options that states may consider (see Section VI). EPA solicits
comment, nevertheless, on whether co-firing methods should be included
among the list of BSER candidate technologies for states to evaluate
when establishing a standard of performance for each affected source in
their jurisdiction.
a. Natural Gas Co-Firing
    Coal-fired power plants typically use natural gas or other clean
fuel (such as low sulfur fuel oil) for start-up operations and, if
needed, to maintain the unit in ``warm stand-by.'' Some plants co-fire
natural gas simultaneously with coal--either directly as a combustion
fuel or in configuration referred to as natural gas reburn, which is
used for NOx control. During periods of natural gas co-firing, an EGU's
CO2 emission rate is reduced as natural gas is a less carbon
intensive fuel than coal. For example, at 10 percent natural gas co-
firing, the net emissions rate (lb/MWh-net) of a typical unit would
decrease by approximately 4 percent. On the other hand, co-firing can
negatively impact a unit's efficiency due to the high hydrogen content
of natural gas and the resulting production of water as a combustion
by-product. And depending on the design of the boiler and extent of
modifications, some boilers may be forced to de-rate (a reduction in
generating capacity) in order to maintain steam temperatures at or
within design limits, or for other technical reasons.
    In evaluating BSER technology options, CAA section 111(a)(1)
directs EPA to take into account nonair quality health and
environmental impacts, and energy requirements. EPA is unaware of any
significant nonair quality health or environmental impacts associated
with natural gas co-firing. However, in taking energy requirements into
account, EPA notes that co-firing natural gas in coal-fired utility
boilers is not the best, most efficient use of natural gas and, as
noted above, can lead to inefficient operation of utility boilers. NGCC
stationary combustion turbine units are much more efficient at using
natural gas as a fuel for the production of electricity and it would
not be an environmentally positive outcome for utilities and owner/
operators to redirect natural gas from the more efficient NGCC EGUs to
the less efficient coal-fired EGUs in order to satisfy an emission
standard at the coal-fired unit.
    Moreover, unlike coal, natural gas cannot be stored in quantities
sufficient for sustained utilization on site. Accordingly, delivery of
natural gas via pipeline is essential for using natural gas at coal-
fired EGUs. Many existing coal-fired plants, however, do not have
access to natural gas transportation infrastructure and gaining access
would be either infeasible (due to technical or timing considerations)
or unreasonably costly.\31\ For plants that currently co-fire natural
gas and have access to an existing natural gas pipeline, many may be
capacity constrained (i.e., they are not able to greatly increase
purchase volumes with the existing infrastructure). Accordingly,
although natural gas fuel prices are currently low and some sources
currently co-fire natural gas, on balance, there are notable challenges
and concerns with instituting natural gas co-firing on a wide variety
of units across the country. Therefore, EPA is not proposing that
natural gas co-firing should be part of the BSER.
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    \31\ In addition to new pipeline infrastructure, conversion to
natural gas co-firing in a coal-fired boiler typically involves
installation of new gas burners and supply piping, modifications to
combustion air ducts and control dampers, and possibly modifications
to the boiler's steam superheater, reheater, and economizer heating
surfaces that transfer heat from the hot flue gas exiting the boiler
furnace. The conversion may also involve modification and possible
deactivation of some downstream air pollution emission control
equipment.
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b. Co-Firing Biomass
    The infrastructure, proximity and cost aspects of co-firing biomass
at existing coal EGUs are similar in nature and concept to those of
natural gas. While there are some existing coal-fired EGUs that
currently co-fire with biomass fuel, those are in relatively close
proximity to cost-effective biomass supplies; and, there are regional
supply and demand dynamics at play. As with the other emission
reduction measures discussed in this section, EPA expects that use of
some types of biomass may be economically attractive for certain
individual sources. However, on a broader scale, biomass co-firing is
more expensive and/or less achievable than the measures determined to
be part of the BSER. As such, EPA is not proposing that the use of
biomass fuels is part of the BSER because too few individual sources
will be able to employ that measure in a cost-reasonable manner.

VI. State Plan Development

A. Establishing Standards of Performance

1. Application of the BSER
    As discussed in Section III above, EPA has the authority to
determine the BSER as part of regulations it promulgates pursuant to
CAA section 111(d)(1) (providing that states shall submit plans to EPA
establishing ``standards of performance'' for existing sources); see
also CAA section 111(a)(1) (defining ``standard of performance'' with
reference to the ``best system of emission reduction which . . . the
Administrator determines has been adequately demonstrated''). For such
regulations, EPA has traditionally promulgated emission guidelines
governing the process for states to

submit plans which establish standards of performance which reflect the
degree of emission limitation achievable through application of the
BSER to each affected source within the state, in addition to the
implementing regulations EPA initially promulgated in 1975 to set the
general framework under which it would administer section 111(d). The
implementing regulations that are also being proposed in this action
(see Section VII below for a discussion on the proposed new
implementing regulations) contain certain requirements for EPA in
promulgating an emission guideline under section 111(d). One
requirement of the new proposed implementing regulations (consistent
with the previous implementing regulations and section 111(d) of the
CAA) is that an EPA-promulgated emission guideline provide information
on the degree of emission reduction which is achievable with each
system, together with information on the costs, and nonair health and
environmental effects, and energy requirements of applying each system
to designated facilities.\32\ This means that EPA will provide, in
addition to the BSER, information on the degree of emission reduction
that is achievable when the BSER is applied. In the case of this
proposed rulemaking and as described above in Section V, EPA is
proposing that the BSER is HRI made at the unit level. To meet the
requirements of the new proposed implementing regulations, EPA is
proposing candidate technologies for HRI measures corresponding to a
range of reductions and costs as information regarding the degree of
emission reduction achievable through application of the BSER. Because
affected EGUs in each state are different and the application of
different HRI measures may take into account source-specific factors,
EPA is providing expected ranges of HRIs. These ranges are shown in
Table 1.
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    \32\ This is consistent with the statutory definition of
``standard of performance'' at CAA section 111(a)(1) (emphases
added): ``a standard for emissions of air pollutants which reflects
the degree of emission limitation achievable through the application
of the best system of emission reduction which (taking into account
the cost of achieving such reduction and any nonair quality health
and environmental impact and energy requirements) the Administrator
determines has been adequately demonstrated.''
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    EPA expects that states can use the information that EPA provides
on the degree of emission limitation in developing standards of
performance for affected EGUs as part of establishing a standard of
performance for inclusion in a state's plan pursuant to the
requirements of section 111(d)(1). In this case, the ranges of HRIs are
provided as guidance for states to use in evaluating the efficacy of
implementing each measure identified as part of the BSER candidate
technologies at each affected EGU. While the HRI potential range is
provided as guidance for the states, the actual HRI performance for
each of the candidate technologies will be unit-specific and will
depend upon a range of unit-specific factors. The states will use the
information provided by EPA as guidance, but will be expected to
conduct unit-specific evaluations of HRI potential, technical
feasibility, and applicability for each of the BSER candidate
technologies. Once a state evaluates the HRIs identified as part of the
BSER in establishing a standard of performance for a particular
affected EGU, it is within the state's discretion to take certain
factors concerning that source, such as remaining useful life, into
consideration when determining how the standard of performance should
be applied. The next section describes how states may derive a standard
of performance reflecting the degree of emission limitation achievable
through application of the BSER.
    Additionally, the new proposed implementing regulations require
that an emission guideline identify information such as a timeline for
compliance with standards of performance that reflect the application
of the BSER. See proposed 40 CFR 60.22a. However, given the source-
specific nature of this proposed emission guideline and reasonably
anticipated variation between standards established for sources within
a state, EPA believes it more appropriate that a state establish
tailored compliance deadlines for its sources based on the standard
ultimately determined for each source. Accordingly, the EPA proposes to
supersede this aspect of proposed 40 CFR 60.22a, as allowed under the
applicability provision under proposed 60.20a, and allow for states to
include appropriate compliance deadlines for sources based on the
standards of performance determined as part of the state plan process.
    EPA is proposing, consistent with the new proposed implementing
regulations (subpart Ba), that states will include custom compliance
schedules for affected EGUs as part of their state plan. This is
another area that states have latitude for taking into account unit
specific factors. It should be noted however, that per the proposed new
implementing regulations, if a state chooses to include a compliance
schedule for a source that extends more than twenty-four months from
the submittal of the state plan, the plan must also include legally
enforceable increments of progress for that source (See proposed 40 CFR
60.24a(d)(1)). The EPA solicits comment on whether states should
determine source-specific compliance schedules under this emission
guideline, or if a uniform compliance schedule is appropriate, and if
so, what length of time is appropriate. (Comment C-13).
2. Determination of a Unit's Standard of Performance
    As described in other parts of this section, while EPA's role is to
determine the BSER, section 111(d)(1) squarely places the
responsibility of establishing a standard of performance for an
existing source on the state as part of developing a state plan. EPA is
proposing that once EPA determines the BSER, states are expected to
evaluate each of the BSER HRI measures that EPA has determined
represent BSER in establishing a standard of performance for each
source within their jurisdiction. The states, in applying the standards
of performance, may take into consideration, among other factors, the
remaining useful life of the existing source to which the standard
would apply (see Section VI.B.1 for further discussion on remaining
useful life and other factors). The proposed BSER is a list of
candidate technologies that are HRI measures, which states should
evaluate, and potentially apply to existing sources as appropriate
based upon the specific characteristics of those units. In general, EPA
envisions that, under the proposed program, the states would set
standards based on considerations most appropriate to individual
sources or groups of sources (e.g., subcategories). These may include
consideration of historical emission rates, effect of potential HRIs
(informed by the information in EPA's candidate technologies described
earlier in Section V), or changes in operation of the units, among
other factors the state believes are relevant. As such, states have
considerable flexibility in determining emission standards for units,
as contemplated by the express statutory text.
    Several commenters on the ANPRM suggested that EPA should develop a
default methodology for determining appropriate standards of
performance that are consistent with the BSER. More specifically,
commenters suggested that EPA should use a methodology that is similar
to the one finalized for major modifications at coal-fired EGUs under
the section 111(b) program--i.e., based on the use of historical heat
rate or emissions data for the individual

source. Commenters also suggested that any approach covering all
existing units should use at least ten years' worth of historical data
and should be based on rolling averages for multiple year periods
(e.g., the fourth highest three-year average during the historical
look-back period). Other commenters suggested that the approach used
for major modifications was too stringent to apply to all units. EPA
understands that if the Agency were to provide a specific and
presumptively-approvable methodology for establishing standards of
performance, that approach would provide states with certainty in how
to develop plans. EPA is not proposing a specific methodology or
formula for establishing standards of performance for existing sources
in this action. EPA believes that such a presumptive standard could be
viewed as limiting a state's ability to deviate from the prescribed
methodology and that the approach could ultimately be more limiting
than helpful. While EPA is not proposing a presumptive formulaic
approach in this action, the Agency is soliciting comment on approaches
based on the use of historical heat rate or emissions data for the
individual source (Comment C-14). The circumstances and considerations
for establishing standards of performance under CAA 111(b) for affected
sources that have undergone a modification (i.e., any physical change
in or change in the method of operation that increases the hourly
emissions of GHG) are not the same as the circumstances and
considerations for states should take into account in establishing
standards of performance under these proposed emission guidelines, but
there are certainly parallels and similarities.
    As mentioned earlier, states may take into consideration other
factors, including remaining useful life, when applying unit-specific
standards of performance. Consideration of these factors may result in
the application of the standard of performance in a less stringent
manner than would otherwise be suggested by strict implementation of
the BSER technologies. This topic is discussed in detail in Section
VI.B.
    As previously described, this proposal seeks to clarify the
Agency's and states' roles under section 111(d). The statute is clear
that EPA determines the BSER, and states submit plans that establish
standards of performance for existing sources that, under the
definition of ``standard of performance in CAA section 111(a)(1),
reflect the degree of emission limitation achievable though the
application of the BSER. Consistent with the statute, EPA's proposed
implementing regulations at 40 CFR 60.22a(b)(2) specify that an
emission guideline must include information on the degree of emission
reduction which is achievable, but does not require that EPA must
provide a standard of performance that presumptively reflects such
degree of emission reduction which is achievable through application of
the BSER, as that is appropriately the states' role. EPA is proposing
to clarify that the implementing regulations do not require EPA to
provide a presumptive numerical standard as part of its emission
guidelines and that the ranges of expected emission reductions that can
be achieved in EPA's BSER determination adequately provide sufficient
information to the states on the degree of emission limitation that
will result from application of the BSER to existing sources to
appropriately inform the states' exercise of their authority to develop
plans under 111(d).
    Given that section 111(d)(1) requires states to submit plans that
establish standards of performance for affected sources, EPA believes
it is consistent with the spirit of cooperative federalism to provide
information sufficient to assist states in the development of state
plans, which in turn will provide both states and sources with
regulatory certainty via a plan that is approvable under section
111(d)(2) and applicable regulations. As mentioned above, EPA is
proposing to provide information regarding ranges of expected
reductions associated with the various HRIs identified as the BSER,
which will assist states in establishing appropriate standards of
performance for affected EGUs. EPA proposes to determine providing such
information is consistent with both the implementing regulations at 40
CFR 60.22(b) and CAA section 111(d) regarding the roles of states and
EPA determining the degree of emission limitation achievable through
application of the BSER.
    As described below in Section VI.B, under the statute, the proposed
new implementing regulations, and these proposed emission guidelines,
states have considerable flexibility in developing their plans and
establishing and applying standards of performance to existing sources.
One of the areas of flexibility described is in the standard setting
process for EGUs. As part of this flexibility, EPA is proposing that
states should have broad flexibility on whether and how the state
chooses to group, sort, or subcategorize affected EGUs within the state
to establish standards of performance. In evaluating affected EGUs, if
a state finds that there is an overlap in circumstances around a group
of EGUs, it might make sense to implement a uniform methodology for
setting a standard of performance across that group. Another area of
flexibility is explicitly provided in the statutory text of 111(d)(1)
itself. The statute requires that EPA's regulations implementing
section 111(d) shall permit the State in applying a standard of
performance to any particular source under a plan submitted under this
paragraph to take into consideration, among other factors, the
remaining useful life of the existing source to which such standard
applies.
3. Forms of Standards of Performance
    As described further in Section VII.C of this preamble, EPA is
proposing a new implementing regulation for section 111(d) which
includes a proposed definition of ``standard of performance that aligns
with the statutory definition of the term under CAA section 111(a)(1).
EPA is further proposing, as part of the new implementing regulations,
that a specific emission guideline may contain provisions that
supersede the applicability of the implementing regulations. In the
context of these emission guidelines, EPA is proposing that an
allowable emission rate (i.e., rate-based standard in, for example, lb
CO2/MWh-gross) be the form of standard of performance that
states would include in their state plans for affected EGUs. Primarily,
an allowable emission rate most closely aligns to EPA's BSER
determination for these emission guidelines. When HRIs are made at an
EGU, by definition, the CO2 emission rate will decrease as
described above in Section V.B. There is a natural correspondence
between the BSER and an allowable emission rate as the standard of
performance in this action. Secondly, EPA is proposing that state plans
include only the one form of standard of performance (i.e., proposing
only an allowable emission rate) to create continuity across states,
prevent ambiguity, and to ensure as much simplicity as possible.
However, EPA solicits comment on whether other forms of standards of
performance should be allowed in state plans and whether a different
form of standard should be the primary form that is authorized for
state plans under a final emission guideline in response to this
proposal (Comment C-15).
    EPA is proposing an allowable emission rate of CO2 as
the form of the standard of performance because it creates the most
straightforward system for states to determine standards and ensure
compliance. This also creates a more streamlined evaluation for EPA to
consider in state plan evaluation as there are fewer variables to
consider (e.g., projections of utilization which

would be required if the standard of performance took a mass-based
form).
4. Gross Versus Net Emission Standards
    EPA also requests comment on the merits of differentiating between
gross and net heat rate (Comment C-16). This may be particularly
important when considering the effects of part load operations (i.e.,
net heat rate would include inefficiencies of the air quality control
system at a part load whereas gross heat rate would not). This will
also be important in recognizing the improved efficiency obtained from
upgrades to equipment that reduce the auxiliary power demand.

B. Flexibilities for States and Sources

    Once EPA determines the BSER, section 111(d)(1) of the CAA requires
that ``each State shall submit to the Administrator a plan which (A)
establishes standards of performance for any existing source [. . .],
and (B) provides for the implementation and enforcement of such
standards of performance.'' Section 111(d)(1) further requires EPA to
``permit the State in applying a standard of performance to any
particular source under a plan [. . .] to take into consideration,
among other factors, the remaining useful life of the existing source
to which such standard applies.''
    In light of the cooperative-federalist structure of section 111(d)
and its express language requiring that EPA allow states to take into
account source-specific factors when establishing standards of
performance for existing sources, EPA believes it is appropriate in
this proposal to provide considerable flexibility for states to set
standards of performance for units and also allow states to have
considerable latitude for implementing measures and standards for
affected EGUs. A detailed discussion of the flexibility that states
have in developing standards of performance is provided below in
Section VI.B.1. States also have flexibility in the measures and
processes that they put in place for affected EGUs to meet their
compliance obligations. One of the examples of this is discussed in
Section VI.B.2 on averaging and trading. As previously discussed, the
BSER's candidate technologies affords states considerable flexibility
to determine how to apply standards of performance to affected sources.
Several commenters noted in the ANPRM that flexibility for States and
affected sources should be part of any replacement rule, with States
being able to choose from a wide variety of possible methods for
developing a standard of performance, along with options for how to
implement the standard through their state plans. Other commenters
suggested that any flexible compliance opportunities provided should be
directly linked to the determination of the BSER, such that increased
compliance flexibility in the state's establishment of a standard of
performance for an existing source can only be included to the extent
that the flexibility is included as part of the BSER.
    Another important and distinctly different element of flexibility
in this proposal is the availability of compliance options for affected
sources in meeting their standards of performance. To the extent that a
state develops a standard of performance for an affected source within
its jurisdiction, the state is free to give the source flexibility to
meet that standard of performance using either BSER technologies or
some other non-BSER technology or strategy. In other words, an affected
source may have broad discretion in meeting its standard of performance
within the requirements of a state's plan. For example, there are
technologies, methods, and/or fuels that can be adopted at the affected
source to allow the source to comply with its standard of performance
that were not determined to be the BSER, but which may be applicable
and prudent for specific units to use to meet their compliance
obligations. Examples of non-BSER technologies and fuels include HRI
technologies that were not included as candidate technologies, CCS, and
fuel co-firing (natural gas or certain biomass). In keeping with past
programs that regulated affected sources using a standard of
performance, EPA takes no position regarding whether there may be other
methods or approaches to meeting such a standard, since there are
likely various approaches to meeting the standard of performance that
EPA is either unable to include as part of the BSER, or is unable to
predict. EPA proposes that affected sources may use both BSER and non-
BSER measures to achieve compliance with their state plan obligations.
    To demonstrate that measures taken to meet compliance obligations
for a source actually reduce its emission rate, EPA proposes that the
measures should meet two criteria: (1) They are implemented at the
source itself, and (2) they are measurable at the source of emissions
using data, emissions monitoring equipment or other methods to
demonstrate compliance, such that they can be easily monitored,
reported and verified at a unit. There may be other technologies or
compliance measures that meet these general criteria. EPA solicits
comment on whether these two criteria are appropriate or not and why,
and whether there may be compliance flexibilities that might meet the
two proposed criteria (Comment C-17). This proposed rule is intended to
generally allow compliance flexibility in state plans where
appropriate, to the extent they contribute to meeting any particular
standard of performance, consistent with the criteria. EPA is further
soliciting comment on whether there are certain non-BSER measures that
should be disallowed for compliance, and if so, under what criteria or
rationale should measures be disallowed for compliance (Comment C-18).
    Section 111(d)(1)(B) additionally requires state plans to include
measures that provide for the implementation and enforcement of
standards of performance. EPA believes states can meet these
requirements by including measures as described in Section VI.C of this
proposal regarding state plan components, such as monitoring,
reporting, and recordkeeping requirements. EPA solicits comments on
what other implementation and enforcement measures may be necessary for
states to meet the requirements of section 111(d)(1)(B) (Comment C-19).
Additionally, as part of ensuring that regulatory obligations
appropriately meet statutory requirements such as enforceability, EPA
has historically and consistently required that obligations placed on
sources be quantifiable, non-duplicative, permanent, verifiable, and
enforceable. EPA is similarly proposing that standards of performance
places on affected EGUs as part of a state plan be quantifiable, non-
duplicative, permanent, verifiable, and enforceable.
    The Agency specifically recognizes that some entities may be
interested in using biomass as a compliance option for meeting the
state determined emission standard.\33\ As with the other non-BSER
measures discussed in this section, EPA expects that use of biomass may
be economically attractive for certain individual sources even though
on a broader scale it may be more expensive or less achievable than the
measures determined to be part of the BSER (and therefore EPA is not
proposing to determine that it should be included within the BSER,
which is properly limited to measures likely to be cost-reasonable for
a greater proportion

of existing sources than we believe biomass to be at this time).
---------------------------------------------------------------------------

    \33\ EPA believes that biomass co-firing can meet the two
criteria above because the biomass can be burned at the source and
there are different methods that can be used to monitor or calculate
the amount of biogenic CO2 emissions associated with
biomass use at a unit.
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    Certain kinds of biomass, including that from managed forests, have
the potential to offer a wide range of economic and environmental
benefits, including carbon benefits. However, these benefits can
typically only be realized if biomass feedstocks are sourced
responsibly, which can include ensuring that forest biomass is not
sourced from lands converted to non-forest uses. States that intend to
propose the use of forest-derived biomass for compliance by affected
units may refer to EPA's April 2018 statement on its intended treatment
of biogenic CO2 emissions from stationary sources that use
forest biomass for energy production.34 35 As discussed in
the recent statement, EPA's policy is to treat biogenic CO2
emissions resulting from the combustion of biomass from managed forests
at stationary sources for energy production as carbon neutral.36 EPA
will continue to evaluate the applicability of this policy of treating
forest-biomass derived biogenic CO2 as carbon neutral based
on relevant information, including data from interagency partners on
updated trends in forest carbon stocks.
---------------------------------------------------------------------------

    \34\ https://www.epa.gov/sites/production/files/2018-04/documents/biomass_policy_statement_2018_04_23.pdf.
    \35\ This policy statement aligns with provisions in the
Consolidated Appropriations Act, 2018, which calls for EPA, the
Department of Energy and the Department of Agriculture to establish
policies that, consistent with their missions, jointly ``reflect the
carbon-neutrality of forest bioenergy and recognize biomass as a
renewable energy source, provided the use of forest biomass for
energy production does not cause conversion of forests to non-forest
use.'' https://www.congress.gov/115/bills/hr1625/BILLS-115hr1625enr.pdf.
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    EPA solicits comments on the inclusion of forest-derived biomass as
a compliance option for affected units to meet state plan standards
under this rule (Comment C-20). The Agency also solicits comment on the
inclusion of non-forest biomass (e.g., agricultural, waste stream-
derived) for energy production as a compliance option, and what value
to attribute to the biogenic CO2 emissions associated with
non-forest biomass feedstocks (Comment C-21). EPA recognizes that CCS
technology (described above in this section) could be applied in
conjunction with biomass use.
1. State Discretion To Consider Remaining Useful Life and Other Factors
in Setting Standards of Performance
    Section 111(d)(1) requires that EPA's regulations must permit
states to take into account, among other factors, an affected source's
remaining useful life when establishing an appropriate standard of
performance. In other words, Congress explicitly envisioned under
section 111(d)(1) that states could implement standards of performance
that vary from EPA's emission guidelines under appropriate
circumstances.
    Congress explicitly mentions consideration of remaining useful life
in 111(d). Ultimately remaining useful life impacts cost. When EPA
develops a BSER, EPA typically considers factors such as cost relative
to assumptions about a typical unit. If the remaining useful life of a
particular unit is less, that will generally increase the cost of
control because the time to amortize capital costs is less. When
congress mentions other factors, EPA believes that these are generally
other factors that may substantially increase costs relative to a more
typical unit.
    As such, EPA is proposing, as part of the proposed implementing
regulations, to permit states to take into account remaining useful
life, among other factors, in establishing a standard of performance
for a particular affected source, consistent with section 111(d)(1)(B).
EPA solicits comments on the manner in which states should be permitted
to exercise their statutory authority to take into account remaining
useful life and on what ``other factors'' might appropriately be
besides remaining useful life (Comment C-22). As described in Section
VII.F., EPA further proposes as part of the new implementing
regulations that the following factors give meaning to section
111(d)(1)(B):
     Unreasonable cost of control resulting from plant age,
location, or basic process design;
     Physical impossibility of installing necessary control
equipment; or
    Other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable. Given that there are unique
attributes and aspects of each affected source, there are important
factors that influence decisions to invest in technologies to meet a
potential performance standard. These include timing considerations
like expected life of the source, payback period for investments, the
timing of regulatory requirements, and other unit-specific criteria.
The state may find that there are space or other physical barriers to
implementing certain HRIs at specific units. Or the state may find that
some heat rate improvement options are either not applicable or have
already been implemented at certain units. EPA understands that many of
these ``other factors'' that can affect the application of the BSER
candidate technologies distill down to a consideration of cost.
Applying a specific candidate technology at an affected EGU can be a
unit-by-unit determination that weighs the value of both the cost of
installation and the CO2 reductions. Accordingly, EPA
proposes that these factors are the types that are specific to the
facility (or class of facilities) that make a variance from the
emission guideline significantly more reasonable, as allowed under
proposed 40 CFR 60.24a(e)(3). EPA, therefore, proposes to allow states
to take these factors into account in establishing a standard of
performance for state plans in response to this emission guideline. EPA
further solicits comments on what are other factors that states should
be allowed to consider in establishing a standard of performance, per
the proposed variance provision (Comment C-23).
    As previously described, EPA proposes that states that utilize the
proposed variance provision in the new implementing regulations to
establish a less stringent standard of performance for an affected EGU
and/or a compliance schedule that is longer than that contemplated in
EPA's final emission guideline must demonstrate as part of their state
plan submission that such application of the provision meets the
criteria described in the factors in Section VII.D. EPA also recognizes
that for some sources, the criteria may result in determining that no
measures in the candidate technologies are applicable. Two examples of
this might be a unit with a very short remaining useful life or a unit
that has already implemented all of the candidate technologies of the
BSER. In cases such as these, a state should still establish a standard
of performance. In the case of a unit with a short remaining useful
life, EPA takes comment on what such a standard might look like
(Comment C-24). For instance, a state could set a standard using both
an emission rate and a compliance deadline to address this instance.
The emission standard would only be applicable if a source did not shut
down by the compliance deadline. In the case of an affected EGU that
has already implemented all of the candidate technologies, EPA would
expect that a state set a standard of performance that would reflect an
emission rate that is at least as stringent as ``business as usual''
for that source without allowing for any backsliding on performance.
EPA requests comment on these proposed treatments of a source that
either has a short remaining useful

life or has already implemented all of the HRIs identified as the BSER.
    EPA is also generally soliciting comment on whether there are
considerations in allowing states to utilize this proposed variance
provision in the new implementing regulations in response to the final
emission guideline, including the potential interaction of the
compliance flexibilities proposed in this proposal with utilization of
the provision (Comment C-25). For example, could states authorize
trading as a compliance mechanism for affected EGUs and additionally
invoke this provision, or would utilizing both trading and this
provision in establishing standards in a state plan potentially result
in such standards going beyond what section 111(d) permits (i.e., would
allowing for both trading and a variance with respect to the same
standard result in a standard that is impermissibly less stringent than
what application of the BSER in conjunction with invocation of this
provision would result in)? EPA welcomes comments on the legality and
appropriateness of utilizing this provision generally, and in the
context of specific compliance flexibilities that states may employ in
developing their plans (Comment C-26).
    Another consideration for states in determining a standard of
performance with consideration to unique aspects at an affected EGU is
the interaction between BSER and NSR. EPA is aware that the prospect of
triggering NSR, and its associated permitting requirements, may have
discouraged sources from implementing some heat rate improvements
previously. In Section VIII of this preamble, EPA discusses proposed
changes to alleviate NSR burdens for EGUs undertaking heat rate
improvements. The proposed action on NSR would ultimately impact the
level of reductions reflected in the standard of performance that a
state establishes for its sources. In considering each of the candidate
technologies, EPA believes it is appropriate for states to consider the
potential that the application of HRI may trigger NSR for some sources,
and associated NSR requirements could ultimately impact the cost of HRI
and the way the state applies standards to an affected EGU. EPA
solicits comment on any factors that may play a role in a state setting
a standard of performance with consideration to NSR (Comment C-27).
2. Averaging and Trading
    EPA solicits comment on the question of whether CAA section 111(d)
authorizes states to include averaging and trading between existing
sources in the plans they submit to meet the requirements of a final
emission guideline (Comment C-28). Section 111(d)(1) provides that
states shall submit a plan which (A) establishes standards of
performance for any existing source of certain air pollutants to which
a 111(b) standard would apply if they were new sources, and (B)
provides for the implementation and enforcement of such standards of
performance. EPA's regulations under section 111(d) must permit the
state, in applying a standard of performance to any particular existing
source under a state plan, to consider, among other factors, the
remaining useful life of that source.
    To be clear, this section discusses averaging in the context of
averaging across a facility and across multiple existing sources. For a
discussion on EPA allowing individual EGU emissions averaging over a
period of time, see Section VI.C.
    EPA is proposing to allow states to incorporate, as a part of their
plan, emissions averaging among EGUs across a single facility. The
Agency's determination of the BSER is predicated on measures that can
be implemented at the facility level and averaging across a facility is
consistent with the proposed BSER. EPA is proposing that averaging at a
facility only be applicable to affected EGUs (i.e. coal-fired steam
EGUs) for several reasons. First, if averaging could include non-
affected EGUs, this might not result in real reductions, but simply
result in averaging with lower-emitting emitting fossil-fuel-fired EGUs
such as NGCC units that would have been operating anyway. Further, even
if it did result in generation shifting to lower emitting units it is
contrary to the intention of the rule which is to focus on reducing the
rate at coal-fired EGUs when they run, not to reduce the amount they
run. Second, EPA is currently considering whether NGCC units should
become affected EGUs. How NGCC units fit into an averaging program will
be determined if a determination is made that they are affected EGUs in
this program. Third, EPA is proposing that facility-wide averaging only
apply to affected EGUs because it would mirror the BSER determination
for this rule. The EPA solicits comment on whether this type of
facility-wide averaging of affected EGUs is appropriate and whether
there should be other types of considerations involved (Comment C-29).
EPA is also taking comment on the possibility of averaging affected
EGUs with non-affected EGUs within a facility in the limited case when
they represent incremental new non-emitting capacity (Comment C-30).
This would be consistent with a compliance option such as integrated
solar.
    Notwithstanding EPA's discussion above, EPA believes that there are
both legal and practical concerns may weigh against the inclusion of
averaging and trading between existing sources in state plans at any
level more broad than averaging between sources across a particular
facility. First, EPA is concerned that averaging and trading across
affected sources (or between affected sources and non-affected sources,
e.g., wind turbines) would be inconsistent with our proposed
interpretation of the BSER as limited to measures that apply at and to
an individual source. Because state plans must establish standards of
performance--which by definition ``reflect . . . the application of the
[BSER],'' CAA section 111(a)(1)--implementation and enforcement of such
standards should correspond with the approach used to set the standard
in the first place. Applying a different analytical approach to
standard-setting may result in asymmetrical regulation (for example, a
state's implementation measures might result in a more stringent
standard than could otherwise be derived from application of the
BSER).\37\
---------------------------------------------------------------------------

    \37\ While CAA section 116 allows for states to adopt more
stringent state laws, and provides that the CAA does not preempt
such state laws, it does not provide that those more stringent
standards are federalized.
---------------------------------------------------------------------------

    Second, EPA believes that if section 111(d) authorized states to
include trading and averaging between sources in their plans, the
express provision under 111(d)(1) authorizing states to consider
existing sources' remaining useful life and other factors when
establishing and applying standards of performance could be viewed as
superfluous. Once a state takes into consideration a source's remaining
useful life and other factors (e.g., unreasonable cost of control
resulting from plant age, location, or basic process design; physical
impossibility of installing necessary control equipment; whether the
source has already undertaken some of the measures encompassed in the
BSER; or other factors), then additional compliance flexibilities may
not be required or otherwise appropriate. Indeed, averaging and trading
by themselves would appear to eliminate the need to take into
consideration a source's remaining useful life: If a source cannot meet
a performance standard (or if it is impractical or inadvisable to
require that source to do so), but if the state, in its plan, is
authorized to permit that

source to average or otherwise obtain credits for its performance with
other sources' performance, there may have been no need for Congress to
specifically require EPA to permit states to conduct a remaining-
useful-life analysis. Moreover, the source-focused language in
111(d)(1) both generally weighs in favor of EPA's proposed
interpretation of the BSER as limited to source-specific measures, and
specifically weighs against interpreting section 111(d) to authorize
state plans to include averaging and trading.
    Third, multiple practical concerns regarding emissions averaging
and trading between sources inform EPA's concerns regarding inclusion
of those mechanisms in state plans under section 111(d) and its
solicitation of comment on this issue. These concerns include the
relative complexity of development and implementation of a state plan
that includes averaging or trading, as well as the difficulty in
ensuring robust compliance with standards of performance by means of
averaging or trading. Trading programs necessitate developing adequate
means of evaluation, monitoring, and verification (EM&V) to ensure that
standards of performance are actually complied with, and these
programmatic aspects increase the burden on states in developing a
satisfactory state plan, and on sources in demonstrating compliance.
Additionally, either a mass-based or rate-based trading program
potentially brings into question of whether the state has established
standards of performance that appropriately reflect the BSER. Under a
trading program, a single source could potentially shut down or reduce
utilization to such an extent that its reduced or eliminated operation
generates adequate compliance instruments for a state's remaining
sources to meet their standards of performance without implementing any
additional measures at any other source. This compliance strategy might
undermine EPA's BSER, which EPA is proposing to determine as a menu of
heat rate improvements. It would also undermine the purpose of section
111 in a broader sense. The section is directed toward the improvement
of performance of new sources, and, through section 111(d)'s specific
procedures, of existing sources. It is not, under EPA's proposed
interpretation of section 111 (and contrary to the interpretation
underlying the CPP), directed toward the aggregate emissions of an
industrial sector as a whole, at either the state or national level.
Adopting an interpretation of section 111(d) that could lead to relying
on the shutdown or reduced operation of one or a small handful of
sources in order to cap or limit the source category's aggregate
emissions, while not resulting in the improved performance of any other
source, may be contrary to the structure and purpose of section 111 as
a whole and section 111(d) specifically.
    However, EPA recognizes that there are significant benefits of
averaging and trading across affected sources and is interested in
whether emissions averaging could be a way to provide flexibility while
still focusing on a core tenet of the BSER for this rule: Reducing
emissions per MWH of coal-fired generation. Since averaging
traditionally focuses only on the emission rate during hours of
operation, it focuses on encouraging lowering emissions per MW
generated and not on encouraging generation shifting away from the
affected source category. The EPA welcomes comment on whether there is
a way to allow trading between affected EGUs across affected sources
while not encouraging generation shifting (Comment C-31).
    EPA is soliciting comment on whether section 111(d) should be read
not to authorize states to include trading and averaging between
sources, EPA is also interested in affording flexibility to states and
sources in meeting their respective obligations and solicits public
comment on whether this proposed interpretation and conclusion is
compatible with that goal. EPA is primarily interested in comments
pertaining to whether averaging could and should be allowed for
trading, and to what degree (i.e., averaging across a state, or
trading) (Comment C-32). If a commenter believes that averaging across
multiple affected sources should be allowed as part of a state's plan,
EPA requests comment on how the averaging system should conceptually
work (Comment C-33). EPA requests comment on how allowing averaging
across multiple affected sources would or would not undermine the BSER
determination (Comment C-34). If a commenter believes that trading
should be allowed as part of a state's plan, EPA requests comment on
what type of EM&V criteria should be included for the compliance
instruments (Comment C-35). If a commenter believes that trading should
be allowed as part of a state's plan, EPA requests comment on whether
sources should be allowed to bank compliance instruments (Comment C-
36). If a commenter believes that averaging across multiple affected
sources should be allowed as part of a state's plan, EPA requests
comment on what mechanisms states would need to employ to ensure
compliance is maintained and tracked for purposes of providing for the
implementation and enforcement of the standards of performance (Comment
C-37). If a commenter believes that averaging across multiple affected
sources should be allowed as part of a state's plan, EPA requests
comment on which and/or if technology should be limited in the
averaging program (Comment C-38). If a commenter believes that
averaging across multiple affected sources should be allowed as part of
a state's plan, EPA requests comment on whether affected EGUs across
state lines could be able to average and what measures state plans
should include to provide for the implementation and enforcement of
such multi-state averaging (Comment C-39). EPA further requests comment
on the issues of statutory interpretation laid forth above, whether
they are appropriate interpretations of section 111(d) specifically and
section 111 generally, in terms of the provision's text, structure, and
purpose (Comment C-40). EPA additionally solicits comment on whether
such averaging, trading, or ``bubbling'' compliance flexibilities as
are available under other sections of title I of the CAA suggest that
such flexibilities should be afforded under state plans under section
111(d) (Comment C-41).

C. Submission of State Plans

    Section 111(d)(1) of the Clean Air Act requires that in addition to
establishing standards of performance for affected sources, such plans
must also provide for the implementation and enforcement of such
standards. As described in Section VII, EPA is proposing new
implementing regulations for section 111(d), which in part carry over a
number of the same provisions currently present in the existing
implementing regulations under 40 CFR part 60, subpart B. EPA is
proposing that these provisions apply for states to meet the
requirement that state plans include implementation and enforcement
measures. EPA requests comment on whether these provisions are
appropriate to apply for purposes of meeting obligations under a final
rule in response to this proposal, or whether other implementation or
enforcement measures should be required (Comment C-42).
    Additionally, EPA is proposing that states must include appropriate
monitoring, reporting, and recordkeeping requirements to ensure that
state plans adequately provide for the implementation and enforcement
of standards of performance. Each state will have the flexibility to
design a

monitoring program for assessing compliance with the standards of
performance identified in the plan. Most potentially affected coal-
fired EGUs already continuously monitor CO2 emissions, heat
input, and gross electric output and report hourly data to EPA under 40
CFR part 75. Accordingly, if a state plan establishes a standard of
performance for a unit's CO2 emissions rate (e.g., lb/MWh),
EPA proposes that states may elect to use data collected by EPA under
40 CFR part 75 to meet the required monitoring, reporting, and
recordkeeping requirements under this emission guideline.
    EPA also notes that states have it within their discretion to
establish averaging times for affected EGUs. Averaging the emission
rate of an affected EGU over different time periods may have different
effects on the demonstration of compliance for an EGU to the state. EPA
solicits comment on whether there should be any bounds or consideration
to the averaging times that states are allowed to consider (Comment C-
43).
    EPA is further proposing to apply generally the proposed new
implementing regulations for timing, process and required components
for state plan submissions and implementation for state plans required
under for affected EGUs. The new implementing regulations are described
in detail in Section VII. In addition to application of the
implementing regulations to state plans in response to a final emission
guideline under this proposal, EPA is also proposing that state plans
be comprehensively submitted electronically through an EPA provided
platform. EPA solicits comment on whether electronic submittals are
appropriate and less burdensome to states (Comment C-44) and whether
this should be the sole means of submitting state plans (Comment C-45).
EPA believes that electronic submittals will ease the burden of state
plan submittals for both states and EPA.
    In section 60.5740a of the regulatory text for this proposal, there
is description and list of what a state plan must include. EPA solicits
comment on whether this list is comprehensive to submit a state plan
(Comment C-46).

VII. Proposed New Implementing Regulations for Section 111(d) Emission
Guidelines

    Distinct from EPA's proposed emission guidelines for the regulation
of GHGs for existing affected EGUs, EPA is also proposing to promulgate
new regulations to implement section 111(d) regulations. As previously
described, the current implementing regulations at 40 CFR part 60,
subpart B were promulgated in 1975 [See 40 FR 53346.]. Section
111(d)(1) of the CAA explicitly requires that EPA establish regulations
similar to those under section 110 of the CAA to establish a procedure
for states to submit plans to EPA. The implementing regulations have
not been significantly revised since their original promulgation in
1975. Notably, the implementing regulations do not reflect section
111(d) in its current form as amended by Congress in 1977, and do not
reflect section 110 in its current form as amended by Congress in 1990.
Accordingly, EPA believes that certain portions of the implementing
regulations do not appropriately align with section 111(d), contrary to
that provision's mandate that EPA's regulations be ``similar'' to the
provisions under section 110. Therefore, EPA is proposing to promulgate
new implementing regulations that are in accordance with the statute in
its current form. As previously discussed, agencies have the ability to
revisit prior decisions, and EPA believes it is appropriate to do so
here in light of the potential mismatch between certain provisions of
the implementing regulations and the statute.\38\
---------------------------------------------------------------------------

    \38\ The authority to reconsider prior decisions exists in part
because EPA's interpretations of statutes it administers ``[are not]
instantly carved in stone,'' but must be evaluated ``on a continuing
basis.'' Chevron U.S.A. Inc. v. NRDC, Inc., 467 U.S. 837, 863-64
(1984). Indeed, ``[a]gencies obviously have broad discretion to
reconsider a regulation at any time.'' Clean Air Council v. Pruitt,
862 F.3d 1, 8-9 (DC Cir. 2017).
---------------------------------------------------------------------------

    EPA is proposing to largely carry over the current implementing
regulations in 40 CFR part 60, subpart B to a new subpart that will be
applicable to EPA's emission guidelines and state plans or federal
plans associated with such emission guidelines, both those contemplated
in this proposal and for any others that may be published or
promulgated either concurrently or subsequent to final promulgation of
the new implementing regulations. For purposes of regulatory certainty,
EPA believes it is appropriate to apply these new implementing
regulations prospectively, and retain the existing implementing
regulations as applicable to section 111(d) emission guidelines and
associated state plans that were promulgated previously. Additionally,
the existing implementing regulations at 40 CFR part 60, subpart B are
applicable to regulations promulgated under CAA section 129, and
associated state plans. EPA intends to retain the applicability of the
existing implementing regulations with respect to rules and state plans
associated with section 129, and the proposed new implementing
regulations are intended to apply only to section 111(d) regulations
and associated state plans issued solely under the authority of section
111(d). EPA requests comments on this proposed applicability of both
the existing and new implementing regulations (Comment C-47).
    EPA is aware that there are a number of cases where state plan
submittal and review processes are still ongoing for existing 111(d)
emission guidelines. Because EPA is proposing changes to the timing
requirements to more closely align 111(d) with both general SIP
submittal timing requirements and because of the realities of how long
these actions take, EPA is proposing to apply the changes to timing
requirements to both emission guidelines published after the new
implementing regulations are finalized, and to all ongoing emission
guidelines already published under section 111(d). EPA is soliciting
comment on the proposed timing requirements for prospective emission
guidelines under the new implementing regulations and the alignment of
ongoing emission guidelines by amending their respective regulatory
text to incorporate the new timing requirements. (Comment C-48). EPA is
proposing to apply the timing changes to all ongoing 111(d) regulations
for the same reasons that EPA is changing the timing requirements
prospectively. Based on years of experience with working with states to
develop SIPs under section 110, EPA believes that given the comparable
amount of work, effort, coordination with sources, and the time
required to develop state plans that more time is necessary for the
process. Giving states three years to develop state plans is more
appropriate than the nine months provided for under the existing
implementing regulations considering the workload. These practical
considerations regarding the time needed for state plan development are
also applicable and true for recent emission guidelines where the state
plan submittal and review process are still ongoing.
    For those provisions that are being carried over from the existing
implementing regulations into the new implementing regulations, EPA
believes the placement of those provisions under a new subpart is a
ministerial action that does not require reopening the substance of
those provisions for notice and comment. EPA is not intending to
substantively change those provisions from their original promulgation,
and continues to rely on the record under

which they were promulgated. Therefore, EPA is not soliciting comment
on the following provisions, which remain substantively the same from
their original promulgation: 40 CFR 60.21a(a)-(d), (g)-(j)
(Definitions); 60.22a(a), 60.22a(b)(1)-(3), (b)(5), (c) (Publication of
emission guidelines); 60.23a(a)-(c), (d)(3)-(5), (e)-(h) (Adoption and
submittal of State plans; public hearings); 60.24a(a)-(d), (f)
(Standards of performance and compliance schedules); 60.25a (Emission
inventories, source surveillance, reports); 60.26a (Legal authority);
60.27a(a), (e)-(f) (Actions by the Administrator); 60.28a(b) (Plan
revisions by the State); 60.29a (Plan revisions by the Administrator).
    EPA is also sensitive to potential confusion over whether these new
implementing regulations would apply to an emission guideline
previously promulgated or to state plans associated with a prior
emission guideline, so EPA is proposing that the new implementing
regulations are applicable only to emission guidelines and associated
plans developed after promulgation of this regulation, including the
emission guideline being proposed as part of this action for GHGs and
existing affected EGUs. EPA solicits comment on this proposed
applicability of the new implementing regulations (Comment C-49).
    While EPA is carrying over a number of requirements from the
existing implementing regulations, EPA is proposing specific changes to
better align the regulations with the statute. These changes are
reflected in the proposed regulatory text for this action, and EPA
solicits comments on both the substance of these changes and the
proposed regulatory text (Comment C-50). These changes include:
     An explicit provision allowing a specific emission
guideline to supersede the requirements of the new implementing
regulations;
     Changes to the definition of ``emission guideline'';
     Updated timing requirements for the submission of state
plans;
     Updated timing requirements for EPA's action on state
plans;
     Updated timing requirements for EPA's promulgation of a
federal plan;
     Updated timing requirement for when increments of progress
must be included as part of a state plan;
     Completeness criteria and a process for determining
completeness of state plan submissions similar to CAA section 110(k)(1)
and (2);
     Updated definition replacing ``emission standard'' with
``standard of performance;''
     Usage of the internet to satisfy certain public hearing
requirements;
     No longer making a distinction between public health-based
and welfare-based pollutants in an emission guideline; and,
     Updating the variance provision to be consistent with CAA
section 111(d)(1)(B).
    EPA is proposing to include a provision in the new implementing
regulations that expressly allows for any emission guideline to
supersede the applicability of the implementing regulations as
appropriate. EPA cannot foresee all of the unique circumstances and
factors associated with a particular future emission guideline, and
therefore different requirements may be necessary for a particular
111(d) rulemaking that EPA cannot envision at this time. The proposed
provision is parallel to one contained in the 40 CFR part 63 General
Provisions implementing section 112 of the CAA. EPA solicits comments
on the inclusion of such provision as part of the implementing
regulations for section 111(d) (Comment C-51).
    Because EPA is updating the implementing regulations and many of
the provisions from the existing implementing regulations are being
carried over, EPA wants to be clear and transparent with regard to the
changes that are being made to the implementing regulations. As such,
EPA is providing Table 4 that summarizes the changes being made. EPA
also has included in the docket for this action a red-line-strike-out
of the changes that are being proposed.

       Table 4--Summary of Changes to the Implementing Regulations
------------------------------------------------------------------------
                                              Existing implementing
 New implementing regulations--subpart    regulations--subpart B for all
   Ba for all future 111(d)  emission     previously  promulgated 111(d)
               guidelines                      emission guidelines
------------------------------------------------------------------------
Explicit authority for a new 111(d)      No explicit authority.
 emission guideline requirement to
 supersede these implementing
 regulations.
Use of term ``guideline document'';      Use of term ``emission
 does not require EPA to provide a        guideline''; arguably required
 presumptive emission standard.           EPA to provide a presumptive
                                          emission standard.
Use of term ``standard of performance''  Use of term ``emission
                                          standard''.
``Standard of performance'' allows       ``Emission standard'' allows
 states to include design, equipment,     states to prescribe equipment
 work practice, or operational            specifications when EPA
 standards when EPA determines it's not   determines it's clearly
 feasible to prescribe or enforce a       impracticable to establish an
 standard pf performance, consistent      emission standard.
 with the requirements of CAA section
 111(h).
State submission timing: 3 years from    State submission timing: 9
 promulgation of a final emission         months from promulgation of a
 guideline.                               final emission guideline.
EPA action on state plan submission      EPA action on state plan
 timing: 12 months after determination    submission timing: 4 months
 of completeness.                         after submittal deadline.
Timing for EPA promulgation of a         Timing for EPA promulgation of
 federal plan, as appropriate: 2 years    a federal plan, as
 after finding of failure to submit a     appropriate: 6 months after
 complete plan, or disapproval of state   submittal deadline.
 plan.
Increments of progress are required if   Increments of progress are
 compliance schedule for a state plan     required if compliance
 is longer than 24 months after the       schedule for a state plan is
 plan is due.                             longer than 12 months after
                                          the plan is due.
Completeness criteria and process for    No previous discussion.
 state plan submittals.
Usage of the internet to satisfy         No previous discussion.
 certain public hearing requirements.
No distinction made in treatment         Different provisions for health-
 between health-based and welfare-based   based and welfare-based
 pollutants; variance provision           pollutants; state plans must
 available regardless of type of          be as stringent as EPA's
 pollutant.                               emission guideline for health-
                                          based pollutants unless
                                          variance provision is invoked.
------------------------------------------------------------------------

A. Changes to the Definition of ``Emission Guideline''

    The existing implementation regulations under 40 CFR 60.21(e)
contain a definition of ``emission guideline'', defining it as a
guideline which reflects the degree of emission reduction achievable
through the application of the best system of emission reduction which
(taking into account the cost of such reduction) the Administrator has
determined has been adequately demonstrated for designated facilities.
This definition additionally references that an emission guideline may
be set forth in 40 CFR part 60, subpart C or a ``final guideline
document'' published under 40 CFR 60.22(a). While the implementing
regulations do not define the term ``final guideline document,'' 40 CFR
60.22 generally contains a number of requirements pertaining to the
contents of guideline documents, which are intended to provide
information for the development of state plans. See 40 CFR 60.22(b).
The preambles for both the proposed and final existing implementing
regulations suggest that an ``emission guideline'' would be a guideline
provided by EPA that presumptively reflects the degree of emission
limitation achievable by the BSER. EPA believes it is important to at
least provide information on such degree of emission limitation in
order to guide states in their establishment of standards of
performance as required under CAA section 111(d). However, EPA does not
believe anything in CAA section 111(a)(1) or section 111(d) compels EPA
to provide a presumptive emission standard that reflects the degree of
emission limitation achievable by application of the BSER. Accordingly,
as part of the new implementing regulations, EPA proposes to re-define
``emission guideline'' as a final guideline document published under
Sec.  60.22a(a), which includes information on the degree of emission
reduction achievable through the application of the best system of
emission reduction which (taking into account the cost of such
reduction and any nonair quality health and environmental impact and
energy requirements) EPA has determined has been adequately
demonstrated for designated facilities.

B. Updates to Timing Requirements

    The timing requirements in the existing implementing regulations
for state plan submissions, EPA's action on state plan submissions and
EPA's promulgation of federal plans generally track the timing
requirements for SIPs and federal implementation plans (FIPs) under the
1970 version of the Clean Air Act. Congress revised these SIP/FIP
timing requirements in section 110 as part of the 1990 Clean Air Act
amendments. EPA proposes to accordingly update the timing requirements
regarding state and federal plans under section 111(d) to be consistent
with the current timing requirements for SIPs and FIPs under section
110. The existing implementing regulations at 40 CFR 60.23(a)(1)
requires state plans to be submitted to EPA within nine months after
publication of a final emission guideline, unless otherwise specified
in an emission guideline. EPA is proposing, as part of new implementing
regulations, to provide states with three years after the notice of the
availability of the final emission guideline to adopt and submit a
state plan to EPA. Because of the amount of work, effort, and time
required for developing state plans that include unit-specific
standards, and implementation and enforcement measures for such
standards, EPA believes that extending the submission date of state
plans from nine months to three years is appropriate. Because states
have considerable flexibility in implementing section 111(d), this
timing also allows states to interact and work with the Agency in the
development of state plan and minimize the chances of unexpected issues
arising that could slow down eventual approval of state plans. EPA
solicits comment on generally providing states with three years after
the publication of the final emission guidelines, and solicits comment
on any other timeframes that may be appropriate for submission of state
plans given the flexibilities EPA intends to provide through its
emission guidelines (Comment C-52). EPA also proposes to give itself
discretion to determine in a specific emission guideline that a shorter
time period for the submission of state plans particular to that
emission guideline is appropriate. Such authority is consistent with
CAA section 110(a)(1)'s grant of authority to the Administrator to
determine that a period shorter than three years is appropriate for the
submission of particular SIPs implementing the NAAQS.
    Following submission of state plans, EPA will review plan
submittals to determine whether they are ``satisfactory'' as per CAA
section 111(d)(2)(A). Given the flexibilities section 111(d) and
emission guidelines generally accord to states, and EPA's prior
experience on reviewing and acting on SIPs under section 110, EPA is
proposing to extend the period for EPA review and approval or
disapproval of plans from the four-month period provided in EPA
implementing regulations to a twelve-month period after a determination
of completeness (either affirmatively by EPA or by operation of law,
see below for EPA's proposal on completeness) as part of the new
implanting regulations. This timeline will provide adequate time for
EPA to review plans and follow notice-and-comment rulemaking procedures
to ensure an opportunity for public comment on EPA's proposed action on
a state plan. EPA solicits comment on extending the timing of EPA's
action on a state plan from 4 months of when a plan is due to 12 months
from determination that a state plan submission is complete (Comment C-
53).
    EPA additionally proposes to extend the timing from six months in
the existing implementing regulations to two years, as part of new
implementing regulations, for EPA to promulgate a federal plan for
states that fail to submit an approvable state plan in response to a
final emission guideline. This two-year timeline is consistent with the
FIP deadline under section 110(c) of the CAA. EPA solicits comment on
change in timing for EPA to promulgate a federal plan from six months
to two years (Comment C-54). EPA solicits comment on extending deadline
for promulgating a final (i.e., after appropriate notice and comment)
federal plan for a state to two years after either (1) EPA finds that a
state has failed to submit a complete plan, or (2) EPA disapproves a
state plan submission (Comment C-55).

C. Compliance Deadlines

    The existing implementing regulations require that any compliance
schedule for state plans extending more than 12 months from the date
required for submittal of the plan must include legally enforceable
increments of progress to achieve compliance for each designated
facility or category of facilities. 40 CFR 60.24(e)(1). However, as
described in section VII.B, the EPA is proposing certain updates to the
timing requirements for the submission of, and action on, state plans.
Consequently, it follows that the requirement for increments of
progress should also be updated in order to align with the proposed new
timelines. Given that the EPA is proposing a period of up to 18 months
for its action on state plans (i.e. 12 months from the determination
that a state plan submission is complete, which could occur up to six
months after receipt of the state plan), EPA

believes it is appropriate that the requirement for increments of
progress should attach to plans that contain compliance periods that
are longer than the period provided for EPA's review of such plans.
This way, sources subject to a plan have more certainty that their
regulatory compliance obligations would not change between the period
between when a state plan is due and when EPA acts on a plan.
Accordingly, EPA proposes that increments of progress will be included
for state plans that contain compliance schedules longer than 24 months
from the date when state plans are due for a particular emission
guideline. EPA solicits comments on whether this 24-month component, or
some other period of time, is appropriate as a trigger for requiring
increments of progress as part of a plan's compliance schedule.

D. Completeness Criteria

    Similar to requirements regarding determinations of completeness
under section 110(k)(1), EPA is proposing completeness criteria that
provide the Agency with a means to determine whether a state plan
submission includes the minimum elements necessary for EPA to act on
the submission. EPA would determine completeness simply by comparing
the state's submission against these completeness criteria. In the case
of SIPs under CAA section 110(k)(1), EPA promulgated completeness
criteria in 1990 at Appendix V to 40 CFR part 51 (55 FR 5830; February
16, 1990). EPA proposes to adopt criteria similar to the criteria set
out at section 2.0 of Appendix V for determining the completeness of
submissions under CAA section 111(d).
    EPA notes that the addition of completeness criteria in the
framework regulations does not alter any of the submission requirements
states already have under any applicable emission guideline. The
completeness criteria proposed by this action are those that would
generally apply to all plan submissions under section 111(d), but
specific emission guidelines may supplement these general criteria with
additional requirements.
    The completeness criteria that EPA is proposing in this action can
be grouped into administrative materials and technical support. For
administrative materials, the completeness criteria mirror criteria for
SIP submissions because the two programs have similar administrative
processes. Under these criteria, the submittal must include the
following:
    (1) A formal letter of submittal from the Governor or the
Governor's designee requesting EPA approval of the plan or revision
thereof.
    (2) Evidence that the state has adopted the plan in the state code
or body of regulations. That evidence must include the date of adoption
or final issuance as well as the effective date of the plan, if
different from the adoption/issuance date.
    (3) Evidence that the state has the necessary legal authority under
state law to adopt and implement the plan.
    (4) A copy of the official state regulation(s) or document(s)
submitted for approval and incorporated by reference into the plan,
signed, stamped and dated by the appropriate state official indicating
that they are fully adopted and enforceable by the state. The effective
date of the regulation or document must, whenever possible, be
indicated in the document itself. The state's electronic copy must be
an exact duplicate of the hard copy. For revisions to the approved
plan, the submission must indicate the changes made to the approved
plan by redline/strikethrough.
    (5) Evidence that the state followed all of the procedural
requirements of the state's laws and constitution in conducting and
completing the adoption/issuance of the plan.
    (6) Evidence that public notice was given of the plan or plan
revisions with procedures consistent with the requirements of 40 CFR
60.23, including the date of publication of such notice.
    (7) Certification that public hearing(s) were held in accordance
with the information provided in the public notice and the state's laws
and constitution, if applicable and consistent with the public hearing
requirements in 40 CFR 60.23.
    (8) Compilation of public comments and the state's response
thereto.
    The technical support required for all plans must include each of
the following:
    (1) Description of the plan approach and geographic scope.
    (2) Identification of each designated facility; identification of
emission standards for each designated facility; and monitoring,
recordkeeping, and reporting requirements that will determine
compliance by each designated facility.
    (3) Identification of compliance schedules and/or increments of
progress.
    (4) Demonstration that the state plan submission is projected to
achieve emissions performance under the applicable emission guidelines.
    (5) Documentation of state recordkeeping and reporting requirements
to determine the performance of the plan as a whole.
    (6) Demonstration that each emission standard is quantifiable, non-
duplicative, permanent, verifiable, and enforceable.
    EPA intends that these criteria be generally applicable to all CAA
section 111(d) plans submitted on or after final new implementing
regulations are promulgated, with the proviso that specific emission
guidelines may provide otherwise.
    Consistent with the requirements of CAA section 110(k)(1)(B) for
SIPs, EPA is proposing to determine whether a state plan is complete
(i.e., meets the completeness criteria) no later than 6 months after
the date, if any, by which a state is required to submit the plan. EPA
further proposes that any plan or plan revision that a State submits to
EPA, and that has not been determined by EPA by the date 6 months after
receipt of the submission to have failed to meet the minimum
completeness criteria, shall on that date be deemed by operation of law
to be a complete state plan. Then, as previously discussed, EPA is
relatedly proposing to act on a state plan submission within 12 months
after determining a plan is complete, either through an affirmative
determination or by operation of law.
    When plan submissions do not contain the minimum elements, EPA is
proposing to find that a state has failed to submit a complete plan
through the same process as finding a state has made no submission at
all. Specifically, EPA would notify the state that its submission is
incomplete and therefore, that it has not submitted a required plan,
and EPA would also publish a finding of failure to submit in the
Federal Register, which triggers EPA's obligation to promulgate a
federal plan for the state. This determination that a submission is
incomplete and the state has failed to submit a plan is ministerial in
nature and requires no exercise of discretion or judgment on the
Agency's part, nor does it reflect a judgment on the eventual
approvability of the submitted portions of the plan.

E. Standard of Performance

    As previously described, the implementing regulations were
promulgated in 1975 and effectuated the 1970 version of the Clean Air
Act as at it existed at that time. The 1970 version of section 111(d)
required state plans to include ``emission standards'' for existing
sources, and consequently the implementing regulations refer to this
term. However, as part of the 1977 amendments to the CAA, Congress
replaced the term ``emission standard'' in section 111(d) with
``standard of performance.'' EPA has not since

revised the implementing regulations to reflect this change in
terminology. For clarity's sake and to better track with statutory
requirements, EPA is proposing to include a definition of ``standards
of performance'' as part of the new implementing regulations, and to
consistently refer to this term as appropriate within those regulations
in lieu of referring to an ``emission standard.'' Additionally, the
current definition of ``emission standard'' in the implementing
regulations is incomplete and requires clean-up regardless. For
example, the definition encompasses equipment standards, which is an
alternative form of standard provided for in CAA section 111(h) under
certain circumstances. However, section 111(h) provides for other forms
of alternative standards, such as work practice standards, which are
not covered by the existing regulatory definition of ``emission
standard.'' Furthermore, the definition of ``emission standard''
encompasses allowance systems, a reference that was added as part of
EPA's Clean Air Mercury Rule. 70 FR 28605. This rule was vacated by the
D.C. Circuit, and therefore this added component to the definition of
``emission standard'' had no legal effect because of the court's
vacatur. Consistent with the court's opinion, EPA signaled its intent
to remove this reference as part of its Mercury Air Toxics rule. 77 FR
9304. However, in the final regulatory text of that rulemaking, EPA did
not take action removing this reference, and it remains as a vestigial
artifact.
    For these reasons, EPA is proposing to replace the existing
definition of ``emission standard'' with a definition of ``standard of
performance'' that tracks with the definition provided for under CAA
section 111(a)(1). This means a standard of performance for existing
sources would be defined as a standard for emissions or air pollutants
which reflects the degree of emission limitation achievable through the
application by the state of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated. EPA is
further proposing to incorporate into a definition of standard of
performance CAA section 111(h)'s allowance for design, equipment, work
practice, or operational standards as alternative standards of
performance under the statutorily prescribed circumstances. Currently,
the existing implanting regulations allow for state plans to prescribe
equipment specifications when emission rates are ``clearly
impracticable'' as determined by EPA. CAA section 111(h)(1) by contrast
allows for alternative standards such as equipment standards to be
promulgated when standards of performance are ``not feasible to
prescribe or enforce,'' as those terms are defined under CAA section
111(h)(2). Given the potential discrepancy between the conditions under
which alternative standards may be established based on the different
terminology used by the statute and existing implementing regulations,
EPA proposes to use the ``not feasible to prescribe or enforce''
language as the condition for the new implementing regulations under
which alternative standards may be established.
    EPA solicits comment on all of these means of tracking and
incorporating the section 111(a)(1) and 111(h) for purposes of a
regulatory definition of ``standard of performance,'' and requests
comment on any other considerations for such definition (Comment C-56).

F. Variance

    EPA believes that the existing implementing regulations'
distinction between public health-based and welfare-based pollutants is
not a distinction unambiguously required under section 111(d) or any
other applicable provision of the statute. EPA does not believe the
nature of the pollutant in terms of its impacts on health and/or
welfare impact the manner in which it is regulated under this
provision. Particularly, 60.24(c) requires that for health-based
pollutants, a state's standards of performance must be of equivalent
stringency to EPA's emission guidelines. However, section 111(d)(1)(B)
requires that EPA's regulations must permit states to take into
account, among other factors, an affected source's remaining useful
life when establishing an appropriate standard of performance. In other
words, Congress explicitly envisioned under section 111(d)(1)(B) that
states could implement standards of performance that vary from EPA's
emission guidelines under appropriate circumstances. Notably, the
implementing regulations at 40 CFR 60.24(f) contain a variance
provision that allow for states to also apply less stringent standards
on sources under certain circumstances. However, the variance provision
attaches to the distinction between health-based and welfare-based
pollutants, and is available to the states only under EPA's discretion.
The variance provision was also promulgated prior to Congress's
addition of the requirement in section 111(d)(1)(B) that EPA permit
states to take into account remaining useful life and other factors,
and the terms of the regulatory provision and statutory provision do
not match one another, meaning that the variance provision may not
account for all of the factors envisioned under section 111(d)(1)(B).
Given all of these factors, EPA is proposing to not make a distinction
between health-based and welfare-based pollutants and attach
requirements contingent upon this distinction as part of the new
implementing regulations. EPA is also proposing a new variance
provision to permit states to take into account remaining useful life,
among other factors, in establishing a standard of performance for a
particular affected source, consistent with section 111(d)(1)(B).
    Given that there are unique attributes and aspects of each affected
source, these other factors may be ones that influence decisions to
invest in technologies to meet a potential performance standard. Such
other factors may include timing considerations like expected life of
the source, payback period for investments, the timing of regulatory
requirements, and other unit-specific criteria. EPA solicits comments
on how a new variance provision can permit states to take into account
remaining useful life and other factors, and what other factors might
appropriately be (Comment C-57). EPA is also soliciting comment on
whether the factors outlined in the existing variance provision at 40
CFR 60.24(f) are appropriate to carry over to a new variance provision
if they adequately give meaning to the requirements of section
111(d)(1)(B) (Comment C-58). Those factors are:
     Unreasonable cost of control resulting from plant age,
location, or basic process design;
     Physical impossibility of installing necessary control
equipment; or
     Other factors specific to the facility (or class of
facilities) that make application of a less stringent standard or final
compliance time significantly more reasonable.

VIII. New Source Review Permitting of HRIs

A. What is New Source Review?

    The NSR program is a preconstruction permitting program that
requires stationary sources of air pollution to obtain permits prior to
beginning construction. The NSR program applies both to new
construction and to modifications of existing sources. New construction
and modifications of

stationary sources that emit or increase emissions of ``regulated NSR
pollutants'' \39\ at or above certain thresholds defined in either the
CAA or the NSR regulations are subject to major NSR requirements, while
smaller emitting sources and modifications may be subject to minor NSR
requirements.\40\ A pollutant is a ``regulated NSR pollutant'' if it
meets at least one of four requirements, which are, in general, any
pollutant for which EPA has promulgated a NAAQS or a NSPS, certain
ozone depleting substances, and ``[a]ny pollutant that otherwise is
subject to regulation under the Act.'' See, e.g., 40 CFR 52.21(b)(50).
For purposes of NSR, hazardous air pollutants are excluded. Id.
---------------------------------------------------------------------------

    \39\ 40 CFR 51.165(a)(1)(xxxvii), 40 CFR 52.21(b)(50).
    \40\ The one exception to this approach is for GHG. Regardless
of the GHG emissions resulting from construction of a new source or
modification, the source will not be required to obtain a major NSR
permit unless the emissions of another regulated NSR pollutant equal
or exceed the major NSR threshold. 80 FR 50199 (August 19, 2015);
Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427 (2015).
---------------------------------------------------------------------------

    NSR permits for major sources emitting pollutants for which the
area is classified as attainment or unclassifiable, and for other
pollutants regulated under the CAA, are referred to as prevention of
significant deterioration (PSD) permits. NSR permits for major sources
emitting pollutants for which the area is in nonattainment are referred
to as nonattainment NSR (NNSR) permits. The pollutant(s) at issue and
the air quality designation of the area where the facility is located
or proposed to be built determine the specific permitting
requirements.\41\ Among other requirements, the CAA requires sources
subject to PSD to meet emission limits based on Best Available Control
Technology (BACT) as specified by section 165(a)(4), and the CAA
requires sources subject to NNSR to meet the Lowest Achievable
Emissions Rate (LAER) pursuant to section 173(a)(2). These technology
requirements for major NSR permits are not predetermined by a rule or
state plan, but are case-by-case determinations made by the permitting
authority.\42\ Other requirements to obtain a major NSR permit vary
depending on whether the source needs a PSD or an NNSR permit.
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    \41\ PSD applies on a regulated NSR pollutant-by-regulated NSR
pollutant basis. The PSD requirements do not apply to regulated NSR
pollutants for which the area is designated as nonattainment. NNSR
could only be applicable with regard to a source's emissions of
criteria pollutants, as those are the only pollutants with respect
to which areas are designated as attainment or nonattainment.
    \42\ The term `best available control technology' means an
emission limitation . . . which the permitting authority, on a case
by case basis, taking into account energy, environmental, and
economic impacts and other costs, determines is achievable for such
facility . . .'' 42 U.S.C. 7479(3); see e.g., supra Section III.C;
PSD and Title V Permitting Guidance for Greenhouse Gases (Mar.
2011), available at https://www.epa.gov/sites/production/files/2015-07/documents/ghgguid.pdf.
---------------------------------------------------------------------------

    The test to determine whether a source is subject to major NSR
differs for new stationary sources and for modifications to existing
stationary sources. A new source is subject to major NSR permitting
requirements if its potential to emit (PTE) any regulated NSR pollutant
equals or exceeds the statutory emission threshold. For sources in
attainment areas, the major source threshold is either 100 or 250 tons
per year, depending on the type of source.\43\ The major source
threshold for sources in nonattainment areas is generally 100 tons per
year, although lower thresholds apply to sources located in areas
classified at higher levels of nonattainment.
---------------------------------------------------------------------------

    \43\ The NSR major source and major modification emission
thresholds are expressed in short tons (i.e., 2000 lbs.).
---------------------------------------------------------------------------

    A modification at an existing major source is subject to major NSR
permitting requirements when it is a ``major modification,'' which
occurs when a source undertakes a physical change or change in method
of operation (i.e., a ``project'') \44\ that would result in both (1) a
significant emissions increase from all emission units that are part of
the project, and (2) a significant net emissions increase from the
source, which is determined by a source-wide analysis that considers
creditable emission increases and decreases occurring at the source as
a result of other projects over a 5-year contemporaneous period. See,
e.g., 40 CFR 52.21(b)(2)(i). For this analysis, the NSR regulations
define emissions rates that are ``significant'' for each NSR pollutant.
See, e.g., 40 CFR 52.21(b)(23). In calculating the emissions increase
that will result from a proposed project, existing NSR regulations
require a comparison of the ``projected actual emissions'' (PAE) to the
``baseline actual emissions'' (BAE). The PAE is currently defined as
the maximum annual rate that the modified unit is projected to emit a
pollutant in any one of the 5 years (or 10 years if the design capacity
increases) after the project, excluding any increase in emissions that
(1) is unrelated to the project, and (2) could have been accommodated
during the baseline period (commonly referred to as the ``demand growth
exclusion''). See, e.g., 40 CFR 52.21(b)(41). For electric utility
steam generating units (EUSGU), the BAE is defined as the average
annual rate of actual emissions during any 24-month period within the
last 5 years. See, e.g., 40 CFR 52.21(b)(48)(i). For non-EUSGUs, the
BAE is defined the same as for EUSGUs, except that the 24-month period
can be within the last 10 years. See, e.g., 40 CFR
52.21(b)(48)(ii).\45\
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    \44\ The NSR regulations expressly exempt certain activities
from being considered a physical change or change in method of
operation, including routine maintenance, repair and replacement,
increases in hours of operation or production rate, and change in
ownership. See, e.g., 40 CFR 52.21(b)(2)(iii).
    \45\ While we are discussing federal regulations, a state or
local permitting authority may have different regulations to define
NSR applicability if approved by EPA into its implementation plan.
---------------------------------------------------------------------------

    As noted above, new stationary sources and modifications of
stationary sources that do not require a major NSR permit may instead
require a minor NSR permit prior to construction. Minor NSR permits are
primarily issued by state and local air agencies. Minor NSR
requirements are approved into an implementation plan in order to
achieve and maintain national ambient air quality standards (NAAQS).
See CAA section 110(a)(2)(C).\46\ The Act, EPA regulations and EPA
guidance each specify minor NSR requirements, although the requirements
are not as prescriptive as those covering the major NSR program. This
reduced specificity affords agencies flexibility in designing their
minor NSR programs. Since the minor NSR program deals with smaller
sources and smaller increases in air pollution, the control
requirements that are identified for a minor NSR permit tend to be less
stringent than a BACT or LAER requirement for a major NSR permit. In
addition, the time to process a permit for a minor NSR source or a
minor modification is generally faster than for a major NSR permit, due
to having fewer requirements.
---------------------------------------------------------------------------

    \46\ EPA's regulations at 40 CFR 51.160-51.169 apply to state
permitting programs; however, these provisions cover both major and
minor sources. The requirements that apply to strictly minor sources
are limited to sections 51.160-51.164. In addition, in 2011 EPA
created the Indian country minor NSR permitting program, which
authorizes EPA regional offices to issue minor source permits on
tribal lands. These regulations are located at 40 CFR 49.101-49.104
and 49.151-49.164.
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B. Interaction of NSR and the ACE Rule

    Since emission guidelines that are established pursuant to CAA
section 111(d) apply to units at existing sources, the way in which the
NSR programs treat modifications of existing sources is implicated by
implementation of a CAA section 111(d) program. Specifically, in
complying with the emission guidelines, a state agency may develop

a CAA section 111(d) plan that results in an affected source
undertaking a physical or operational change. As explained above, under
the NSR program undertaking a physical or operational change may
require that the source obtain a preconstruction permit for the
proposed change, with the type of NSR permit depending on the amount of
the emissions increase resulting from the change and the air quality at
the location of the source. Thus, a source that is adding equipment or
otherwise making changes to its facility, on either its own volition or
to comply with a national or state level requirement, will typically
need some type of NSR permit prior to making such changes to its
facility. EPA sought to exempt environmentally beneficially pollution
control projects from NSR requirements in a 2002 rule that codified
longstanding EPA policy, but this rule was struck down in court. New
York v. EPA, 413 F.3d 3, 40-42 (DC Cir. 2005) (New York I).
    With respect to the proposed action, should it be promulgated,
states will be called upon to develop a section 111(d) plan that
evaluates BSER technologies for each of their EGU sources and assigns
emission reduction compliance obligations to their affected EGUs.
Assuming the promulgated action adopts the same form as this proposal,
the state may require a source with an affected EGU to achieve a HRI of
a specified percentage. As described in Section VI.B of this preamble,
a HRI project is designed to lower the heat rate of the EGU, which
correlates to the unit consuming less fuel per kWh and emitting lower
amounts of CO2 (and other air pollutants) per kWh generated
as compared to a less efficient unit. Along with this increase in
energy efficiency, the EGU which undergoes the HRI project will
typically experience greater unit availability and reliability, all of
which contribute to lower operating costs. EGUs that operate at lower
costs are generally preferred in the dispatch order by the system
operator over units that have higher operational costs,\47\ and EPA's
regulatory impact analysis (RIA) for this action (located in the
docket) shows that improving an EGU's heat rate will lead to increased
generation due to its improved efficiency and relative economics. As
the EGU increases its generation, to the extent the EGU operates beyond
its historical levels by a meaningful amount, it could result in an
increase in emissions on an annual basis, as calculated pursuant to the
current NSR regulations. Specifically, if a source is undertaking a HRI
project and its future emissions (i.e., PAE) are projected to increase
above its historical emissions (i.e., BAE) in an amount greater than
the relevant ``significant'' level, the source could be required to
obtain a major NSR permit for the modification.
---------------------------------------------------------------------------

    \47\ See, e.g., Comments of Florida Municipal Elec Association
on the U.S. Environmental Protection Agency's ANPRM entitled,
``State Guidelines for Greenhouse Gas Emissions from Existing
Electric Utility Generating Units,'' 82 FR 61507 (December 28, 2017)
at 11 (EPA-HQ-OAR-2017-0545-0155); see also https://www.eia.gov/todayinenergy/detail.php?id=7590.
---------------------------------------------------------------------------

    Thus, it is possible that a source undertaking a HRI project at its
EGU would project, or actually experience, an increase in operation of
its EGU and a corresponding increase in annual emissions. This would
require the source, at a minimum, to conduct an analysis to determine
whether the project by itself is projected to lead to a significant
emissions increase (at step one of the two-step analysis that
determines whether a project constitutes a ``major modification''). If
so, the source would have to conduct a netting analysis to determine
whether there is also a significant net increase when contemporaneous
increases and decreases from other projects are considered (step two of
that analysis). If both of these types of increases would be projected
to occur, this could result in the source being subject to additional
pollutant control requirements (e.g., BACT or LAER), in addition to the
substantial extra time and cost of applying for a major NSR permit
prior to undertaking the HRI project. Such could be the consequence
despite the fact that the project would lower the EGU's output-based
emissions rate for its air pollutants, and despite the fact that the
resulting effect on the dispatch order could yield an emission
reduction from a system-wide standpoint.
    Similarly, over the years, some stakeholders have asserted that the
NSR rules discourage companies from exercising the discretion to
undertake energy efficiency improvement projects, which they assert
results in less environmentally protective outcomes from a system-wide
standpoint. Stakeholders have claimed that triggering major NSR
permitting requirements can increase the costs of beneficial plant
improvement projects, like HRIs, and often contribute to a company's
decision to forego the projects. For instance, a commenter on the CPP
proposal stated that ``many coal-fired plants may refrain from making
improvements based on the financial risk associated with potentially
triggering a New Source Review, which may result in the requirement to
invest in additional emissions controls . . . . [T]he [permitting]
requirements could increase costs of potential heat rate improvements
and therefore are a potential impediment which should be recognized in
the rule's calculations.'' \48\
---------------------------------------------------------------------------

    \48\ Electric Power Research Institute comments U.S.
Environmental Protection Agency's Proposed Rule ``Carbon Pollution
Emissions Guidelines for Existing Stationary Sources: Electric
Utility Generating Units,'' 79 FR 34830 (June 18, 2014) at 12-13
(EPA-HQ-OAR-2013-0602-21697).
---------------------------------------------------------------------------

    In promulgating the CPP, EPA noted that these stakeholders
expressed concerns of the potential NSR permitting effects from a state
implementing the rule, stating ``[w]hile there may be instances in
which an NSR permit would be required, we expect those situations to be
few . . . states have considerable flexibility in selecting varied
measures as they develop their plans to meet the goals of the emission
guidelines. One of these flexibilities is the ability of the state to
establish emission standards in their CAA section 111(d) plans in such
a way so that their affected sources, in complying with those
standards, in fact would not have emissions increases that trigger NSR.
To achieve this, the state would need to conduct an analysis consistent
with the NSR regulatory requirements that supports its determination
that as long as affected sources comply with the emission standards in
their CAA section 111(d) plan, the source's emissions would not
increase in a way that trigger NSR requirements.'' 80 FR 64920 (October
23, 2015). The CPP also explained that sources can voluntarily take
enforceable limits on hours of operation, in the form of a synthetic
minor source limitation, in order to avoid triggering major NSR
requirements that would otherwise apply to the source. 80 FR 64781,
64920.
    However, these concerns regarding the applicability of NSR take on
even greater significance and may not be as easily avoided in the
context of this proposed rule, which constrains the compliance options
available in the CPP to within-the-fenceline measures and may therefore
more directly result in individual sources making HRIs.
    Individuals within the academic community have examined the NSR
interplay with making efficiency gains at existing coal plants. A 2014
report projected that 80 percent of non-retiring coal-fired units have
emissions rates for NOX and SO2 at levels that
exceed those typically required under NSR and concluded that the units
would have to install additional controls for NOX or sulfur
dioxide (SO2) if these HRI projects triggered the
applicability of

NSR.\49\ For these units then, the potential requirement to undertake a
HRI to satisfy 111(d) may result in substantial time, effort, and money
to comply with the requirements of major NSR. In addition, the
potential need to permit so many of the projects being required under a
111(d) plan could substantially increase the burden for permit agencies
in processing permit applications. To help reduce the effect this may
have on the effective and prompt implementation of a revised CAA
section 111(d) standard for EGUs, EPA is proposing revisions to the NSR
regulations in this action.
---------------------------------------------------------------------------

    \49\ Sarah K. Adair, David C. Hoppock, Jonas J. Monast (from
Duke University's Nicholas Institute for Environmental Policy
Solutions and School of Law, ``New Source Review and coal plant
efficiency gains: How new and forthcoming air regulations affect
outcomes''; Elsevier, Energy Policy 70 (2014), 183-192.
---------------------------------------------------------------------------

C. ANPRM Solicitation and Comments Received

    Through the ANPRM, EPA took comment on the topic of how the NSR
program overlays with emission guidelines established under CAA section
111(d). EPA specifically acknowledged the concerns raised previously by
stakeholders regarding the potential for a source to make energy
efficient improvements that could trigger major NSR requirements.
Furthermore, as EPA did in the CPP, EPA described current approaches
available within the NSR program to avoid triggering NSR requirements.
These include the ability for a source to obtain a synthetic minor
source limitation, which restricts its hours of operation and its
emissions below major NSR levels, and the Plantwide Applicability Limit
(PAL), which allows a source to operate within a source-wide emissions
cap to avoid triggering NSR for changes.
    The ANPRM solicited input on possible actions that EPA can take to
harmonize and streamline the NSR applicability or the NSR permitting
processes for an amended rule. EPA requested comment on ways to
minimize the impact of the NSR program on the implementation of a
performance standard for EGU sources under CAA section 111(d),
specifically asking ``[w]hat rule or policy changes or flexibilities
can EPA provide as part of the NSR program that would enable EGUs to
implement projects required under a CAA section 111(d) plan and not
trigger major NSR permitting while maintaining environmental
protections?'' 82 FR 61519 (Dec. 28, 2017).
    Several ANPRM commenters reiterated concerns that were raised on
the CPP proposal regarding the NSR program--specifically that, if an
air agency, as part of its plan to comply with emission guidelines
established pursuant to CAA section 111(d), requires an affected source
to make modifications (e.g., HRI projects), it could potentially
trigger major NSR requirements. Some commenters alleged that the NSR
program unfairly treats sources that are undertaking changes to become
more energy efficient by requiring a costly and time consuming
permitting burden. As expressed by one industry representative, ``EGUs
engaging in HRI projects can face NSR pre-construction permitting
requirements consisting of, at a minimum, costly, detailed analyses and
permitting delays. In some cases, this has resulted in costly and
protracted litigation, and expensive new emission control requirements,
both of which result in substantial time delays for these projects.
These concerns remain should unit operators pursue HRI upgrades . . .
that could trigger NSR in an effort to comply with . . . revised CAA
section 111(d) GHG emissions guidelines.'' \50\ Another commenter noted
that the major NSR permitting process ``is time and resource
intensive'' and, including pre-permit application work, ``can take as
long as 3 years or longer.'' \51\ The same commenter noted that ``[the]
uncertainty of permit timing can hinder investment decisions as much as
the actual permit schedule delays.'' \52\ Some commenters indicated
that the current flexibilities offered within the NSR program are not
sufficient to avoid placing a significant permitting burden on EGUs and
permitting agencies, which could result in substantial delays during
the planned implementation stage.\53\ To avoid such outcomes, a number
of commenters suggested that EPA undertake actions to clarify or change
the NSR regulations, including, for example, revising the NSR
modification applicability to be based on pounds per kilowatt-hour (lb/
kW-h) \54\ or rejecting as BSER any project that would result in
triggering NSR.\55\
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    \50\ Edison Electric Institute comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 22 (EPA-HQ-
OAR-2017-0545-0221).
    \51\ General Electric Company (GE) comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 29-30 (EPA-
HQ-OAR-2017-0545-0271).
    \52\ Id. at 30.
    \53\ See, e.g., Ohio Environmental Protection Agency comments on
the U.S. Environmental Protection Agency's ANPRM entitled, ``State
Guidelines for Greenhouse Gas Emissions from Existing Electric
Utility Generating Units,'' 82 FR 61507 (December 28, 2017) at 9, 32
(EPA-HQ-OAR-2017-0545-0246).
    \54\ GE comments, supra note at 33.
    \55\ Indiana Municipal Power Agency comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 3 (EPA-HQ-
OAR-2017-0545-0204).
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    However, other commenters disagreed. For instance, the Natural
Resources Defense Council (NRDC) suggested that changes to the NSR
program ``are unwarranted.'' \56\ They added that EPA needs to remain
in the boundary of the controlling judicial decisions in considering
what approaches could be used to reduce the number of existing sources
that will be subject to NSR permitting while crafting CAA section
111(d) plans. NRDC focused the basis of many of its concerns on the
court's opinion in New York v. EPA, 443 F.3d 880 (D.C. Cir. 2006) (New
York II), which vacated EPA's attempt to more clearly define ``routine
maintenance, repair, and replacement'' (RMRR) projects that are exempt
from major NSR by EPA's rules. NRDC also referenced the following
observation from an earlier decision by the same court that vacated the
``pollution control project exclusion'' that EPA finalized in 2002:
``Absent clear congressional delegation, however, EPA lacks authority
to create an exemption from NSR by administrative rule.'' \57\
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    \56\ Natural Resources Defense Council comments on the U.S.
Environmental Protection Agency's ANPRM entitled, ``State Guidelines
for Greenhouse Gas Emissions from Existing Electric Utility
Generating Units,'' 82 FR 61507 (December 28, 2017) at 14-17 (EPA-
HQ-OAR-2017-0545-0358).
    \57\ New York v. EPA, 413 F.3d 3, 41 (D.C. Cir. 2005) (New York
I) (citing Sierra Club v. EPA, 129 F.3d 137, 140 (D.C. Cir. 1997)).
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D. Proposing NSR Changes for Improved ACE Implementation

1. Overview
    EPA acknowledges the NSR program may have unintended consequences
for implementation of this emission guidelines for GHG emissions from
existing EGUs. Based on the comments received on the ANPRM and EPA's
experience with the NSR program generally, EPA recognizes the potential
for triggering major NSR permitting when sources undertake HRI
projects. EPA further recognizes that the prospect of a protracted
permitting process and a possible requirement to install pollution
control equipment at the emissions unit can create a disincentive for
sources to voluntarily make energy efficiency

improvements. Many of these concerns with the NSR program were raised
nearly two decades ago, and formed the cornerstone of EPA's initiative
in the early 2000's to reform the NSR program.\58\
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    \58\ In May 2001, President Bush's National Energy Policy
Development Group issued findings and key recommendations for a
National Energy Policy. This document included numerous
recommendations for action, including a recommendation that the EPA
Administrator, in consultation with the Secretary of Energy and
other relevant agencies, review NSR regulations, including
administrative interpretation and implementation. The recommendation
requested that EPA issue a report to the President on the impact of
the regulations on investment in new utility and refinery generation
capacity, energy efficiency, and environmental protection. The
report to the President was issued on June 13, 2002, and is
available at https://www.epa.gov/nsr/new-source-review-report-president. In the report to the President, EPA concluded ``[as]
applied to existing power plants and refineries . . . the NSR
program has impeded or resulted in the cancellation of projects
which would maintain and improve reliability, efficiency and safety
of existing energy capacity. Such discouragement results in lost
capacity, as well as lost opportunities to improve energy efficiency
and reduce air pollution.'' New Source Review Report to the
President at 3.
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    But this dynamic takes on a new character in the context of a
regulation that may result in a source undertaking a HRI or another
project to meet a standard of performance as determined by the state.
When a state's 111(d) plan requires an EGU to comply with a standard of
performance, sources cannot choose to forego a project in an effort to
avoid NSR permitting as they could with improvement projects they were
otherwise considering. Despite recent actions by EPA to streamline the
NSR program, the reality remains that a source that undertakes a HRI
project may trigger major NSR under the current NSR applicability test
when required to undertake a HRI project as part of a state's 111(d)
plan. As has been noted by commenters on the ANPRM, this can require
the source to undertake significant planning and analysis with the
process to receive a preconstruction permit, sometimes taking 3 or more
years. This added time and cost to sources and the associated burden on
permitting agencies could hinder the effective and prompt
implementation of state 111(d) plans.
    In this context, our approach in the CPP of encouraging agencies to
minimize the triggering of major NSR for their affected EGUs by
conducting emissions analyses as part of their CAA section 111(d) plan
development does not appear to be a sufficient solution. While EPA
supports states having the primary authority to implement the air
programs, state agencies should not be burdened with having to
determine a ``work around'' for the NSR program requirements in
developing their plans to implement the emission guidelines for
affected EGUs. The responsibility of ensuring that emission guidelines
under 111(d) are clearly articulated and easily implementable rests
squarely with EPA. Thus, EPA addressing the time delays and costs that
can result from NSR requirements could be one tool for helping ensure
the successful implementation of a national program for controlling GHG
emissions from existing EGUs.
    It is important for a state that is developing a CAA section 111(d)
plan to completely understand the full costs being imposed on their
affected sources in order for the state to make informed decisions in
applying a standard of performance to each of their existing sources
(much like a state would consider, among other factors, the remaining
useful life of each source). However, EPA has historically not
considered the costs of complying with other CAA programs, like NSR,
when determining BSER for a source category under section 111. This was
in part because, for many years, EPA applied a policy of excluding
pollution control projects from NSR. But, as noted earlier in this
section, EPA's attempt to codify such a policy in the NSR regulations
was struck down by the D.C. Circuit in 2005. Since that decision, EPA
has not written a significant number of rules under section 111, and
the rules that EPA has written have not presented a need to consider
this question. However, due to the nature of the electric utility
industry and the types of candidate control measures being considered
in this proposal, it may be appropriate to consider NSR compliance
costs in this instance. Specifically, the BSER measures chosen in this
rule may result in a source undertaking a physical change that
significantly increases its annual emissions and triggers major NSR
permitting requirements such that permitting costs are unavoidable.
However, due to the case-specific analysis required to determine NSR
applicability, it would likely be difficult for a state to adequately
predict and quantify the effect of a HRI on an EGU's operational costs,
change in dispatch order, and other variables that would factor into
whether the source needs a major NSR permit or, perhaps, a minor NSR
permit. In addition, even if a state can reasonably predict an EGU's
emissions increase resulting from a HRI project such that it can expect
the source will need a major NSR permit, it would likely be difficult
to predict the expected permitting costs since the emission control and
other permitting requirements are case-by-case determinations and can
therefore vary significantly due to a number of factors, including how
well the source is already controlled, the emissions from nearby
sources and their contribution to air quality concerns, whether the
source is located in an attainment or nonattainment area, and the
potential for the air permit to trigger other requirements (e.g.,
Endangered Species Act, National Historic Preservation Act). In some
cases, a source triggering major NSR may be required to conduct
extensive modeling and install additional pollution controls for non-
GHG pollutants. Thus, the case-by-case nature of the NSR program can
lead to uncertainty for a state that is creating its 111(d) plan and
wanting to ensure that the plan fully appreciates the projected
compliance costs for its affected EGUs.
    EPA is, therefore, inviting comment on whether it is appropriate to
consider the costs of NSR compliance in the BSER analysis under section
111(d), assuming that triggering NSR cannot otherwise be avoided
through actions by the source or through revisions to the NSR
regulations that are proposed by EPA in this rule or if EPA does not
finalize revisions to the NSR regulations (Comment C-59). In addition,
EPA solicits comment on how a state or local permitting agency may
estimate or project the cost for the source to comply with any NSR
requirements that may flow from a selected BSER, and on how the
potential for delays because of an influx of NSR permit applications
may be accounted for in setting an implementation schedule for 111(d)
plans (Comment C-60).
    Recognizing that EPA issuing this 111(d) rule would mean that a
source may no longer be in a position to forego a HRI project due to
unwanted permitting costs, EPA has continued to look for ways to reduce
the costs of NSR requirements, while being mindful of the requirements
of the CAA and the court decisions on prior NSR reform rules that were
referenced by some commenters. In this light, EPA believes that a past
option for revising the NSR regulation that EPA has considered may
warrant further consideration to address this concern. In 2005 and
2007, EPA previously proposed adopting an hourly emissions rate test
for NSR applicability for EGUs. While this rulemaking was never
completed, EPA believes that it warrants a fresh look in a new context
here where NSR program flexibility takes on added significance as a
means to facilitate the HRI projects that are expected to be undertaken
should the proposed ACE rule be finalized. This same idea was also
raised by a few

commenters on the ANPRM.\59\ Thus, EPA is soliciting comment on whether
a narrower range of options for implementing an hourly emissions test
for NSR for EGUs would both help promote energy efficiency and the
effectiveness of implementing the ACE rule, while at the same time
being consistent with the NSR provisions in CAA and past judicial
decisions interpreting those provisions (Comment C-61).
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    \59\ See, e.g., Arizona Public Service Company comments on the
U.S. Environmental Protection Agency's ANPRM entitled, ``State
Guidelines for Greenhouse Gas Emissions from Existing Electric
Utility Generating Units,'' 82 FR 61507 (Dec. 28, 2017) at 6 (EPA-
HQ-OAR-2017-0545-0286);Unions for Jobs & Environmental Progress
comments on the U.S. Environmental Protection Agency's ANPRM
entitled, ``State Guidelines for Greenhouse Gas Emissions from
Existing Electric Utility Generating Units,'' 82 FR 61507 (Dec. 28,
2017) at 14-17 (EPA-HQ-OAR-2017-0545-0162).
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2. The 2007 Supplemental Rule Proposal
    In 2007, EPA proposed to revise the NSR provisions to include an
NSR applicability test for EGUs that is based on maximum hourly
emissions. 72 FR 26202 (May 8, 2007). The 2007 proposed action was a
``supplemental'' notice of proposed rulemaking (SNPRM), because the
2007 proposal followed an earlier action by EPA that proposed a more
limited form of the hourly emissions test for NSR applicability. 70 FR
61081 (October 20, 2005) (NPRM). These proposals followed EPA's NSR
regulatory reform efforts of 2002 and 2003, when EPA promulgated final
regulations that implemented several of the recommendations in the New
Source Review Report to the President.\60\ Those earlier regulatory
actions, however, left the NSR provisions for electric utilities
largely unchanged.
---------------------------------------------------------------------------

    \60\ See supra note.
---------------------------------------------------------------------------

    The 2007 SNPRM requested comment on two basic options, and various
alternatives within each of the two options, for changing the test for
determining an emissions increase from an EGU undergoing a physical or
operational change. The proposal included emissions test alternatives
based on an EGU's maximum achieved hourly emissions rate--applying
either a ``statistical approach'' or a ``one-in-5-year baseline
approach''--and an EGU's maximum achievable hourly emissions rate,
which mirrored the NSPS modification applicability test. While EPA did
not propose rule amendments in the 2005 NPRM, in 2007 EPA proposed to
amend 40 CFR part 51 to include a new provision at Sec.  51.167, which
largely mirrored the NSPS modification provisions in Sec.  60.2 and
Sec.  60.14. The 2007 SNPRM provided EPA's legal and policy basis for
incorporating an hourly emissions increase test within the NSR program
for EGUs.
    For the proposed maximum achieved hourly test alternatives, an EGU
owner/operator would determine whether an emissions increase would
occur by comparing the pre-change maximum actual hourly emissions rate
to a projection of the post-change maximum actual hourly emissions
rate. In establishing the baseline, both alternatives considered the
unit's actual performance during the 5-year period immediately
preceding the physical or operational change. For the one-in-5-year
baseline approach, the emissions rate would be computed based on what
the unit actually achieved for any single hour within the 5-year period
immediately before the physical or operational change. For the