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

    \191\ Monitors are included in the docket for this rulemaking.
While EPA is providing information about cumulative upwind
contribution to the California monitors, the Agency is not making a
determination in this action that these monitors are ozone transport
receptors.
---------------------------------------------------------------------------

    The EPA previously made a similar assessment of the nature of
certain other monitoring sites in California in approving Arizona's
2008 ozone NAAQS transport SIP submittal.\192\ There, the EPA noted
that a ``factor [. . .] relevant to determining the nature of a
projected receptor's interstate transport problem is the magnitude of
ozone attributable to transport from all upwind states collectively
contributing to the air quality problem.'' \193\ The EPA observed that
only one upwind state (Arizona) was linked above 1 percent of the 2008
ozone NAAQS to the two relevant monitoring sites in California, and the
cumulative ozone contribution from all upwind states to those sites was
2.5 percent and 4.4 percent of the total ozone, respectively. The EPA
determined the size of those cumulative upwind contributions was
``negligible, particularly when compared to the relatively large
contributions from upwind states in the East or in certain other areas
of the West.'' \194\ In that action, the EPA concluded the two
California sites to which Arizona was linked should not be treated as
receptors for the purposes of determining Good Neighbor obligations for
the 2008 ozone NAAQS.\195\
---------------------------------------------------------------------------

    \192\ 81 FR 15200 (March 22, 2016) (proposal); 81 FR 31513 (May
19, 2016) (final rule).
    \193\ 81 FR 15203.
    \194\ Id.
    \195\ Id.
---------------------------------------------------------------------------

    Comment: Commenters criticized what they considered to be unfair
treatment of Oregon, stating that the EPA is applying a higher
contribution threshold than it applies to other states. Commenters
argued that EPA has not established a specific threshold for why the
level of upwind-state impact at these sites should not be considered
meaningful. Commenters argued that our analysis ignored the fact that
there are many monitoring sites in California to which Oregon
contributes above 1 percent of the NAAQS. Commenters state that EPA has
failed to explain why Oregon is not subject to this rulemaking, while
other states contribute lower total downwind ozone contributions and
fewer receptors. Commenters concluded that since Oregon is linked it
should be subject to the same emissions control determinations at Step
3 and 4 as every other state, or otherwise apply the same ``nature of
the air quality problem'' consideration to eliminate other receptors.
    Response: The EPA acknowledges that several commenters opposed the
proposed treatment of Oregon and the California monitoring sites to
which it is linked in the proposed and final modeling. We also
recognize that other commenters expressed confusion regarding the role
of this proposed determination at Step 1 and how it relates to the
longstanding 4-step interstate transport framework that the EPA is
otherwise applying in this action. In recognition of these concerns and
the need to give further thought to the appropriate treatment of both
upwind states and downwind receptors in these circumstances, the EPA is
deferring finalizing a finding at this time for Oregon. The current
approval of the state's SIP submission will remain in place for the
time being, pending further review. We make no final determination in
this action regarding whether the California monitoring sites at issue
should or should not be treated as receptors for purposes of addressing
interstate transport for the 2015 ozone NAAQS.

V. Quantifying Upwind-State NOX Emissions Reduction Potential To Reduce
Interstate Ozone Transport for the 2015 Ozone NAAQS

A. The Multi-Factor Test for Determining Significant Contribution

    This section describes the EPA's methodology at Step 3 of the 4-
step framework for identifying upwind emissions that constitute
``significant'' contribution for the states subject to this final rule
and focuses on the 23 states with FIP requirements identified in the

previous sections. Following the existing framework as applied in the
prior CSAPR rulemakings, the EPA's assessment of linked upwind state
emissions is based primarily on analysis of several alternative levels
of NOX emissions control stringency applied uniformly across
all of the linked states. The analysis includes assessment of non-EGU
stationary sources in addition to EGU sources in the linked upwind
states.
    The EPA applies a multi-factor test--the same multi-factor test
that was used in CSAPR, the CSAPR Update, and the Revised CSAPR Update
\196\--to evaluate increasing levels of uniform NOX control
stringency. The multi-factor test, which is central to EPA's Step 3
quantification of significant contribution, considers cost, available
emissions reductions, downwind air quality impacts, and other factors
to determine the appropriate level of uniform NOX control
stringency that would eliminate significant contribution to downwind
nonattainment or maintenance receptors. The selection of a uniform
level of NOX emissions control stringency across all of the
linked states, reflected as a representative cost per ton of emissions
reduction (or a weighted average cost per ton in the case of EPA's non-
EGU and EGU analysis for 2026 mitigation measures), also serves to
apportion the reduction responsibility among collectively contributing
upwind states. This approach to quantifying upwind state emission-
reduction obligations using uniform cost was reviewed by the Supreme
Court in EME Homer City Generation, which held that using such an
approach to apportion emissions reduction responsibilities among upwind
states that are collectively responsible for downwind air quality
impacts ``is an efficient and equitable solution to the allocation
problem the Good Neighbor Provision requires the Agency to address.''
572 U.S. at 519.
---------------------------------------------------------------------------

    \196\ See CSAPR, Final Rule, 76 FR 48208 (August 8, 2011).
---------------------------------------------------------------------------

    There are four stages in developing the multi-factor test: (1)
identify levels of uniform NOX control stringency; (2)
evaluate potential NOX emissions reductions associated with
each identified level of uniform control stringency; (3) assess air
quality improvements at downwind receptors for each level of uniform
control stringency; and (4) select a level of control stringency
considering the identified cost, available NOX emissions
reductions, and downwind air quality impacts, while also ensuring that
emissions reductions do not unnecessarily over-control relative to the
contribution threshold or downwind air quality.
    As mentioned in section III.A.2 of this document, commenters on the
proposed rule and previous ozone transport rules have suggested that
the EPA should regulate VOCs as an ozone precursor. For this final
rule, the EPA examined the results of the contribution modeling
performed for this rule to identify the portion of the ozone
contribution attributable to anthropogenic NOX emissions
versus VOC emissions from each linked upwind state to each downwind
receptor. Of the total upwind-downwind linkages in 2023, the
contributions from NOX emissions comprise 80 percent or more
of the total anthropogenic contribution for nearly all of the linkages
(121 out of 124 total). Across all receptors, the contribution from
NOX emissions ranges from 84 percent to 97 percent of the
total anthropogenic contribution from upwind states. This review of the
portion of the ozone contribution attributable to anthropogenic
NOX emissions versus VOC emissions from each linked upwind
state leads the Agency to conclude that the vast majority of the
downwind air quality areas addressed by the final rule under are
primarily NOX-limited, rather than VOC-limited. Therefore,
the EPA continues to find that regulation of VOCs as an ozone precursor
in upwind states is not necessary to eliminate significant contribution
or interference with maintenance in downwind areas in this final rule.
The remainder of this section focuses on EPA's strategy for reducing
regional-scale transport of ozone by targeting NOX emissions
from stationary sources to achieve the most effective reductions of
ozone transport over the geography of the affected downwind areas.
    For both EGUs and non-EGUs, section V.B of this document describes
the available NOX emissions controls that the EPA evaluated
for this final rule and their representative cost levels (in 2016$).
Section V.C of this document discusses EPA's application of that
information to assess emissions reduction potential of the identified
control stringencies. Finally, section V.D of this document describes
EPA's assessment of associated air quality impacts and EPA's subsequent
identification of appropriate control stringencies considering the key
relevant factors (cost, available emissions reductions, and downwind
air quality impacts).
    This multi-factor approach is consistent with EPA's approach in
prior transport actions, such as CSAPR. In addition, as was evaluated
in the CSAPR Update and Revised CSAPR Update, the EPA evaluated
whether, based on particularized evidence, its selected control
strategy would result in over-control for any upwind state by examining
whether an upwind state is linked solely to downwind air quality
problems that could have been resolved at a lesser threshold of control
stringency and whether an upwind state could reduce its emissions below
the 1 percent air quality contribution threshold at a lesser threshold
of control stringency. This analysis is described in section V.D of
this document.
    Finally, while the EPA has evaluated potential emissions reductions
from non-EGU sources in prior rules and found certain non-EGU emissions
reductions should inform the budgets established in the NOX
SIP Call, this is the first action for which the EPA is finalizing non-
EGU emissions reductions within the context of the specific, 4-step
interstate transport framework established in CSAPR. The EPA applies
its multi-factor test to non-EGUs and independently evaluates non-EGU
industries in a consistent but parallel track to its Step 3 assessment
for EGUs. This is consistent with the parallel assessment approach
taken for EGUs and non-EGUs in the Revised CSAPR Update. Following the
conclusions of the EGU and non-EGU multi-factor tests, the identified
reductions for EGUs and non-EGUs are combined and collectively analyzed
to assess their effects on downwind air quality and whether the rule
achieves a full remedy to eliminate ``significant contribution'' while
avoiding over-control.
    To ensure that this rule implements a full remedy for the
elimination of significant contribution from upwind states, the EPA has
reviewed available information on all major industrial source sectors
in the upwind states inclusive of commenter-provided data. This
analysis leads the EPA to conclude that both EGUs and certain large
sources in several specific industrial categories should be evaluated
for emissions control opportunities. As discussed in the sections that
follow, the EPA determines, for both EGUs and the selected non-EGU
source categories, there are impactful emissions reduction
opportunities available at reasonable cost-effectiveness thresholds. As
in the Revised CSAPR Update, the EPA examines EGUs and non-EGUs in this
section on consistent but distinct parallel tracks due to differences
stemming from the unique characteristics of the power sector

compared to other industrial source categories.
    Since the NOX SIP Call, EGUs have consistently been
regulated under ozone transport rules. These units operate in a
coordinated manner across a highly interconnected electrical grid.
Their configuration and emissions control strategies are relatively
homogenous, and their emissions levels and emissions control
opportunities are generally very well understood due to longstanding
monitoring and data-reporting requirements. Non-EGU sources, by
contrast, are relatively heterogeneous, even within a single industrial
category, and have far greater variation in existing emissions control
requirements, emissions levels, and technologies to reduce emissions.
In general, despite these differences, the information available for
this rulemaking indicates that both EGUs and certain non-EGU categories
have available cost-effective NOX emissions reduction
opportunities at relatively commensurate cost per ton levels, and these
emissions reductions will make a meaningful improvement in air quality
at the downwind receptors. Section V.B.2 of this document describes
EPA's process for selecting specific non-EGU industries and emissions
unit types included in this final rulemaking.
    The EPA notes that its Step 3 analysis for this FIP does not assess
additional emissions reduction opportunities from mobile sources. The
EPA continues to believe that title II of the CAA provides the primary
authority and process for reducing these emissions at the Federal
level. EPA's various Federal mobile source programs, summarized in this
section, have delivered and are projected to continue to deliver
substantial nationwide reductions in both VOCs and NOX
emissions; these reductions from final rules are factored into the
Agency's assessment of air quality and contributions at Steps 1 and 2.
Further, states are generally preempted from regulating new vehicles
and engines with certain exceptions, and therefore a question exists
regarding EPA's authority to address such emissions through such means
when regulating in place of the states under CAA section 110(c). See
generally CAA section 209. See also 86 FR 23099. As noted earlier, the
EPA accounted for mobile source emissions reductions resulting from
other federally enforceable regulatory programs in the development of
emissions inventories used to support analysis for this final
rulemaking, and the EPA does not evaluate any mobile source control
measures in its Step 3 evaluation in this rule.\197\ For further
discussion of EPA's existing and ongoing mobile source measures, see
section V.B.4 of this document.
---------------------------------------------------------------------------

    \197\ The EPA recognizes that mechanisms exist under title I of
the CAA that allow for the regulation of the use and operation of
mobile sources to reduce ozone-precursor emissions. These include
specific requirements that apply in certain ozone nonattainment
areas including motor vehicle inspection and maintenance (I/M)
programs, gasoline vapor recovery, clean-fuel vehicle programs,
transportation control programs, and vehicle miles traveled
programs. See, e.g., CAA sections 182(b)(3), 182(b)(4), 182(c)(3),
182(c)(4), 182(c)(5), 182(d)(1), 182(e)(3), and 182(e)(4). The EPA
views these programs as well as others that meet CAA requirements
can be effective and appropriate in the context of the planning
requirements applicable to designated nonattainment areas.
---------------------------------------------------------------------------

B. Identifying Control Stringency Levels

1. EGU NOX Mitigation Strategies
    In identifying levels of uniform control stringency for EGUs, the
EPA assessed the same NOX emissions controls that the Agency
analyzed in the CSAPR Update and the Revised CSAPR Update, all of which
are considered to be widely available in this sector: (1) fully
operating existing SCR, including both optimizing NOX
removal by existing operational SCRs and turning on and optimizing
existing idled SCRs; (2) installing state-of-the-art NOX
combustion controls; (3) fully operating existing SNCRs, including both
optimizing NOX removal by existing operational SNCRs and
turning on and optimizing existing idled SNCRs; (4) installing new
SNCRs; and (5) installing new SCRs. Finally, for each of these
combustion and post combustion technologies identified, EPA evaluated
whether emissions reduction potential from generation shifting at that
representative dollar per ton level was appropriate at this Step.
Shifting generation to lower NOX emitting or zero-emitting
EGUs may occur in response to economic factors. As the cost of emitting
NOX increases, it becomes increasingly cost-effective for
units with lower NOX rates to increase generation, while
units with higher NOX rates reduce generation. Because the
cost of generation is unit-specific, this generation shifting occurs
incrementally on a continuum. For the reasons explained in the
following sections and supported by technical information provided in
the EGU NOX Mitigation Strategies Final Rule TSD included in
the docket for this final rule, the EPA determined that for the
regional, multi-state scale of this rulemaking, only EGU NOX
emissions controls 1 and 3 are possible for the 2023 ozone season
(fully operating existing SCRs and SNCRs). The EPA finds that it is not
possible to install state-of-the-art NOX combustion controls
by the 2023 ozone season on a regional scale; those controls are
assumed to be available by the beginning of the 2024 ozone season. All
cost values discussed in the rest of the section for EGUs are in 2016
dollars.
a. Optimizing Existing SCRs
    Optimizing (i.e., turning on idled or improving operation of
partially operating) existing SCRs can substantially reduce EGU
NOX emissions quickly, using investments that have already
been made in pollution control technologies. With the promulgation of
the CSAPR Update and the Revised CSAPR Update, most operators in the
covered states improved their SCR performance and have continued to
maintain that level of improved operation. However, this optimized SCR
performance was not universal and not always sustained. Between 2017
and 2020, as the CSAPR Update ozone-season NOX allowance
price declined, NOX emissions rates at some SCR-controlled
EGUs increased. For example, power sector data from 2019 revealed that,
in some cases, operating units had SCR controls that had been idled or
were operating partially, and therefore suggested that there remained
emissions reduction potential through optimization.\198\ The EPA
determined in the Revised CSAPR Update that optimizing SCRs was a
readily available approach for EGUs to reduce NOX emissions
in the 12 states addressed by a FIP in that rulemaking. Noticeable
improvements in emissions rates at units with SCRs during the 2021 and
2022 compliance period further affirm the ability of sources to quickly
implement this mitigation strategy and to realize emissions reductions
from doing so. This emissions reduction measure is currently available
at EGUs across the broader geography affected in this final rulemaking
(including in states not previously affected by the Revised CSAPR
Update). The EPA thus determines that SCR optimization, of both idled
and partially operating controls, is a viable mitigation strategy for
the 2023 ozone season.
---------------------------------------------------------------------------

    \198\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason.
---------------------------------------------------------------------------

    The EPA estimates a representative marginal cost of optimizing SCR
controls to be approximately $1,600 per ton, consistent with its
estimation in the Revised CSAPR Update for this technology. EPA's EGU
NOX Mitigation Strategies Final Rule TSD for this rule
describes a range of cost estimates for

this technology noting that the costs are frequently lower than--and
for the majority of EGUs, significantly lower than--this representative
marginal cost. While the costs of optimizing existing, operational SCRs
include only variable costs, the cost of optimizing SCR units that are
currently idled considers both variable and fixed costs of returning
the control into service. Variable and fixed costs include labor,
maintenance and repair, parasitic load, and ammonia or urea for use as
a NOX reduction reagent in SCR systems. Depending on a
unit's control operating status, the representative cost at the 90th
percentile unit (among the relevant fleet of coal units with SCR
covered in this rulemaking) ranges between $900 and $1,700 per ton. The
EPA performed an in-depth cost assessment for all coal-fired units with
SCRs and found that for the subset of SCRs that are already partially
operating, the cost of optimizing is often much lower than $1,600 per
ton and is often under $900 per ton. The EPA anticipates the vast
majority of realized cost for compliance with this strategy to be
better reflected by the $900 per ton end of that range (reflecting the
90th percentile of EGUs optimizing SCRs that are already partially
operating) because this circumstance is considerably more common than
EGUs that have ceased operating their SCR. This cost distinction is
reflected in the EPA's RIA cost estimates. When representing the cost
of optimization here, the EPA uses the higher value to reflect both
optimization of partially operating and idled controls. EPA's analysis
of this emissions control is informed by the latest engineering
modeling equations used in EPA's IPM platform. These cost and
performance equations were recently updated in the summer of 2021 in
preparation for this rule, and subsequently evaluated for the final
rule in 2022 and determined to still be appropriate. The description
and development of the equations are documented in EGU NOX
Mitigation Strategies Final Rule TSD and accompanying documents.\199\
They are also implemented in an interactive spreadsheet tool called the
Retrofit Cost Analyzer and applied to all units in the fleet. These
materials are available in the docket for this action.
---------------------------------------------------------------------------

    \199\ The CSAPR Update estimated $1,400 per ton as a
representative cost of turning on idled SCR controls. EPA used the
same costing methodology while updating for input cost increases
(e.g., urea reagent) to arrive at $1,600 per ton in the final
Revised CSAPR Update (while also updating from 2011 dollars to 2016
dollars).
---------------------------------------------------------------------------

    The EPA is using the same methodology to identify SCR performance
as it did in the Revised CSAPR Update. To estimate EGU NOX
reduction potential from optimizing, the EPA considers the difference
between the non-optimized NOX emissions rates and an
achievable operating and optimized SCR NOX emissions rate.
To determine this rate, EPA evaluated nationwide coal-fired EGU
NOX ozone season emissions data from 2009 through 2019 and
calculated an average NOX ozone season emissions rate across
the fleet of coal-fired EGUs with SCR for each of these eleven years.
The EPA found it prudent to not consider the lowest or second-lowest
ozone season NOX emissions rates, which may reflect SCR
systems that have all new components (e.g., new layers of catalyst).
Data from these systems are potentially not representative of ongoing
achievable NOX emissions rates considering broken-in
components and routine maintenance schedules. Considering the emissions
data over the full time period from 2009-2019 results in a third-best
rate of 0.079 pounds NOX per million British thermal units
(lb/mmBtu). Therefore, consistent with the Revised CSAPR Update, where
EPA identified 0.08 lb/mmBtu as a reasonable level of performance for
units with optimized SCR, the EPA finalizes a rate of 0.08 lb/mmBtu as
the optimized rate for this rule. The EPA notes that half of the SCR-
controlled EGUs achieved a NOX emissions rate of 0.064 lb/
mmBtu or lower over their third-best entire ozone season. Moreover, for
the SCR-controlled coal units that the EPA identified as having a 2021
emissions rate greater than 0.08 lb/mmBtu, the EPA verified that in
prior years, the majority (more than 90 percent) of these same units
had demonstrated and achieved a NOX emissions rate of 0.08
lb/mmBtu or less on a seasonal or monthly basis. This further supports
EPA's determination that 0.08 lb/mmBtu reflects a reasonable emissions
rate for representing SCR optimization at coal steam units in
identifying uniform control stringency. This emissions rate assumption
of 0.08 lb/mmBtu reflects what those units would achieve on average
when optimized, recognizing that individual units may achieve lower or
higher rates based on unit-specific configuration and dispatch
patterns. Units historically performing at, or better, than this rate
of 0.08 lb/mmBtu are assumed to continue to operate at that prior
performance level.
    Given the magnitude and duration of the air quality problems
addressed by this rulemaking, the EPA also applied the same methodology
to identify a reasonable level of performance for optimizing existing
SCRs at oil- and gas-fired steam units and simple cycle units (for
which EPA determined that a 0.03 lb/mmBtu emissions rate reflected SCR
optimization) as well as at combined-cycle units (for which the EPA
determined that a 0.012 lb/mmBtu emissions rate reflected SCR
optimization).
    The EPA evaluated the feasibility of optimizing idled SCRs for the
2023 ozone season. Based on industry past practice, the EPA determined
that idled controls can be restored to operation quickly (i.e., in less
than 2 months). This timeframe is informed by many electric utilities'
previous long-standing practice of utilizing SCRs to reduce EGU
NOX emissions during the ozone season while putting the
systems into protective lay-up during the non-ozone season months. For
example, this was the long-standing practice of many EGUs that used SCR
systems for compliance with the NOX Budget Trading Program.
It was quite typical for SCRs to be turned off following the end of the
ozone season control period on September 30. These controls would then
be put into protective lay-up for several months of non-use before
being returned to operation by May 1 of the following ozone
season.\200\ Therefore, the EPA believes that optimization of existing
SCRs is possible for the portion of the 2023 ozone season covered under
this final rule. The recent successful implementation of this strategy
for the Revised CSAPR Update Rule, and corresponding fast improvement
in SCR performance rates at units with optimization potential, provides
further supporting evidence of the viability of this timeframe.
---------------------------------------------------------------------------

    \200\ In the 22-state CSAPR Update region, 2005 EGU
NOX emissions data suggest that 125 EGUs operated SCR
systems in the summer ozone season while idling these controls for
the remaining 7 non-ozone season months of the year. Units with SCR
were identified as those with 2005 ozone season average
NOX rates that were less than 0.12 lb/mmBtu and 2005
average non-ozone season NOX emissions rates that
exceeded 0.12 lb/mmBtu and where the average non-ozone season
NOX rate was more than double the ozone season rate.
---------------------------------------------------------------------------

    The vast majority of SCR-controlled units (nationwide and in the 23
linked states for which EPA is issuing a FIP for EGUs) are already
partially operating these controls during the ozone season based on
reported 2021 and 2022 emissions rates. Notably, the higher ozone
season NOX allowance price observed in 2022 resulted in more
units operating their controls closer to their potential and bringing
collective emissions from those 12 states closer to the 2023 emissions
budgets for those states in this final rule, accordingly.

Existing SCRs operating at partial capacity still provide functioning,
maintained systems that may only require an increased chemical reagent
feed rate (i.e., ammonia or urea) up to their design potential and
catalyst maintenance for mitigating NOX emissions; such
units may require increased frequency or quantity of deliveries, which
can be accomplished within a few weeks. In many cases, EGUs with SCR
have historically achieved more efficient NOX removal rates
than their current performance and can therefore simply revert to
earlier operation and maintenance plans that achieved demonstrably
better SCR performance.
    In the 12 states subject to this control stringency in the Revised
CSAPR Update, the EPA observed significant immediate-term improvements
in SCR performance in the first ozone season following finalization of
that rule, as evidenced in particular by the sharp drop in emissions
rate at Miami Fort unit 7 (see EGU NOX Mitigation Strategies
Final Rule TSD). For instance, in June of 2021--within months of the
Revised CSAPR Rule being finalized--Miami Fort Unit 7 and Unit 8 (which
had substantial SCR optimization potential) were able to reach levels
of 0.07 lb/mmBtu of NOX (a greater than 50 percent reduction
from where they had operated the prior year during the same month).
Such empirical data further illustrates the viability of this
mitigation strategy for the 2023 control period in response to this
rule.
    Comment: EPA received comments supporting the 0.08 lb/mmBtu
emissions rate as achievable and, according to some commenters,
underestimate the control's potential. Some of these commenters went on
to provide their own analysis demonstrating that the 0.08 lb/mmBtu was
achievable not only on average for the non-optimized fleet, but also
for these individual units and that the resulting state emissions
budgets were likewise achievable. Some commenters suggested that the
rate should be lower and premised on EPA using the first- or second-
best year instead of the third best year of SCR performance. Some
commenters observed that using the same methodology, but omitting SCR
units that have since retired, could deliver an even lower SCR
performance benchmark rate.
    Response: The EPA notes that updating the inventory of coal-fired
EGUs to reflect recent retirements and to include data reported since
2019 (e.g., 2009-2021) would provide a lower value of 0.071 lb/mmBtu.
However, EPA acknowledges that 2020 operational data included impacts
from COVID-19 pandemic shutdowns (such as atypical electricity demand
patterns) which complicate interpretations of typical EGU emissions
performance. Additionally, EPA believes that in this context, a unit's
retirement in 2020 or 2021 does not obviate the usefulness of its prior
SCR operational data for assessing the emissions control performance of
other existing SCRs across the fleet. Consequently, EPA is continuing
to use the same value of the 0.08 lb/mmBtu emissions rate calculated
from the 2009-2019 data set identified at the time of the final Revised
CSAPR Update Rule in this rulemaking. EPA's analysis focuses on the
third best ozone season average rate because EPA believes that the
first- or second-best rate, consistent with its CSAPR Update final rule
and in the Revised CSAPR Update, could give undue weight to the
emissions control performance of new SCRs in their first year of
service and their corresponding newer SCR components. It does not
necessarily reflect achievable ongoing NOX emissions rates
at relatively older SCRs. The third-lowest season was selected because
it represents a time when the unit was most likely consistently and
efficiently operating its SCR in a manner representative of sustained
future operation.
    Comment: Other commenters suggested that EPA should apply a higher
NOX emissions rate than 0.08 lb/mmBtu to existing SCR at
coal EGUs premised on considerations such as: a generally reduced
average capacity factor for coal units in recent years, the age of the
boiler, coal rank (bituminous or subbituminous), or other unit-specific
considerations that commenters claim make the 0.08 lb/mmBtu rate
unattainable for a specific unit.
    Response: EPA did not find sufficient justification to apply a
higher average emissions rate than 0.08 lb/mmBtu. EPA found that some
commenters were misunderstanding or misconstruing both EPA's assumption
and implementation mechanism as a unit-level requirement for every SCR-
controlled unit instead of a reflection of a fleet-wide average based
on a third-best rate. The commenters' observation--that 0.08 lb/mmBtu
may be difficult for some units to achieve or may not be a preferred
compliance strategy for a given unit given its dispatch levels--does
not contradict EPA's assumption, but rather supports its methodology
and assumptions. As EPA pointed out in the proposed rule, this fleet-
level emissions rate assumption of 0.08 lb/mmBtu for non-optimized
units reflects, on average, what those units would achieve when
optimized. Some of these units may achieve rates that are lower than
0.08 lb/mmBtu, and some units may operate above that rate based on
unit-specific configuration and dispatch patterns. In other words, EPA
is using this assumption as the average performance of a unit that
optimizes its SCR, recognizing that heterogeneity within the fleet will
likely lead some units to overperform and others to underperform this
rate. Moreover, a review of unit-specific historical data indicates
that this is a reasonable assumption: not only has the group of units
with SCR optimization potential demonstrated they can perform at or
better than the 0.08 lb/mmBtu rate on average, over 90 percent of the
individual units in this group have already met this rate on a seasonal
and/or monthly basis based on their reported historical data.
    Additionally, EPA's examination of units experiencing SCR
performance deterioration included notable instances of poor
NOX control at increased capacity factors. As an example,
Miami Fort Unit 7 had considerably more hours of operation at a 70 to
79 percent capacity factor in 2019 compared to previous years. However,
Miami Fort Unit 7's ozone-season NOX emissions rate
substantially increased in 2019 compared to previous years. This SCR
performance deterioration runs counter to the notion that an increase
in emissions rates is purely driven by reduced capacity factor, as
suggested by commenters. This substantial deterioration in the median
emissions rate performance is observable even when comparing specific
hours in 2019 to specific hours in prior years when the unit operated
in the same 70 to 79 percent capacity factor range. In fact, in 2019
the unit experienced notable emissions rate increases from prior years
across multiple capacity factor ranges as low as 40 percent to as high
as 80 percent. This type of data indicates instances where the increase
in emissions rate (and emissions) is not necessitated by load changes
but is more likely due to the erosion of the existing incentive to
optimize controls (i.e., the ozone-season NOX allowance
price has fallen so low that unit operators find it more economic to
surrender additional allowances instead of continuing to operate
pollution controls at an optimized level).
    EPA observed this pattern in other units identified in this
rulemaking as having significant SCR optimization emissions reduction
potential. In the accompanying Emissions Data TSD for the supplemental
notice that EPA recently released in a proceeding to

address a recommendation submitted to EPA by the Ozone Transport
Commission under CAA section 184(c), EPA noted, ``In their years with
the lowest average ozone season NOX emissions rates in this
analysis, these EGUs had relatively low NOX emissions rates
at mid- and high-operating levels; moreover, there was little
variability in NOX emissions rates at these operating
levels. However, during the 2019 ozone season, these EGUs had higher
NOX emissions rates and greater variability in
NOX emissions rates across operating levels than in the
past, particularly at mid-operating levels.'' \201\ That hourly data
analysis, included in this docket, controls for operating level changes
and still finds there to be instances across multiple SCR-controlled
units where hourly emissions rates are increasing even when compared to
the same load levels in previous years.
---------------------------------------------------------------------------

    \201\ ``Analysis of Ozone Season NOX Emissions Data
for Coal-Fired EGUs in Four Mid-Atlantic States,'' EPA Clean Air
Markets Division. December 2020. Available at https://www.epa.gov/sites/production/files/2020-12/documents/184c_emission_data_tsd.pdf.
---------------------------------------------------------------------------

    Some commenters have alleged that in recent years coal-fired EGUs
have declined in capacity factor and that SCR performance declines at
those lower operating levels. However, hourly data indicate that
maintaining consistent SCR performance at lower capacity factors is
possible. For example, the unit-level performance data in Figure 2 to
section VI.B of this document show the emissions rate at a coal-fired
EGU with existing SCR staying relatively low (consistent with our
optimization assumption of 0.08 lb/mmBtu) and stable across a wide
range of capacity factors.\202\
---------------------------------------------------------------------------

    \202\ EPA, Air Markets Program Data. Available at www.epa.gov/ampd.
[GRAPHIC] [TIFF OMITTED] TR05JN23.000

    Furthermore, most recent data from 2022 illustrates that cycling
units do have the ability to adjust cycling patterns in a manner that
enables them to maintain a lower emissions rate throughout the season
while still achieving a load cycling pattern at the unit. For example,
the SCR-controlled Conemaugh Unit 2 in Pennsylvania adjusted operating
patterns in 2022 to have a slightly higher minimum load in most hours
(maintaining a range of 550 MW-900 MW for most hours as opposed to 450
MW-900 MW observed in 2021). This change in minimum load, and
corresponding minimum operating temperature, enabled the unit to
maintain emissions rates in the 0.05 lb/mmBtu to 0.10 lb/mmBtu range
for most of the 2022 season (as opposed to NOX emissions
rates that regularly exceeded 0.25 lb/mmBtu in the 2021 season). This
2022 improvement in SCR operation occurred during a period when
allowance prices increased relative to prior years, creating an
incentive for potential emissions reductions through SCR optimization.
    Comment: EPA also received comment suggesting it should deviate
from its approach in the CSAPR Update of using a nationwide data set of
all SCR controlled coal units to establish a third best year, and
instead limit the dataset to either just the covered states, or--in the
case of some commenters--just to the baseline years of those units at
which EPA is identifying optimization potential. They claim the current
methodology may capture extremely efficient SCR performance years at
the best performing units and that level of performance may not be
available at all units with optimization potential. These commenters
also disagree with the EPA finding that SCRs can consistently maintain
a 0.08 lb/mmBtu rate over time.
    Response: EPA reviewed the data and its methodology and evaluated
it against its intention to identify a technology-specific
representative emissions rate for SCR optimization. In doing so, EPA
did not identify any need to make the suggested change. EPA is
interested in the performance potential of a technology, and a larger
dataset provides a superior indication of that potential as opposed to
a smaller, state-limited dataset. Moreover, EPA's use of the third best
year (as opposed to best) from its baseline period results in an
average optimization level that is robust

to the commenters' concern that EPA should not overstate the fleetwide
representative optimization level. Prior experience with EPA's
methodology and program has borne out empirical evidence of its
reasonableness. In both the CSAPR Update and in Revised CSAPR Update
rule, EPA appropriately relied on the largest dataset possible (i.e.,
nationwide) to derive technology performance averages that it then
applied respectively to the CSAPR Update 22-state region and the
Revised CSAPR Update's 12-state region. EPA repeats that successful
approach in this rule. Finally, as noted in the preceding paragraphs,
in affirming the reasonableness of this approach, EPA examined the
historical reported data (pre-2021) for the units in the states with
SCR optimization potential and found the nationwide derived average
appropriate and consistent with demonstrated capability and performance
of units within those states. That is, the vast majority of units to
which this resulting emissions rate assumption was being applied had
demonstrated the ability to achieve this rate in some prior year for an
extended monthly or seasonal basis. This information is discussed
further in the EGU NOX Mitigation Strategies Final Rule TSD
in the docket.
    Comment: Some commenters suggested the price of SCR optimization is
higher than the $1,600 per ton figure proposed due to current market
conditions for aqueous ammonia or other input prices.
    Response: EPA provides a representative cost for this mitigation
technology which is anticipated to reflect the cost, on average,
throughout the compliance period for the rule. While there may be
volatility in the market during that period where the price falls above
or below the single representative threshold value, EPA's EGU
NOX Mitigation Strategies Final Rule TSD explains how the
representative cost is derived and is inclusive of consultation and
vetting by third party air pollution control consulting groups.
Commenters did not demonstrate that observed 2021 elevated prices amid
market volatility would continue into the future compliance periods
discussed in this rule. Moreover, the selection of the mitigation
technology is reflective of a variety of factors including reduction
potential and air quality impact. A higher cost (commenter suggests up
to $3,800 per ton) would not change EPA's determination that optimizing
already existing SCRs is an appropriate mitigation strategy for Step 3
emissions reduction analysis in this rulemaking as it would remain one
of the most widely available, widely practiced, and lowest cost
mitigation measures with meaningful downwind air quality benefit.
Appendix B of the EGU NOX Mitigation Strategies Final Rule
TSD further addresses commenters' concerns as it provides a variety of
sensitivities showing cost per ton levels under a variety of different
input assumptions (including higher material and reagent cost). It
supports the continued inclusion of this technology in the rule even in
the event that higher reagent costs extend into compliance years.
    Comment: While many commenters supported the feasibility of 2023
ozone-season implementation by noting the ``immediate availability'' of
SCR optimization, other commenters argued that the engineering,
procurement, and other steps required for SCR optimization were not
feasible given the anticipated limited window between rule finalization
and the start of the 2023 ozone season.
    Response: There is ample evidence of units restoring their optimal
performance within a two-month timeframe. Not only do units reactivate
SCR performance level at the start of an ozone-season when tighter
emissions limits begin, but unit-level data also shows instances where
sources have demonstrated the ability to quickly alter their emissions
rate within an ozone-season and even within the same day in some cases.
Moreover, this emissions control is familiar to sources and was
analyzed and included in the Revised CSAPR Update emissions budgets
finalized in 2021 and the CSAPR Update emissions budgets finalized in
2016. With this experience, and notice through the March 2022 proposed
rule, as well as over two months from final rule to effective date, the
viability of this emissions control for the 2023 ozone season is
consistent with the 2-week to 2-month timeframe that EPA identified as
reasonable in the CSAPR Update, Revised CSAPR Update, and in this
rulemaking. Similar to prior rules, commenters provide some unit-level
examples where it has taken longer. Also similar to those prior rules,
EPA does not find those unit-level examples compelling in the context
of its fleet average assumptions and in the implementation context of a
trading program which provides compliance alternatives in the event a
specific unit prefers more time to implement a given control measure.
As noted in Wisconsin, ``. . . all those anecdotes show is that
installation can drag on when companies are unconstrained by the
ticking clock of the law.'' 938 F.3d at 330.
b. Installing State-of-the-Art NOX Combustion Controls
    The EPA estimates that the representative cost of installing state-
of-the-art combustion controls is comparable to, if not notably less
than, the estimated cost of optimizing existing SCR (represented by
$1,600 per ton). State-of-the-art combustion controls such as low-
NOX burners (LNB) and over-fire air (OFA) can be installed
or updated quickly and can substantially reduce EGU NOX
emissions. Nationwide, approximately 99 percent of coal-fired EGU
capacity greater than 25 MW is equipped with some form of combustion
control; however, the control configuration or corresponding emissions
rates at a small portion of those units (including units in those
states covered in this action) indicate they do not currently have
state-of-the-art combustion control technology. For this rulemaking,
the Agency re-evaluated its NOX emissions rate assumptions
for upgrading existing combustion controls to state-of-the-art
combustion control. The EPA is maintaining its determination that
NOX emissions rates of 0.146 to 0.199 lb/mmBtu can be
achieved on average depending on the unit's boiler configuration,\203\
and, once installed, reduce NOX emissions at all times of
EGU operation.
---------------------------------------------------------------------------

    \203\ Details of EPA's assessment of state-of-the-art
NOX combustion controls are provided in the EGU
NOX Mitigation Strategies Final Rule TSD.
---------------------------------------------------------------------------

    These assumptions are consistent with the Revised CSAPR Update.
They are further discussed in the EGU NOX Mitigation
Strategies Final Rule TSD. In particular, the EPA is finalizing, as
proposed, the application of the 0.199 lb/mmBtu emissions rate
assumption for both boiler types (tangentially and wall fired). EPA's
analysis calculated average emissions rates of 0.199 lb/mmBtu for
combustion controls on dry bottom wall fired units and 0.146 lb/mmBtu
for tangentially fired units. However, many of the likely impacted
units burn bituminous coal, and the 0.146 lb/mmBtu nationwide average
for tangentially-fired (inclusive of subbituminous units) appears to be
below the demonstrated emissions rate of state-of-the-art combustion
controls for bituminous coal units of this boiler type. Therefore,
EPA's assignment of a 0.199 lb/mmBtu emissions rate for combustion
controls at all affected unit types is robust to current and future
coal choice at a unit.
    The EPA has previously examined the feasibility of installing
combustion controls and found that industry had demonstrated ability to
install state-of-

the-art LNB controls on a large unit (800 MW) in under six months when
including the pre-installation phases (design, order placement,
fabrication, and delivery).\204\ In prior rules, the EPA has documented
its own assessment of combustion control timing installation as well as
evaluated comments it received regarding installation of combustion
controls from the Institute of Clean Air Companies.\205\ Those comments
provided information on the equipment and typical installation time
frame for new combustion controls, accounting for all steps. To date,
EPA has found it generally takes between 6-8 months on a typical
boiler--covering the time through bid evaluation through start-up of
the technology. The deployment schedule is repeated here as:
---------------------------------------------------------------------------

    \204\ The EPA finds that, generally, the installation phase of
state-of-the-art combustion control upgrades--on a single-unit
basis--can be as little as 4 weeks to install with a scheduled
outage (not including the pre-installation phases such as
permitting, design, order, fabrication, and delivery) and as little
as 6 months considering all implementation phases.
    \205\ EPA-HQ-OAR-2015-0500-0093.

 4-8 weeks--bid evaluation and negotiation
 4-6 weeks--engineering and completion of engineering drawings
 2 weeks--drawing review and approval from user
 10-12 weeks--fabrication of equipment and shipping to end user
site
 2-3 weeks--installation at end user site
 1 week--commissioning and start-up of technology

    Given the referenced timeframe of approximately 6 to 8 months to
complete combustion control installation in the region, the EPA is
finalizing that installation of state-of-the-art combustion controls is
a readily available approach for EGUs to reduce NOX
emissions by the start of the 2024 ozone season. More details on these
analyses can be found in the EGU NOX Mitigation Strategies Final Rule
TSD.
    The cost of installing state-of-the-art combustion controls per ton
of NOX reduced is dependent on the combustion control type
and unit type. The EPA estimates the cost per ton of state-of-the-art
combustion controls to be $400 per ton to $1,200 per ton of
NOX removed using a representative capacity factor of 85
percent. This cost fits well within EPA's representative cost threshold
observed for SCR optimization and combustion controls (of $1,600 per
ton) which would accommodate combustion control upgrade even under
scenarios where a lower capacity factor is assumed. 99 percent of units
have some form of combustion controls, indicating the widespread cost-
effectiveness of this control. See the EGU NOX Mitigation Strategies
Final Rule TSD for additional details.
    At proposal EPA assumed that emissions reductions from combustion
control upgrades at affected EGUs in states subject to the Revised
CSAPR Update program could occur by 2023 given that those EGUs may have
already begun pursuing such upgrades in response to that previous rule.
However, EPA does not have data to confirm that presumption, and hence
EPA is determining in this final rule that combustion control upgrades
for all affected EGUs, regardless of whether they were previously
subject to the Revised CSAPR Update program, should be considered
available by the 2024 ozone season, consistent with the deployment
schedule noted in this section.
    Comment: Some commenters suggested that EPA, in its modeling for
the proposed rule, overestimated the ability of combustion control
technologies to achieve very low NOX emissions rates. The
commenters claim EPA's assumptions are derived from projected
NOX emissions rates based on ideal circumstances for
NOX emissions reductions, including combinations of fuel
composition and unit design that are not typical and should not be
extrapolated to the national inventory.
    Response: EPA's emissions performance rate for state-of-the-art
combustion controls is derived from historical data and takes both
boiler type and coal choice into account. EPA reviewed historical data
and identified the average emissions rates for units with this
technology already in place. It segmented this analysis by boiler type
(dry-bottom wall-fired boiler and tangentially-fired, and further
segmented by coal rank to assess the average performance among these
varying parameters. As explained in the EGU NOX Mitigation Strategies
Final Rule TSD, EPA chose an emissions rate for which it verified
accommodated (i.e., was greater than or equal to) the average
performance rate identified above for each boiler configuration with
state-of-the-art combustion controls and resulted in reductions
consistent with the technology's assumed percent reduction potential
when applied to this subset of units. It also assessed whether the rate
had been demonstrated by both subbituminous and bituminous coal units
with state-of-the-art combustion controls. EPA further assessed the
percent reduction that achieving this rate would require from the
specific segment of the fleet identified as having this mitigation
measure available. Here too, EPA found that the effective percent
reduction for the identified fleet (inclusive of their existing coal
rank choice) is well within the historical performance range for this
technology. Therefore, EPA is finalizing the combustion control upgrade
performance assumption of 0.199 lb/mmBtu as appropriate representative
average performance rate for this technology and robust to different
boiler types and coal ranks.
c. Optimizing Already Operating SNCRs or Turning on Idled Existing
SNCRs
    Optimizing already operating SNCRs or turning on idled existing
SNCRs can also reduce EGU NOX emissions quickly, using
investments in pollution control technologies that have already been
made. Compared to no post-combustion controls on a unit, SNCRs can
achieve a 25 percent reduction on average in EGU NOX
emissions (with sufficient reagent). They are less capital intensive
but less efficient at NOX removal than SCRs. These controls
are in use to some degree across the U.S. power sector. In the 22
linked states with EGU reductions identified in this final rule,
approximately 11 percent of coal-fired EGU capacity is equipped with
SNCR.\206\ Recent power sector data suggest that, in some cases, SNCR
controls have been operating less in 2021 relative to performance in
prior years. For instance, EPA reviewed the last five years of
performance data for all the units with SNCR optimization potential in
its Engineering Analysis. It found that in 2021--the most recent year
reviewed--that the weighted average ozone season emissions rate for
these units was higher than the prior three years (indicating some
deterioration in average performance). Moreover, a unit level review
illustrated that 80 of the 107 units had performed better in a prior
year by an average of 13 percent--indicating substantial optimization
potential.\207\
---------------------------------------------------------------------------

    \206\ https://www.epa.gov/airmarkets/national-electric-energy-data-system-needs-v6.
    \207\ See ``Historical Emission Rates for Units with SNCR
Optimization Potential'' in the docket for this rulemaking.
---------------------------------------------------------------------------

    The EPA determined that optimizing already operating SNCRs or
turning on idled SNCRs is an available approach for EGUs to reduce
NOX emissions, has similar implementation timing to
restarting idled SCR controls (less than 2 months for a given unit),
and therefore could be implemented in time for the 2023 ozone season.
In this final rule, the EPA is determining that this emissions

control measure is available beginning in the 2023 ozone season.
    Using the Retrofit Cost Analyzer described in the EGU NOX
Mitigation Strategies Final TSD, the EPA estimates a representative
cost of optimizing SNCR ranging from approximately $1,800 per ton (for
partially operating SNCRs) to $3,900 per ton (for idled SNCRs). For
existing SNCRs that have been idled, unit operators may need to restart
payment of some fixed and variable operating costs including labor,
maintenance and repair, parasitic load, and ammonia or urea. The EPA
determined that the majority of units with existing SNCR optimization
potential were already partially operating their controls. Therefore,
the EPA finalizes a representative cost of $1,800 per ton for SNCR
optimization as this value best reflects the circumstances of the
majority of the affected EGUs with SNCR.
d. Installing New SNCRs
    The EPA evaluated potential emissions reductions and associated
costs from retrofitting EGUs with new SNCR post-combustion controls at
steam units lacking such controls, which can achieve a 25 percent
NOX reduction on average. New SNCR technology provides
owners with a relatively less capital-intensive option for reducing
NOX emissions compared to new SCR technology, albeit at the
expense of higher operating costs on a per-ton basis and less total
emissions reduction potential. SNCR is more widely observed on
relatively smaller coal units given its low capital/variable cost
ratio. The average capacity of a coal unit with SNCR is half the size
of the average capacity of coal unit with SCR.\208\ Given these
observations, the EPA identifies this technology as an emissions
reduction measure for coal units less than 100 MW lacking post-
combustion NOX control technology. As described in the EGU
NOX Mitigation Strategies Final Rule TSD, the EPA estimated that $6,700
per ton reflects a representative SNCR retrofit cost level for these
units.
---------------------------------------------------------------------------

    \208\ See EGU NOX Mitigation Strategies Final Rule
TSD for additional discussion.
---------------------------------------------------------------------------

    For this rulemaking, EPA is not considering SNCR installation
timing unto itself but is instead considering how long eligible EGUs
may need to adopt either SNCR or SCR as a post-combustion control
measure. SNCR installations generally have shorter project installation
timeframes relative to other post-combustion controls. The time for
engineering review, contract award, fabrication, delivery, and hookup
is as little as 16 months including pre-contract award steps for an
individual power plant installing controls on more than one boiler.
However, SNCR retrofits have less pollution reduction potential than
SCRs, and as explained further in the next section, the EPA is
identifying the retrofit of new SCR rather than SNCR as a strategy for
larger steam units due to this lower removal efficiency. This approach
respects empirical evidence that larger coal-fired EGUs which installed
post-combustion NOX control technology have overwhelmingly
chosen SCRs over SNCRs. Even for smaller units less than 100 MW
identified as potential candidates for SNCR technology, the EPA does
not want to preclude those units from pursuing SCR in lieu of SNCR.
    Therefore, in this final rule the EPA defines the availability of
emissions reductions from post-combustion control installation to be in
2026, the same period as the start of SCR-based reductions becoming
available, to allow enough time for eligible EGUs to choose between SCR
or SNCR. SNCR installation shares similar implementation steps with and
also need to account for the same regional factors as SCR
installations, which are described in the next section. While the EPA
is determining that at least 16 months would be needed to complete all
necessary steps of SNCR development and installation, an eligible EGU
choosing new SCR instead would require installation timing of 36 to 48
months. EPA believes its finalized joint timing considerations for
post-combustion control retrofits (SNCR and SCR) are justified given
that post-combustion control retrofit decisions are subject to unit-
specific economic and engineering factors and are sensitive to operator
compliance strategy choices with respect to multiple regulatory
requirements.
    Comment: Some commenters argued that post-combustion control timing
assumptions (SCR and SNCR) should be decoupled, which could result in
the EPA using the 16-month time frame specific to SNCR installation to
require emissions reductions related to new SNCR installations by the
2025 ozone season.
    Response: The EPA does not agree that decoupling SCR and SNCR
timing consideration is justified in the context of this final rule's
emissions control program for EGUs. Approximately 1,000 tons of
emissions reduction potential are estimated for the small coal EGUs
deemed eligible for SNCR retrofit. The incentives provided through the
implementation of this rule's trading program will encourage these EGUs
to determine and adopt emissions reduction measures (including SNCR or
SCR) as soon as possible to reduce their allowance holding compliance
burden. By scheduling SNCR-related emissions reductions potential for
the 2026 ozone season, the EPA preserves the opportunity for
considerably superior emissions reduction potential from these EGUs
should they select SCR retrofit instead, while still requiring post-
combustion control emissions reduction potential ahead of the next
attainment date.
    Comment: Some commenters argued that the upper range of SNCR
NOX removal performance (40 percent) referenced by EPA is
optimistic for many boilers.
    Response: EPA evaluated both actual performance and engineering
literature regarding SNCR retrofit technology and found both sources
supported the range of reduction estimates cited by EPA. (Refer to the
EGU NOX Mitigation Strategies Final Rule TSD in the docket for this
rulemaking for additional information.) Moreover, for purposes of
calculating state budgets, EPA assumes 25 percent reduction from this
technology--not 40 percent--which reflects a value well within the
range of documented performance for this technology. Remaining comments
on SNCR performance potential are addressed in the RTC Document and in
the EGU NOX Mitigation Strategies Final Rule TSD.
e. Installing New SCRs
    Selective Catalytic Reduction (SCR) controls already exist on over
66 percent of the coal fleet in the linked states that are subject to a
FIP in this rulemaking. Nearly every pulverized coal unit larger than
100 MW built in the last 30 years has installed this control, which is
generally required for Best Available Control Technology (BACT)
purposes. Other than circulating fluidized bed coal units which can
achieve a comparably low emissions rate without this technology, the
EPA identifies this emissions reduction measure for coal steam units
greater than or equal to 100 MW. SCR is widely available for existing
coal units of this size and can provide significant emissions reduction
potential, with removal efficiencies of up to 90 percent. The EPA
limited its consideration of SCR technology to steam units greater than
or equal to 100 MW. The costs for retrofitting a plant smaller than 100
MW with SCR increase

rapidly due to a lack of economies of scale.\209\
---------------------------------------------------------------------------

    \209\ IPM Model-Updates to Cost and Performance for APC
Technologies. SCR Cost Development Methodology for Coal-fired
Boilers. February 2022.
---------------------------------------------------------------------------

    The amount of time needed to retrofit an EGU with new SCR extends
beyond the 2023 ozone season. Similar to the SNCR retrofits discussed
in this section, the EPA evaluated potential emissions reductions and
associated costs from this control technology, as well as the impacts
and need for this emissions control strategy, at the earliest point in
time when their installation could be achieved. EPA notes that it has
previously determined in the context of ozone transport that regional
scale implementation of SCRs at numerous EGUs is achievable in 36
months. See 63 FR 57356, 57447-50 (October. 27, 1998). However, since
that time, the EPA has found up to 36-48 months to be a more
appropriate installation timeframe for regionwide actions when the EPA
is evaluating multiple installations at multiple locations.\210\
---------------------------------------------------------------------------

    \210\ See, e.g., CSAPR Close-Out, 83 FR 65878, 65895 (December
21, 2018) and Revised CSAPR Update, 86 FR 23102 (April 30, 2021).
See also Final Report: Engineering and Economic Factors Affecting
the Installation of Control Technologies for Multipollutant
Strategies, EPA-600/R-02/073 (Oct. 2002), available at https://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf.
---------------------------------------------------------------------------

    In the past, the EPA has found the amount of time to retrofit a
single EGU with new SCR, depending on the regulatory program under
which such control may be required, may vary between approximately 2
and 4 years depending on site-specific engineering considerations and
on the number of installations being considered. This includes steps
for engineering review, construction permit, operating permit, and
control technology installation (including fabrication, pre hookup,
control hookup, and testing). EPA's assessment of installation
procedures suggests as little as 21 months may be needed for a single
SCR at an individual plant and 36 months at a single plant with
multiple boilers. EPA's assessment of units with SCR retrofit potential
indicate the majority fall into this first classification, i.e., a
single SCR at a power plant.
    While EPA finds that 36 months is a possible time frame for SCR
installation at individual units or plants, the total of nearly 31 GW
of coal capacity with SCR retrofit potential and 19 GW of oil/gas steam
capacity with SCR retrofit potential within the geographic footprint of
the final rule is a scale of retrofit activity that is not demonstrated
to have been achieved within a three-year span based on data from the
past two decades. Given that some of the assumed SCR retrofit potential
occurs at plants with multiple units identified with retrofit
potential, and given the total volume of SCR retrofit capacity being
implemented across the region, EPA is allowing in this final rule
between 36 to 48 months, consistent with the regional time frame
discussed for SCR retrofit in prior rules, for the full implementation
of reductions commensurate with this volume of SCR retrofit capacity,
as described further in section VI.A of this document.
    The Agency examined the cost for retrofitting a coal unit with new
SCR technology, which typically attains controlled NOX rates
of 0.05 lb/mmBtu or less. These updates are further discussed in the
EGU NOX Mitigation Strategies Final Rule TSD.\211\ Based on
the characteristics of coal units of 100 MW or greater capacity that do
not have post-combustion
---------------------------------------------------------------------------

    \211\ As noted in that TSD, approximately half of the recent SCR
retrofits (i.e., installed in the last 10 years) have demonstrated
an emission rate across the ozone season below 0.05 lb/mmBtu, even
absent a requirement or strong incentive to operate at that level in
many cases.
---------------------------------------------------------------------------

    NOX control technology, the EPA estimated a weighted-
average representative SCR cost of $11,000 per ton.\212\
---------------------------------------------------------------------------

    \212\ This cost estimate is representative of coal units lacking
any post-combustion control. A subset of units within the universe
of coal sources with SCR retrofit potential, but that have an
existing SNCR technology in place would have a weighted average cost
that falls above this level, but still cost effective. See the EGU
NOX Mitigation Strategies Final Rule TSD for more
discussion.
---------------------------------------------------------------------------

    The 0.05 lb/mmBtu emissions rate performance assumption for new SCR
retrofits is supported by historical data and third party independent
review by pollution control engineering and consulting firms. The EPA
first examined unit-level emissions rate data for coal-fired units that
had a relatively recent SCR installation (within the last 10 years).
The best performing 10 percent of these SCRs were demonstrating
seasonal emissions rates of 0.036 lb/mmBtu during this time.
    While the EPA identified the 0.05 lb/mmBtu performance assumption
consistent with historical data, these performance levels are also
informed and consistent with the Agency's IPM modeling assumptions used
for more than a decade. These modeling assumptions are based on input
from leading engineering and pollution control consulting entities.
Most recently, these data assumptions were affirmed and updated in the
summer of 2021 and included in the docket for this rulemaking.\213\ The
EPA relies on a global firm providing engineering, construction
management, and consulting services for power and energy with expertise
in grid modernization, renewable energy, energy storage, nuclear power,
and fossil fuels. Their familiarity with state-of-the art pollution
controls at power plants derives from experience providing
comprehensive project services--from consulting, design, and
implementation to construction management, commissioning, and
operations/maintenance. This review and update supported the 0.05 lb/
mmBtu performance assumption as a representative emissions rate for new
SCR across coal types.
---------------------------------------------------------------------------

    \213\ See ``IPM Model--Updates to Cost and Performance for APC
Technologies: SCR Cost Development Methodology for Coal-fired
Boilers''.
---------------------------------------------------------------------------

    The EPA performed an assessment for oil/gas steam units in which it
evaluated the nationwide performance of those units with SCR
technology. For these units, the EPA tabulated EGU NOX ozone
season emissions data from 2009 through 2021 and calculated an average
NOX ozone season emissions rate across the fleet of oil- and
gas-fired EGUs with SCR for each of these years. The EPA identified the
third lowest year which yielded an SCR performance rate of 0.03 lb/
mmBtu as representative of performance for this retrofit technology
applied to this type of EGU. Next, the EPA evaluated the emissions and
operational characteristics for the existing oil/gas steam fleet
lacking SCR technology. EPA's analysis indicated that the majority of
reduction potential (approximately 76 percent) from these units
occurred at units greater than or equal to 100 MW and that were
emitting more than 150 tons per ozone season (i.e., approximately 1 ton
per day). Moreover, the cost of reductions for units falling below
these criteria increased significantly on a dollar per ton basis.
Therefore, the EPA identified the portion of the oil/gas steam fleet
meeting these criteria (i.e., greater than or equal to 100 MW and
emitting more than 150 tons per ozone season) as representative of the
SCR retrofit reduction potential.\214\ For this segment of the oil/gas
steam units lacking post-combustion NOX control technology,
the EPA estimated a weighted-average representative SCR cost of $7,700
per ton.
---------------------------------------------------------------------------

    \214\ The EPA used a 3-year average of 2019-2021 reported ozone
season emissions to derive a tons per ozone season value
representative for each covered oil/gas steam unit.
---------------------------------------------------------------------------

    Comment: Some commenters disagreed with EPA's proposed 36-month
timeframe for SCR retrofit. These commenters noted that, while possible
at the unit or plant level, the collective volume of SCR installation
occurring in

a limited region of the country would not be possible given the labor
constraints, supply constraints, and simultaneous outages necessary to
complete SCR retrofit projects on such a schedule. They noted that
achieving such a timeframe against a backdrop of such challenging
circumstances is unprecedented and that EPA's assumptions ignore that
many of the remaining unretrofitted coal units reflect more site-
specific challenges than those that were already retrofitted on a
quicker timeframe.
    Response: EPA reviewed the comments and is making several changes
in this final rule to address some of the concerns identified by the
commenters. In particular, EPA found that its own review of historical
retrofit patterns as well as technical information submitted by
commenters supported commenters' concerns regarding: (1) current and
anticipated constraints in labor and supply markets, (2) the potential
collective capacity levels of SCR retrofit within 36 months, and (3)
possible site-specific complexities at the remaining units without an
existing SCR. To address these concerns, EPA is phasing in its SCR
installation requirement over a 48-month time frame in this final rule,
instead of a 36-month time frame as proposed (see additional detail and
discussion in section VI.A.2.a and the EGU NOX Mitigation
Strategies Final Rule TSD). EPA will require half of the reductions
associated with SCR installation in 2026 and the other half in 2027.
Additionally, EPA is moving the daily backstop rate for these units
with identified SCR reduction potential from 2027 to no later than
2030, which defers the increased allowance surrender ratio for
emissions above the backstop rate at any outlier units unable to
complete the retrofit during that time frame. These adjustments
continue to incentivize reductions in NOX emissions by the
attainment date that are consistent with cost-effective SCR controls,
but provide more flexibility (both from timing and technology
perspective) in how they are procured.
    Some commenters requested more than 48 months to install SCR
controls based on the collective total volume of SCR retrofit volume
identified and past projects that took five or more years. EPA
disagrees with these comments and finds that they ignored key aspects
of the proposed rule. First, the final rule does not directly require
implementation of SCR; rather, it requires reductions commensurate with
SCR installations based on a rigorous assessment of SCR retrofit
potential. Implementing the reductions through a trading program means
that sources in many cases, as suggested by the Regulatory Impact
Analysis (RIA), will find alternative, and more economic means, of
reducing emissions--including reduced generation and retirements that
are already planned based on the age of the unit, decarbonization
goals, or compliance with other Federal/state/local regulation
compliance dates. Moreover, the additional new generation incentives
provided by the Inflation Reduction Act (enacted after the proposed
rule) will further increase the pace of new generation replacing some
of the older generating capacity identified as having retrofit
potential.\215\ In short, although EPA identified the total SCR
retrofit capacity potential for today's existing fleet and does not
premise any reduction requirements of incremental retirements, the
announced and planned futures for these units indicates that many will
likely retire instead of installing SCR. For the capacity identified at
Step 3 which lacks SCR, the planned or projected retirement in place of
a retrofit moots the SCR timing for these units. Moreover, it also
reduces the demand for associated labor and materials which, in turn,
frees up resources for any units proceeding with a SCR retrofit.
Therefore, comments which cite labor and supply chain challenges for
accommodating the entire fleet capacity identified as having SCR
retrofit potential significantly overstate the supply-side challenge--
as it ignores the fact that much of this capacity has explicit or
expected operation plans that will result in compliance without a
retrofit.
---------------------------------------------------------------------------

    \215\ See ``Regulatory Impact Analysis for 2015 Good Neighbor
Plan, Appendix 4A: Inflation Reduction Act EGU Sensitivity Run
Results.'' EPA estimated the compliance costs and emissions changes
of the final rule in the presence of the IRA, but given time and
resource constraints, did not quantify benefits for this
sensitivity.
---------------------------------------------------------------------------

    Even for sources choosing a SCR retrofit compliance pathway, many
of these comments ignore the timing flexibilities of the trading
program, which (particularly with the changes to the backstop daily
emissions rate in this final rule) allow sources to temporarily comply
through means other than SCR retrofit if they experience any site-
specific retrofit limitations that increase their time frame. Also,
historical examples of SCR retrofit projects that exceeded 48 months in
duration do not necessarily demonstrate that such projects are
impossible in less than 48 months, but rather that they can extend
beyond the timeframe if no requirements or incentives are in place for
a faster installation. Some also cite site-specific conditions that
resulted an outlier cases of project timing that would not be
representative of the conditions expected at future retrofit
projects.\216\
---------------------------------------------------------------------------

    \216\ Commenters, for example, cited the timing of SCR
installation at Sammis 6 and 7. Here, the SCR design and material
delivery schedule were tailored to meet unique site conditions that
were unlike many other SCR systems where large modules can be used
to maximize shop and ground assembly techniques. Additional
information is available at https://www.babcock.com/home/about/resources/success-stories/sammis-plant.
---------------------------------------------------------------------------

    Comment: Some stakeholders suggested that EPA's cost estimates of
$11,000 per ton are premised on a 15-year book life of the equipment
and are therefore too optimistic for units that plan to retire in well
under 15 years.
    Response: EPA analysis of SCR retrofit cost reflects a
representative value for the technology based on a weighted average
cost. The underlying data and the discussion in the EGU NOX
Mitigation Strategies Final TSD illustrates that these costs can vary
significantly at the unit level based on factors such as the length of
time a pollution control technology would be in operation, the capacity
factor of the unit (i.e., how much does it operate), its size or
potential to emit, and its baseline emissions rate. The EPA has not in
prior transport rulemakings used such factors as justification to
excuse any source that is significantly contributing to nonattainment
or interfering with maintenance in another state from eliminating that
significant contribution as expeditiously as practicable. Unlike under
other statutory provisions that may require retrofit of emissions
controls on existing sources, such as under CAA section 111(d) or CAA
section 169A, there is no remaining useful life factor expressly
identified as a justification to relax the requirements of CAA section
110(a)(2)(D)(i)(I). EPA continues to believe that where an emissions
control strategy has been identified at Step 3 that is cost-effective
on a regional scale and provides meaningful downwind air quality
improvement, and is thus appropriately identified as necessary to
eliminate significant contribution under the good neighbor provision,
it would not be appropriate to allow emissions to continue in excess of
those achievable emissions reductions beyond the timeframe for
expeditious implementation of reductions as provided under the larger
title I structure of the Act for attaining and maintaining the NAAQS.
The court in Wisconsin recognized that where such emissions have been
identified, they should be eliminated as expeditiously as practicable,
and in line with the

attainment schedule for downwind areas, which, for the 2015 ozone
NAAQS, is provided in CAA section 181. 938 F.3d at 313-20.
    Further, EPA observes that more than one-third of the identified
SCR retrofit potential (in terms of generating capacity) has no planned
retirement date within 15 years, and therefore the cost of pollution
control technology on such units would likely be lower, holding all
other parameters equal, on a dollar per ton basis by virtue of the
length of time the pollution control equipment may be in operation. Nor
does EPA agree that units that would retire in less than 15 years
should automatically be considered to face an unreasonably higher cost
burden. Based on data analyzed in the EGU NOX Mitigation
Strategies Final Rule TSD, we find that the cost per ton associated
with SCR retrofit technology does not begin to increase significantly
above the $11,000/ton benchmark unless units have dramatically lower
operating capacity or retire in less than 5 years' time--as illustrated
in Figure 1 to section V.B.1.e of this document.
[GRAPHIC] [TIFF OMITTED] TR05JN23.001

    Finally, EPA's identification of this mitigation strategy is not
meant to be limited only to units that experience a retrofit cost that
is less than the representative cost threshold. First, that threshold
represents an average, meaning that EPA's analysis already recognizes
that some units on a facility-specific basis may face costs higher than
that threshold. Further, EPA identifies this technology as widely
available, implemented in practice already at many existing EGUs, and
now standard for any coal-fired unit coming online in the past 25
years. More than 66 percent of the current large coal fleet already has
such controls in place. Even if the cost were higher for some units for
the reasons provided by commenters--and there were no less costly means
provided to them to achieve the same level of emissions reduction
(which the trading program allows for)--that would not necessarily
obviate EPA's basis for finding that an emissions-reduction requirement
commensurate with this standard pollution control practice for this
unit type is warranted. The implementation of emissions reductions
through a trading program, and its corresponding compliance
flexibilities, make the use of a single representative cost all the
more appropriate in this assessment. Therefore, upon reviewing all of
the data including the information supplied by commenters, and even
accounting for certain units' announced plans to retire earlier than an
assumed 15-year book life for SCR retrofit technology, EPA finds its
representative cost for this technology to be appropriate and
reasonable for purposes of analysis under CAA section
110(a)(2)(D)(i)(I) and maintains this cost estimate in the final rule.
---------------------------------------------------------------------------

    \217\ ``Debt Life'' refers to the term length, or duration, for
a loan used to finance the retrofit.
---------------------------------------------------------------------------

    However, in recognition of the unique circumstances related to the
transition of the power sector away from coal-fired and other high-
NOX emitting fuels and generating technologies, which is
anticipated to accelerate in the late 2020s and into the 2030s, EPA has
adjusted the final rule to avoid imposing a capital-intensive control
technology retrofit obligation which could have overall net-negative
environmental consequences (e.g., by extending the life of a higher-
emitting EGU or necessitating the allocation of material and personnel
that could be used for more advanced clean-technology

innovations). For units that plan to retire by 2030, the final rule--by
extending the daily backstop rate to 2030--allows these units to
continue to operate, so long as they comply with the mass-based
emissions trading program requirements.\218\ Therefore, a unit
experiencing a higher dollar per ton retrofit cost due to retirement
plans has the flexibility to install less capital intensive controls
such as SNCR, procure less costly allowances through either banking or
purchase, or they may also reduce their allowance holding requirement
through reduced utilization consistent with their phasing out towards a
planned retirement date. This flexibility that EPA has included in the
final rule is discussed in further detail in section VI.B of this
document.
---------------------------------------------------------------------------

    \218\ In the RIA, EPA has modeled the mass-based budgets that
are premised on retrofit of SCR technology with the option of
complying through other strategies, and finds that they are readily
achievable through those other strategies.
---------------------------------------------------------------------------

    Comment: Some commenters suggested that the 0.05 lb/mmBtu emissions
rate assumed for new SCRs at large coal units is not achievable at all
coal units with retrofit potential and that EPA should raise this
performance assumption to a value of 0.08 lb/mmBtu consistent with that
assumption for existing SCRs.
    Response: First, EPA believes the commenter misunderstands its
intention with the 0.05 lb/mmBtu SCR rate assumption. This is meant to
reflect a representative assumption for emissions rate performance for
new SCR installed on the currently unretrofitted coal fleet--in this
respect, it represents an average, not a maximum. EPA recognizes that
some units will likely perform better (i.e., lower) than this rate and
some will potentially perform worse (i.e., higher) than this rate--but
that 0.05 lb/mmBtu is a reasonable representation of new SCR retrofit
potential on a fleet-wide basis and for identifying expected state and
regional emissions reduction potential from this technology. It would
be inappropriate for EPA to use the worst performing tier of new SCR
retrofit for this representative value. Moreover, EPA's review of
historical environmental performance for recently installed SCRs does
not support any indication that 0.05 is not representative of the
retrofit potential for the fleet. EPA found that three quarters of the
SCR retrofit projects completed in the last 15 years have achieved a
rate of 0.05 lb/mmBtu or better on a monthly or seasonal basis.
Moreover, its review of the engineering literature and consultation
with third party pollution control engineering consultancies suggests
that vendors are often willing to guarantee 0.05 lb/mmBtu seasonal
performance for new SCR retrofit projects. Current SCR catalyst
suppliers provide NOX emissions warranties based at the
catalyst's end-of-life period, often after 16,000 to 24,000 hours of
operations, with newer catalyst achieving similar or better
NOX removal rates. Standard commercial terms, made by the
purchaser to the SCR Retrofit supplier, can specify a system capable of
meeting the proposed NOX emissions rate and define the
catalyst operational life before replacement. Thus, achieving the
proposed reduction rates is accomplished through the buyer specifying
the SCR retrofit requirements and the supplier providing an optimized
system design and installing sufficient catalyst for the targeted end-
of-life NOX emissions rate. The agency is confident that SCR
retrofit suppliers will be able to warrant their offerings for the
emissions rates proposed in the regulation and to provide sufficient
operating life for the affected sector.
    Comment: Some commenters suggest that the evaluation of pollution
control installation cost at Step 3 should be segmented depending on
unit characteristics, and by failing to do so understate the cost of
retrofitting SCR controls. In particular, these commenters note that
units with lower capacity factors, different coal ranks, with pre-
existing controls--such as SNCR--face substantially higher dollar per
ton reduced costs than those that do not have such controls in place
and should not be identified as a cost-effective mitigation strategy.
    Response: Consistent with prior CSAPR rulemakings, at Step 3 EPA
evaluates a mitigation technology and its representative cost and
performance for the fleet on average. This representative cost is
inclusive and robust to the portion of the fleet that may face higher
dollar per ton cost. Both the ``Technical Support Document (TSD) for
the Proposed Federal Implementation Plan Addressing Regional Ozone
Transport for the 2015 Ozone National Ambient Air Quality Standard,
Docket ID No. EPA-HQ-OAR-2021-0668, EGU NOX Mitigation
Strategies Proposed Rule TSD'' (Feb. 2022), hereinafter referred to as
the EGU NOX Mitigation Strategies Proposed Rule TSD, and the
EGU NOX Mitigation Strategies Final TSD discuss the SCR
retrofit cost specific to the segment of the fleet that has a SNCR in
place and notes that those unit-level higher retrofit cost estimates
are factored into its determination of the fleet-wide representative
number. Although EPA believes its representative cost are appropriate
and underpinned by operating assumptions reflective of the fleet
averages, it nevertheless examined how cost would vary based on some of
the variables highlighted by commenter. The EPA derived its capacity
factor assumption based on expected future operations of this fleet
segment that are inclusive of units operating at a range of capacity
factors. It also examined how cost would change assuming different coal
rank, assuming different book life, and different reagent cost. These
analyses are discussed and shown in Appendix B of the EGU
NOX Mitigations Strategies Final Rule TSD and demonstrate
that even under different operating assumptions, the variation in cost
does not reach a point that would reverse EPA's finding regarding the
appropriateness of this technology as part of this final rule's control
stringency. Moreover, as discussed in section V.D of this document, EPA
identifies appropriate mitigation strategies based on multiple
factors--not solely on cost, and there is no indication that an
individual unit's higher retrofit cost would obviate the
appropriateness of retrofitting this standard and best practice
technology at the unit. Finally, in prior rules and in the proposal,
EPA recognized that some units will have higher cost and some will have
lower cost relative the fleetwide representative value provided.
Implementing the region and state reduction requirements through a
mass-based trading program provides a means of alternative lower cost
compliance for those sources particularly concerned about the higher
retrofit cost at their unit.
    Comment: Some commenters suggested that EPA's proposed
representative cost for SCR pollution control is likely too high and
overstates the true cost of such control. They also noted it aligns
with agency precedent. These commenters claim that EPA's cost recovery
factor is higher than necessary (thus inflating the cost) as it
reflects a weighting of utility-owned to merchant-owned plants that is
representative of the fleet, but not the unretrofitted fleet with this
retrofit potential identified in this rule. They also noted that EPA's
assumed interest rate informing the cost estimate was higher than the
prime rate in June of 2022.
    Response: EPA agrees that its approach for identifying
representative cost thresholds is aligned with prior rules and agrees
that its approach is reasonable. As the commenter points out, prime
rates and cost recovery factors may indeed be lower in recent data than
those assumed by EPA for future years. However, given the

volatility among these metrics, EPA believes its choices are
appropriate to build cost estimates that are robust to future
uncertainty, and if these cost input factors do materialize to be the
lower values highlighted by commenter, then it will result in a lower
cost assumed in this final rule, but would not otherwise alter any of
the stringency identification or regulatory findings put forward in
this final rule. EPA performed a cost sensitivity analysis in Appendix
B of the EGU NOX Mitigation Strategies Final Rule TSD which
shows how cost for this technology would vary based on different
assumed levels for this variable. This analysis shows that under lower
interest rates such as those put forward by commenter, that technology
cost would drop by approximately 15 percent relative to the
representative values put forward in this rule.
f. Generation Shifting
    At proposal, EPA considered intrastate emissions reduction
potential from generation shifting across the representative dollar per
ton levels estimated for the emissions controls considered in previous
sections. As the cost of emitting NOX increases, it becomes
increasingly cost-effective for units with lower NOX rates
to increase generation, while units with higher NOX rates
reduce generation. Because the cost of generation is unit-specific,
this generation shifting occurs incrementally on a continuum.
Consequently, there is more generation shifting at higher cost
NOX-control levels.
    The EPA recognizes that imposing a NOX-control
requirement on affected EGUs, like any environmental regulation,
internalizes the cost of their pollution, which could result in
generation shifting away from those sources toward other generators
offering electricity at a lower pollution cost. If, in the context of a
market-based allowance trading program form of implementation, the EPA
imposes a preset emissions budget that is premised only on assumed
installation, optimization, and continued operation of unit-specific
pollution control technologies, with no accounting for the likely
generation shift in the marketplace away from these higher-polluting
sources, that preset emissions budget will contain more tons than would
be emitted if the affected EGUs achieved the emissions performance
level (on a rate basis) selected at step 3. Hence, EPA has previously
quantified and required expected emissions reductions from generation
shifting in prior transport rules to avoid undermining the program's
incentive to install, optimize, and operate controls identified in the
Agency's determinations regarding the requisite level of emissions
control at Step 3. See, e.g., 81 FR 74544-45; 76 FR 48280.
    As in these prior rules, at proposal, the EPA did not identify
generation shifting as a primary mitigation strategy and stringency
measure on its own, but included emissions reductions from this
strategy as it would be projected to occur in response to the selected
emissions control stringency levels (and corresponding allowance price
signals in step 4 implementation). For this rule's proposal, the EPA
only specified emissions reductions from generation shifting in its
preset budget calculations for 2023 and 2024. Because this rule's
dynamic budget methodology applies the selected control stringency's
emissions rates to the most recently reported heat input at each
affected EGU, dynamic budgeting effectively serves a similar purpose to
our ex ante quantification of emissions reduction potential from
generation shifting for preset budgets in prior transport rules, i.e.,
to adequately and continuously incentivize the implementation of the
emissions control strategies selected at Step 3. Therefore, dynamic
budgets under this rule's program moot the need to specify discrete
emissions reduction potential from generation shifting for those
control periods, as they automatically reflect whatever generation
balance affected EGUs would determine in the marketplace inclusive of
their response to the emissions performance levels imposed by this
rule.
    Comment: Commenters offered both support for and opposition against
the inclusion of generation shifting at Step 3 analysis for EGUs. Those
in support noted that inclusion of emissions reductions from
generation-shifting is integral to the successful implementation of the
pollution control measures identified in the selected control
stringency at Step 3. Those opposed generally argued the EPA was
overestimating reduction potential from generation shifting in light of
recent volatility and high prices in the markets for lower emitting
fuels such as natural gas. Commenters also noted the electrical grid in
certain regions has constraints that would make generation shifting
more difficult than the EPA assumed. Commenters also asserted that the
EPA did not have the legal authority to require generation shifting.
    Response: The EPA disagrees with these comments regarding our legal
authority but notes this issue is not relevant for purposes of this
final action. The EPA continues to believe it has authority under CAA
section 110(a)(2)(D)(i)(I) to consider and require emissions reductions
from generation shifting if the EPA were to find that strategy was
necessary to eliminate significant contribution. However, based on
circumstances currently facing affected EGUs, as well as the inherent
strength of the dynamic budget methodology to automatically reflect the
market-determined balance of generation across sources responding to
this rule, the EPA is not specifying emissions reduction potential from
generation shifting as a part of the Step 3 analysis, nor to require
any emissions reductions from generation shifting in preset budgets
formulated under Step 4 for any control period, for this final rule.
    Currently observable market conditions (e.g., fuel prices) present
unusual uncertainty with respect to key economic drivers of generation
shifting. The availability of emissions reductions through generation
shifting, and the magnitude of those emissions, is dependent on the
availability and cost of substitute generation. The primary driver of
near-term generation shifting-based emissions reductions has been
shifting to lower-emitting natural gas generation. Recent volatility
and high prices in the natural gas market have increased the
uncertainty and reduced the potential of this emissions control
strategy at any given cost threshold in the near term. For example,
Henry Hub natural gas prices went from under $3.00/mmBtu during most of
the last decade to an average of nearly $8.00/mmBtu for the most recent
(2022) ozone season before declining sharply at the start of 2023. The
current volatility in natural gas prices reduces the availability of
emissions reductions from generation shifting and make its
identification and quantification too uncertain for incorporation into
Step 3 emissions reduction estimates for this rulemaking.
    The Step 4 dynamic budget-setting process of this rule obviates the
need to specify and require discrete emissions reductions from
generation shifting under Step 3. As discussed in section VI of this
document, the EPA in this final rule will implement a budget-setting
approach that relies on two components: first, we have calculated
``preset'' budgets that reflect the best information currently
available about fleet change over the period 2023 through 2029. Second,
beginning in 2026, dynamic state emissions budgets will be calculated
that will reflect the balance of generation across sources reported to
EPA by EGU operators. Between 2026 and 2029, the actual budget that
will be implemented will

reflect the greater of either the preset budget or the dynamic budget
calculation; from 2030 onwards, the budgets will be set only through
the dynamic budget calculation. This overall approach is well suited
for a period of significant power sector transition driven by a variety
of economic, policy, and regulatory forces and allows for the balance
of generation in this period to adjust in response to these forces
while nonetheless ensuring that the budgets will continuously
incentivize the emissions control stringency identified at Step 3. See
section VI.B.4 of this document for further discussion on the
interaction of preset and dynamic budgets during the 2026-2029 time
period. With these approaches, and on the present record before the
Agency, we conclude that the estimation and incorporation of specified
emissions reductions from generation shifting at Step 3 is not
necessary to eliminate significant contribution from EGUs for the 2015
ozone NAAQS through this rule's program implementation.
    In previous CSAPR rulemakings, the EPA included generation shifting
in the budget setting process to capture those reductions that would
occur through shifting generation as an economic response to the
control stringency determined based on the selected NOX
control strategies. See, e.g., 81 FR 74544-45. ``Because we have
identified discrete cost thresholds resulting from the full
implementation of particular types of emissions controls, it is
reasonable to simultaneously quantify the reduction potential from
generation shifting strategy at each cost level. Including these
reductions is important, ensuring that other cost-effective reductions
(e.g., fully operating controls) can be expected to occur.'' EGU
NOX Mitigation Strategies Final Rule TSD (EPA-HQ-OAR-2015-
0500-0554), at 11-12.
    Commenters on this rule and prior transport rules have observed
that using preset budgets to factor in generation shifting is flawed in
that it results in EPA incorporating specific quantities of emissions
reductions from discrete levels of generation shifting that are
projected to occur but may in fact ultimately transpire differently in
the marketplace. Commenters on this rule claim that other variables,
such as constraints in transmission capacity or changes in fuel prices,
can drive such differences in projected versus realized generation
shifting, and these concerns are particularly exacerbated in a time of
significant uncertainty around energy supplies and markets together
with new laws passed by Congress (e.g., the Infrastructure Investment
and Jobs Act and the Inflation Reduction Act) driving the current
transformation of the power sector. By refraining in this rule from
specifying discrete emissions reductions from generation shifting in
preset budgets and instead relying on a dynamic budgeting approach to
reflect market-driven generation patterns, EPA ensures that its budgets
remain sufficiently stringent over the long term to continually
incentivize the emissions control stringency it determined to be cost-
effective and therefore appropriate to eliminate significant
contribution at Step 3. Thus, dynamic budgeting addresses the same
concern that animated our use of generation shifting in the CSAPR
rulemakings, but in doing so uses a market-following approach that will
accommodate, over the long term, unforeseen drops or increases in heat
input levels.
g. Other EGU Mitigation Measures
    The EPA requested comment on whether other EGU ozone-season
NOX Mitigation technologies should be required to eliminate
significant contribution. For instance, the EGU NOX
Mitigation Strategies Proposed and Final Rule TSDs discussed certain
mitigation technologies that have been applied to ``peaking'' units
(small, low-capacity factor gas combustion turbines often only
operating during periods of peak demand).
    Comment: Some commenters emphasized that simple cycle combustion
turbines play a significant role in downwind contribution, and they
highlight that states such as New York have imposed emissions limits on
these sources acknowledging their impact on downwind nonattainment.
These commenters suggest that EPA pursue and expedite the
implementation of these or similar mitigation measures.
    Response: As explained in greater detail in the EGU NOX
Mitigation Strategies Final TSD, both the configuration and operation
of this segment of the EGU fleet reflects significant variability among
units and across time. In other words, one unit may have a capacity
factor in a given year that is one hundred times greater than a similar
unit in that same year, or even than its own capacity factor from a
preceding year. This type of variability and heterogeneity make it
unlikely that there is a single cost-effective control strategy across
this fleet segment, and commenters did not provide evidence to the
contrary. EPA's analysis discussed in the EGU NOX Mitigation
Strategies Final Rule TSD highlights that there are 32 units emitting
more than 10 tons per year on average for the 2019-2021 ozone seasons
and lacking combustion controls or more advanced controls (totaling
approximately 1,000 tons of ozone season NOX emissions in
2021). EPA analysis estimates a representative cost of $22,000 per ton
for dry low NOX burners or ultra-low NOX burners
at these simple cycle combustion turbines, and over $100,000 per ton
for SCR retrofit at some combustion turbines. Therefore, EPA does not
identify any such uniform mitigation measure at Step 3 when estimating
reduction potential.
    Nonetheless, the EPA recognizes that these simple cycle combustion
turbines may have cost-effective emissions-reduction opportunities.
These units are included in the emissions trading program and
therefore, as in prior transport rules, the program continues to
subject them to an allowance holding requirement under this rule which
will likely incentivize any available cost-effective NOX
reductions from these EGUs. For instance, emissions rates from these
units in New York were considerably lower in 2022, when they faced a
high allowance price, versus 2021, when the allowance price was much
lower. Therefore, we find that the appropriate treatment of these units
in this final rule is to continue to include them in the emissions
trading program to incentivize cost-effective emissions reductions, but
EPA does not find the magnitude or consistency of cost-effective
mitigation potential to establish a specific increment of emissions
reduction through a specific Step 3 emissions control determination.
Moreover, while EPA's program will incentivize any available cost-
effective reductions within this cadre of units (and such behavior is
captured in its final program evaluation and modeling the RIA), it does
not obviate the need for the other EGU cost-effective reductions
elsewhere as suggested by some commenters.
2. Non-EGU or Stationary Industrial Source NOX Mitigation
Strategies
    In the early stages of preparing the proposed FIP, the EPA
evaluated air quality modeling information, annual emissions, and
information about potential controls to determine which industries,
beyond the power sector, could have the greatest impact on downwind
receptors' air quality and therefore the greatest impact in providing
ozone air quality improvements in affected downwind states through
reducing those emissions. Specifically, the EPA conducted a screening
assessment focused on individual emissions units with >100

tpy of actual NOX emissions in 23 upwind states. Once the
industries were identified, the EPA used its Control Strategy Tool to
identify potential emissions units and control measures and to estimate
emissions reductions and compliance costs associated with application
of non-EGU emissions control measures. The technical memorandum
``Screening Assessment of Potential Emissions Reductions, Air Quality
Impacts, and Costs from Non-EGU Emissions Units for 2026'' (``Non-EGU
Screening Assessment'' or ``screening assessment'') lays out the
analytical framework and data used to prepare proxy estimates for 2026
of potentially affected non-EGU facilities and emissions units,
emissions reductions, and costs.\219\
---------------------------------------------------------------------------

    \219\ The memorandum is available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0150.
---------------------------------------------------------------------------

    This screening assessment was not intended to identify the specific
emissions units subject to the proposed emissions limits for non-EGU
sources but was intended to inform the development of the proposed rule
by identifying proxies for (1) non-EGU emissions units that potentially
had the most impact in terms of the magnitude of emissions and
potential for emissions reductions, (2) potential controls for and
emissions reductions from these emissions units, and (3) control costs
from the potential controls on these emissions units. This information
helped shape the proposed rule.
    To further evaluate the industries and emissions unit types
identified by the screening assessment and to establish the
applicability criteria and proposed emissions limits, the EPA reviewed
RACT rules, NSPS rules, NESHAP rules, existing technical studies, rules
in approved SIP submittals, consent decrees, and permit limits. That
evaluation is detailed in the Proposed Non-EGU Sectors TSD prepared for
the proposed FIP.\220\
---------------------------------------------------------------------------

    \220\ The TSD for the proposed FIP is available in the docket
here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668-0145.
---------------------------------------------------------------------------

    In this final rule, for purposes of this part of the Step 3
analysis, the EPA is retaining emissions control requirements for these
industries and many of the emissions unit types included in the
proposal. However, based on comments that credibly indicated in certain
cases that emissions reduction opportunities are either not available
for certain unit types or are at costs that are far greater than the
EPA estimated at proposal, the EPA has changed the final rule to either
remove or adjust the applicability criteria for such units. For a
detailed discussion of the changes between the proposed FIP and this
final rule, in emissions unit types included and in emissions limits,
see section VI.C of this document. Tables I.B-2 through I.B-7 in
section I.B of this document identify the emissions units and
applicable emissions limitations, and Table II.A-1 in section II.A of
this document identifies the industries included in the final rule.
    For the final rule, to determine NOX emissions reduction
potential for the non-EGU industries and emissions unit types, with the
exception of Solid Waste Combustors and Incinerators, we used a 2019
inventory prepared from the emissions inventory system (EIS) to
estimate a list of emissions units captured by the applicability
criteria for the final rule. For Solid Waste Combustors and
Incinerators, the EPA estimated the list of covered units using the
2019 inventory, as well as the NEEDS-v6-summer-2021-reference-case
workbook.\221\ Based on the review of RACT, NSPS, NESHAP rules, as well
as SIPs, consent decrees, and permits, we also assumed certain control
technologies could meet the final emissions limits.\222\ We did not run
the Control Strategy Tool to estimate emissions reductions and costs
and instead programmed the assessment using R.\223\ Using the list of
emissions units estimated to be captured by the final rule
applicability criteria, the assumed control technologies that would
meet the emissions limits, and information on control efficiencies and
default cost/ton values from the control measures database (CMDB),\224\
the EPA estimated NOX emissions reductions and costs for the
year 2026. We estimated emissions reductions using the actual emissions
from the 2019 emissions inventory. In the assessment, we matched
emissions units by Source Classification Code (SCC) from the inventory
to the applicable control technologies in the CMDB. We modified SCC
codes as necessary to match control technologies to inventory records.
---------------------------------------------------------------------------

    \221\ The workbook is available here: https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.
    \222\ The Final Non-EGU Sectors TSD is available in the docket.
    \223\ R is a free software environment for statistical computing
and graphics. Additional information is available here: https://www.r-project.org/.
    \224\ More information about the Control Strategy Tool (CoST)
and the control measures database (CMDB) can be found at the
following link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
---------------------------------------------------------------------------

    The EPA recognized both at proposal and in the final rule that the
cost per ton of emissions controls could vary by industry and by
facility. The $7,500 marginal cost/ton threshold reflected in the Non-
EGU Screening Assessment functioned as a relative, representative cost/
ton level. Similar to the role of cost-effectiveness thresholds the EPA
uses at Step 3 to evaluate EGU emissions control opportunities, this
threshold is not intended to represent the maximum cost any facility
may need to expend but is rather intended to be a representative figure
for evaluating technologies to allow for a relative comparison between
different levels of control stringency. The value was used to identify
potentially cost-effective controls for further evaluation.
    In the final rule, partly in recognition of the many comments
indicating widely varying cost-per-ton values across industries and
facilities, the EPA has updated its analysis of costs for the covered
non-EGU industries. This data is summarized in the Technical Memorandum
``Summary of Final Rule Applicability Criteria and Emissions Limits for
Non-EGU Emissions Units, Assumed Control Technologies for Meeting the
Final Emissions Limits, and Estimated Emissions Units, Emissions
Reductions, and Costs,'' available in the docket. We further respond to
comments on the screening assessment in section 2.2 of the response to
comments document.
3. Other Stationary Sources NOX Mitigation Strategies
    As part of its analysis for this final rule, the EPA also reviewed
whether NOX mitigation strategies for any other stationary
sources may be appropriate. In this section, the EPA discusses three
classes of units that have historically been excluded from our
interstate air transport programs: (1) solid waste incineration units,
(2) electric generating units less than or equal to 25 MW, and (3)
cogeneration units. EPA's initial assessment did not lead it to propose
inclusion of the units in these categories. However, EPA requested
comment on whether any particular units within this category may offer
cost-effective reduction potential.
    Based on our request for comment, comments received, and our
further evaluation, the EPA is including emissions limits and
associated control requirements for the ozone season for solid waste
incinerator units in this final rule, in line with the requirements we
laid out for comment at proposal. Our analysis in this final rule
confirms that these units have emissions reductions of a magnitude,
degree of beneficial impact, and cost-effectiveness that is on par with
the units in other industrial sectors included in this final rule.

    For electric generating units less than 25 MW and cogeneration
units previously exempted from EGU emissions budgets established
through ozone interstate transport rules, the EPA has determined that
these units should not be treated as EGUs in this final rule.
    The EPA provides a summary of these three segments, their emissions
control opportunities, and potential air quality benefits in the
following sections. Additional considerations are further discussed in
the EGU NOX Mitigation Strategies Final TSD and in the RTC
Document.
a. Municipal Solid Waste Units
    At proposal, the EPA solicited comments on whether NOX
emissions reductions should be sought from municipal waste combustors
(MWCs) to address interstate ozone transport, specifically on potential
emissions limits, control technologies, and control costs. The EPA
requested comment on emissions limits of 105 ppmvd on a 30-day rolling
average and a 110 ppmvd on a 24-hour block average based on
determinations made in the June 2021 Ozone Transport Commission (OTC)
Municipal Waste Combustor Workgroup Report (OTC MWC Report). See 87 FR
20085-20086. The OTC MWC Report found that MWCs in the Ozone Transport
Region (OTR) are a significant source of NOX emissions and
that significant annual NOX reductions could be achieved
from MWCs in the OTR using several different technologies, or
combination of technologies at a reasonable cost. The OTC MWC report is
included in the docket for this action.
    Comment: The EPA received multiple comments supporting the
inclusion of emissions limits for MWCs in the final rule. Commenters
noted that MWCs are significant sources of NOX that
contribute to ozone problems in the states covered by the proposal.
Multiple commenters referenced the OTC MWC report to contend that
NOX emissions from MWCs could be significantly reduced at a
reasonable cost. Some commenters reasoned that sources closer to
downwind monitors, including MWCs, should be regulated as a more
targeted approach and a means to prevent overcontrol of upwind sources.
Commenters also noted that the OTC recently signed a memorandum of
understanding (MOU) requesting that OTC member states develop cost
effective solutions and select the strategy or combination of
strategies, as necessary and appropriate, that provides both the
maximum certainty and flexibility for that state and its MWCs.
Additionally, multiple commenters noted that MWCs are often located in
economically marginalized communities or communities of color. Lastly,
one commenter stated that MWCs were arbitrarily excluded from the non-
EGU screening assessment prepared for the proposal.
    Response: As described in section VI.B.2 of the notice of proposed
rulemaking, the EPA assessed emissions reduction potential from non-
EGUs by preparing a screening assessment to identify those industries
that could have the greatest air quality impact at downwind receptors.
While the EPA did not prepare an updated non-EGU screening assessment
in preparation for this final rule, the Agency did evaluate MWCs using
the criteria developed in the screening assessment for proposal and
determined that MWCs should be included in this rulemaking. A
discussion of this analysis for MWCs is available in the Municipal
Waste Combustor Supplement to February 28, 2022 Screening Assessment of
Potential Emissions Reductions, Air Quality Impacts, and Costs from
Non-EGU Emissions Units for 2026, which is available in the docket for
this rule.
    Considering EPA's conclusion that MWCs should be included in this
final rule if EPA applied the same criteria developed in the screening
assessment for proposal, the findings from the OTC MWC report and
recent MOU, the fact that many state RACT NOX rules apply to
MWCs, and information received during public comment, the EPA finds
that MWCs should be included in this final rule. Thus, the EPA is
finalizing NOX emissions limits and compliance assurance
requirements for large MWCs as defined in the regulatory text at Sec.
52.46 and as described in this section.
    Comment: Some commenters did not support the inclusion of emissions
limits for MWCs in the final rule. Some commenters suggested that the
inclusion of NOX limits in a FIP is not necessary to
continue to reduce NOX emissions from MWCs or to address
interstate transport problems. Some commenters noted that many of the
MWCs in the states covered by the proposal are already subject to RACT-
based NOX emissions limits that are below the current
Federal NSPS NOX emissions limits for MWCs under 40 CFR part
60, subparts Cb and Eb. One commenter noted that MWCs do not always
account for a large percentage of statewide NOX emissions.
Others suggested that voluntary industry actions are also driving
downward trends of NOX emissions for some MWCs. Some
commenters also asserted that regulation could interfere with state
waste reduction policies and associated environmental considerations.
    Response: Regarding the comments that some MWCs are already subject
to RACT NOX emissions limits, the EPA acknowledges that some
states included in this rulemaking have promulgated RACT NOX
emissions limits that apply to certain MWCs, including some that are
lower than current MWC NSPS NOX emissions limits. The EPA
does not consider a source to be exempt from this rulemaking just
because the source may be subject to other regulatory requirements. As
noted, the Agency did evaluate MWCs using the criteria developed in the
screening assessment for proposal and has concluded that MWCs should be
included in this rulemaking. In considering the emissions limits that
are being finalized in this rulemaking, the EPA reviewed existing state
RACT rules as described in section VI.C.6 of this document and the
``Technical Support Document (TSD) for the Final Rule, Docket ID No.
EPA-HQ-OAR-2021-0668, Non-EGU Sectors TSD'' (Mar. 2023), hereinafter
referred to as Final Non-EGU Sectors TSD. We note that sources already
subject to RACT NOX emissions limits that are equal to or
more stringent than the limits finalized in this rulemaking will have
the option to streamline regulatory requirements through the Title V
permitting process.
    Regarding the statement that regulation could interfere with state
waste reduction policies and associated environmental considerations,
the EPA acknowledges that MWCs serve an important role in municipal
solid waste management programs, and that many function as cogeneration
facilities that produce electrical power for the power grid. The EPA
also analyzed control costs and determined that the required
NOX emissions limits for MWCs can be achieved at a
reasonable cost, as described in section VI.C.6 of this document, the
Final Non-EGU Sectors TSD, and the OTC MWC Report. Although the EPA
does not expect these regulations to disrupt the ability of the
industry to provide municipal solid waste and electric services, to the
extent a facility is unable to comply with the standards due to
technical impossibility or extreme economic hardship, the final rule
includes provisions for facility operators to apply for a case-by-case
alternative emissions limit. See section VI.C of this document and 40
CFR 52.40(d). In addition, for MWC facilities that are unable to comply
with the standard by the 2026 ozone season, the final rule includes
provisions for requesting limited extensions of time to

comply. See section VI.C and 40 CFR 52.40(c).
b. Electric Generating Units Less Than or Equal to 25 MW
    The EPA has historically not included control requirements for
emissions for electric generating units less than or equal to 25 MW of
generation for three primary reasons: low potential reductions,
relatively high cost per ton of reduction, and high monitoring and
other compliance burdens. In the January 11, 1993, Acid Rain permitting
rule, the EPA provided for a conditional exemption from the emissions
reduction, emitting, and emissions monitoring requirements of the Acid
Rain Program for new units having a nameplate capacity of 25 MWe or
less that burn fuels with a sulfur content no greater than 0.05 percent
by weight, because of the de minimis nature of their potential
SO2, CO2 and NOX emissions. See 63 FR
57484. The NOX SIP Call identified these as Small Point
Sources. For the purposes of that rulemaking, the EPA considered
electricity generating boilers and turbines serving a generator 25 MWe
or less, to be small point sources. The EPA noted that the collective
emissions from small sources were relatively small and the
administrative burden to the states and regulated entities of
controlling such sources was likely to be considerable. As a result,
the rule did not assume reductions from those sources in state
emissions budgets requirements (63 FR 57402). Similar size thresholds
have been incorporated in subsequent transport programs such as CAIR
and CSAPR. As these sources were not identified as having cost-
effective reductions and so were not included in those programs, they
were also exempted from certain reporting requirements and the data for
these sources is, therefore, not of the same caliber as that of covered
larger sources.
    EPA's preliminary survey of current data, compared to this initial
justification, does not appear to offer a compelling reason to depart
from this past practice by requiring emissions reductions from these
small EGU sources as part of this rule. For instance, as explained in
the EGU NOX Mitigation Strategies Final Rule TSD, EPA has
evaluated the costs of SCR retrofits at small EGUs using its Retrofit
Cost Analyzer and found that such controls become markedly less cost-
effective at lower levels of generating capacity. This analysis
concluded that, after controlling for all other unit characteristics,
the dollar per ton cost for a SCR retrofit increases by about a factor
of 2.5 when moving from a 500 MW to a 10 MW unit, and a factor of 8
when moving to a 1 MW unit.\225\ Moreover, the EPA estimates that under
6 percent of nationwide EGU emissions come from units that are less
than 25 MW and not covered by current applicability criteria due to
this size exemption threshold. Therefore, the EPA is not finalizing any
emissions reductions for these units.
---------------------------------------------------------------------------

    \225\ Preliminary estimate based on representative coal units
with starting NOX rate of 0.2 lb/mmBtu, 10,000 BTU/kwh,
and assuming 80 percent reduction.
---------------------------------------------------------------------------

    Comment: EPA received comment supporting the continued application
of the 25 MW threshold.
    Response: Consistent with prior rules, the proposal, and
stakeholder comment, EPA is continuing to apply its 25 MW applicability
threshold for EGUs in this rulemaking. EPA did not find compelling
comment to reverse its determination that (1) these sources offer low
potential reductions, (2) have relatively high cost per ton, and (3)
have high monitoring and other compliance burdens.
c. Cogeneration Units
    Consistent with prior transport rules, fossil fuel-fired boilers
and combustion turbines that produce both electricity and useful
thermal energy (generally referred to as ``cogeneration units'') and
that meet the applicability criteria to be included in the CSAPR
NOX Ozone Season Group 3 Trading Program would be subject to
the emissions reduction requirements established in this rulemaking for
EGUs. However, those applicability criteria--which the EPA is not
altering in this rulemaking (see section VI.B.3 of this document)--
exempt some cogeneration units from coverage as EGUs under the trading
program. The EPA is finalizing that fossil fuel-fired boilers and