subcategorization is to tailor the BSER for different sets of sources:
---------------------------------------------------------------------------

    \173\ 40 CFR 60.22(b)(5), 60.22a(b)(5). Because the definition
of subcategories depends on characteristics relevant to the BSER,
and because those characteristics can differ as between new and
existing sources, the EPA may establish different subcategories as
between new and existing sources.

    EPA's emission guidelines will reflect subcategorization within
source categories where appropriate, taking into account differences
in sizes and types of facilities and similar considerations,
including differences in control costs that may be involved for
sources located in different parts of the country. Thus, EPA's
emission guidelines will in effect be tailored to what is reasonably
---------------------------------------------------------------------------
achievable by particular classes of existing sources. . . .

Id. at 53343.
    The EPA's authority to ``distinguish among classes, types, and
sizes within categories,'' as provided under CAA section 111(b)(2),
generally allows the Agency to place types of sources into
subcategories when they have characteristics that are relevant to the
controls they can apply to reduce their emissions. This is consistent
with the commonly understood meaning of the term ``type'' in CAA
section 111(b)(2): ``a particular kind, class, or group,'' or
``qualities common to a number of individuals that distinguish them as
an identifiable class.'' See https://www.merriam-webster.com/dictionary/type. That is, subcategorization is appropriate for a set of
sources that have qualities in common that are relevant for determining
what controls are appropriate for those sources. And where the
qualities in common are not relevant for determining what controls are
appropriate, subcategorization is not appropriate. This view is
consistent with the D.C. Circuit's interpretation of CAA section
112(d)(1), which is a subcategorization provision that is substantially
similar to CAA section 111(b)(2). In NRDC v. EPA, 489 F.3d 1364, 1375-
76 (D.C. Cir. 2007), the court upheld the EPA's decision under CAA
section 112(d)(1) not to subcategorize sources subject to control
requirements under CAA section 112(d)(3), known as the maximum
achievable control technology (MACT) floor, on the basis of

costs. That was because the EPA is not authorized to consider costs in
setting the MACT floor.\174\
---------------------------------------------------------------------------

    \174\ See Chem. Mfrs. Ass'n v. NRDC, 470 U.S. 116, 131 (1985)
(Court interprets similar subcategorization provision under the
Clean Water Act to grant the EPA broad discretion).
---------------------------------------------------------------------------

    The EPA has developed subcategories in numerous rulemakings under
CAA section 111 since it began promulgating them in the 1970s. These
rulemakings have included subcategories on the basis of the size of the
sources, see 40 CFR 60.40b(b)(1)-(2) (subcategorizing certain coal-
fired steam generating units on the basis of heat input capacity); the
types of fuel combusted, see Sierra Cub, v. EPA, 657 F.2d 298, 318-19
(D.C. Cir. 1981) (upholding a rulemaking that established different
NSPS ``for utility plants that burn coal of varying sulfur content''),
2015 NSPS, 80 FR 64510, 64602 (table 15) (October 23, 2015)
(subdividing new combustion turbines on the basis of type of fuel
combusted); the types of equipment used to produce products, see 81 FR
35824 (June 3, 2016) (promulgating separate NSPS for many types of oil
and gas sources, such as centrifugal compressors, pneumatic
controllers, and well sites); types of manufacturing processes used to
produce product, see 42 FR 12022 (March 1, 1977) (announcing
availability of final guideline document for control of atmospheric
fluoride emissions from existing phosphate fertilizer plants) and
``Final Guideline Document: Control of Fluoride Emissions From Existing
Phosphate Fertilizer Plants, EPA-450/2-77-005 1-7 to 1-9, including
table 1-2 (applying different control requirements for different
manufacturing operations for phosphate fertilizer); levels of
utilization of the sources, see 2015 NSPS, 80 FR 64510, 64602 (table
15) (October 23, 2015) (dividing new natural gas-fired combustion
turbines into the subcategories of base load and non-base load); the
activity level of the sources, see 81 FR 59276, 59278-79 (August 29,
2016) (dividing municipal solid waste landfills into the subcategories
of active and closed landfills); and geographic location of the
sources, see 71 FR 38482 (July 6, 2006) (SO2 NSPS for
stationary combustion turbines subcategories turbines on the basis of
whether they are located in, for example, a continental area, a
noncontinental area, the part of Alaska north of the Arctic Circle, and
the rest of Alaska), see also Sierra Club v. Costle, 657 F.2d 298, 330
(D.C. Cir. 1981) (stating that the EPA could create different
subcategories for new sources in the Eastern and Western U.S. for
requirements that depend on water-intensive controls). As these
references indicate, the EPA has subcategorized many times in
rulemaking under CAA sections 111(b) and 111(d) and based on a wide
variety of physical, locational, and operational characteristics. It
should also be noted that in some instances, the EPA has declined to
subcategorize. Lignite Energy Council, 198 F.3d at 933 (upholding EPA
decision not to subcategorize utility boilers for purposes of
NOX NSPS on grounds that the decision was not arbitrary and
capricious).
    Regardless of whether the EPA subcategorizes within a source
category for purposes of determining the BSER and the emission
performance level for the emission guideline, a State retains certain
flexibility in assigning standards of performance to its affected EGUs.
The statutory framework for CAA section 111(d) emission guidelines, and
the flexibilities available to States within that framework, are
discussed below.
D.C. Circuit Order To Reinstate the ACE Rule
    On October 27, 2022, the D.C. Circuit responded to the U.S. Supreme
Court's reversal by recalling its mandate for the vacatur of the ACE
Rule. American Lung Ass'n v. EPA, No. 19-1140, Order (October 27,
2022). Accordingly, at that time, the ACE Rule came back into effect.
The court also revised its judgment to deny petitions for review
challenging the CPP Repeal Rule, consistent with the West Virginia
decision, so that the CPP remains repealed. The court took further
action denying several of the petitions for review unaffected by the
Supreme Court's decision in West Virginia, which means that certain
parts of its 2021 decision in American Lung Ass'n remain valid. These
parts include the holding that the EPA's prior regulation of mercury
emissions from coal-fired electric power plants under CAA section 112
does not preclude the Agency from regulating CO2 from coal-
fired electric power plants under CAA section 111, and the holding,
discussed above, that the 2015 NSPS included a valid significant
contribution determination and therefore provided a sufficient basis
for a CAA section 111(d) rule regulating greenhouse gases from existing
fossil fuel-fired EGUs. The court's holding to invalidate amendments to
the implementing regulations applicable to emission guidelines under
CAA section 111(d) that extended the preexisting schedules for State
and Federal actions and sources' compliance, also remains valid. Based
on the EPA's stated intention to replace the ACE Rule, the court stayed
further proceedings with respect to the ACE Rule, including the various
challenges that its BSER was flawed because it did not achieve
sufficient emission reductions and failed to specify an appropriately
specific degree of emission limitation.
3. Key Elements of Determining a Standard of Performance
    Congress first included the definition of ``standard of
performance'' when enacting CAA section 111 in the 1970 Clean Air Act
Amendments (CAAA), amended it in the 1977 CAAA, and then amended it
again in the 1990 CAAA to largely restore the definition as it read in
the 1970 CAAA. The current text of CAA section 111(a)(1) reads: ``The
term `standard of performance' means a standard for emission of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' The
D.C. Circuit has reviewed CAA section 111 rulemakings on numerous
occasions since 1973,\175\ and has developed a body of caselaw that
interprets the term ``standard of performance,'' as discussed
throughout this preamble.
---------------------------------------------------------------------------

    \175\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C.
Cir. 1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427 (D.C.
Cir. 1973); Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981);
Lignite Energy Council v. EPA, 198 F.3d 930 (D.C. Cir. 1999);
Portland Cement Ass'n v. EPA, 665 F.3d 177 (D.C. Cir. 2011);
American Lung Ass'n v. EPA, 985 F.3d 914 (D.C. Cir. 2021), rev'd in
part, West Virginia v. EPA, 142 S. Ct. 2587 (2022). See also
Delaware v. EPA, No. 13-1093 (D.C. Cir. May 1, 2015).
---------------------------------------------------------------------------

    The basis for standards of performance, whether promulgated by the
EPA under CAA section 111(b) or established by the States under CAA
section 111(d), is that the EPA determines the ``degree of emission
limitation'' that is ``achievable'' by the sources by application of a
``system of emission reduction'' that the EPA determines is
``adequately demonstrated,'' ``taking into account'' the factors of
``cost . . . nonair quality health and environmental impact and energy
requirements,'' and that the EPA determines to be the ``best.'' The
D.C. Circuit has stated that in determining the ``best'' system, the
EPA must also take into account ``the amount of air

pollution'' \176\ reduced and the role of ``technological innovation.''
\177\ The determination of the ``best'' system entails weighing the
various factors against each other, and the D.C. Circuit has emphasized
that the EPA has discretion in weighing the factors.178 179
---------------------------------------------------------------------------

    \176\ See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir.
1981).
    \177\ See Sierra Club v. Costle, 657 F.2d at 347.
    \178\ See Lignite Energy Council, 198 F.3d at 933.
    \179\ Although CAA section 111(a)(1) may be read to state that
the factors enumerated in the parenthetical are part of the
``adequately demonstrated'' determination, the D.C. Circuit's case
law may be read to treat them as part of the ``best'' determination.
See Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA
section 111 gives the EPA authority ``when determining the best
technological system to weigh cost, energy, and environmental
impacts''). Nevertheless, it does not appear that those two
approaches would lead to different outcomes. See, e.g., Lignite
Energy Council, 198 F.3d at 933 (rejecting challenge to the EPA's
cost assessment of the ``best demonstrated system''). Regardless of
whether the factors are part of the ``adequately demonstrated''
determination or the ``best'' determination, our analysis and
outcome would be the same.
---------------------------------------------------------------------------

    The EPA's overall approach to determining the BSER and degree of
emission limitation achievable, which incorporates the various
elements, is as follows: The EPA identifies ``system[s] of emission
reduction'' that have been ``adequately demonstrated'' for a particular
source category and determines the ``best'' of these systems after
evaluating the amount of reductions, costs, any nonair health and
environmental impacts, and energy requirements. As discussed below, for
each of numerous subcategories, the EPA followed this approach to
propose the BSER on the basis that the identified costs are reasonable
and that the proposed BSER is rational in light of the statutory
factors and other impacts, including the amount of emission reductions,
that the EPA examined in its BSER analysis, consistent with governing
precedent.
    After determining the BSER, the EPA determines an achievable
emission limit based on application of the BSER.\180\ For a CAA section
111(b) rule, we determine the standard of performance that reflects the
achievable emission limit. For a CAA section 111(d) rule, the States
have the obligation of establishing standards of performance for the
affected sources that reflect the degree of emission limitation that
the EPA has determined. As discussed below, the EPA proposed these
determinations in association with each of the proposed BSER
determinations.
---------------------------------------------------------------------------

    \180\ See, e.g., Oil and Natural Gas Sector: New Source
Performance Standards and National Emission Standards for Hazardous
Air pollutants Reviews (77 FR 49490, 49494; August 16, 2012)
(describing the three-step analysis in setting a standard of
performance).
---------------------------------------------------------------------------

    The remainder of this subsection discusses each element in our
general analytical approach.
a. System of Emission Reduction
    The CAA does not define the phrase ``system of emission
reduction.'' In West Virginia v. EPA, the Supreme Court recognized that
historically, the EPA had looked to ``measures that improve the
pollution performance of individual sources and followed a
``technology-based approach'' in identifying systems of emission
reduction. In particular, the Court identified ``the sort of `systems
of emission reduction' [the EPA] had always before selected,'' which
included `` `efficiency improvements, fuel-switching,' and `add-on
controls'.'' 142 S. Ct. at 2611 (quoting the Clean Power Plan).\181\
Section 111 itself recognizes that such systems may include off-site
activities that may reduce a source's pollution contribution,
identifying ``precombustion cleaning or treatment of fuels'' as a
``system'' of ``emission reduction.'' 42 U.S.C. 7411(a)(7)(B). A
``system of emission reduction'' thus, at a minimum, includes measures
that an individual source applies that improve the emissions
performance of that source. Measures are fairly characterized as
improving the pollution performance of a source where they reduce the
individual source's overall contribution to pollution.
---------------------------------------------------------------------------

    \181\ As noted in section V.B.4 of this preamble, the ACE Rule
adopted the interpretation that CAA section 111(a)(1), by its plain
language, limits ``system of emission reduction'' to those control
measures that could be applied at and to each source to reduce
emissions at each source. 84 FR 32523-24 (July 8, 2019). The EPA has
proposed to reject that interpretation as too narrow. See
``Implementing Regulations under 40 CFR part 60 Subpart Ba Adoption
and Submittal of State Plans for Designated Facilities: Proposed
Rule,'' 87 FR 79176, 79208 (December 23, 2022).
---------------------------------------------------------------------------

    In West Virginia, the Supreme Court did not define the term
``system of emissions reduction,'' and so did not rule on whether
``system of emission reduction'' is limited to those measures that the
EPA has historically relied upon. It did go on to apply the major
questions doctrine to hold that the term ``system'' does not provide
the requisite clear authorization to support the Clean Power Plan's
BSER, which the Court described as ``carbon emissions caps based on a
generation shifting approach.'' Id. at 2614. While the Court did not
define the outer bounds of the meaning of ``system,'' systems of
emissions reduction like fuel switching, add-on controls, and
efficiency improvements fall comfortably within the scope of prior
practice as recognized by the Supreme Court.
b. ``Adequately Demonstrated''
    Under CAA section 111(a)(1), an essential, although not sufficient,
condition for a ``system of emission reduction'' to serve as the basis
for an ``achievable'' emission limitation, is that the Administrator
must determine that the system is ``adequately demonstrated.'' This
means, according to the D.C. Circuit, that the system is ``one which
has been shown to be reasonably reliable, reasonably efficient, and
which can reasonably be expected to serve the interests of pollution
control without becoming exorbitantly costly in an economic or
environmental way.'' \182\ It does not mean that the system ``must be
in actual routine use somewhere.'' \183\ Rather, the court has said,
``[t]he Administrator may make a projection based on existing
technology, though that projection is subject to the restraints of
reasonableness and cannot be based on `crystal ball' inquiry.'' \184\
Similarly, the EPA may ``hold the industry to a standard of improved
design and operational advances, so long as there is substantial
evidence that such improvements are feasible.'' \185\ Ultimately, the
analysis ``is partially dependent on `lead time,' '' that is, ``the
time in which the technology will have to be available.'' \186\ The
caselaw is clear that the EPA may treat a set of control measures as
``adequately demonstrated'' regardless of whether the measures are in
widespread commercial use. For example, the D.C. Circuit upheld the
EPA's determination that selective catalytic reduction (SCR) was
adequately demonstrated to reduce NOX emissions from coal-
fired industrial boilers, even though it was a ``new technology.'' The
court explained that ``section 111 `looks toward what may fairly be
projected for the regulated future, rather than the state of the art at
present.' '' Lignite Energy Council, 198 F.3d at 934 (citing Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)). The
Court added that the EPA may determine that control measures are
``adequately demonstrated'' through a ``reasonable

extrapolation of [the control measures'] performance in other
industries.'' Id.
---------------------------------------------------------------------------

    \182\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C.
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \183\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted) (discussing the Senate and
House bills and reports from which the language in CAA section 111
grew).
    \184\ Ibid.
    \185\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
    \186\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted).
---------------------------------------------------------------------------

    The D.C. Circuit's view that the EPA may determine a ``system of
emission reduction'' to be ``adequately demonstrated'' if the EPA
reasonably projects that it will be available by a future date certain,
is well-grounded in the purposes of CAA section 111 to reduce dangerous
air pollutants. This view recognizes that pollution control systems may
be complex and may require a predictable amount of time for sources
across the source category to be able to design, acquire, install, and
begin to operate them. In some instances, the control technology may be
available, but the installation may be a multi-year process. For
example, an existing coal-fired steam generating unit may require
several years to plan, design, and install a Flue Gas Desulfurization
(FGD) wet scrubber for the control of sulfur dioxide (SO2)
emissions. Under these circumstances, common sense dictates that the
EPA may promulgate a rulemaking that imposes a standard on the sources,
but establishes the date for compliance as a date-certain in the
future, consistent with the period of time the source needs to install
and start operating the control equipment. In other circumstances, a
system of emission reduction may be well-recognized as effective in
controlling pollutants emitted by a large source category, but
manufacturers may require a predictable amount of time to manufacture
enough control equipment to cover the source category. In still other
circumstances, the infrastructure needed to support the system so that
it will cover sources across the category--whether physical
infrastructure such as pipelines or human infrastructure such as
skilled labor to install the equipment--may require a predictable
amount of time to build out or develop in sufficient quantity to
achieve such coverage. In all of these circumstances, adopting
requirements under CAA section 111 at the time that the EPA is able to
reasonably project the future deployment of the system of emission
reduction, and establishing the date of compliance as a date-certain in
the future, serves the statutory purposes of protecting against
dangerous air pollution by ensuring that sources take action to control
their emissions as soon as practicable. It should also be noted that
because pollution control invariably entails additional cost, in some
cases, the EPA's promulgation of regulatory requirements may be an
essential trigger for the sometimes lengthy process of implementing
pollution controls. In these cases, delaying the promulgation of the
regulatory requirements until the pollution controls can be immediately
deployed would be futile.
c. Costs
    Under CAA section 111(a)(1), in determining whether a particular
emission control is the ``best system of emission reduction . . .
adequately demonstrated,'' the EPA is required to take into account
``the cost of achieving [the emission] reduction.'' By its terms, this
provision makes clear that the cost that the EPA must take into account
is the cost to the affected source of the system of emission reduction.
Although the Clean Air Act does not describe how the EPA is to account
for costs, the D.C. Circuit has formulated the cost standard in various
ways.\187\ It has stated that the EPA may not adopt a standard the cost
of which would be ``exorbitant,'' \188\ ``greater than the industry
could bear and survive,'' \189\ ``excessive,'' \190\ or
``unreasonable.'' \191\ These formulations appear to be synonymous, and
for convenience, in these rulemakings, we are treating them as
synonymous with reasonableness as well, so that a control technology
may be considered the ``best system of emission reduction . . .
adequately demonstrated'' if its costs are reasonable, but cannot be
considered the best system if its costs are unreasonable.\192\
---------------------------------------------------------------------------

    \187\ 79 FR 1430, 1464 (January 8, 2014).
    \188\ Lignite Energy Council, 198 F.3d at 933.
    \189\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
    \190\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \191\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \192\ These cost formulations are consistent with the
legislative history of CAA section 111. The 1977 House Committee
Report noted:
    In the [1970] Congress [sic: Congress's] view, it was only right
that the costs of applying best practicable control technology be
considered by the owner of a large new source of pollution as a
normal and proper expense of doing business.
    1977 House Committee Report at 184. Similarly, the 1970 Senate
Committee Report stated:
    The implicit consideration of economic factors in determining
whether technology is ``available'' should not affect the usefulness
of this section. The overriding purpose of this section would be to
prevent new air pollution problems, and toward that end, maximum
feasible control of new sources at the time of their construction is
seen by the committee as the most effective and, in the long run,
the least expensive approach.
    S. Comm. Rep. No. 91-1196 at 16.
---------------------------------------------------------------------------

    The D.C. Circuit has repeatedly upheld the EPA's consideration of
cost in reviewing standards of performance. In several cases, the court
upheld standards that entailed significant costs, consistent with
Congress's view that ``the costs of applying best practicable control
technology be considered by the owner of a large new source of
pollution as a normal and proper expense of doing business.'' \193\ See
Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir.
1973); \194\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 387-88
(D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 298, 313 (D.C. Cir.
1981) (upholding NSPS imposing controls on SO2 emissions
from coal-fired power plants when the ``cost of the new controls . . .
is substantial. EPA estimates that utilities will have to spend tens of
billions of dollars by 1995 on pollution control under the new
NSPS.'').
---------------------------------------------------------------------------

    \193\ 1977 House Committee Report at 184.
    \194\ The costs for these standards were described in the
rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 5769
(March 21, 1972).
---------------------------------------------------------------------------

    In its CAA section 111 rulemakings, the EPA has frequently used a
cost-effectiveness metric, which determines the cost in dollars for
each ton or other quantity of the regulated air pollutant removed
through the system of emission reduction. See, e.g., 81 FR 35824 (June
3, 2016) (NSPS for GHG and VOC emissions for the oil and natural gas
source category); 71 FR 9866, 9870 (February 27, 2006) (NSPS for
NOX, SO2, and PM emissions from fossil fuel-fired
electric utility steam generating units); 61 FR 9905, 9910 (March 12,
1996) (NSPS and emissions guidelines for nonmethane organic compounds
and landfill gas from new and existing municipal solid waste
landfills); 50 FR 40158 (October 1, 1985) (NSPS for SO2
emissions from sweetening and sulfur recovery units in natural gas
processing plants). This metric allows the EPA to compare the amount a
regulation would require sources to pay to reduce a particular
pollutant across regulations and industries. In rules for the electric
power sector, a metric that determines the dollar increase in the cost
of a megawatt hour of electricity generated by the affected sources due
to the emission controls, shows the cost of controls relative to the
output of electricity. See section VII.F.3.b.iii(B)(5) of this
preamble, which discusses $/MWh costs of the March 15, 2023 Good
Neighbor Plan for the 2015 Ozone NAAQS and the Cross-State Air
Pollution Rule (CSAPR) 76 FR 48208 (August 8, 2011). This metric
facilitates comparing costs across regulations and pollutants. In this
proposal, as explained herein, the EPA looks at both of these metrics
to assess the cost reasonableness of the proposed requirements.

d. Non-Air Quality Health and Environmental Impact and Energy
Requirements
    Under CAA section 111(a)(1), the EPA is required to take into
account ``any nonair quality health and environmental impact and energy
requirements'' in determining the BSER. Non-air quality health and
environmental impacts may include the impacts of the disposal of
byproducts of the air pollution controls, or requirements of the air
pollution control equipment for water. Portland Cement Ass'n v.
Ruckelshaus, 465 F.2d 375, 387-88 (D.C. Cir. 1973), cert. denied, 417
U.S. 921 (1974). Energy requirements may include the impact, if any, of
the air pollution controls on the source's own energy needs.
e. Sector or Nationwide Component of Factors in Determining the BSER
    Another component of the D.C. Circuit's interpretations of CAA
section 111 is that the EPA may consider the various factors it is
required to consider on a national or regional level and over time, and
not only on a plant-specific level at the time of the rulemaking.\195\
The D.C. Circuit based this interpretation--which it made in the 1981
Sierra Club v. Costle case regarding the NSPS for new power plants--on
a review of the legislative history, stating,
---------------------------------------------------------------------------

    \195\ See 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club
v. Costle, 657 F.2d at 351).

    [T]he Reports from both Houses on the Senate and House bills
illustrate very clearly that Congress itself was using a long-term
lens with a broad focus on future costs, environmental and energy
effects of different technological systems when it discussed section
111.\196\
---------------------------------------------------------------------------

    \196\ Sierra Club v. Costle, 657 F.2d at 331 (citations omitted)
(citing legislative history).

    The court has upheld EPA rules that the EPA ``justified . . . in
terms of the policies of the Act,'' including balancing long-term
national and regional impacts. For example, the court upheld a standard
of performance for SO2 emissions from new coal-fired power
---------------------------------------------------------------------------
plants on grounds that it--

reflects a balance in environmental, economic, and energy
consideration by being sufficiently stringent to bring about
substantial reductions in SO2 emissions (3 million tons
in 1995) yet does so at reasonable costs without significant energy
penalties. . . .\197\
---------------------------------------------------------------------------

    \197\ Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR
33583-33584; June 11, 1979).

    The EPA interprets this caselaw to authorize it to assess the
impacts of the controls it is considering as the BSER, including their
costs and implications for the energy system, on a sector-wide,
regional, or national basis, as appropriate. For example, the EPA may
assess whether controls it is considering would create risks to the
reliability of the electricity system in a particular area or
nationwide and, if they would, to reject those controls as the BSER.
f. ``Best''
    In determining which adequately demonstrated system of emission
reduction is the ``best,'' the D.C. Circuit has made clear that the EPA
has broad discretion. Specifically, in Sierra Club v. Costle, 657 F.2d
298 (D.C. Cir. 1981), the court explained that ``section 111(a)
explicitly instructs the EPA to balance multiple concerns when
promulgating a NSPS,'' \198\ and emphasized that ``[t]he text gives the
EPA broad discretion to weigh different factors in setting the
standard,'' including the amount of emission reductions, the cost of
the controls, and the non-air quality environmental impacts and energy
requirements.\199\ In Lignite Energy Council v. EPA, 198 F.3d 930 (D.C.
Cir. 1999), the court reiterated:
---------------------------------------------------------------------------

    \198\ Sierra Club v. Costle, 657 F.2d at 319.
    \199\ Sierra Club v. Costle, 657 F.2d at 321; see also New York
v. Reilly, 969 F.2d at 1150 (because Congress did not assign the
specific weight the Administrator should assign to the statutory
elements, ``the Administrator is free to exercise [her] discretion''
in promulgating an NSPS).

    Because section 111 does not set forth the weight that should be
assigned to each of these factors, we have granted the agency a
great degree of discretion in balancing them. . .-. EPA's choice [of
the `best system'] will be sustained unless the environmental or
economic costs of using the technology are exorbitant. . . . EPA
[has] considerable discretion under section 111.\200\
---------------------------------------------------------------------------

    \200\ Lignite Energy Council, 198 F.3d at 933 (paragraphing
revised for convenience). See New York v. Reilly, 969 F.2d 1147,
1150 (D.C. Cir. 1992) (``Because Congress did not assign the
specific weight the Administrator should accord each of these
factors, the Administrator is free to exercise his discretion in
this area.''); see also NRDC v. EPA, 25 F.3d 1063, 1071 (D.C. Cir.
1994) (The EPA did not err in its final balancing because ``neither
RCRA nor EPA's regulations purports to assign any particular weight
to the factors listed in subsection (a)(3). That being the case, the
Administrator was free to emphasize or deemphasize particular
factors, constrained only by the requirements of reasoned agency
decisionmaking.'').

See AEP v. Connecticut, 564 U.S. 410, 427 (2011) (under CAA section
111, ``The appropriate amount of regulation in any particular
greenhouse gas-producing sector cannot be prescribed in a vacuum: . . .
informed assessment of competing interests is required. Along with the
environmental benefit potentially achievable, our Nation's energy needs
and the possibility of economic disruption must weigh in the balance.
The Clean Air Act entrusts such complex balancing to the EPA in the
first instance, in combination with State regulators. Each ``standard
of performance'' the EPA sets must ``tak[e] into account the cost of
achieving [emissions] reduction and any nonair quality health and
environmental impact and energy requirements.'' (paragraphing revised;
citations omitted)).
    Moreover, the D.C. Circuit has also read ``best'' to authorize the
EPA to consider factors in addition to the ones enumerated in CAA
section 111(a)(1), that further the purpose of the statute. In Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 1973), the D.C.
Circuit held that under CAA section 111(a)(1) as it read prior to the
enactment of the 1977 CAA Amendments that added a requirement that the
EPA take account of non-air quality environmental impacts, the EPA must
consider ``counter-productive environmental effects'' in determining
the BSER. Id. at 385. The court elaborated: ``The standard of the `best
system' is comprehensive, and we cannot imagine that Congress intended
that `best' could apply to a system which did more damage to water than
it prevented to air.'' Id., n.42. In Sierra Club v. Costle, 657 F.2d
298, 326, 346-47 (D.C. Cir. 1981), the court added that the EPA must
consider the amount of emission reductions and technology advancement
in determining BSER.
    The court's view that ``best'' includes additional factors that
further the purpose of CAA section 111 is a reasonable interpretation
of that term in its statutory context. The purpose of CAA section 111
is to reduce emissions of air pollutants that endanger public health or
welfare. CAA section 111(b)(1)(A). The court reasonably surmised that
the EPA's determination of whether a system of emission reduction that
reduced certain air pollutants is ``best'' should be informed by
impacts that the system may have on other pollutants that affect public
or welfare. Portland Cement Ass'n, 486 F.2d at 385. The Supreme Court
confirmed the D.C. Circuit's approach in Michigan v. EPA 576 U.S. 743
(2015), explaining that administrative agencies must engage in
``reasoned decisionmaking'' that, in the case of pollution control,
cannot be based on technologies that ``do even more damage to human
health'' than the emissions they eliminate. Id. at 751-52. After
Portland Cement Ass'n, Congress revised CAA section 111(a)(1) to make
explicit that in determining whether a system of emission reduction is
the ``best,'' the EPA should account for non-air quality health and
environmental impacts. By the same token, the EPA

takes the position that in determining whether a system of emission
reduction is the ``best,'' the EPA may account for the impacts of the
system on air pollutants other than the ones that are the subject of
the CAA section 111 regulation.\201\ We discuss immediately below other
factors that the D.C. Circuit has held the EPA should account for in
determining what system is the ``best.''
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    \201\ See generally ``Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Notice of Proposed Rulemaking,'' 87 FR 74702, 74765
(December 6, 2022) (proposing the BSER for reducing methane and VOC
emissions from natural gas-driven controllers in the oil and natural
gas sector on the basis of, among other things, impacts on emissions
of criteria pollutants). In this preamble, for convenience, the EPA
generally discusses the effects of controls on non-GHG air
pollutants along with the effects of controls on non-air quality
health and environmental impacts.
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g. Amount of Emissions Reductions
    Consideration of the amount of emissions from the category of
sources or the amount of emission reductions achieved as factors the
EPA must consider in determining the ``best system of emission
reduction'' is implicit in the plain language of CAA section
111(a)(1)--the EPA must choose the best system of emission reduction.
Indeed, consistent with this plain language and the purpose of CAA
section 111, the D.C. Circuit has stated that the EPA must consider the
quantity of emissions at issue. See Sierra Club v. Costle, 657 F.2d
298, 326 (D.C. Cir. 1981) (``we can think of no sensible interpretation
of the statutory words ``best . . . system'' which would not
incorporate the amount of air pollution as a relevant factor to be
weighed when determining the optimal standard for controlling . . .
emissions'').\202\ The fact that the purpose of a ``system of emission
reduction'' is to reduce emissions, and that the term itself explicitly
incorporates the concept of reducing emissions, supports the court's
view that in determining whether a ``system of emission reduction'' is
the ``best,'' the EPA must consider the amount of emission reductions
that the system would yield. Even if the EPA were not required to
consider the amount of emission reductions, the EPA has the discretion
to do so, on grounds that either the term ``system of emission
reduction'' or the term ``best'' may reasonably be read to allow that
discretion.
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    \202\ Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was
governed by the 1977 CAAA version of the definition of ``standard of
performance,'' which revised the phrase ``best system of emission
reduction'' to read, ``best technological system of continuous
emission reduction.'' As noted above, the 1990 CAAA deleted
``technological'' and ``continuous'' and thereby returned the phrase
to how it read under the 1970 CAAA. The court's interpretation of
the 1977 CAAA phrase in Sierra Club v. Costle to require
consideration of the amount of air emissions focused on the term
``best'', and the terms ``technological'' and ``continuous'' were
irrelevant to its analysis. It thus remains valid for the 1990 CAAA
phrase ``best system of emission reduction.''
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h. Expanded Use and Development of Technology
    The D.C. Circuit has long held that Congress intended for CAA
section 111 to create incentives for new technology and therefore that
the EPA is required to consider technological innovation as one of the
factors in determining the ``best system of emission reduction.'' See
Sierra Club v. Costle, 657 F.2d at 346-47. The court has grounded its
reading in the statutory text of CAA 111(a)(1), defining the term
``standard of performance''.\203\ In addition, the court's
interpretation finds support in the legislative history.\204\ The
legislative history identifies three different ways that Congress
designed CAA section 111 to authorize standards of performance that
promote technological improvement: (1) The development of technology
that may be treated as the ``best system of emission reduction . . .
adequately demonstrated;'' under CAA section 111(a)(1); \205\ (2) the
expanded use of the best demonstrated technology; \206\ and (3) the
development of emerging technology.\207\ Even if the EPA were not
required to consider technological innovation as part of its
determination of the BSER, it would be reasonable for the EPA to
consider it because technological innovation may be considered an
element of the term ``best,'' particularly in light of Congress's
emphasis on technological innovation.
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    \203\ Sierra Club v. Costle, 657 F.2d at 346 (``Our
interpretation of section 111(a) is that the mandated balancing of
cost, energy, and nonair quality health and environmental factors
embraces consideration of technological innovation as part of that
balance. The statutory factors which EPA must weigh are broadly
defined and include within their ambit subfactors such as
technological innovation.'').
    \204\ See S. Rep. No. 91-1196 at 16 (1970) (``Standards of
performance should provide an incentive for industries to work
toward constant improvement in techniques for preventing and
controlling emissions from stationary sources''); S. Rep. No. 95-127
at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 346 n.
174) (``The section 111 Standards of Performance . . . sought to
assure the use of available technology and to stimulate the
development of new technology'').
    \205\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (the best system of emission reduction must ``look[
] toward what may fairly be projected for the regulated future,
rather than the state of the art at present'').
    \206\ 1970 Senate Committee Report No. 91-1196 at 15 (``The
maximum use of available means of preventing and controlling air
pollution is essential to the elimination of new pollution
problems'').
    \207\ Sierra Club v. Costle, 657 F.2d at 351 (upholding a
standard of performance designed to promote the use of an emerging
technology).
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i. Achievability of the Degree of Emission Limitation
    For new sources, CAA section 111(b)(1)(B) and (a)(1) provides that
the EPA must establish ``standards of performance,'' which are
standards for emissions that reflect the degree of emission limitation
that is ``achievable'' through the application of the BSER. According
to the D.C. Circuit, a standard of performance is ``achievable'' if a
technology can reasonably be projected to be available to an individual
source at the time it is constructed that will allow it to meet the
standard.\208\ Moreover, according to the court, ``[a]n achievable
standard is one which is within the realm of the adequately
demonstrated system's efficiency and which, while not at a level that
is purely theoretical or experimental, need not necessarily be
routinely achieved within the industry prior to its adoption.'' \209\
To be achievable, a standard ``must be capable of being met under most
adverse conditions which can reasonably be expected to recur and which
are not or cannot be taken into account in determining the `costs' of
compliance.'' \210\ To show a standard is achievable, the EPA must
``(1) identify variable conditions that might contribute to the amount
of expected emissions, and (2) establish that the test data relied on
by the agency are representative of potential industry-wide
performance, given the range of variables that affect the achievability
of the standard.'' \211\
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    \208\ Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C.
Cir. 1981).
    \209\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34
(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974).
    \210\ Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433, n.46 (D.C.
Cir. 1980).
    \211\ Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981)
(citing Nat'l Lime Ass'n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). In
considering the representativeness of the source tested, the EPA may
consider such variables as the `` `feedstock, operation, size and
age' of the source.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416, 433
(D.C. Cir. 1980). Moreover, it may be sufficient to ``generalize
from a sample of one when one is the only available sample, or when
that one is shown to be representative of the regulated industry
along relevant parameters.'' Nat'l Lime Ass'n v. EPA, 627 F.2d 416,
434, n.52 (D.C. Cir. 1980).
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    Although the D.C. Circuit established these standards for
achievability in cases concerning CAA section 111(b) new source
standards of performance, generally comparable standards for
achievability should apply under CAA section 111(d), although the BSER
may differ as between new and existing sources due to, for example,
higher costs

of retrofit. 40 FR 53340 (November 17, 1975). For existing sources, CAA
section 111(d)(1) requires the EPA to establish requirements for State
plans that, in turn, must include ``standards of performance.'' As the
Supreme Court has recognized, this provision requires the EPA to
promulgate emission guidelines that determine the BSER for a source
category and then identify the degree of emission limitation achievable
by application of the BSER. See West Virginia v. EPA, 142 S. Ct. 2587,
2601-02 (2022).\212\
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    \212\ 40 CFR 60.21(e), 60.21a(e).
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    The EPA has promulgated emission guidelines on the basis that the
existing sources can achieve the degree of emission limitation
described therein, even though under the RULOF provision of CAA section
111(d)(1), the State retains discretion to apply standards of
performance to individual sources that are more or less stringent,
which indicates that Congress recognized that the EPA may promulgate
emission guidelines that are consistent with CAA section 111(d) even
though certain individual sources may not be able to achieve the degree
of emission limitation identified therein by applying the controls that
the EPA determined to be the BSER. Note further that this requirement
that the emission limitation be ``achievable'' based on the ``best
system of emission reduction . . . adequately demonstrated'' indicates
that the technology or other measures that the EPA identifies as the
BSER must be technically feasible.
4. EPA Promulgation of Emission Guidelines for States To Establish
Standards of Performance
    CAA section 111(d)(1) directs the EPA to promulgate regulations
establishing a CAA section 110-like procedure under which States submit
State plans that establish ``standards of performance'' for emissions
of certain air pollutants from sources which, if they were new sources,
would be regulated under CAA section 111(b), and that implement and
enforce those standards of performance. The term ``standard of
performance'' is defined under CAA section 111(a)(1), quoted above.
Thus, CAA sections 111(a)(1) and (d)(1) collectively require the EPA to
determine the BSER for the existing sources and, based on the BSER, to
establish emission guidelines that identify the minimum amount of
emission limitation that a State, in its State plan, must impose on its
existing sources through standards of performance. Consistent with
these CAA requirements, the EPA's regulations require that the EPA's
guidelines reflect--

the degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into account
the cost of such reduction and any non-air quality health and
environmental impact and energy requirements) the Administrator has
determined has been adequately demonstrated from designated
facilities.\213\
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    \213\ 40 CFR 60.21a(e).

    Following the EPA's promulgation of emission guidelines, each State
must determine the standards of performance for its existing sources,
which the EPA's regulations call ``designated facilities.'' \214\ While
the EPA specifies in emission guidelines the degree of emission
limitation achievable through application of the best system of
emission reduction, which it may express as a presumptive standard of
performance, a State retains discretion in applying such a presumptive
standard of performance to any particular designated facility. CAA
section 111(d)(1) requires the EPA's regulations to ``permit the State
in applying a standard of performance to any particular source . . . to
take into consideration, among other factors, the remaining useful life
the . . . source . . . .'' Consistent with this statutory direction,
the EPA's regulations provide requirements for States that wish to
apply standards of performance that deviate from an emission guideline.
In December 2022, the EPA proposed to clarify these requirements,
including the three circumstances under which States can invoke a
particular source's remaining useful life and other factors (RULOF), to
apply a less stringent standard of performance. These proposed
clarifications provided:
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    \214\ 40 CFR 60.21a(b), 60.24a(b).

    The State may apply a standard of performance to a particular
source that is less stringent than otherwise required by an
applicable emission guideline, taking into consideration remaining
useful life and other factors, provided that the State demonstrates
with respect to each such facility (or class of such facilities)
that it cannot reasonably apply the best system of emission
reduction to achieve the degree of emission limitation determined by
the EPA, based on:
    (1) Unreasonable cost of control resulting from plant age,
location, or basic process design;
    (2) Physical impossibility or technical infeasibility of
installing necessary control equipment; or
    (3) Other circumstances specific to the facilities (or class of
facilities) that are fundamentally different from the information
considered in the determination of the best system of emission
reduction in the emission guidelines.

87 FR 79176 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.24a(e)).\215\ In addition, under CAA sections
111(d) and 116, the State is authorized to establish a standard of
performance for any particular source that is more stringent than the
presumptive standards contained in the EPA's emission guidelines.\216\
Thus, for any particular source, a State may apply a standard of
performance that is either more stringent or less stringent than the
presumptive standards of performance in the emission guidelines. The
State must include the standards of performance in their State plans
and submit the plans to the EPA for review.\217\ Under CAA section
111(d)(2)(A), the EPA approves State plans that are determined to be
``satisfactory.''
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    \215\ The EPA intends to finalize the December 2022 proposed
revisions to the CAA section 111 implementation regulations in 40
CFR part 60, subpart Ba, including any changes made in response to
public comments, prior to promulgating these emission guidelines.
Thus, 40 CFR part 60, subpart Ba, as revised, would apply to these
emission guidelines.
    \216\ 40 CFR 60.24a(f). The EPA's December 2022 proposed
revisions to 40 CFR part 60, subpart Ba reflect its current
interpretation that the EPA has the authority to review and approve
plans that include standards of performance that are more stringent
than the presumptive standards in the EPA's emission guidelines,
thus making those more stringent requirements federally enforceable.
87 FR 79204 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.24a(m), (n)). In addition, CAA section 116
authorizes the state to set standards of performance for all of its
sources that, together, are more stringent than the EPA's emission
guidelines.
    \217\ 40 CFR 60.23a. In January 2021, the D.C. Circuit Court of
Appeals vacated the three-year deadline for state plan submissions
of a final emission guideline in 40 CFR 60.23a(a)(1). The EPA's
December 2022 proposed revisions to subpart Ba would revise 60.23a
to, inter alia, provide for a fifteen-month submission deadline. 87
FR 79182 (December 23, 2022), Docket ID No. EPA-HQ-OAR-2021-0527-
0002 (proposed 40 CFR 60.23a(a)).
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IV. Stakeholder Engagement

    Prior to proposing these actions, the EPA conducted outreach to a
broad range of stakeholders. The EPA also opened a non-regulatory pre-
proposal docket to solicit public input on the Agency's efforts to
reduce GHG emissions from new and existing EGUs.\218\ For additional
details on stakeholder engagement, see the memorandum in the docket
titled Stakeholder Outreach.
---------------------------------------------------------------------------

    \218\ Docket ID No. EPA-HQ-OAR-2022-0723.
---------------------------------------------------------------------------

    The EPA conducted two rounds of outreach to gather input for these
proposals. In the first round of outreach, in early 2022, the EPA
sought input in a variety of formats and settings from States, Tribal
nations, and a broad range

of stakeholders on the state of the power sector and how the Agency's
regulatory actions affect those trends. This outreach included State
energy and environmental regulators; Tribal air regulators; power
companies and trade associations representing investor-owned utilities,
rural electric cooperatives, and municipal power agencies;
environmental justice and community organizations; and labor,
environmental, and public health organizations. A second round of
outreach took place in August and September 2022, and focused on
seeking input specific to this rulemaking. The EPA asked to hear
perspectives, priorities, and feedback around five guiding questions,
and encouraged public input to the nonregulatory docket (Docket ID No.
EPA-HQ-OAR-2022-0723) on these questions as well.
    The EPA also regularly interacts with other Federal agencies and
departments whose activities intersect with the power sector, and in
the course of developing these proposed rules the Agency conducted
multiple discussions with these agencies to benefit from their
expertise and to explore the potential interaction of these proposed
rules with their independent missions and initiatives. Among other
things, these discussions focused on the impacts of proposed
investments in energy technology by the Department of Energy and
Department of Treasury on the technical and economic analyses
underlying this proposal. In addition, the EPA evaluated structures in
these proposals to address reliability considerations with the
Department of Energy.

VII. Proposed Requirements for New and Reconstructed Stationary
Combustion Turbine EGUs and Rationale for Proposed Requirements

A. Overview

    This section discusses and proposes requirements for stationary
combustion turbine EGUs that commence construction or reconstruction
after the date of publication of this proposed action. The EPA is
proposing that those requirements will be codified in 40 CFR part 60,
subpart TTTTa. The EPA explains in section VII.B the two basic turbine
technologies in use in the power sector and covered by 40 CFR part 60,
subpart TTTT, simple cycle turbines and combined cycle turbines. It
further explains how these technologies are used in the three
subcategories of low load turbines, intermediate load turbines, and
base load turbines. Section VII.C provides an overview of how
stationary combustion turbines have been previously regulated and how
the EPA recently took comment on a proposed white paper on GHG
mitigation options for stationary combustion turbines. Section VII.D
discusses the EPA's decision to revisit the standards for turbines as
part of the statutorily required 8-year review. Section VII.E discusses
changes that the EPA is proposing in both applicability and
subcategories in the new proposed 40 CFR part 60, subpart TTTTa as
compared to those codified in 40 CFR part 60, subpart TTTT. Most
notably, for natural gas-fired combustion turbines, the EPA is
proposing three subcategories, a low load subcategory, an intermediate
load subcategory, and a base load subcategory.
    Section VII.F discusses the EPA's determination of the BSER for
each of the subcategories of turbines. For low load combustion
turbines, the EPA continues to believe that use of lower emitting fuels
is the appropriate BSER. For intermediate load turbines, the EPA
believes that both highly efficient generation and co-firing low-GHG
hydrogen are appropriate components of the BSER, and that there will be
enough low-GHG hydrogen at a reasonable price to supply the combustion
turbines that would need to use it in 2032. For this reason, the EPA is
proposing a two-component BSER for intermediate load combustion
turbines, and a two-phase standard of performance. The first component
of the BSER would be highly efficient generation (based on the
performance of a highly efficient simple cycle turbine), with a
corresponding first-phase standard of performance. The second component
of the BSER is co-firing 30 percent (by volume) low-GHG hydrogen, along
with continued use of highly efficient generation, with a corresponding
second-phase standard of performance. The EPA is also soliciting
comment on whether intermediate load combustion turbines should be
subject to a more stringent third-phase standard based on higher levels
of low-GHG hydrogen co-firing by 2038. Additionally, the EPA is
soliciting comment on whether the electric sales threshold used to
define intermediate and base load units should be reduced further.
    For base load turbines, the EPA likewise believes that the BSER
includes multiple components that correspond to a multi-phase standard
of performance. This is appropriate based on consideration of the
manufacturing and installation capabilities within the larger EGU
category and other industries, and considerations of projected
operation of combustion turbines in the future. For base load turbines,
the EPA is proposing two BSER pathways with corresponding standards of
performance that new and reconstructed stationary combustion turbines
may take--one BSER pathway is based on the use of 90 percent CCS and a
separate BSER pathway is based on co-firing low-GHG hydrogen. The EPA
proposes that the first component of the BSER for both pathways is
highly efficient generation (based on the performance of a highly
efficient combined cycle unit) and the second component of the BSER is
based on the use of either 90 percent CCS in 2035 or co-firing 30
percent (by volume) low-GHG hydrogen in 2032, along with continued use
of highly efficient generation for both pathways. For base load
turbines that are subject to a second phase standard of performance
based on a highly efficient combined cycle unit co-firing 30 percent
(by volume) low-GHG hydrogen, the EPA proposes that those units also
meet a third phase component of the BSER based on the co-firing of 96
percent (by volume) low-GHG hydrogen by 2038. These two BSER pathways
both offer significant opportunities to reduce GHG emissions even
though they may be available on slightly different timescales. The EPA
seeks comment specifically on the percentages of hydrogen co-firing and
CO2 capture, the dates that meet the statutory BSER criteria
for each pathway, whether the Agency should finalize both pathways as
separate subcategories with separate standards of performance, or
whether it should finalize one pathway with the option of meeting the
standard of performance using either system of emission reduction--
e.g., a single standard of 90 lb CO2/MWh-gross based on the
application of CCS with 90 percent capture, which could also be met by
co-firing 96 percent low-GHG hydrogen.
    For both intermediate load and base load turbines, the standards of
performance corresponding to both components of the BSER would apply to
all new and reconstructed sources that commence construction or
reconstruction after the publication date of this proposal. The EPA
occasionally refers to these standards of performance as the phase-1,
phase-2, or phase-3 standards.

B. Combustion Turbine Technology

    For purposes of 40 CFR part 60, subparts TTTT and TTTTa, stationary
combustion turbines include both simple cycle and combined cycle EGUs.
Simple cycle turbines operate in the Brayton thermodynamic cycle and
include three primary components: a

multistage compressor, a combustion chamber (i.e., combustor), and a
turbine. The compressor is used to supply large volumes of high-
pressure air to the combustion chamber. The combustion chamber converts
fuel to heat and expands the now heated, compressed air to create shaft
work. The shaft work drives an electric generator to produce
electricity. Combustion turbines that recover their high-temperature
exhaust--instead of venting it directly to the atmosphere--are combined
cycle EGUs and can obtain additional useful electric output. A combined
cycle EGU includes a heat recovery steam generator (HRSG) operating in
the Rankine thermodynamic cycle. The HRSG receives the high-temperature
exhaust and converts the heat to mechanical energy by producing steam
that is then fed into a steam turbine that, in turn, drives a second
electric generator. As the thermal efficiency of a stationary
combustion turbine EGU is increased, less fuel is burned to produce the
same amount of electricity, with a corresponding decrease in fuel costs
and lower emissions of CO2 and, generally, of other air
pollutants. The greater the output of electric energy for a given
amount of fuel energy input, the higher the efficiency of the electric
generation process.
    Combustion turbines serve various roles in the power sector. Some
combustion turbines operate at low annual capacity factors and are
available to provide temporary power during periods of high load
demand. These turbines are often referred to as ``peaking units.'' Some
combustion turbines operate at intermediate annual capacity factors and
are often referred to as cycling or load-following units. Other
combustion turbines operate at high annual capacity factors to serve
base load demand and are often referred to as base load units. In this
proposal, the EPA refers to these types of combustion turbines as low
load, intermediate load, and base load, respectively.
    Low load combustion turbines provide reserve capacity, support grid
reliability, and generally provide power during periods of peak
electric demand. As such, the units may operate at or near their full
capacity, but only for short periods, as needed. Because these units
only operate occasionally, capital expenses are a major factor in the
overall cost of electricity, and often, the lowest capital cost (and
generally less efficient) simple cycle EGUs are intended for use only
during periods of peak electric demand. Due to their low efficiency,
these units require more fuel per MWh of electricity produced and their
operating costs tend to be higher. Because of the higher operating
costs, they are generally some of the last units in the dispatch order.
Important characteristics for low load combustion turbines include
their low capital costs, their ability to start and quickly ramp to
full load, and their ability to operate at partial loads while
maintaining acceptable emission rates and efficiencies. The ability to
start and quickly attain full load is important to maximize revenue
during periods of peak electric prices and to meet sudden shifts in
demand. In contrast, under steady-state conditions, more efficient
combined cycle EGUs are dispatched ahead of low load turbines and often
operate at higher capacity factors.
    Highly efficient simple cycle turbines and fast-start combined
cycle turbines both offer different advantages and disadvantages when
operating at intermediate loads. One of the roles of these intermediate
or load-following EGUs is to provide dispatchable backup power to
support variable renewable generating sources. A developer's decision
of whether to build a simple cycle combustion turbine or a combined
cycle combustion turbine to serve intermediate load demand would be
based on several factors related to the intended operation of the unit.
These factors include how frequently the unit is expected to cycle
between starts and stops, the predominant load level at which the unit
is expected to operate, and whether this level of operation is expected
to remain consistent or is expected to vary over the lifetime of the
unit. While the owner/operator of an individual combustion turbine
controls whether and how that unit will operate over time, they do not
necessarily control the precise timing of dispatch for the unit in any
given day or hour. Such short-term dispatch decisions are often made by
regional grid operators that determine, on a moment-to-moment basis,
which available individual units should operate to balance supply and
demand and other requirements in an optimal manner, based on operating
costs, price bids, and/or operational characteristics. However,
operating permits for simple cycle turbines often contain restrictions
on the annual hours of operation that owners/operators incorporate into
longer term operating plans and short-term dispatch decisions.
    Intermediate load combustion turbines vary their generation,
especially during transition periods between low and high electric
demand. Both high-efficiency simple cycle combustion turbines and fast-
start combined cycle combustion turbines can fill this cycling role.
While the ability to start and quickly ramp is important, efficiency is
also an important characteristic. These combustion turbines generally
have higher capital costs than low load combustion turbines but are
generally less expensive to operate.
    Base load combustion turbines are designed to operate for extended
periods at high loads with infrequent starts and stops. Quick start
capability and low capital costs are less important than low operating
costs. High-efficiency combined cycle combustion turbines typically
fill the role of base load combustion turbines.
    The increase in generation from variable renewable energy sources
during the past decade has impacted the way in which firm dispatchable
generating resources operate.\219\ For example, the electric output
from wind and solar generating sources fluctuates daily and seasonally
due to increases and decreases in the wind speed or solar intensity.
Due to this variable nature of wind and solar, firm dispatchable
electric generating units are used to ensure the reliability of the
electric grid. This requires technologies such as dispatchable power
plants to start and stop and change load more frequently than was
previously needed. Important characteristics of combustion turbines
that provide firm backup capacity are the ability to start and stop
quickly and the ability to quickly change loads. Natural gas-fired
combustion turbines are much more flexible than coal-fired utility
boilers in this regard and have played an important role in ensuring
electric supply and demand are in balance during the past decade.
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    \219\ Dispatchable EGUs can be turned on and off and adjust the
amount of power supplied to the electric grid based on the demand
for electricity. Variable (sometimes referred to as intermittent)
EGUs supply electricity based on external factors that are not
controlled by the owner/operator of the EGU.
---------------------------------------------------------------------------

    As discussed in section IV.F.2 of this preamble and in the
accompanying RIA, the post-IRA 2022 reference case projects that
natural gas-fired combustion turbines will continue to play an
important role in meeting electricity demand. However, that role is
projected to evolve as additional renewable and non-renewable low-GHG
generation and energy storage technologies are added to the grid.
Energy storage technologies can store energy during periods when
generation from renewable resources is high relative to demand and
provide electricity to the grid during other periods. This could reduce
the need for fossil fuel-fired firm dispatchable power plants to start
and stop as frequently. Consequently, in the future, natural gas-

fired stationary combustion turbine EGUs may run at more stable
operation and, thus, more efficiently (i.e., at higher duty cycles and
for longer periods of operation per start). The EPA is soliciting
comment on whether this a likely scenario.

C. Overview of Regulation of Stationary Combustion Turbines for GHGs

    As explained earlier in this preamble, the EPA originally regulated
stationary combustion turbine EGUs for emissions of GHGs in 2015 under
40 CFR part 60, subpart TTTT. In 40 CFR part 60, subpart TTTT, the EPA
created three subcategories, two for natural gas-fired combustion
turbines and one for multi-fuel-fired combustion turbines. For natural
gas-fired turbines, the EPA created a subcategory for base load
turbines and a separate subcategory for non-base load turbines. Base
load turbines were defined as combustion turbines with electric sales
greater than a site-specific electric sales threshold that is based on
the design efficiency of the combustion turbine. Non-base load turbines
were defined as combustion turbines with a capacity factor less than or
equal to the site-specific electric sales threshold. For base load
turbines, the EPA set a standard of 1,000 lb CO2/MWh-gross
based on efficient combined cycle turbine technology and for non-base
load and multi-fuel-fired turbines, the EPA set a standard based on the
use of lower emitting fuels that varied from 120 lb CO2/
MMBtu to 160 lb CO2/MMBtu depending upon whether the turbine
burned primarily natural gas or other lower emitting fuels.
    On April 21, 2022, the EPA issued an informational draft white
paper, titled Available and Emerging Technologies for Reducing
Greenhouse Gas Emissions from Combustion Turbine Electric Generating
Units.\220\ The draft document included discussion of the basic types
of available stationary combustion turbines as well as factors that
influence GHG emission rates from these sources. The technology
discussion in the draft white paper included information on an array of
new and existing control technologies and potential reduction measures
for GHG emissions. These reduction measures included: the GHG reduction
potential of various efficiency improvements; technologies capable of
firing or co-firing alternative fuels such as hydrogen; the ongoing
advancement of CCS projects with NGCC units; and the co-location of
technologies that do not emit onsite GHG emissions with EGUs, such as
onsite renewables or short-duration energy storage.
---------------------------------------------------------------------------

    \220\ https://www.epa.gov/stationary-sources-air-pollution/white-paper-available-and-emerging-technologies-reducing.
---------------------------------------------------------------------------

    The EPA provided an opportunity for the public to comment on this
white paper to inform its approach to this proposed rulemaking. More
than 30 groups or individuals provided public comments on the topics
and technologies discussed in the draft white paper. Commenters
included representatives from utilities, technology providers, trade
associations, States, regulatory agencies, NGOs, and public health
advocates. The information provided in the public comments was
beneficial in enabling the EPA to review the current NSPS for new
stationary combustion turbines and to develop the proposed revisions
described in this preamble.

D. Eight-Year Review of NSPS

    CAA section 111(b)(1)(B) requires the Administrator to ``at least
every 8 years, review and, if appropriate, revise [the NSPS] . . .''
The provision further provides that ``the Administrator need not review
any such standard if the Administrator determines that such review is
not appropriate in light of readily available information on the
efficacy of such [NSPS].''
    The EPA promulgated the NSPS for GHG emissions for stationary
combustion turbines in 2015. Announcements and modeling projections
show companies are building new fossil fuel-fired combustion turbines
and plan to continue building additional capacity. Because the
emissions from this capacity have the potential to be large and these
units are likely to have long lives (25 years or more), the EPA
believes it is important to consider options to reduce emissions from
these new units. In addition, the EPA is aware of developments
concerning the types of control measures that may be available to
reduce GHG emissions from new stationary combustion turbines.
Accordingly, the EPA is proceeding to review and is proposing updated
NSPS for newly constructed and reconstructed fossil fuel-fired
stationary combustion turbines.

E. Applicability Requirements and Subcategorization

    This section describes the proposed amendments to the specific
applicability criteria for non-fossil fuel-fired EGUs, industrial EGUs,
CHP EGUs, and combustion turbines EGUs not connected to a natural gas
pipeline. The EPA is also proposing certain changes to the
applicability requirements for stationary combustion turbines affected
by this proposal as compared to those for sources affected by the 2015
NSPS. The proposed changes are described below and include the
elimination of the multi-fuel-fired subcategory, further binning non-
base load combustion turbines into low and intermediate load
subcategories, and lowering the electric sales threshold for base load
combustion turbines.
1. Applicability Requirements
    In general, the EPA refers to fossil fuel-fired EGUs that would be
subject to a CAA section 111 NSPS as ``affected'' EGUs or units. An EGU
is any fossil fuel-fired electric utility steam generating unit (i.e.,
a utility boiler or IGCC unit) or stationary combustion turbine (in
either simple cycle or combined cycle configuration). To be considered
an affected EGU under the current NSPS at 40 CFR part 60, subpart TTTT,
the unit must meet the following applicability criteria: The unit must:
(1) Be capable of combusting more than 250 million British thermal
units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of heat input
of fossil fuel (either alone or in combination with any other fuel);
and (2) serve a generator capable of supplying more than 25 MW net to a
utility distribution system (i.e., for sale to the grid).\221\ However,
40 CFR part 60, subpart TTTT includes applicability exemptions for
certain EGUs, including: (1) Non-fossil fuel-fired units subject to a
federally enforceable permit that limits the use of fossil fuels to 10
percent or less of their heat input capacity on an annual basis; (2)
CHP units that are subject to a federally enforceable permit limiting
annual net electric sales to no more than either the unit's design
efficiency multiplied by its potential electric output, or 219,000
megawatt-hours (MWh), whichever is greater; (3) stationary combustion
turbines that are not physically capable of combusting natural gas
(e.g., those that are not connected to a natural gas pipeline); (4)
utility boilers and IGCC units that have always been subject to a
federally enforceable permit limiting annual net electric sales to one-
third or less of their potential electric output (e.g., limiting hours
of operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less; (5) municipal waste combustors
that are subject to 40 CFR part 60, subpart Eb; (6) commercial or
industrial solid waste incineration units subject to 40 CFR part 60,
subpart CCCC; and (7)

certain projects under development, as discussed below.
---------------------------------------------------------------------------

    \221\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------

a. Revisions to 40 CFR Part 60, Subpart TTTT
    The EPA is proposing to amend 40 CFR 60.5508 and 60.5509 to reflect
that 40 CFR part 60, subpart TTTT will remain applicable to steam
generating EGUs and IGCC units constructed after January 8, 2014 or
reconstructed after June 18, 2014. The EPA is also proposing that
stationary combustion turbines that commenced construction after
January 8, 2014 or reconstruction after June 18, 2014 and before May
23, 2023 that meet the relevant applicability criteria would be subject
to 40 CFR part 60, subpart TTTT. Upon promulgation of 40 CFR part 60,
subpart TTTTa, stationary combustion turbines that commence
construction or reconstruction after May 23, 2023 and meet the relevant
applicability criteria will be subject to 40 CFR part 60, subpart
TTTTa.
b. Revisions to 40 CFR Part 60, Subpart TTTT That Would Also Be
Included in 40 CFR Part 60, Subpart TTTTa
    The EPA is proposing that 40 CFR part 60, subpart TTTT and 40 CFR
part 60, subpart TTTTa use similar regulatory text except where
specifically stated. This section describes proposed amendments that
would be included in both subparts.
i. Applicability to Non-Fossil Fuel-Fired EGUs
    The current non-fossil applicability exemption in 40 CFR part 60,
subpart TTTT is based strictly on the combustion of non-fossil fuels
(e.g., biomass). To be considered a non-fossil fuel-fired EGU, the EGU
must both (1) Be capable of combusting more than 50 percent non-fossil
fuel and (2) be subject to a federally enforceable permit condition
limiting the annual capacity factor for all fossil fuels combined of 10
percent (0.10) or less. The current language does not take heat input
from non-combustion sources (e.g., solar thermal) into account. Certain
solar thermal installations have natural gas backup burners larger than
250 MMBtu/h. As currently written, these solar thermal installations
would not be eligible to be considered non-fossil units because they
are not capable of deriving more than 50 percent of their heat input
from the combustion of non-fossil fuels. Therefore, solar thermal
installations that include backup burners could meet the applicability
criteria of 40 CFR part 60, subpart TTTT even if the burners are
limited to an annual capacity factor of 10 percent or less. These EGUs
would readily comply with the standard of performance, but the
reporting and recordkeeping would increase costs for these EGUs.
    The EPA is proposing several amendments to align the applicability
criteria with the original intent to cover only fossil fuel-fired EGUs.
This would ensure that solar thermal EGUs with natural gas backup
burners, like other types of non-fossil fuel-fired units in which most
of their energy is derived from non-fossil fuel sources, are not
subject to the requirements of 40 CFR part 60, subparts TTTT or TTTTa.
Amending the applicability language to include heat input derived from
non-combustion sources would allow these facilities to avoid the
requirements of 40 CFR part 60, subparts TTTT or TTTTa by limiting the
use of the natural gas burners to less than 10 percent of the capacity
factor of the backup burners. Specifically, the EPA is proposing to
amend the definition of non-fossil fuel-fired EGUs from EGUs capable of
``combusting 50 percent or more non-fossil fuel'' to EGUs capable of
``deriving 50 percent or more of the heat input from non-fossil fuel at
the base load rating.'' (emphasis added). The definition of base load
rating would also be amended to include the heat input from non-
combustion sources (e.g., solar thermal).
    The proposed amended non-fossil fuel applicability language
changing ``combusting'' to ``deriving'' will ensure that 40 CFR part
60, subparts TTTT and TTTTa cover the fossil fuel-fired EGUs, properly
understood, that the original rule was intended to cover, while
minimizing unnecessary costs to EGUs fueled primarily by steam
generated without combustion (e.g., through the use of solar thermal).
The corresponding change in the base load rating to include the heat
input from non-combustion sources is necessary to determine the
relative heat input from fossil fuel and non-fossil fuel sources.
ii. Industrial EGUs
(A) Applicability to Industrial EGUs
    In simple terms, the current applicability provisions in 40 CFR
part 60, subpart TTTT require that an EGU be capable of combusting more
than 250 MMBtu/h of fossil fuel and be capable of selling 25 MW to a
utility distribution system to be subject to 40 CFR part 60, subpart
TTTT. These applicability provisions exclude industrial EGUs. However,
the definition of an EGU also includes ``integrated equipment that
provides electricity or useful thermal output.'' This language
facilitates the integration of non-emitting generation and avoids
energy inputs from non-affected facilities being used in the emission
calculation without also considering the emissions of those facilities
(e.g., an auxiliary boiler providing steam to a primary boiler). This
language could result in certain large processes being included as part
of the EGU and meeting the applicability criteria. For example, the
high-temperature exhaust from an industrial process (e.g., calcining
kilns, dryer, metals processing, or carbon black production facilities)
that consumes fossil fuel could be sent to a HRSG to produce
electricity. If the industrial process is more than 250 MMBtu/h heat
input and the electric sales exceed the applicability criteria, then
the unit could be subject to 40 CFR part 60, subparts TTTT or TTTTa.
This is potentially problematic for multiple reasons. First, it is
difficult to determine the useful output of the EGU (i.e., HRSG) since
part of the useful output is included in the industrial process. In
addition, the fossil fuel that is combusted might have a relatively
high CO2 emissions rate on a lb/MMBtu basis, making it
potentially problematic to meet the standard of performance using
efficient generation. This could result in the owner/operator reducing
the electric output of the industrial facility to avoid the
applicability criteria. Finally, the compliance costs associated with
40 CFR part 60, subparts TTTT or TTTTa could discourage the development
of environmentally beneficial projects.
    To avoid these outcomes, the EPA is proposing to amend the
applicability provision that exempts EGUs where greater than 50 percent
of the heat input is derived from an industrial process that does not
produce any electrical or mechanical output or useful thermal output
that is used outside the affected EGU.\222\ Reducing the output or not
developing industrial electric generating projects where the majority
of the heat input is derived from the industrial process itself would
not necessarily result in reductions in GHG emissions from the
industrial facility. However, the electricity that would have been
produced from the industrial project could still be needed. Therefore,
projects of this type provide significant environmental benefit with
little if any additional emissions. Including these types of projects
would result in regulatory burden without any

associated environmental benefit and could discourage project
development, leading to potential overall increases in GHG emissions.
---------------------------------------------------------------------------

    \222\ Auxiliary equipment such as boilers or combustion turbines
that provide heat or electricity to the primary EGU (including to
any control equipment) would still be considered integrated
equipment and included as part of the affected facility.
---------------------------------------------------------------------------

(B) Industrial EGUs Electric Sales Threshold Permit Requirement
    The current electric sales applicability exemption in 40 CFR part
60, subpart TTTT for non-CHP steam generating units includes the
provision that EGUs have ``always been subject to a federally
enforceable permit limiting annual net electric sales to one-third or
less of their potential electric output (e.g., limiting hours of
operation to less than 2,920 hours annually) or limiting annual
electric sales to 219,000 MWh or less'' (emphasis added). The
justification for this restriction includes that the 40 CFR part 60,
subpart Da applicability language includes ``constructed for the
purpose of . . .'' and the Agency concluded that the intent was defined
by permit conditions (80 FR 64544; October 23, 2015). This
applicability criterion is important for determining applicability with
both the new source CAA section 111(b) requirements and if existing
steam generating units are subject to the existing source CAA section
111(d) requirements. For steam generating units that commenced
construction after September 18, 1978, the applicability of 40 CFR part
60, subpart Da, would be relatively clear by what criteria pollutant
NSPS is applicable to the facility. However, for steam generating units
that commenced construction prior to September 18, 1978, or where the
owner/operator determined that criteria pollutant NSPS applicability
was not critical to the project (e.g., emission controls were
sufficient to comply with either the EGU or industrial boiler criteria
pollutant NSPS), owners/operators might not have requested an electric
sales permit restriction be included in the operating permit. Under the
current applicability language, some onsite EGUs could be covered by
the existing source CAA section 111(d) requirements even if they have
never sold electricity to the grid. To avoid covering these industrial
EGUs, the EPA is proposing to amend the electric sales exemption in 40
CFR part 60, subparts TTTT and TTTTa to read, ``annual net-electric
sales have never exceeded one-third of its potential electric output or
219,000 MWh, whichever is greater, and is'' (the ``always been'' would
be deleted) subject to a federally enforceable permit limiting annual
net electric sales to one-third or less of their potential electric
output (e.g., limiting hours of operation to less than 2,920 hours
annually) or limiting annual electric sales to 219,000 MWh or less''
(emphasis added). EGUs that reduce current generation would continue to
be covered as long as they sold more than one-third of their potential
electric output at some time in the past. The proposed revisions would
simply make it possible for an owner/operator of an existing industrial
EGU to provide evidence to the Administrator that the facility has
never sold electricity in excess of the electricity sales threshold and
to modify their permit to limit sales in the future. Without the
amendment, owners/operators of any non-CHP industrial EGU capable of
selling 25 MW would be subject to the existing source CAA section
111(d) requirements even if they have never sold any electricity.
Therefore, the EPA is proposing the exemption to eliminate the
requirement that existing industrial EGUs must have always been subject
to a permit restriction limiting net electric sales.
iii. Determination of the Design Efficiency
    The design efficiency (i.e., the efficiency of converting thermal
energy to useful energy output) of a combustion turbine is used to
determine the electric sales applicability threshold and is relevant to
both new and existing EGUs.\223\ The sales criteria are based in part
on the individual EGU design efficiency. Three methods for determining
the design efficiency are currently provided in 40 CFR part 60, subpart
TTTT.\224\ Since the 2015 NSPS was finalized, the EPA has become aware
that owners/operators of certain existing EGUs do not have records of
the original design efficiency. These units are not able to readily
determine whether they meet the applicability criteria and are
therefore subject to the CAA section 111(d) requirements for existing
sources in the same way that 111(b) sources would be able to determine
if the facility meets the applicability criteria. Many of these EGUs
are CHP units and it is likely they do not meet the applicability
criteria. However, the language in the 2015 NSPS would require them to
conduct additional testing to demonstrate this. The requirement would
result in burden to the regulated community without any environmental
benefit. The electricity generating market has changed, in some cases
dramatically, during the lifetime of existing EGUs, especially
concerning ownership. As a result of acquisitions and mergers, original
EGU design efficiency documentation as well as performance guarantee
results that affirmed the design efficiency, may no longer exist.
Moreover, such documentation and results may not be relevant for
current EGU efficiencies, as changes to original EGU configurations,
upon which the original design efficiencies were based, render those
original design efficiencies moot, meaning that there would be little
reason to maintain former design efficiency documentation since it
would not comport with the efficiency associated with current EGU
configurations. As the three specified methods would rely on
documentation from the original EGU configuration performance guarantee
testing, and results from that documentation may no longer exist or be
relevant, it is appropriate to allow other means to demonstrate EGU
design efficiency. To reduce compliance burden, the EPA is proposing in
40 CFR part 60, subparts TTTT and TTTTa to allow alternative methods as
approved by the Administrator on a case-by-case basis. Owners/operators
of EGUs would petition the Administrator in writing to use an alternate
method to determine the design efficiency. The Administrator's
discretion is intentionally left broad and could extend to other
American Society of Mechanical Engineers (ASME) or International
Organization for Standardization (ISO) methods as well as to operating
data to demonstrate the design efficiency of the EGU. The EPA is also
proposing to change the applicability of paragraph 60.8(b) in table 3
of 40 CFR part 60, subpart TTTT from ``no'' to ``yes'' and that the
applicability of paragraph 60.8(b) in table 3 of 40 CFR part 60,
subpart TTTTa is ``yes.'' This would allow the Administrator to approve
alternatives to the test methods specified in 40 CFR part 60, subparts
TTTT and TTTTa.
---------------------------------------------------------------------------

    \223\ While the EPA could specifically allow different methods
to determine the design efficiency in the 111(d) existing source
emission guidelines, the Agency is proposing to align the criteria
for regulatory clarity.
    \224\ 40 CFR part 60, subpart TTTT currently lists ASME PTC 22
Gas Turbines, ASME PTC 46 Overall Plant Performance, and ISO 2314
Gas turbines acceptance tests as approved methods to determine the
design efficiency.
---------------------------------------------------------------------------

c. Applicability for 40 CFR Part 60, Subpart TTTTa
    This section describes proposed amendments that would only be
incorporated into 40 CFR part 60, subpart TTTTa and would differ from
the requirements in 40 CFR part 60, subpart TTTT.
i. Proposed Applicability
    Section 111 of the CAA defines a new or modified source for
purposes of a given NSPS as any stationary source

that commences construction or modification after the publication of
the proposed regulation. Thus, any standards of performance the Agency
finalizes as part of this rulemaking will apply to EGUs that commence
construction or reconstruction after the date of this proposal. EGUs
that commenced construction after the date of the proposal for the 2015
NSPS and by the date of this proposal will remain subject to the
standards of performance promulgated in the 2015 NSPS. A modification
is any physical change in, or change in the method of operation of, an
existing source that increases the amount of any air pollutant emitted
to which a standard applies.\225\ The NSPS General Provisions (40 CFR
part 60, subpart A) provide that an existing source is considered a new
source if it undertakes a reconstruction.\226\
---------------------------------------------------------------------------

    \225\ 40 CFR 60.2.
    \226\ 40 CFR 60.15(a).
---------------------------------------------------------------------------

    The EPA is proposing the same applicability requirements in 40 CFR
part 60, subpart TTTTa as the applicability requirements in 40 CFR part
60, subpart TTTT. The stationary combustion turbine must meet the
following applicability criteria: The stationary combustion turbine
must: (1) Be capable of combusting more than 250 million British
thermal units per hour (MMBtu/h) (260 gigajoules per hour (GJ/h)) of
heat input of fossil fuel (either alone or in combination with any
other fuel); and (2) serve a generator capable of supplying more than
25 MW net to a utility distribution system (i.e., for sale to the
grid).\227\ In addition, the EPA is proposing in 40 CFR part 60,
subpart TTTTa to include applicability exemptions for stationary
combustion turbines that are: (1) Capable of deriving 50 percent or
more of the heat input from non-fossil fuel at the base load rating and
subject to a federally enforceable permit condition limiting the annual
capacity factor for all fossil fuels combined of 10 percent (0.10) or
less; (2) combined heat and power units subject to a federally
enforceable permit condition limiting annual net-electric sales to no
more than 219,000 MWh or the product of the design efficiency and the
potential electric output, whichever is greater; (3) serving a
generator along with other steam generating unit(s), IGCC, or
stationary combustion turbine(s) where the effective generation
capacity is 25 MW or less; (4) municipal waste combustors that are
subject to 40 CFR part 60, subpart Eb; (5) commercial or industrial
solid waste incineration units subject to 40 CFR part 60, subpart CCCC;
and (6) deriving greater than 50 percent of heat input from an
industrial process that does not produce any electrical or mechanical
output that is used outside the affected stationary combustion turbine.
---------------------------------------------------------------------------

    \227\ The EPA refers to the capability to combust 250 MMBtu/h of
fossil fuel as the ``base load rating criterion.'' Note that 250
MMBtu/h is equivalent to 73 MW or 260 GJ/h heat input.
---------------------------------------------------------------------------

    The EPA is proposing to apply the same requirements to combustion
turbines in non-continental areas (i.e., Hawaii, the Virgin Islands,
Guam, American Samoa, the Commonwealth of Puerto Rico, and the Northern
Mariana Islands) and non-contiguous areas (non-continental areas and
Alaska) as the EPA is proposing for comparable units in the contiguous
48 States. However, new units in non-continental and non-contiguous
areas may operate on small, isolated electric grids, may operate
differently from units in the contiguous 48 States, and may have
limited access to certain components of the proposed BSER due to their
uniquely isolated geography or infrastructure. Therefore, the EPA is
soliciting comment on whether combustion turbines in non-continental
and non-contiguous areas should be subject to different requirements.
ii. Applicability to CHP Units
    For 40 CFR part 60, subpart TTTT, owner/operators of CHP units
calculate net electric sales and net energy output using an approach
that includes ``at least 20.0 percent of the total gross or net energy
output consists of electric or direct mechanical output.'' It is
unlikely that a CHP unit with a relatively low electric output (i.e.,
less than 20.0 percent) would meet the applicability criteria. However,
if a CHP unit with less than 20.0 percent of the total output
consisting of electricity were to meet the applicability criteria, the
net electric sales and net energy output would be calculated the same
as for a traditional non-CHP EGU. Even so, it is not clear that these
CHP units would have less environmental benefit per unit of electricity
produced than more traditional CHP units. For 40 CFR part 60, subpart
TTTTa, the EPA is proposing to eliminate the restriction that CHP units
produce at least 20.0 percent electrical or mechanical output to
qualify for the CHP-specific method for calculating net electric sales
and net energy output.
    In the 2015 NSPS, the EPA did not issue standards of performance
for certain types of sources--including industrial CHP units and CHPs
that are subject to a federally enforceable permit limiting annual net
electric sales to no more than the unit's design efficiency multiplied
by its potential electric output, or 219,000 MWh or less, whichever is
greater. For CHP units, the approach in 40 CFR part 60, subpart TTTT
for determining net electric sales for applicability purposes allows
the owner/operator to subtract the purchased power of the thermal host
facility. The intent of the approach is to determine applicability
similarly for third-party developers and CHP units owned by the thermal
host facility.\228\ However, as written in 40 CFR part 60, subpart
TTTT, each third-party CHP unit would subtract the entire electricity
use of the thermal host facility when determining its net electric
sales. It is clearly not the intent of the provision to allow multiple
third-party developers that serve the same thermal host to all subtract
the purchased power of the thermal host facility when determining net
electric sales. This would result in counting the purchased power
multiple times. In addition, it is not the intent of the provision to
allow a CHP developer to provide a trivial amount of useful thermal
output to multiple thermal hosts and then subtract all the thermal
hosts' purchased power when determining net electric sales for
applicability purposes. The proposed approach in 40 CFR part 60,
subpart TTTTa would set a limit to the amount of thermal host purchased
power that a third-party CHP developer can subtract for electric sales
when determining net electric sales equivalent to the percentage of
useful thermal output provided to the host facility by the specific CHP
unit. This approach would eliminate both circumvention of the intended
applicability by sales of trivial amounts of useful thermal output and
double counting of thermal host-purchased power.
---------------------------------------------------------------------------

    \228\ For contractual reasons, many developers of CHP units sell
all the generated electricity to the electricity distribution grid
even though in actuality a significant portion of the generated
electricity is used onsite. Owners/operators of both the CHP unit
and thermal host can subtract the site purchased power when
determining net electric sales. Third party developers that do not
own the thermal host can also subtract the purchased power of the
thermal host when determining net electric sales for applicability
purposes.
---------------------------------------------------------------------------

    Finally, to avoid potential double counting of electric sales, the
EPA is proposing that for CHP units determining net electric sales,
purchased power of the host facility would be determined based on the
percentage of thermal power provided to the host facility by the
specific CHP facility.
iii. Non-Natural Gas Stationary Combustion Turbines
    There is currently an exemption in 40 CFR part 60, subpart TTTT for

stationary combustion turbines that are not physically capable of
combusting natural gas (e.g., those that are not connected to a natural
gas pipeline). While combustion turbines not connected to a natural gas
pipeline meet the general applicability of 40 CFR part 60, subpart
TTTT, these units are not subject to any of the requirements. The EPA
is proposing requirements for new and reconstructed combustion turbines
that are not capable of combusting natural gas. As described in the
standards of performance section, the Agency is proposing that owners/
operators of combustion turbines burning fuels with a higher heat input
emission rate than natural gas would adjust the natural gas-fired
emissions rate by the ratio of the heat input-based emission rates. The
overall result is that new stationary combustion turbines combusting
fuels with higher GHG emissions rates than natural gas on a lb
CO2/MMBtu basis would have to maintain the same efficiency
compared to a natural gas-fired combustion turbine and comply with a
standard of performance based on the identified BSER. Therefore, the
EPA is not including in 40 CFR part 60, subpart TTTTa, the exemption
for stationary combustion turbines that are not physically capable of
combusting natural gas.

F. Determination of the Best System of Emission Reduction (BSER) for
New and Reconstructed Stationary Combustion Turbines

    In this section, the EPA describes the technologies it is proposing
to determine are the BSER for each of the subcategories of new and
reconstructed combustion turbines that commence construction after the
date of this proposal, and explains its basis for proposing those
controls, and not others, as the BSER. The controls that the EPA is
evaluating include combusting non-hydrogen lower emitting fuels (e.g.,
natural gas and distillate oil), using highly efficient generation,
using CCS, and co-firing with low-GHG hydrogen.
    For the low-load subcategory, the EPA is proposing the use of lower
emitting fuels as the BSER. For the intermediate load subcategory, the
EPA is proposing an approach under which the BSER is made up of two
components that each represent a different set of controls, and that
form the basis of standards of performance that apply in multiple
phases. That is, affected facilities--which are facilities that
commence construction or reconstruction after the date of this proposed
rulemaking--must meet the first phase of the standard of performance,
which is based on the application of the first component of the BSER,
highly efficient generation, by the date the rule is finalized; and
then meet the second and more stringent phase of the standard of
performance, which is based on co-firing 30 percent (by volume) low-GHG
hydrogen by 2032. The EPA is also soliciting comment on whether the
intermediate load subcategory should apply a third component of BSER,
which is co-firing 96 percent (by volume) low-GHG hydrogen by 2038. In
addition, the EPA is also soliciting comment on whether the low load
subcategory should apply the second component of BSER, which is co-
firing 30 percent (by volume) low-GHG hydrogen by 2032. These latter
components of BSER would also include the continued application of
highly efficient generation.
    For the base load subcategory, the EPA is also proposing a multi-
component BSER and an associated multi-phase standard of performance.
The first component of the BSER, as with intermediate load combustion
turbines, is highly efficient generation. New base load combustion
turbines would be required to meet a phase one standard of performance
based on the application of the first component of the BSER upon
initial startup of the source. Subsequently, EPA is proposing two
technology pathways as potential BSER for base load combustion
turbines, with corresponding standards of performance. The first
technology pathway is based on 90 percent CCS, which base load
combustion turbines may install and begin to operate to meet the
standard of performance by 2035. The second technology pathway is based
on co-firing low-GHG hydrogen, which EPA proposes base load combustion
turbines may undertake in two steps--by co-firing 30 percent (by
volume) low-GHG hydrogen to meet the second phase of the standard of
performance by 2032 and, then by co-firing 96 percent (by volume) low-
GHG hydrogen to meet the third phase of the standard of performance by
2038. Throughout, base load turbines, like intermediate load turbines,
would remain subject to the BSER of highly efficient generation.
    This approach reflects the EPA's view that the BSER for the
intermediate load and base load subcategories should reflect the deeper
reductions in GHG emissions that can be achieved by implementing CCS
and co-firing low-GHG hydrogen but recognizes that building the
infrastructure required to support widespread use of CCS and low-GHG
hydrogen in the power sector will take place on a multi-year time
scale. Accordingly, newly constructed or reconstructed facilities must
be aware of their need to ramp toward more stringent phases of the
standards, which reflect application of the more stringent controls in
the BSER, either through use of co-firing a lower level of low-GHG
hydrogen by 2032 and a higher level of low-GHG hydrogen by 2038 or
through use of CCS by 2035. The EPA is also soliciting comment on the
potential for an earlier compliance date for the second phase, for
instance, 2030 for units co-firing 30 percent hydrogen by volume and
2032 for units installing CCS.
    For the base load subcategory, the EPA is proposing both potential
BSER pathways because it believes there may be more than one viable
BSER pathway for base load combustion turbines to significantly reduce
their CO2 emissions and believes there is value in receiving
comment on, and potentially finalizing, both BSER pathways to enable
project developers to elect how they will reduce their CO2
emissions on timeframes that make sense for each BSER pathway. The EPA
recognizes that standards of performance are technology neutral and
that if the EPA finalizes a standard based on application of CCS, units
could meet that standard using co-firing of low-GHG hydrogen. The EPA
solicits comment on whether co-firing of low-GHG hydrogen should be
considered a compliance pathway for sources to meet a single standard
of performance based on application of CCS rather than a separate BSER
pathway. The EPA believes that there will be earlier opportunities for
units to begin co-firing lower amounts of low-GHG hydrogen than to
install and begin operating 90 percent CCS systems. However, it will
likely take a longer timeframe for those units to then ramp up to co-
firing significant quantities of low-GHG hydrogen. Therefore, in this
proposal, the EPA presents these pathways as separate subcategories,
while soliciting comment on the option of finalizing a single standard
of performance based on application of CCS.
    Specifically, with respect to the first phase of the standards of
performance, for both the intermediate load and base load
subcategories, the EPA is proposing that the BSER is highly efficient
generating technology--combined cycle technology for the base load
subcategories and simple cycle technology for the intermediate load
subcategory--as well as operating and maintaining it efficiently. The
EPA sometimes refers to highly efficient generating technology in
combination with the best operating and

maintenance practices as highly efficient generation.
    The affected sources must meet standards based on this efficient
generating technology upon the effective date of the final rule. With
respect to the second phase of the standards of performance, for base
load combustion turbines adopting the CCS pathway, the BSER includes
the use of 90 percent CCS. These sources would be required to meet
standards of performance by 2035 that reflect application of both
components of the BSER--highly efficient generation and CCS--and thus
are more stringent. For base load combustion turbines adopting the low-
GHG hydrogen co-firing pathway and for intermediate load combustion
turbines, the BSER includes co-firing 30 percent by volume (12 percent
by heat input) low-GHG hydrogen. These sources would be required to
meet second phase standards of performance by 2032 that reflect the
application of both components of the BSER--in this case, highly
efficient generation and co-firing 30 percent (by volume) low-GHG
hydrogen--and that are, again, more stringent. Finally, for base load
combustion turbines adopting the low-GHG hydrogen co-firing pathway,
the BSER also includes a third component--co-firing 96 percent (by
volume) low-GHG hydrogen. These sources would be required to meet a
third phase standard of performance equivalent to that for the affected
sources applying CCS as a second component of the BSER. These sources
would be required to meet that equivalent standard of performance
reflecting the application of highly efficient generation and co-firing
high levels of low-GHG hydrogen. Table 1 summarizes the proposed BSER
for combustion turbine EGUs that commence construction or
reconstruction after publication of this proposal. The EPA is also
proposing standards of performance based on those BSER for each
subcategory, as discussed in section VII.G.

                               Table 1--Proposed BSER for Combustion Turbine EGUs
----------------------------------------------------------------------------------------------------------------
                                                         1st Component       2nd Component       3rd Component
           Subcategory                   Fuel                BSER                BSER                BSER
----------------------------------------------------------------------------------------------------------------
Low Load *......................  All Fuels.........  Lower emitting      N/A...............  N/A
                                                       fuels.
Intermediate Load...............  All Fuels.........  Highly Efficient    30 percent (by      N/A
                                                       Generation.         volume) Low-GHG
                                                                           Hydrogen Co-
                                                                           firing by 2032.
Base Load.......................  Sources adopting    Highly Efficient    90 percent CCS by   N/A
                                   the CCS pathway.    Generation.         2035.
                                  Sources adopting    ..................  30 percent (by      96 percent (by
                                   the low-GHG                             volume) Low-GHG     volume) Low-GHG
                                   hydrogen co-                            Hydrogen Co-        Hydrogen Co-
                                   firing pathway.                         firing by 2032.     firing by 2038
----------------------------------------------------------------------------------------------------------------
* The low load subcategory has a single-component BSER consisting of fuels that emit lower GHG emissions.

1. BSER for Low Load Subcategory
    This section describes the proposed BSER for the low load (i.e.,
peaking) subcategory, which is the use of lower emitting fuels. For
this proposed rule, the Agency proposes to determine that the use of
lower emitting fuels, which the EPA determined to be the BSER for the
non-base load subcategory in the 2015 NSPS, is the BSER for this low
load subcategory in the standards of performance proposed in this
action. As explained above, the EPA is proposing to narrow the
definition of the low load subcategory by lowering the electric sales
threshold (as compared to the electric sales threshold for non-base
load combustion turbines in the 2015 NSPS), so that turbines with
higher electric sales would be placed in the proposed intermediate load
subcategory and therefore be subject to a more stringent standards
based on the more stringent component of the BSER. Unlike the proposals
for intermediate and base load combustion turbines, the proposed low
load subcategory includes only a single-phase BSER component.
a. Background: The Non-Base Load Subcategory in the 2015 NSPS
    The 2015 NSPS defined non-base load natural gas-fired EGUs as
stationary combustion turbines that (1) Burn more than 90 percent
natural gas and (2) have net electric sales equal to or less than their
design efficiency (not to exceed 50 percent) multiplied by their
potential electric output (80 FR 64601; October 23, 2015). These are
calculated on 12-operating-month and 3-year rolling average bases. The
EPA also determined in the 2015 NSPS that the BSER for newly
constructed and reconstructed non-base load natural gas-fired
stationary combustion turbines is the use of lower emitting fuels. Id.
at 64515. These lower emitting fuels are primarily natural gas with a
small allowance for distillate oil (i.e., Nos. 1 and 2 fuel oils),
which have been widely used in stationary combustion turbine EGUs for
decades.
    The EPA also determined in the 2015 NSPS that the standard of
performance for sources in this subcategory is a heat input-based
standard of 120 lb CO2/MMBtu. The EPA established this
clean-fuels BSER for this subcategory because of the variability in the
operation in non-base load combustion turbines and the challenges
involved in determining a uniform output-based standard that all new
and reconstructed non-base load units could achieve.
    Specifically, in the 2015 NSPS, the EPA recognized that a BSER for
the non-base load subcategory based on the use of lower emitting fuels
results in limited GHG reductions, but further recognized that an
output-based standard of performance could not reasonably be applied to
the subcategory. The EPA explained that a combustion turbine operating
at a low capacity factor could operate with multiple starts and stops,
and that its emission rate would be highly dependent on how it was
operated and not its design efficiency. Moreover, combustion turbines
with low annual capacity factors typically operated differently from
each other, and therefore had different emission rates. The EPA
recognized that, as a result, it would not be possible to determine a
standard of performance that could reasonably apply to all combustion
turbines in the subcategory. For that reason, the EPA further
recognized, efficient design \229\ and operation would not qualify as
the BSER; rather, the BSER should be lower

emitting fuels and the associated standard of performance should be
based on heat input. Since the 2015 NSPS, all newly constructed simple
cycle turbines have been non-base load units and thus have become
subject to this standard of performance.
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    \229\ Important characteristics for minimizing emissions from
low load combustion turbines include the ability to operate
efficiently while operating at part load conditions and the ability
to rapidly achieve maximum efficiency to minimize periods of
operation at lower efficiencies. These characteristics do not
necessarily always align with higher design efficiencies that are
determined under steady state full load conditions.
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b. Proposed BSER
    Consistent with the rationale of the 2015 NSPS, the EPA proposes
that the use of fuels with an emissions rate of less than 160 lb
CO2/MMBtu (i.e., lower emitting fuels) meets the BSER
requirements for the low load subcategory. Use of these fuels is
technically feasible for combustion turbines. Natural gas comprises the
majority of the heat input for simple cycle turbines and is the lowest
cost fossil fuel. In the 2015 NSPS, the EPA determined that natural gas
comprised 96 percent of the heat input for simple cycle turbines. See
80 FR 64616 (October 23, 2015). Therefore, a BSER based on the use of
natural gas and/or distillate oil would have minimal, if any, costs to
regulated entities. The use of lower emitting fuels would not have any
significant adverse energy requirements or non-air quality or
environmental impacts, as the EPA determined in the 2015 NSPS. Id. at
64616. In addition, the use of fuels meeting this criterion would
result in some emission reductions by limiting the use of fuels with
higher carbon content, such as residual oil, as the EPA also explained
in the 2015 NSPS. Id. Although the use of fuels meeting this criterion
would not advance technology, in light of the other reasons described
here, the EPA proposes that the use of natural gas, Nos. 1 and 2 fuel
oils, and other fuels \230\ currently specified in 40 CFR part 60,
subpart TTTT, qualify as the BSER for new and reconstructed combustion
turbine EGUs in the low load subcategory. The EPA is also proposing to
add low-GHG hydrogen to the list of fuels meeting the uniform fuels
criteria in 40 CFR part 60, subpart TTTTa. The addition of low-GHG
hydrogen (and fuels derived from hydrogen) to 40 CFR part 60, subpart
TTTTa would simplify the recordkeeping and reporting requirements for
low load combustion turbines that elect to burn low-GHG hydrogen. As
described in section VII.F, a component of the BSER for certain
subcategories in subpart TTTTa is based on the use of low-GHG hydrogen.
An owner/operator of a subpart TTTTa affected combustion turbine that
combusts hydrogen for compliance purposes not meeting the definition of
low-GHG hydrogen would be in violation of the subpart TTTTa
requirements.
---------------------------------------------------------------------------

    \230\ The BSER for multi-fuel-fired combustion turbines subject
to 40 CFR part 60, subpart TTTT is also the use of fuels with an
emissions rate of 160 lb CO2/MMBtu or less. The use of
these fuels would demonstrate compliance with the low load
subcategory.
---------------------------------------------------------------------------

    For the reasons discussed in the 2015 NSPS and noted above, the EPA
is not proposing that efficient design and operation qualify as the
BSER for the low load subcategory. The EPA is not proposing high-
efficiency simple cycle or combined cycle turbine design and operation
as the BSER for the low load subcategory because they are not
necessarily cost reasonable and would not necessarily result in
emission reductions. High efficiency combustion turbines have higher
initial costs compared to lower efficiency combustion turbines. The
cost of combustion turbine engines is dependent upon many factors, but
the EPA estimates that the capital cost of a high-efficiency simple
cycle turbine is 5 percent more than that of a comparable lower
efficiency simple cycle turbine. Assuming all other costs are the same
and that the high-efficiency simple cycle turbine uses 6 percent less
fuel, it would not necessarily be cost reasonable to use a high-
efficiency simple cycle turbine until the combustion turbine is
operated at a 12-operating-month capacity factor of approximately 20
percent. At lower capacity factors, the CO2 abatement costs
on both a $/ton and $/MW basis increase rapidly.\231\ Further, the
emission rate of a low load combustion turbine is highly dependent upon
the way the combustion turbine is operated. If the combustion turbine
is frequently operated at part load conditions with frequent starts and
stops, a combustion turbine with a high design efficiency, which is
determined at full load steady state conditions, would not necessarily
emit at a lower GHG rate than a combustion turbine with a lower design
efficiency.
---------------------------------------------------------------------------

    \231\ The cost effectiveness calculation is highly dependent
upon assumptions concerning the increase in capital costs, the
decrease in heat rate, and the price of natural gas.
---------------------------------------------------------------------------

    The EPA solicits comment on whether, and the extent to which, high-
efficiency designs also operate more efficiently at part loads and can
start more quickly and reach the desired load more rapidly than
combustion turbines with less efficient design efficiencies. If high-
efficiency simple cycle turbines do operate at higher part-load
efficiencies and are able to reach the intended operating load more
quickly, the use of highly efficient simple cycle turbines for low load
applications would result in lower GHG reductions. In addition, the EPA
solicits comment on the cost premium of high-efficiency simple cycle
turbines. If the use of highly efficient simple cycle turbines results
in GHG reductions at reasonable cost, their use could qualify as the
BSER for low load combustion turbines. The EPA is soliciting comment on
whether the BSER for new low load combustion turbines should be the use
of high efficiency simple cycle technology. However, since the method
of operation has a substantial impact on the emissions rate, it may not
be feasible for to prescribe or enforce a single numerical standard of
performance for affected sources strictly based on design efficiency.
Accordingly, the EPA solicits comment on whether it would be
appropriate to promulgate such a requirement as a design standard
pursuant to CAA section 111(h). Pursuant to such a design standard,
compliance would be demonstrated (i) initially, through an emissions
test and (ii) subsequently, based on the use of lower emitting fuels.
The initial full load performance test for natural gas-fired low load
combustion turbines the EPA is considering is 1,150 lb CO2/
MWh-gross or 1,100 lb CO2/MWh-gross.\232\ Combustion turbine
manufacturers conduct testing on their products and the initial
performance test is equivalent to a design efficiency of approximately
35 and 36 percent, respectively. According to Gas Turbine World 2021,
approximately three-fourths of simple cycle combustion turbines have
design efficiencies of 35 percent or higher and half of simple cycle
combustion turbines have design efficiencies of 36 percent or higher.
The EPA is soliciting comment on if the initial performance test for
low load combustion turbines could be conducted by the manufacturer
certifying the design GHG emissions rate or if the owner or operator
should be required to conduct separate testing to verify the emissions
rate. The EPA notes that even if the Agency determines that a
manufacturer design efficiency-based emissions requirement is
appropriate for new low load combustion turbines, owners/operators
would also have the option to either comply with the intermediate load
standard of performance on a continuous basis or conduct an initial
performance test as an alternative to purchasing a combustion turbine
that

achieves the specified design efficiency. For example, owners/operators
could elect to cofire low-GHG hydrogen or install integrated renewable
generation as an alternative to purchasing a combustion turbine that
meets the specified design efficiency.
---------------------------------------------------------------------------

    \232\ The initial full load compliance test would be a 3-hour
performance test and the measured emissions rate would be corrected
to ISO conditions.
---------------------------------------------------------------------------

    The EPA expects that units in the low load subcategory will be
simple cycle turbines. The capital cost of a combined cycle EGU is
approximately 250 percent that of a comparable sized simple cycle EGU
and would not be recovered by reduced fuel costs if operated as low
load units. Furthermore, low load combustion turbines start and stop so
frequently that there might not be sufficient periods of continuous
operation for the HRSG to begin generating steam to operate the steam
turbine enough to significantly lower the emissions rate of the EGU.
    The EPA is not proposing the use of CCS or hydrogen co-firing as
the BSER (or as a component of the BSER) for low load combustion
turbines.\233\ As described in the section discussing the second
component of BSER for the intermediate load subcategory, the EPA is not
proposing that CCS is the BSER for simple cycle combustion turbines
based on the Agency's assessment that CCS may not be cost-effective for
such combustion turbines when operated at intermediate load. This
rationale applies with even greater force for low load combustion
turbines. In addition, currently available post-combustion amine-based
carbon capture systems require that the exhaust from a combustion
turbine be cooled prior to entering the carbon capture equipment. The
most energy efficient way to do this is to use a HSRG, which is an
integral component of a combined cycle turbine system but is not
incorporated in a simple cycle unit. For these reasons, the Agency is
not proposing that CCS qualifies as the BSER for this subcategory of
sources.
---------------------------------------------------------------------------

    \233\ The EPA will not finalize the use of CCS or hydrogen co-
firing as the BSER (or as a component of the BSER) for low load
combustion turbines unless it first issues a subsequent notice of
proposed rulemaking further evaluating such measures for that
subcategory.
---------------------------------------------------------------------------

    The EPA is not proposing low-GHG hydrogen co-firing as the BSER for
low load combustion turbines because not all new combustion turbines
can necessarily co-fire higher percentages of hydrogen, there are
potential infrastructure issues specific to low load combustion
turbines, and at the relatively infrequent levels of utilization that
characterize the low load subcategory, a low-GHG hydrogen co-firing
BSER would not necessarily result in cost-effective GHG reductions for
all low load combustion turbines. As discussed later in this section,
the announced hydrogen co-firing combustion turbine projects appear to