combined cycle EGUs.\489\ When these
efficiency improvements are accounted for, a new small natural gas-
fired combined cycle EGU would be able to maintain an emissions rate of
850 lb CO2/MWh-gross. Therefore, the Agency is soliciting
comment on whether the small natural gas-fired base load combustion
turbine standard of performance should be 850 lb CO2/MWh-
gross.
---------------------------------------------------------------------------

    \487\ The Holland Park Energy Center is a CHP system that uses
hot water in the cooling system for a snow melt system that uses a
warm water piping system to heat the downtown sidewalks to clear the
snow during the winter. Since this useful thermal output is low
temperature, it does not materially reduce the electrical efficiency
of the EGU. If the useful thermal output were accounted for, the
emissions rate of the Holland Energy Park would be lower. The
facility ID (ORISPL) is 59093 10 and 11.
    \488\ To estimate an achievable emissions rate for an efficient
combined cycle EGU at 250 MMBtu/h the EPA assumed a linear
relationship for combined cycle efficiency with turbine engines with
base load ratings of less than 2,000 MMBtu/h.
    \489\ If the combustion turbine engine exhaust temperature is
500[deg]C or greater, a HRSG using 3 pressure steam without a reheat
cycle could potentially provide an even greater increase in
efficiency (relative to a HRSG using 2 pressure steam without a
reheat cycle).
---------------------------------------------------------------------------

    In summary, the Agency solicits comment on the following range of
potential standards of performance:
     New and reconstructed natural gas-fired base load
combustion turbines with a heat input rating that is greater than 2,000
MMBtu/h: a range of 730-800 lb CO2/MWh-gross;
     New and reconstructed natural gas-fired base load
combustion turbines with a heat input rating of 250 MMBtu/h: a range of
850 to 900 lb CO2/MWh-gross.
    For intermediate load combustion turbines, the EPA evaluated the
performance of recently constructed high efficiency natural gas-fired
simple cycle EGUs. The EPA evaluated three emission rates for the
intermediate load standard of performance: 1,200, 1,150, and 1,100 lb
CO2/MWh-gross. Sixty two percent of recently constructed
intermediate load simple cycle EGUs have maintained an emissions rate
of 1,200 lb CO2/MWh-gross, 17 percent have maintained an
emissions rate of 1,150 lb CO2/MWh-gross, and 6 percent have
maintained an emissions rate of 1,100 lb CO2/MWh-gross.
However, the units that have maintained an emissions rate of 1,100 lb
CO2/MWh-gross generally have a single large aeroderivative
combustion turbine design. In contrast, the ones that have maintained
an emission rate of 1,150 lb CO2/MWh-gross have multiple
different designs, including an industrial frame combustion turbine
design, and are made by multiple manufacturers. Therefore, the EPA is
proposing an intermediate load standard of performance of 1,150 lb
CO2/MWh-gross. The Agency is soliciting comment on whether
the standard should be 1,100 lb CO2/MWh-gross, or whether
that would result in unacceptably high costs because currently only a
single design for a large aeroderivative simple cycle turbine would be
able to meet this standard. The Agency is also soliciting comment on a
standard of performance of 1,200 lb CO2/MWh-gross. While
this would achieve fewer GHG reductions, it would increase flexibility,
and potentially reduce costs, to the regulated community by allowing
the currently available designs to operate as intermediate load
combustion turbines. For additional information on the EPA analysis of
emission rates for high efficiency intermediate load simple cycle EGUs,
see the Efficient Generation at Combustion Turbine Electric Generating
Units TSD, which is available in the rulemaking docket
    The EPA is also soliciting comment on whether the use of steam
injection is applicable to intermediate load combustion turbines. Steam
injection is the use of a relatively low cost HRSG to produce steam
that is injected into the combustion chamber of the combustion turbine
engine instead of using a separate steam turbine.\490\ Advantages of
steam injection include improved efficiency and increases the output of
the combustion turbine as well as reducing NOX emissions.
Combustion turbines using steam injection have characteristics in-
between simple cycle and combined cycle combustion turbines. They are
more efficient, but more complex and have higher capital costs than
simple cycle combustion turbines without steam injection. Combustion
turbines using steam injection are simpler and have lower capital costs
than combined EGUs but have lower efficiencies. The EPA is aware of a
single combustion turbine that is using steam injection that has
maintained a 12-operaitng month emission rates of less than 1,000 lb
CO2/MWh-gross. The EPA requests that commenters include
information on whether this technology would be applicable to
intermediate load combustion turbines and could be part of either the
first or second component of the BSER along with cost information.\491\
---------------------------------------------------------------------------

    \490\ A steam injected combustion turbine would be considered a
combined cycle combustion turbine (for NSPS purposes) because energy
from the turbine engine exhaust is recovered in a HRSG and that
energy is used to generate additional electricity.
    \491\ The second component of the BSER, 30 percent low-GHG
hydrogen co-firing, would reduce the emissions rate to 880 lb
CO2/MWh-gross.
---------------------------------------------------------------------------

2. Phase-2 Standards
    The use of CCS and hydrogen co-firing are both approaches
developers are considering to reduce GHG emissions beyond highly
efficient generation. However, as noted above, these approaches apply
to different subcategories and are not applicable to

the same EGUs. The proposed phase-2 standards are in table 3.

                Table 3--Phase-2 Standards of Performance
------------------------------------------------------------------------
                                                          Standard of
           Subcategory                   BSER             performance
------------------------------------------------------------------------
Low load........................  Lower emitting      120-160 lb CO2/
                                   fuels.              MMBtu.
Intermediate load...............  Highly efficient    1,000 lb CO2/MWh-
                                   simple cycle        gross.
                                   technology
                                   coupled with co-
                                   firing 30 percent
                                   (by volume) low-
                                   GHG hydrogen.
Base load adopting the CCS        Highly efficient    90 lb CO2/MWh-
 pathway.                          combined cycle      gross.
                                   technology
                                   coupled with 90
                                   percent CCS.
Base load adopting the low-GHG    Highly efficient    680 lb CO2/MWh-
 hydrogen co-firing pathway.       combined cycle      gross.
                                   technology
                                   coupled with co-
                                   firing 30 percent
                                   (by volume) low-
                                   GHG hydrogen.
------------------------------------------------------------------------

    Co-firing 30 percent by volume low-GHG hydrogen reduces emissions
by 12 percent. The EPA applied this percent reduction to the emission
rates for the intermediate load and base load units adopting the low-
GHG hydrogen co-firing pathway subcategories, to determine the phase-1
standards. For the base load combustion turbines adopting the CCS
subcategory, the EPA reduced the emissions rate by 89 percent to
determine the CCS based phase-2 standards.\492\ The CCS percent
reduction is based on a CCS system capturing 90 percent of the emitting
CO2 being operational anytime the combustion turbine is
operating. However, if the carbon capture equipment has lower
availability/reliability than the combustion turbine or the CCS
equipment takes longer to startup than the combustion turbine itself
there would be periods of operation where the CO2 emissions
would not be controlled by the carbon capture equipment. 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 combustion turbine is
operating, and that the combustion turbine 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 combustion turbine. If the combustion
turbine were not permitted to operate when CCS was unavailable, there
may be local reliability consequences or issues during startup or
shutdown, and the EPA is soliciting comment on how to balance these
issues. Additionally, the EPA is soliciting comment on the range of
reduction in emission rate of 75 to 90 percent.
---------------------------------------------------------------------------

    \492\ The 89 percent reduction from CCS accounts for the
increased auxiliary load of a 90 percent post combustion amine-based
capture system. Due to rounding, the proposed numeric standards of
performance do not necessarily match the standards that would be
determined by applying the percent reduction to the phase 1
standards.
---------------------------------------------------------------------------

    The standards of performance for the intermediate and base load
combustion turbines would also be adjusted based on the uncontrolled
emission rates of the fuels relative to natural gas. For 100 percent
distillate oil-fired combustion turbines, the emission rates would be
1,300 lb CO2/MWh-gross, 120 lb CO2/MWh-gross, and
910 lb CO2/MWh-gross for the intermediate load, non low-GHG
hydrogen co-firing base load, and low-GHG hydrogen co-firing base load
subcategories respectively.
3. Phase-3 Standards
    The third component of the BSER is applicable to owner/operators of
base load combustion turbines that elect to implement early GHG
reductions (i.e., comply with an emissions rate of 680 lb
CO2/MWh-gross starting in January 2032). The phase 3 BSER
standard of performance increases the GHG reduction requirements and is
based on co-firing 96 percent by volume low-GHG hydrogen in addition to
the use of highly efficient combined cycle technology in combination
with the best operating and maintenance practices. The proposed phase-3
standards are in table 4.

                Table 4--Phase-3 Standards of Performance
------------------------------------------------------------------------
                                                          Standard of
           Subcategory                   BSER             performance
------------------------------------------------------------------------
Base load electing to implement   Highly efficient    90 lb CO2/MWh-
 early GHG reductions.             combined cycle      gross.
                                   technology
                                   coupled with co-
                                   firing 89 percent
                                   (by heat input)
                                   low-GHG hydrogen.
------------------------------------------------------------------------

    Co-firing 89 percent by heat input (96 percent by volume) low-GHG
hydrogen reduces GHG emissions by 89 percent. The EPA applied this
percent reduction to the emission rates for base load under phase 1 of
the BSER. Similar to the phase 1 and 2 standards of performance, the
numeric standard would be adjusted based on the uncontrolled emission
rates of the fuels relative to natural gas. For 100 percent distillate
oil-fired combustion turbines, the emission rates would be 120 lb
CO2/MWh-gross.
    As a variation on proposing the date for meeting this standard as
2038, the EPA solicits comment on proposing the date as 2035, coupled
with authorizing an approach for crediting early reductions, under
which a source that achieves reductions due to co-firing low-GHG
hydrogen starting in 2032 may apply credit for those reductions to its
emission rate beginning in 2035. Another, more stringent, variation of
this approach would be to allow credit only for reductions below the
emission rate otherwise required by 2032. Other

variations would allow sources to generate credits from reductions from
co-firing low-GHG hydrogen, or from any other reductions below their
standard of performance, in any year before 2035. In this manner, the
source would be authorized to comply with its 2035 standard in part
through use of credits generated by making reductions beginning in
2032. Under such an approach, early credits could only be used by the
unit that generated those credits. For instance, a unit co-firing 30
percent low-GHG hydrogen prior to 2035 would be able to generate
credits that it could use in 2035 and beyond. This would allow a unit
co-firing low-GHG hydrogen to ramp up the amount it co-fired over time,
while still achieving the same amount of emission reductions that would
have been achieved had the unit co-fired enough low-GHG hydrogen (e.g.,
96 percent by volume) starting in 2035. Another variation on this
approach would be to treat such a crediting scheme as a compliance
alternative to the CCS BSER by showing equivalent emission reductions,
rather than the standard itself.
    The EPA proposes the following mechanism to ensure that affected
sources in the base load subcategory comply with the applicable
standard of performance in the event that the EPA finalizes both the
CCS pathway (that is, the use of 90-percent-capture CCS by 2035) and
the low-GHG hydrogen pathway (that is, co-firing 30 percent low-GHG
hydrogen by 2032 and 96 percent by 2038). The EPA proposes that
affected sources must notify the EPA by January 1, 2031, which pathway
they are selecting, and thus which standard they intend to comply with.
If they select the low-GHG hydrogen pathway, they must comply with the
applicable standard based on co-firing 30 percent hydrogen (by volume)
in 2032 through 2037. In addition, in 2033 through 2037, they must be
prepared to demonstrate that they complied with the applicable standard
based on co-firing 30 percent low-GHG hydrogen in the preceding years,
beginning in 2032. In 2038, they must comply with the applicable
standard based on co-firing 96 percent (by volume) now-GHG hydrogen.

H. Reconstructed Stationary Combustion Turbines

    In the previous sections, the EPA explained the background of and
requirements for new and reconstructed stationary combustion turbines
and evaluated various control technology configurations to determine
the BSER. Because the BSER is the same for new and reconstructed
stationary combustion turbines, the Agency is proposing to use the same
emissions analysis for both new and reconstructed stationary combustion
turbines. For each of the subcategories, the EPA is proposing that the
proposed BSER results in the same standard of performance for new
stationary combustion turbines and reconstructed stationary combustion
turbines. Since reconstructed turbines could likely incorporate
technologies to co-fire hydrogen as part of the reconstruction process
at little or no cost, the low-GHG hydrogen co-firing would likely to be
similar to those for newly constructed combustion turbines. For CCS,
the EPA approximated the cost to add CCS to a reconstructed combustion
turbine by increasing the capital costs of the carbon capture equipment
by 10 percent relative to the costs for a newly constructed combustion
turbine. This increases the capital cost from $949/kW to $1,044/
kW.\493\ Using a 12-year amortization period, a 90 percent-capture
amine-based post combustion CCS system increases the LCOE by $8.5/MWh
and has overall CO2 abatement costs of $25/ton ($28/metric
ton).
---------------------------------------------------------------------------

    \493\ The kW value used as reference for the costs is the output
from the combined cycle EGU prior to the installation of the CCS.
---------------------------------------------------------------------------

    A reconstructed stationary combustion turbine is not required to
meet the standards if doing so is deemed to be ``technologically and
economically'' infeasible.\494\ This provision requires a case-by-case
reconstruction determination in the light of considerations of economic
and technological feasibility. However, this case-by-case determination
would consider the identified BSER, as well as technologies the EPA
considered, but rejected, as BSER for a nationwide rule. One or more of
these technologies could be technically feasible and of reasonable
cost, depending on site-specific considerations and if so, would likely
result in sufficient GHG reductions to comply with the applicable
reconstructed standards. Finally, in some cases, equipment upgrades,
and best operating practices would result in sufficient reductions to
achieve the reconstructed standards.
---------------------------------------------------------------------------

    \494\ 40 CFR 60.15(b)(2).
---------------------------------------------------------------------------

I. Modified Stationary Combustion Turbines

    CAA section 111(a)(4) defines a ``modification'' as ``any physical
change in, or change in the method of operation of, a stationary
source'' that either ``increases the amount of any air pollutant
emitted by such source or . . . results in the emission of any air
pollutant not previously emitted.'' Certain types of physical or
operational changes are exempt from consideration as a modification.
Those are described in 40 CFR 60.2, 60.14(e).
    In the 2015 NSPS, the EPA did not finalize standards of performance
for stationary combustion turbines that conduct modifications; instead,
the EPA concluded that it was prudent to delay issuing standards until
the Agency could gather more information (80 FR 64515; October 23,
2015). There were several reasons for this determination: few sources
had undertaken NSPS modifications in the past, the EPA had little
information concerning them, and available information indicated that
few owners/operators of existing combustion turbines would undertake
NSPS modifications in the future; and since the Agency eliminated
proposed subcategories for small EGUs in the 2015 NSPS, questions were
raised as to whether smaller existing combustion turbines that
undertake a modification could meet the final performance standard of
1,000 lb CO2/MWh-gross.
    It continues to be the case that the EPA is aware of no evidence
indicating that owners/operators of combustion turbines intend to
undertake actions that could qualify as NSPS modifications in the
future. EPA is not proposing, or soliciting comment on whether it
should propose, standards of performance for modifications of
combustion turbines.

J. Startup, Shutdown, and Malfunction

    In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the U.S. Court of Appeals for the District of Columbia
Circuit (D.C. Circuit) vacated portions of two provisions in the EPA's
CAA section 112 regulations governing the emissions of HAP during
periods of SSM. Specifically, the court vacated the SSM exemption
contained in 40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that, the
SSM exemption violates the requirement under section 302(k) of the CAA
that some CAA section 112 standard apply continuously. Consistent with
Sierra Club v. EPA, the EPA is proposing standards in this rule that
apply at all times. The NSPS general provisions in 40 CFR 60.11(c)
currently exclude opacity requirements during periods of startup,
shutdown, and malfunction and the provision in 40 CFR 60.8(c) contains
an exemption from non-opacity standards. These general provision
requirements would automatically apply to the standards set in an NSPS,
unless the regulation specifically overrides these general provisions.
The NSPS subpart TTTT (40

CFR part 60 subpart TTTT), does not contain an opacity standard, thus,
the requirements at 40 CFR 60.11(c) are not applicable. The NSPS
subpart TTTT also overrides 40 CFR 60.8(c) in table 3 and requires that
sources comply with the standard(s) at all times. In reviewing NSPS
subpart TTTT and proposing the new NSPS subpart TTTTa, the EPA is
proposing to retain in subpart TTTTa the requirements that sources
comply with the standard(s) at all times. Therefore, the EPA is
proposing in table 3 of the new subpart TTTTa to override the general
provisions for SSM provisions. The EPA is proposing that all standards
in subpart TTTTa apply at all times.
    The EPA has attempted to ensure that the general provisions we are
proposing to override are inappropriate, unnecessary, or redundant in
the absence of the SSM exemption. The EPA is specifically seeking
comment on whether we have successfully done so.
    In proposing the standards in this rule, the EPA has taken into
account startup and shutdown periods and, for the reasons explained in
this section of the preamble, has not proposed alternate standards for
those periods. The EPA analysis of achievable standards of performance
used CEMS data that includes all period of operation. Since periods of
startup, shutdown, and malfunction were not excluded from the analysis,
the EPA is not proposing alternate standard for those periods of
operation.
    Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead, they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
CAA section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting standards of performance,
nothing in CAA section 111 requires the Agency to consider malfunctions
as part of that analysis. The EPA is not required to treat a
malfunction in the same manner as the type of variation in performance
that occurs during routine operations of a source. A malfunction is a
failure of the source to perform in a ``normal or usual manner'' and no
statutory language compels the EPA to consider such events in setting
CAA section 111 standards of performance. The EPA's approach to
malfunctions in the analogous circumstances (setting ``achievable''
standards under CAA section 112) has been upheld as reasonable by the
D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d 579, 606-610 (2016).

K. Testing and Monitoring Requirements

    Because the NSPS reflects the application of the best system of
emission reduction under conditions of proper operation and
maintenance, in doing the NSPS review, the EPA also evaluates and
determines the proper testing, monitoring, recordkeeping and reporting
requirements needed to ensure compliance with the NSPS. This section
will include a discussion on the current testing and monitoring
requirements of the NSPS and any additions the EPA is proposing to
include in 40 CFR part 60, subpart TTTTa.
1. General Requirements
    The current rule allows three approaches for determining compliance
with its emissions limits: Continuous measurement using CO2
CEMS and flow measurements for all EGUs; calculations using hourly heat
input and `F' factors \495\ for EGUs firing uniform oil or gas or non-
uniform fuels; or Tier 3 calculations using fuel use and carbon content
as described in GHGRP regulations for EGUs firing non-uniform fuels.
The first two approaches are in use for carbon dioxide by the Acid Rain
program (40 CFR part 75), to which most, if not all, of the EGUs
affected by NSPS subpart TTTT are already subject, while the last
approach is in use for carbon dioxide, nitrous oxide, and methane
reporting from stationary fuel combustion sources (40 CFR part 98,
subpart C).
---------------------------------------------------------------------------

    \495\ An F factor is the ratio of the gas volume of the products
of combustion to the heat content of the fuel.
---------------------------------------------------------------------------

    The EPA believes continuing the use of these familiar approaches
already in use by other programs represents a cost-effective means of
obtaining quality assured data requisite for determining carbon dioxide
mass emissions. Therefore, no changes to the current ways of collecting
carbon dioxide and associated data needed for mass determination, such
as flow rates, fuel heat content, fuel carbon content, and the like,
are proposed. Because no changes are proposed and because the cost and
burden for EGU owners or operators are already accounted for by other
rulemakings, this aspect of the proposed rule is designed to have
minimal, if any, cost or burden associated with carbon dioxide testing
and monitoring. In addition, the proposal contains no changes to
measurement and testing requirements for determining electrical output,
both gross and net, as well as thermal output, to current existing
requirements.
    However, the EPA requests comment on whether continuous carbon
dioxide and flow measurements should become the sole means of
compliance for this rule. Such a switch would increase costs for those
EGU owners or operators who are currently relying on the oil- or gas-
fired or non-uniform fuel-fired calculation-based approaches for
compliance. By way of reference, the annualized cost associated with
adoption and use of continuous carbon dioxide and flow measurements
where none now exist is estimated to be about $52,000. To the extent
that the rule were to mandate continuous carbon dioxide and flow
measurements in accordance with what is currently allowed as one option
and that an EGU lacked this instrumentation, its owner or operator
would need to incur this annual cost to obtain such information and to
keep the instrumentation calibrated.
2. Requirements for Sources Implementing CCS
    The CCS process is also subject to monitoring and reporting
requirements under the EPA's GHGRP (40 CFR part 98). The GHGRP requires
reporting of facility-level GHG data and other relevant information
from large sources and suppliers in the U.S. The ``suppliers of carbon
dioxide'' source category of the GHGRP (GHGRP subpart PP) requires
those affected facilities with production process units that capture a
CO2 stream for purposes of supplying CO2 for
commercial applications or that capture and maintain custody of a
CO2 stream in order to sequester or otherwise inject it
underground to report the mass of CO2 captured and supplied.
Facilities that inject a CO2 stream underground for long-
term containment in subsurface geologic formations report quantities of
CO2 sequestered under the ``geologic sequestration of carbon
dioxide'' source category of the GHGRP (GHGRP subpart RR). In 2022, to
complement GHGRP subpart RR, the EPA proposed the ``geologic
sequestration of carbon dioxide with enhanced oil recovery (EOR) using
ISO 27916'' source category of the GHGRP (GHGRP subpart VV) to provide
an alternative method of

reporting geologic sequestration in association with
EOR.496 497 498
---------------------------------------------------------------------------

    \496\ 87 FR 36920 (June 21, 2022).
    \497\ International Standards Organization (ISO) standard
designated as CSA Group (CSA)/American National Standards Institute
(ANSI) ISO 27916:2019, Carbon Dioxide Capture, Transportation and
Geological Storage--Carbon Dioxide Storage Using Enhanced Oil
Recovery (CO2-EOR) (referred to as ``CSA/ANSI ISO 27916:2019'').
    \498\ As described in 87 FR 36920 (June 21, 2022), both subpart
RR and proposed subpart VV (CSA/ANSI ISO 27916:2019) require an
assessment and monitoring of potential leakage pathways;
quantification of inputs, losses, and storage through a mass balance
approach; and documentation of steps and approaches used to
establish these quantities. Primary differences relate to the terms
in their respective mass balance equations, how each defines
leakage, and when facilities may discontinue reporting.
---------------------------------------------------------------------------

    The current rule leverages the regulatory requirements under GHGRP
subpart RR and does not reference GHGRP subpart VV. The EPA is
proposing that any affected unit that employs CCS technology that
captures enough CO2 to meet the proposed standard and
injects the captured CO2 underground must report under GHGRP
subpart RR or proposed GHGRP subpart VV. If the emitting EGU sends the
captured CO2 offsite, it must assure that the CO2
is managed at a facility subject to the GHGRP requirements, and the
facility injecting the CO2 underground must report under
GHGRP subpart RR or proposed GHGRP subpart VV. This proposal does not
change any of the requirements to obtain or comply with a UIC permit
for facilities that are subject to the EPA's UIC program under the Safe
Drinking Water Act.
    The EPA also notes that compliance with the standard is determined
exclusively by the tons of CO2 captured by the emitting EGU.
The tons of CO2 sequestered by the geologic sequestration
site are not part of that calculation, though the EPA anticipates that
the quantity of CO2 sequestered will be substantially
similar to the quantity captured. However, to verify that the
CO2 captured at the emitting EGU is sent to a geologic
sequestration site, we are leveraging regulatory reporting requirements
under the GHGRP. The BSER is determined to be adequately demonstrated
based solely on geologic sequestration that is not associated with EOR.
However, EGUs also have the compliance option to send CO2 to
EOR facilities that report under GHGRP subpart RR or proposed GHGRP
subpart VV. We also emphasize that this proposal does not involve
regulation of downstream recipients of captured CO2. That
is, the regulatory standard applies exclusively to the emitting EGU,
not to any downstream user or recipient of the captured CO2.
The requirement that the emitting EGU assure that captured
CO2 is managed at an entity subject to the GHGRP
requirements is thus exclusively an element of enforcement of the EGU
standard. This will avoid duplicative monitoring, reporting, and
verification requirements between this proposal and the GHGRP, while
also ensuring that the facility injecting and sequestering the
CO2 (which may not necessarily be the EGU) maintains
responsibility for these requirements. Similarly, the existing
regulatory requirements applicable to geologic sequestration are not
part of the proposed rule.
3. Requirements for Sources Co-Firing Low-GHG Hydrogen
    Because the EPA is basing its proposed definition of low-GHG
hydrogen consistent with IRC section 45V(b)(2)(D), it is reasonable, if
possible and practicable, for the EPA to adopt, in whole or in part,
the eligibility, monitoring, verification, and reporting protocols
associated with IRC section 45V(b)(2)(D) when finalized by Treasury for
the production of low-GHG hydrogen, and apply those protocols, as
applicable, to requirements the EPA establishes for the demonstration
by EGUs that they are using low-GHG hydrogen. Adopting very similar
requirements for demonstrations by EGUs that they are using low-GHG
hydrogen would help ensure there are not dueling eligibility
requirements for low-GHG hydrogen production with overall emissions
rates of 0.45 kg CO2e/kg H2 or less. Adopting
similar methods for assessing GHG emissions associated with hydrogen
production pathways would create clarity and certainty and reduce
confusion.
    The EPA is taking comment on its proposal to closely follow
Treasury protocols in determining how EGUs demonstrate compliance with
the fuel characteristics required in this rulemaking. The EPA is taking
comment on what forms of acceptable mechanisms and documentary evidence
should be required for EGUs to demonstrate compliance with the
obligation to co-fire low-GHG hydrogen, including proof of production
pathway, overall emissions calculations or modeling results and input,
purchasing agreements, contracts, and energy attribute certificates.
Given the complexities of tracking produced hydrogen and the public
interest in such data, the EPA is also taking comment on whether EGUs
should be required to make fully transparent their sources of low-GHG
hydrogen and the corresponding quantities procured. The EPA is also
seeking comment on requiring that EGUs using low-GHG hydrogen
demonstrate that their hydrogen is exclusively from facilities that
only produce low-GHG hydrogen, as a means of reducing demonstration
burden and opportunities for double counting that could otherwise occur
for hydrogen purchased from facilities that produce multiple types of
hydrogen and the complex recordkeeping and documentation that would be
necessary to reliably verify that the hydrogen purchased from such
facilities qualifies. The EPA solicits comment on a mechanism to
operationalize such a provision.
    Treasury is currently developing implementing rules for IRC section
45V. Congress specified that tax credit eligibility for the credit
tiers (45V(b)(2)(A), 45(V)(b)(2)(B), 45(b)(2)(C), and 45V(b)(2)(D))
should be based on an assessment of the estimated well-to-gate \499\
GHG emissions of hydrogen production, determined based on the most
recent Greenhouse gases, Regulated Emissions, and Energy use in
Transportation model (GREET model) or a successor model as determined
by the Secretary of Treasury. Consistent with its proposal to define
low-GHG hydrogen consistent with IRC section 45V(b)(2)(D), the EPA is
also proposing that, for the purpose of demonstrating compliance with
the requirement to combust low-GHG hydrogen under this NSPS, the
maximum extent possible the same methodology specified in IRC section
45V and requirements currently under development should apply. One
example would be requiring that the owner/operator of the combustion
turbine obtain from the hydrogen producer from which they purchase low-
GHG hydrogen the hydrogen producer's calculation of GHG levels
associated with its hydrogen production using the GREET well-to-gate
analysis. The GREET model is well established, designed to adapt to
evolving knowledge, and capable of including technological advances.
The EPA solicits comment on whether the Agency should consider
unrelated or third-party verification as part of the standards required
for EGUs to demonstrate compliance. Given the

sequential timing of EPA and Treasury processes, the EPA may take
further action, after promulgation of this NSPS, to provide additional
guidance on application of Treasury's framework for IRC section 45V to
this particular context. The EPA requests comment on its proposal to
adopt as much as possible the methodology specified in IRC section 45V
and any associated implementing requirements established by Treasury,
once the methodology and implementing requirements are finalized, as
part of the obligations for EGUs to demonstrate compliance with the
requirement to combust low-GHG hydrogen under this NSPS.
---------------------------------------------------------------------------

    \499\ Well-to-gate analysis of lifecycle GHG emissions
represents a smaller scope than cradle-to-grave analysis. Well-to-
gate emissions of hydrogen production include those associated with
fossil fuel or electricity feedstock production and delivery to the
hydrogen facility; the hydrogen production process itself; and any
associated CCS applied at the hydrogen production facility. Well-to-
gate analysis does not consider emissions associated with the
manufacture or end-of-life of the hydrogen production facility or
facilities providing feedstock inputs to the hydrogen production
facility. Nor does it consider emissions associated with
transportation, distribution, and use of hydrogen beyond the
production facility.
---------------------------------------------------------------------------

    Although proposing to incorporate as much as possible Treasury's
eligibility, monitoring, reporting, and verification protocols, the EPA
recognizes that Treasury protocols concern hydrogen production, whereas
the EPA's proposed requirements apply to affected EGUs that use the
hydrogen to demonstrate compliance with the low-GHG hydrogen co-firing
obligations. The EPA is also taking comment on several underlying
policy issues relevant to ensuring that hydrogen used to comply with
this rule is low-GHG hydrogen. One reason that the EPA is considering
whether an alternative method to the Treasury guidance may be needed to
determine whether hydrogen meets the requirements to be considered low-
GHG is because hydrogen production facilities that begin construction
after 2032 will not be eligible for the tax credits. The EPA wants to
make sure a pathway exists for low-GHG hydrogen to be used for
compliance purposes even if the producer began construction after 2032
and is not receiving tax credits.
    Given this and other uncertainties, the EPA is taking comment on
issues that would be relevant should the Agency develop its own
protocols for EGUs to demonstrate compliance with the overall emissions
rate in IRC section 45V(b)(2)(D) for co-firing as BSER in this
rulemaking.
    The EPA is also taking comment on strategies the EPA could adopt to
inform its own eligibility, monitoring, reporting and verification
protocols for ensuring compliance with the 0.45 kg CO2e/kg
H2 or less emission rate for compliance with the low-GHG
provisions of this rule, if the EPA does not adopt Treasury's
protocols. The purpose of these strategies would be to ensure that EGUs
are using only low-GHG hydrogen, i.e., hydrogen that results in GHG
emissions of less than 0.45 kg CO2 per kg H2. The
EPA is taking comment on the appropriateness of requiring EGUs to
provide verification that the hydrogen they use complies with this
standard, as demonstrated by the GREET model for estimating the GHG
emissions associated with hydrogen production from well-to-gate, and to
what extent EGUs should be required to verify the accuracy of the
energy inputs and conclusions of the GREET model for the hydrogen used
by the EGU to comply with this rule.
    Several important considerations with respect to determining
overall GHG emissions rates for hydrogen production pathways have been
raised by researchers and have been picked up in trade press
coverage.500 501 Given the importance of these issues, the
recent accumulation of relevant research, and the range of stakeholder
positions, the EPA is taking comment on the need for (and design of)
approaches and appropriate timeframes for allowing EGUs to meet
requirements for geographic and temporal alignment requirements to
verify that the hydrogen used by the EGU is compliant with this
rulemaking, recognizing that EPA's low-GHG standard for compliance
would not begin until 2032. The EPA is soliciting comment on these
issues, as they relate to co-firing low-GHG hydrogen in combustion
turbines and the requisite need to only utilize the lowest-GHG hydrogen
in these applications as specified in IRC section 45V, specifically IRC
section 45V(b)(2)(D). The EPA notes this is one of multiple forthcoming
opportunities for public comment on this suite of issues, and the EPA's
proposal is specific to low-GHG hydrogen in the context of qualifying a
co-firing fuel as part of BSER.
---------------------------------------------------------------------------

    \500\ Without Sufficient Guardrails, the Hydrogen Tax Credit
Could Increase Emissions--Union of Concerned Scientists. ucsusa.org.
    \501\ Hydrogen's Power Grid Demands Under Scrutiny in Tax
Credit. bloomberglaw.com.
---------------------------------------------------------------------------

    It is important to note that the landscape for methane emissions
monitoring and mitigation is changing rapidly. For example, the EPA is
in the process of developing enhanced data reporting requirements for
petroleum and natural gas systems under its GHGRP, and is in the
process of finalizing requirements under New Source Performance
Standards and Emission Guidelines for the oil and gas sector that will
result in mitigation of methane emissions. With these changes, it is
expected that the quality of data to verify methane emissions will
improve and methane emissions rates will change over time. Adequately
identifying and accounting for overall emissions associated with
methane-based feedstocks is essential in the determination of accurate
overall emissions rates to comply with the low-GHG hydrogen standards
in this rule. The EPA is taking comment on how methane leak rates can
be appropriately quantified and conservatively estimated given the
inherent uncertainties and wide range of basin-specific
characteristics. The EPA is soliciting comment on whether EGUs should
be required to produce a demonstration of augmented in-situ monitoring
requirements to determine upstream emissions when methane feedstock is
used for low-GHG hydrogen used by the EGU for compliance with this
rule. The EPA is also taking comment on whether EGUs should use a
default assumption for upstream methane leak rates in the event
monitoring protocols are not finalized as part of this rulemaking, and
what an appropriate default leak rate should be, including what
evidence would be necessary for the EGU to deviate from that default
assumption. The EPA is also taking comment on the appropriateness of
requiring EGUs to provide CEMS data for SMR or ATR processes seeking to
produce qualifying low-GHG hydrogen for co-firing to ensure the amount
of carbon captured by CCS is properly and consistently monitored and
outage rates and times are recorded and considered. The EPA is
soliciting comment on providing EGUs with a representative and climate-
protective default assumption for carbon capture rates associated with
SMR and ATR hydrogen pathways, inclusive of outages, if CCS is used for
low-GHG hydrogen production as part of this rulemaking, including what
evidence would be necessary for the EGU to deviate from that default
assumption. These topics are particularly important to ensuring use of
low-GHG hydrogen given the DOE estimate that by 2050, reformation-based
production with CCS may account for 50-80 percent of total U.S.
hydrogen production.\502\ The EPA is taking comment on requiring
substantiation of energy inputs used in any overall GHG emissions
assessment for hydrogen production used by EGUs for compliance with
this requirement.
---------------------------------------------------------------------------

    \502\ 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.
---------------------------------------------------------------------------

    In comparison with petrochemical-based hydrogen production pathways
discussed above, electrolyzer-based hydrogen production has the
potential for lower-GHG hydrogen because the technology is based on
splitting water (H2O) molecules rather than splitting
hydrocarbons (e.g., CH4).\503\ For EGUs

relying on hydrogen produced using this pathway, the EPA is seeking
comment on the method for assuring that energy inputs to that
production are consistent with the low-GHG hydrogen standard that EGUs
would be required to meet under this rule. Specifically, the EPA is
taking comment on requiring EGUs to provide substantiation of low-GHG
energy inputs into any overall emissions assessment for electrolytic
hydrogen production pathways for hydrogen used by the EGUs to comply
with the low-GHG hydrogen standard in this rule. Energy Attribute
Certificates (EACs) (EACs from renewable sources are sometimes known as
Renewable Energy Credits or RECs) are produced for each megawatt hour
of low-GHG generation and therefore offer a measurable, auditable, and
verifiable approach for determining the GHG emissions associated with
the energy used to make the low-GHG hydrogen. EACs with specific
attributes are commonly used in the electricity markets to substantiate
corporate clean energy commitments and use, as well as for utility
compliance with State RPS and CES programs. The EPA is taking comment
on requiring EGUs to provide EAC verification for low-GHG emission
energy inputs into GHG emissions assessments for hydrogen used by that
EGU to comply with the low-GHG standard in this rule, for all hydrogen
pathways. The EPA is seeking comment on allowing EGUs to use EACs as
part of the documentation required for verifying the use of low-GHG
hydrogen.
---------------------------------------------------------------------------

    \503\ 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.
---------------------------------------------------------------------------

    The EPA is taking comment on allowing EGUs to comply with the low-
GHG hydrogen standard in this rule if they demonstrate that the
hydrogen used is produced from: (1) dedicated low-GHG emitting
electricity from a generator sited on the utility side of a meter that
is contractually obligated to a electrolyzer, (2) a generator
collocated with an electrolyzer and sited behind a common utility
meter, or (3) a generator whereby the electrolyzer and generator are
collocated but not interconnected to the grid and have no grid
exchanges of power. The EPA is also taking comment on approaches for
EGUs to demonstrate that purchased hydrogen produced from an
electrolyzer could meet the low-GHG standard, in whole or part, through
an allotment of zero emitting electricity to a portion of the
electrolyzer's hydrogen output. Many announced hydrogen production
projects pair electrolyzers with renewable (including hydroelectric) or
nuclear energy, which are likely capable of producing low-GHG hydrogen.
Wind and solar renewable generation sources are variable, and nuclear
units go offline for refueling purposes. In these cases, and others,
grid-based electricity, which often has a high carbon intensity might
be pursued in combination with EACs for each megawatt hour of grid-
based energy used. Aligning the time and place (temporal and geographic
alignment) of EACs used to allocate and describe delivered grid-based
electricity consumed could potentially help ensure that hydrogen used
is low-GHG hydrogen.\504\ Some degree of alignment geographically, for
example delivery of power to the balancing authority in which the
electricity is consumed by the electrolyzer, could ensure that EACs
used are representative of the allocation of the energy mix consumed by
the electrolyzers. However, alignment could also entail trade-offs,
about which the EPA would like more information.
---------------------------------------------------------------------------

    \504\ ``How Can Hydrogen Producers Show That They Are
``Clean''?, Resources for the Future, October 27, 2022.
---------------------------------------------------------------------------

    In the case of temporal matching, the central issue is whether a
producer must obtain sufficient EACs to match the total electricity
demand of the electrolyzer on an annual basis corresponding to an
overall emissions rates of 0.45 kg CO2e/kg H2 or less, or
whether the producer must verify that it has obtained an EAC for low
carbon generation on a more granular timeframe, such as an hourly or
monthly basis, for each time period the electrolyzer is running. In
other words, how can book and claim methods for grid-connected systems
be developed to reliably claim total energy input emissions are
equivalent to a pure off-grid zero-carbon emitting system.
Considerations around how grid-based electricity can effectively assure
zero-carbon emitting energy inputs as validated by EACs have received
greater attention since passage of the IRA. Solutions offered by
researchers at Princeton University include requiring new grid-based
hydrogen producers to match 100 percent of electricity consumption on
an hourly basis with new carbon-free generation (substantiated through
EACs with hourly attributes), with an estimated cost impact of $1/
kg.\505\ Other research analyzing near-term emissions benefits of
hourly EAC alignment with respect to IRC section 45V implementation is
growing, with some divergent views about the emissions benefits of more
precise alignment requirements.\506\ Several research papers have
focused on the expense, trade-offs, and benefits of phasing in new and
hourly EAC alignment requirements.\507\ An MIT Energy Initiative
Working Paper examined emissions benefits of hourly alignment and
supported a `` `a phased approach'. . . annual matching in the near
term with a re-evaluation leaning towards hourly matching later on in
the decade''.\508\ A Rhodium Report found that while ``[r]equiring a
high degree of stringency across regional, temporal, and additionality
variables on day one . . . increases the total subsidized cost of
hydrogen production'' in the initial phase of the program, and
concludes that ultimately ``policymakers can't ignore the long-term
emissions risk'' and recommends, ``[t]o construct emissions guardrails,
the IRS can establish target dates for ratcheting up the certainty on
key implementation details like a transition to more temporally
granular matching. Such phase-in approaches give the hydrogen and power
industries the signposts they need to develop the tracking tools,
calculation approaches, contract language, and other key elements to
assure green hydrogen contributes to decarbonization.'' \509\ This
analysis did not consider potential system-wide emissions impacts if
costs present a near-term barrier to electrolytic hydrogen production,
and reformation-based methods continue to dominate hydrogen production
market share moving forward. Other research, for example from
Princeton, supports hourly time-matching, additionality, and location
requirements--arguing that all three pillars are important in ensuring
low-GHG outcomes and that additional costs are not unreasonable.
Research by Energy Innovation aligns with the Princeton study with
respect to locational and additionality requirements and diverges in
its recommendation of phasing in hourly EAC requirements by 2026.\510\
---------------------------------------------------------------------------

    \505\ Princeton Citation: Minimizing emissions from grid-based
hydrogen production in the United States--IOPscience January 2023.
    \506\ American Council on Renewable Energy (ACORE), ``Analysis
of Hourly & Annual GHG Emissions: Accounting for Hydrogen
Production'', April 2023. acore.org.
    \507\ Energy Futures Initiative, ``The Hydrogen Demand Action
Plan'', February 2023. https://energyfuturesinitiative.org/wp-content/uploads/sites/2/2023/02/EFI-Hydrogen-Hubs-FINAL-2-1.pdf.
    \508\ MIT Energy Initiative, April 2023 ``Producing hydrogen
from electricity: How modeling additionality drives the emissions
impact of time-matching requirements'' Anna Cybulsky, Michael
Giovanniello, Tim Schittekatte, Dharik S. Mallapragada.
    \509\ Rhodium Group, ``Scaling Green Hydrogen in a post-IRA
World'' March 16, 2023. https://rhg.com/research/scaling-clean-hydrogen-ira/.
    \510\ https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-Hydrogen-Production-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.

---------------------------------------------------------------------------

    The European Commission proposed a phased-in approach to defining
what constitutes `renewable hydrogen' for the European Union (EU). The
EU framework includes multiple components including temporal alignment
requirements: monthly EAC alignment is required at the onset of the
program, and hourly EAC alignment requirements are phased-in by
2030.511 512 An impact assessment of the temporal alignment
requirements is to be completed in 2028 and could impact the timing of
the hourly EAC phase-in requirements. The EU hydrogen requirements and
conditions will apply to domestic producers and imports and do not
expire. EAC alignment requirements impact both new and existing
projects. Geographic alignment for EACs is required at the onset of the
EU program, whereas vintage requirements necessitating new zero-carbon
emitting energy source-based generation, often called `additional', are
phased in after 2028. The EU proposal was released in February and must
be approved by the European Parliament and the Council of the EU within
four months: amendments to the underlying policy are not permitted.
Notably, unlike the United States, the EU has a carbon policy for power
sector emissions that could help ensure that additional electricity
demand from hydrogen production does not result in additional power
sector CO2 emissions. The EU and stakeholders examining
costs and benefits of temporal EAC alignment requirements generally
find that hourly EAC alignment is preferred before the 2032 proposed
effective date of hydrogen co-firing requirements in this proposed
rule, with most converging on or before 2030.513 514
---------------------------------------------------------------------------

    \511\ C_2023_1087_1_EN_ACT_part1_v8.pdf. (europa.eu)
    \512\ European Commission, ``Commission sets out rules for
renewable hydrogen'' Brussels, February 13, 2023. See: Hydrogen
(europa.eu), Delegated regulation on Union methodology for RFNBOs.
(europa.eu)
    \513\ https://energyinnovation.org/wp-content/uploads/2023/04/Smart-Design-Of-45V-Hydrogen-Production-Tax-Credit-Will-Reduce-Emissions-And-Grow-The-Industry.pdf.
    \514\ April 12, 2023, memorandum, ``How annual matching for the
Inflation Reduction Act's (IRA) 45V clean hydrogen tax credit can
accelerate progress towards the Biden administration's
decarbonization and clean hydrogen goals'' signed by 23 companies,
addressed to Treasury Secretary Janet Yellen, Energy Secretary
Jennifer Granholm and Senior Advisor to the President for Clean
Energy Innovation and Implementation Mr. John Podesta, indicated an
openness to examine hourly EAC requirements in 2032 or earlier and
asserted, ``recent studies warn that overly stringent temporal
matching would hinder the development of clean hydrogen industry.''
---------------------------------------------------------------------------

    The EPA is soliciting comment on requiring EGUs to use geographic
and temporal alignment approaches for EAC-related requirements and the
appropriate timing and trade-offs of such approaches. The EPA is
soliciting comment on the appropriateness of requiring geographic
alignment for EACs used in conjunction with energy inputs at the
balancing authority level at the onset of the compliance period for
BSER in 2032. Similarly, the EPA is soliciting comments on the
appropriateness of requiring hourly EAC alignment requirements at the
onset of the compliance period for BSER in 2032. Relatedly, the EPA is
taking comment on whether any hourly EAC alignment requirements should
affect both existing and new projects beginning in 2032, regardless of
when a project became operational and a recipient of IRC section 45V
credits.
    Hourly tracking systems are evolving to meet this need in real
time. For example, PJM announced it would introduce EACs with hourly
data stamping for low-GHG generators in March 2023. M-RETS, a regional
attribute tracking system headquartered in the Midwest, has also
introduced the capability to track hourly energy attributes. While
several tracking systems are announcing or have started issuing hourly
EACs, standardized methods, and nationwide coverage is still
developing. Recognizing that the timing of EPA's proposed regulations
would not require such tracking systems to be fully functional until
the 2030s, the EPA is taking comment on the suitability of emerging and
differentiated tracking systems to provide the infrastructure for
hourly energy attribute tracking for EGUs complying with low-GHG
hydrogen standards. The EPA is also taking comment on the need for
energy attribute tracking systems to uniformly approach the issuance,
allocation, tracking and retirement of hourly EACs using similar
approaches to ensure a common and consistent national practice.

L. Mechanisms To Ensure Use of Actual Low-GHG Hydrogen

    The EPA is soliciting comment on appropriate mechanisms to ensure
that the low-GHG hydrogen used by EGUs is actually low-GHG, and guard
against EGU use of hydrogen that is falsely claimed to be low-GHG
hydrogen. The EPA solicits comment on whether EGUs should be required
to provide an independent third-party verification that hydrogen the
EGU uses to comply with this regulation meets the requirements for low-
GHG hydrogen. EPA also solicits comment on whether any such verifying
third party must hold an active accreditation from an accrediting body,
such as the California Air Resources Board's Low Carbon Fuels Standards
Program or the International Standards Organization 14064 Code. EPA
seeks comment on any other mechanisms to ensure that hydrogen used by
EGUs meets the low-GHG standard and what the remedy should be if an EGU
uses hydrogen that is determined not to meet the definition of low-GHG
hydrogen.

M. Recordkeeping and Reporting Requirements

    The current rule (subpart TTTT of 40 CFR part 60) requires EGU
owners or operators to prepare reports in accordance with the Acid Rain
Program's ECMPS and, for the EGUs relying on the compliance approaches
contained in Appendix G of 40 CFR part 75, with the reporting
requirements of that Appendix. Such reports are to be submitted
quarterly. The EPA believes all EGU owners and operators have extensive
experience in using the ECMPS and use of a familiar system ensures
quick and effective rollout of the program in today's proposal. Because
all EGUs are expected to be covered by and included in the ECMPS,
minimal, if any, costs for reporting are expected for this proposal. In
the unlikely event that a specific EGU is not already covered by and
included in the ECMPS, the estimated annual per unit cost would be
about $8,500.
    The current rule's recordkeeping requirements at 40 CFR part
60.5560 rely on a combination of general provision requirements (see 40
CFR 60.7(b) and (f)), requirements at subpart F of 40 CFR part 75, and
an explicit list of items, including data and calculations; the EPA
proposes to retain those existing subpart TTTT of 40 CFR part 60
requirements in the new NSPS subpart TTTTa of 40 CFR part 60. The
annual cost of those recordkeeping requirements would be the same
amount as is required for subpart TTTT of 40 CFR part 60 recordkeeping.
As the recordkeeping in subpart TTTT of 40 CFR part 60 will be replaced
by similar recordkeeping in subpart TTTTa of 40 CFR part 60 upon
promulgation, this annual cost for recordkeeping will be maintained.

N. Additional Solicitations of Comment and Proposed Requirements

    This section includes additional issues the Agency is specifically
soliciting comment on. It also provides a summary of some of the key
considerations the EPA is soliciting comment on with respect to the

proposed CAA section 111(b) requirements.
1. CCS and Co-Firing Low-GHG Hydrogen as BSER for the Base Load
Subcategory
    As described above, the EPA is proposing to establish two
subcategories with different standards for the base load subcategory,
each based on a different BSER pathway. The first is based on a BSER of
CCS with 90 percent capture by 2035. The second is based on a BSER of
co-firing 30 percent (by volume) low-GHG hydrogen by 2032 and co-firing
96 percent (by volume) by 2038. (Both pathways include efficient
equipment and operation and maintenance as an initial component of the
BSER.) In other sections of this preamble, the EPA solicits comment on
variations in the amount of emissions reduction and the dates for
compliance for each pathway.
    The EPA believes that if it finalizes a subcategory approach with
different standards in which sources may choose between the two
standards and BSER pathways, each must achieve environmentally
comparable emission reductions. Thus, if the EPA determines based on
all of the statutory considerations that CCS with 90 percent capture
qualifies as the BSER for base load combustion sources, then co-firing
hydrogen could qualify as well only if it also achieves comparable
reductions. Because the emissions standards are technology neutral, if
the two pathways can achieve the same emissions reductions at the same
time, there would be no need to establish separate subcategories and
standards as sources could adopt either BSER pathway to meet the
standard. But the EPA also believes that these two technologies may
achieve comparable emissions reductions at slightly different times,
thus potentially necessitating two alternate standards. The EPA
solicits comment on the differences in emissions reductions in both
scale and time that would result from the two standards and BSER
pathways, including how to calculate the different amounts of emission
reductions, how to compare them, and what conclusions to draw from
those differences. From the perspective of an individual turbine, the
proposed co-firing with low-GHG hydrogen-based standard results in
earlier emission reductions because it takes effect in 2032, three
years before the CCS-based standard, but the low-GHG hydrogen-based
standard could also result in fewer total emission reductions because
the 90 percent emission rate reduction is not required until 2038,
three years after the CCS-based standard. Although early emission
reductions have value in addressing climate change, it is the
cumulative impact of the emission reductions that is of primary
importance given the short time-scale over which those early reductions
are occurring. The EPA also solicits comment on the potential benefits
of prescribing two separate standards for new base load combustion
turbines. Owners and operators of new combustion turbine EGUs are
currently pursuing both CCS and co-firing with low-GHG hydrogen as
approaches for reducing GHG emissions, and both require the development
of infrastructure that may proceed at a different pace and scale and
achieve emissions reductions on different timelines with respect to
each technology. Although both CCS and co-firing with low-GHG hydrogen
are, or are expected to be, broadly available throughout the United
States, the EPA solicits comment on whether individual locations where
new base load combustion turbines might be constructed might lend
themselves more to one technology than the other (based on pipeline
availability, proximity to hydrogen production or geologic
sequestration sites, etc.). The EPA recognizes that the design of CAA
section 111--whereby sources decide which emissions controls they use
to meet standards of performance--provides sources with operational
flexibility so long as they achieve the standard. A subcategory
approach, however, may allow the EPA to consider the potentially
differing scale and pace at which these technologies can achieve
environmentally equivalent emissions reductions and whether there are
characteristics of units that make one or the other pathways ``best''
for those types of units.
    As an alternative to the proposed approach of two standards and
BSER pathways for the base load subcategory, the EPA is soliciting
comment on having a single standard, which would be based on CCS with
90 percent capture (along with efficiency as the initial component of
the BSER). Under this alternative, the EPA would not establish a
separate base load subcategory for combustion turbines that adopt the
low-GHG hydrogen co-firing pathway.
    The EPA solicits comment on whether finalizing a single, CCS-based
standard for the baseload subcategory better reflects the more likely
uses of hydrogen as a source of fuel in new combustion turbines. The
EPA has proposed a standard for base load combustion turbines that
adopt the low-GHG hydrogen co-firing in part because the Agency
understands a number of power companies are actively developing
combustion turbines that are designed to co-fire hydrogen. However, the
Agency recognizes that power companies may ultimately come to utilize
low-GHG hydrogen as a storage fuel reserved for intermediate load
combustion turbines that support variable renewable generation, rather
than for combustion turbines that generate at base load. An approach in