sources may decline beyond what we currently project in this rule. For
example, the IRA may result in reductions in fossil-fuel fired
generation, which should in turn result in lower NOX
emissions during the ozone season.\255\ We have

assessed this scenario to ensure our overcontrol conclusions are robust
even if the IRA has those effects. As discussed in the Regulatory
Impact Analysis, the EPA conducted additional modeling of the final
policy scenario (inclusive of economically efficient methods of
compliance available within the Step 4 implementation programs) using
its IPM tool. The EPA observes that the differences in estimated costs
and emissions reductions in the IRA sensitivity (presented in Appendix
4A of the RIA) suggests that there would also be differences in
estimated health and climate benefits under that scenario, although the
Agency did not have time under this rulemaking schedule to quantify
those differences. The EPA also used AQAT to conduct an additional EGU
modeling sensitivity reflecting the IRA. Both the IPM sensitivity and
the corresponding AQAT assessment of the IRA scenarios demonstrated no
overcontrol as every state linkage to a downwind problematic receptor
persisted in the penultimate level of stringency when EPA performed its
Step 3 evaluation--even when the impacts of the IRA are incorporated.
This further affirmed EPA's conclusion of no overcontrol concerns at
the stringency level of the final rule. This overcontrol sensitivity is
further discussed in the Ozone Transport Policy Analysis Final Rule
TSD, Appendix K.
---------------------------------------------------------------------------

    \255\ As discussed in section IV.C.2.b, there are also potential
ways in which the IRA may not necessarily result in reductions in
NOX emissions from EGUs.
---------------------------------------------------------------------------

    In light of the mandate of the CAA to protect the public health and
environment through the elimination of significant contribution under
the Good Neighbor Provision for the 2015 ozone NAAQS, nothing in the
present record establishes on an as-applied, particularized basis that
this rule will result in an unnecessary degree of control of upwind-
state emissions.
    Comment: Many commenters alleged that the rule overcontrols
emissions by more than necessary to eliminate significant contribution
for the 2015 ozone NAAQS, on the basis that the emissions reductions
are unnecessary or are unnecessarily stringent.
    Response: As discussed earlier in this section, EPA has analyzed
whether this rule ``overcontrols'' emissions and has found based on a
robust, multi-faceted analysis, that it does not. In particular, EPA
has not identified a lesser-stringency emissions control strategy for
any state that would either fully resolve the air quality problems at a
downwind receptor location or resolve that upwind state's linkage to a
level below the 1 percent of NAAQS contribution threshold. No commenter
has provided a particularized, as-applied analysis demonstrating that
EPA's emissions control strategy will actually result in any
overcontrol of emissions in the manner the EPA or courts have
understood that term, and overcontrol allegations must be proven
through particularized, as-applied challenges. See EME Homer City, 795
F.3d at 127; see also Wisconsin, 938 F.3d at 325 (``[T]he way to
contest instances of over-control is not through generalized claims
that EPA's methodology would lead to over-control, but rather through a
`particularized, as-applied challenge.' '' Accordingly, as we did when
presented with similar arguments in EME Homer III, we reject Industry
Petitioners' arguments because they do no more than speculate that
aspects of `EPA's methodology could lead to over-control of upwind
States.' '') (cleaned up) (citing EME Homer City, 795 F.3d at 136-137).
    Comment: For 2 of the 20 states linked in 2026, Arkansas and
Mississippi, the last downwind receptor to which these two states are
linked (i.e., Brazoria County, Texas) was estimated to achieve
attainment and maintenance after full application of EGU reductions and
Tier 1 non-EGU reductions at proposal. Commenters noted that this
suggested application of the estimated non-EGU, and/or some EGU,
emissions reductions constituted over-control for these states.
    Response: EPA notes that at proposal, this downwind receptor only
resolved by a small margin after the application of all EGU and Tier 1
non-EGU emissions reductions. As explained earlier in this section, the
final rule air quality modeling shows that the receptors to which these
states are linked do not resolve upon full implementation of the
identified EGU reductions by themselves, and only reach attainment by a
small degree following the additional reductions from the non-EGU
control strategy.\256\ If the EPA were to select the control stringency
of this penultimate step, both upwind-state contribution and downwind-
state air quality receptors would persist while the cost-effective
emissions reductions that were identified to eliminate significant
contribution remain available but un-implemented. This would constitute
under-control. Consequently, as described, the EPA views the control
stringency required of these states in this final rule as not
constituting over-control and appropriate to eliminate significant
contribution to nonattainment and interference with maintenance of this
NAAQS in line with our Step 3 determinations for all other states. See
the Ozone Transport Policy Analysis Final Rule TSD section C.3 for
discussion and analysis regarding overcontrol for states solely linked
to one or both of these receptors.
---------------------------------------------------------------------------

    \256\ Because in the final record we do not identify cost, air
quality, and emission reduction factors that sufficiently
differentiate either source-type or emissions control strategy among
the Tier 1 and Tier 2 industries identified at proposal, we combined
the non-EGU industries and emissions reductions into one group, and
we are finalizing requirements for all non-EGU industries and most
emissions unit types identified at proposal. In light of the small
degree to which the relevant receptors reach attainment and the
multi-faceted assessment of overcontrol we have undertaken, the
overcontrol assessment with respect to non-EGUs in the final rule is
sufficient to establish that there is no overcontrol.
---------------------------------------------------------------------------

    Comment: Commenters raised a variety of arguments that the
enhancements to the EGU trading program in this action will result in
overcontrol of power plant emissions. They alleged that dynamic
budgeting would cause the budget to continually decrease even after
significant contribution is eliminated. They similarly argue that
annual emissions bank recalibration and the emissions backstop
emissions rate have not been shown to be justified to eliminate
significant contribution.
    Response: This final rule's determination regarding the appropriate
level of control stringency for EGUs finds that the amounts of
NOX emissions reduction achieved through these strategies at
EGUs are appropriate and cost-justified under the Step 3 multifactor
analysis. These determinations are associated with particular emissions
control technologies and strategies as detailed in sections V.B.1 and
V.C.1 above. It is the implementation of those strategies at the
covered EGU sources and the air quality effects of those strategies
(coupled with non-EGUs) in the relevant analytic year of 2026 on which
we base our determination of significant contribution at Step 3. This
includes the evaluation of whether there is overcontrol, which is also
conducted for the 2026 analytic year as explained above. As explained
below, we disagree that the enhancements to the trading program at Step
4 implicate the need for further overcontrol analysis. These
enhancements operate together to ensure the trading program continues
to maintain the Step 3 emissions control stringency over time. These
enhancements reflect lessons learned through EPA's experience with
prior trading programs implemented under the good neighbor provision.
None of commenters' arguments that these enhancements result in
overcontrol are persuasive.
    Commenters contend that these enhancements to the trading program
go

beyond a mass-based budget approach as applied in CSAPR. Because these
improvements in the program result in a continuing incentive for each
covered EGU source to maintain the pollution control performance the
EPA found appropriate to eliminate significant contribution at Step 3,
commenters believe these enhancements must necessarily result in
prohibited overcontrol. These arguments appear to be premised on the
assumption that overall emissions may later decline to such a point
that there is no longer a linkage between a particular state and any
downwind receptors for reasons other than the requirements of this
rule.
    As an initial matter, no commenter has provided an empirical
analysis demonstrating that the control stringency identified at Step 3
to eliminate significant contribution would actually result in any
overcontrol. The case law is clear that over-control allegations must
be proven through particularized, as-applied challenges. See prior
response to comments. More importantly here, the Group 3 trading
program enhancements do not impose increased stringency in years after
2030 and do not force emissions to continually be reduced to ever lower
levels. They are only designed to incentivize the implementation of the
Step 3 emissions control stringency that eliminates significant
contribution. The circumstances that could potentially cause a receptor
or linkage to resolve at some point in the future after 2026 are not
circumstances that are within the power of this rule to control. Nor
would those circumstances present a justification as to why upwind
sources should no longer be obligated to eliminate their own
significant contribution. Wisconsin, 938 F.3d at 324-25 (rejecting
overcontrol arguments premised on attributing air quality problems to
other emissions).
    Further, the EPA is not constrained by the statute to only
implement good neighbor obligations through fixed, unchanging, mass-
based emissions budgets. See section III.B.1 of this document. The EPA
has defined the ``amount'' of emissions that must be prohibited to
eliminate significant contribution in this action based on a series of
determinations of which emissions control strategies, for certain
identified EGU and non-EGU sources, are appropriate applying the Step 3
multifactor analysis. Notably, the non-EGU industrial source emissions
reductions in this action are not being achieved at Step 4 through
mass-based emissions trading, nor are they required to be by any
provision of the CAA. See section III.B.1.
    As explained in sections III.B.1.d and VI.B.1 of this document, the
EPA finds good reason based on its experience with trading programs
that using fixed, mass-based, ozone-season wide budgets does not
necessarily ensure the elimination of significant contribution over the
entire region of linked states or throughout each ozone season. Even in
the original CSAPR rulemaking, which promulgated only fixed, mass-based
budgets, such outcomes were never the EPA's intention to allow. See,
e.g., 76 FR 48256-57 (``[I]t would be inappropriate for a state linked
to downwind nonattainment or maintenance areas to stop operating
existing pollution control equipment (which would increase their
emissions and contribution).''). Despite the EPA's expectations in
CSAPR, the experience of the Agency since that time establishes a real
risk of ``under-control'' if the existing trading framework is not
enhanced. See EME Homer City, 572 U.S. at 523 (``[T]he Agency also has
a statutory obligation to avoid `under-control,' i.e., to maximize
achievement of attainment downwind.'').
    Further, the EPA has already once adjusted its historical approach
to better account for known, upcoming changes in the EGU fleet to
ensure mass-based emissions budgets adequately incentivize the control
strategy determined at Step 3. This adjustment was introduced in the
Revised CSAPR Update. See 82 FR 23121-22. The EPA now believes it is
appropriate to ensure in a more comprehensive manner, and in
perpetuity, that a mass-based emissions-trading framework incentivizes
continuing implementation of the Step 3 control strategies to ensure
significant contribution is eliminated in all upwind states and remains
so. This is fully analogous in material respect to an approach to
implementation at Step 4 that relies on application of unit-specific
emissions limitations, which under the Act would typically apply in
perpetuity and may only be modified through a future SIP- or FIP-
revision rulemaking process. See CAA section 110(i) prohibiting
modifications to implementation plan requirements except by enumerated
processes. The availability of unit-specific emissions rates as a means
to eliminate significant contribution is discussed in further detail in
section III.B.1 of this document. The EPA also explained this in the
proposal. See 87 FR 20095-96.
    Further, these enhancements are directly related to assisting
downwind areas specifically with the goal of attaining and maintaining
the 2015 8-hour ozone NAAQS. In this respect, they are not
``unnecessary'' or ``unrelated'' to carrying out the mandates of CAA
section 110(a)(2)(D)(i)(I). Taking measures to ensure that each upwind
source covered by an emissions trading program is adequately
incentivized to eliminate excessive emissions (as found at Step 3)
throughout the entirety of each ozone season is entirely appropriate in
light of the nature of the ozone problem. Ozone exceedances recur on
varying days throughout the summertime ozone season, and it is not
possible to predict in advance which specific days will have high
ozone. Further, impacts to public health and the environment from ozone
can occur through short-term exposure (e.g., over a course of hours,
i.e., on a daily basis). The 2015 ozone NAAQS is expressed as an 8-hour
average, and only a small number of days in excess of the ozone NAAQS
can cause a downwind area to be in nonattainment. Thus, even a small
number of exceedances can result in continuing and/or increased
regulatory burdens on the downwind jurisdiction. Taking these
considerations into account, it is evident that a fixed, mass-based
emissions program that does not adequately incentivize emissions
reductions commensurate with our Step 3 determinations on each day of
every ozone season going forward does not provide a sufficient
guarantee that the emissions that significantly contribute on those
particular days and at particular receptor locations when ozone levels
are at risk of exceeding the NAAQS have been eliminated. See section
V.B.1.a and VI.B of this document for more discussion of data
observations regarding SCR optimization.
    These enhancements are also consistent with the general policies
and principles EPA has long applied in implementing the NAAQS through
the SIP/FIP framework of section 110. Emissions control measures relied
on to meet CAA requirements must be permanent and enforceable and
included in the implementation plan itself. See, e.g., Montana Sulfur &
Chem. Co. v. EPA, 666 F.3d 1174, 1196 (9th Cir. 2012); 40 CFR
51.112(a). In the General Preamble laying out EPA's plans for
implementing the 1990 CAA Amendments, the EPA identified a core
``principle'' that control strategies should be ``accountable.'' ``This
means, for example, that source-specific limits should be permanent and
must reflect the assumptions used in the SIP demonstrations.'' 57 FR
13498, 13568 (April 16, 1992). EPA went on, ``The principles of
quantification, enforceability, replicability, and

accountability apply to all SIPs and control strategies, including
those involving emissions trading, marketable permits and allowances.''
Id. EPA also explained that its ``emissions trading policy provides
that only trades producing reductions that are surplus, enforceable,
permanent, and quantifiable can get credit and be banked or used in an
emissions trade.'' Id. These principles follow from the language of the
Act, including CAA section 110(a)(2), 107(d)(3)(E)(iii), 110(i), and
110(l). These provisions and principles further underscore the
importance of ensuring that the emissions reductions the EPA has found
necessary to eliminate significant contribution are in fact implemented
on a consistent and permanent basis even within the context of an
emissions trading program.
    The EPA disagrees that the budget adjustments that would occur over
time under this final rule (for example, the annual dynamic-budget
adjustment) must be reassessed each time they occur through notice and
comment rulemaking under CAA section 307(d). This would serve no
purpose. The formulas that the EPA will apply to adjust the budgets and
allowance bank are set in this final rule and are intended to maintain,
not increase (or decrease), program stringency. While the EPA intends
to provide an opportunity for stakeholders to review and propose
corrections to its data as it implements the established budget
formulas, no larger reassessment of the emissions control program is
needed on an ongoing basis, because, again, that program is simply
calibrated to ensure that emissions reductions commensurate with the
determination of ``significance'' in Step 3 continue to be obtained
over the long term. As described earlier, these trading program
provisions are analogous to, or mimic, the effect of unit-specific
emissions limitations that apply in perpetuity.\257\
---------------------------------------------------------------------------

    \257\ We note further that because all of the trading program
provisions, including the dynamic budget-setting provisions and
process, are established by this final FIP rulemaking, the
ministerial future-year budget adjustment process complies with the
CAA section 110(i) prohibition on modification of implementation
plan requirements except by enumerated process.
---------------------------------------------------------------------------

    Commenters also confuse the ``amount'' of emissions that must be
eliminated under CAA section 110(a)(2)(D)(i)(I) as being synonymous
with a fixed, mass-based budget that reflects the residual emissions
allowed following the elimination of significant contribution. However,
EPA views the ``amount'' to be eliminated as those emissions that are
in excess of the cost-effective emissions control strategies identified
in Step 3. This is further explained in section III.B.1 of this
document.
    Thus, this rule is in compliance with the overcontrol principles
that the D.C. Circuit applied on remand in EME Homer City to find
certain instances of overcontrol in CSAPR's emissions control
strategies. The D.C. Circuit found that EPA had imposed more stringent
emissions-control strategies for certain states than were necessary to
resolve all of those states' linkages. 795 F.3d at 128-30.
Specifically, for sulfur dioxide, the court found certain receptors
would reach attainment if all linked upwind states had implemented
``cost controls'' at $100/ton or $400/ton, rather than EPA's selected
stringency level of $500/ton. Similarly, for ozone season
NOX, the court found that receptors were projected to attain
the NAAQS at stringencies below $500/ton. The court's focus was on the
stringency of the emissions control obligations as determined through
the application of cost thresholds at Step 3 of the analysis. The court
did not hold that EPA may only use fixed, mass-based budgets to
implement those reductions. The court did not hold that EPA must permit
individual polluting sources to be allowed to increase their emissions
at some point in the future. The court did not hold that EPA's good
neighbor FIPs must, effectively, contain termination clauses, such that
they cease to ensure the implementation of the control stringency
determined as necessary at Step 3, the moment a downwind receptor
reaches attainment. Indeed, such a rule would contravene the statute's
clear, forward-looking directive that EPA must also eliminate upwind
emissions that interfere with maintenance of the NAAQS; see North
Carolina, 531 F.3d at 908-911; Wisconsin, 938 F.3d at 325-26.
    The EME Homer City court on remand in fact rejected various
arguments that other aspects of EPA's emissions control strategy in
CSAPR resulted in overcontrol, holding that EPA had properly given
effect to the interfere with maintenance prong, and noting that
petitioners failed to make out proven, as-applied demonstrations of
overcontrol:

    At bottom, each of those claims is an argument that EPA's
methodology could lead to over-control of upwind States that are
found to interfere with maintenance at a downwind location. That
could prove to be correct in certain locations. But the Supreme
Court made clear in EME Homer that the way to contest instances of
over-control is not through generalized claims that EPA's
methodology would lead to over-control, but rather through a
``particularized, as-applied challenge.'' EME Homer, 134 S. Ct. at
1609, slip op. at 31. And petitioners do not point to any actual
such instances of over-control at downwind locations.

795 F.3d at 137. The court went on to observe, ``EPA may only limit
emissions `by just enough to permit an already-attaining State to
maintain satisfactory air quality.' If States have been forced to
reduce emissions beyond that point, affected parties will have
meritorious as-applied challenges.'' Id. (quoting 572 U.S. at 521-22).
But this too was not a holding that EPA may not ensure effective and
permanent implementation of an emissions control stringency that EPA
has found warranted under CAA section 110(a)(2)(D)(i)(I). Such an
approach is available through the more conventional CAA practice of
setting unit-specific emissions limitations that would apply on a
permanent and enforceable basis. See CAA sections 110(a)(2) and 302(y)
(providing for SIPs and FIPs to include ``enforceable emissions
limitations'' in addition to economic incentive measures like trading
programs).\258\ This is in fact how EPA intends to ensure significant
contribution is eliminated from non-EGU industrial sources for which a
mass-based trading regime is, at least at the present time, unworkable
(see section VI.C of this document). And EPA has provided for the
elimination of significant contribution through source-specific
emissions limitations in prior transport actions as well, so this
position is not novel. See section III.B of this document.
---------------------------------------------------------------------------

    \258\ ``Emissions limitation'' is in turn defined at CAA section
302(k) as a ``requirement . . . which limits the quantity, rate, or
concentration of emissions of air pollutants on a continuous basis.
. . .''
---------------------------------------------------------------------------

    Nonetheless, EPA recognizes that under the Act, both FIPs and SIPs
may be revised, and states may replace FIPs with SIPs if EPA approves
them. Any such revision must be evaluated to ensure no applicable CAA
requirements are interfered with. See, e.g., Indiana v. EPA, 796 F.3d
803 (7th Cir. 2015). For example, states may be able to demonstrate in
the future that through some other permanent and enforceable methods of
emissions reduction that they have adopted into their SIP, they will be
able to achieve a similar emissions control stringency with different
emissions reduction requirements imposed on different sources as
compared to the FIPs finalized in this action. See section VI.D of this
document.
    Therefore, commenters' contentions that EPA's trading program
enhancements result in prohibited

overcontrol are not proven through as-applied, particularized
challenges, and they are premised on an incorrect understanding of the
CAA and the relevant case law. The Agency rejects the contention that
it must somehow provide in the present FIP action for a relaxation in
the stringency of the Step 4 implementation program and thus allow for
the recurrence of pollution that we have found here, in this action,
significantly contributes to downwind ozone nonattainment and
maintenance problems.

VI. Implementation of Emissions Reductions

A. NOX Reduction Implementation Schedule

    This action will ensure that emissions reductions necessary to
eliminate significant contribution will be achieved ``as expeditiously
as practicable'' and no later than the downwind attainment dates except
where compliance by those dates is not possible. See CAA section
181(a); Wisconsin, 938 F.3d at 318-20. The timing of this action will
provide for all possible emissions reductions to go into effect
beginning in the 2023 ozone season for the covered states, which is
aligned with the next upcoming attainment date of August 3, 2024, for
areas classified as Moderate nonattainment under the 2015 ozone
standard. Additional emissions reductions that the EPA finds not
possible to implement by that attainment date will take effect as
expeditiously as practicable. Emissions reductions commensurate with
SCR mitigation measures for EGUs will start in 2026 and be fully
implemented by 2027. Emissions reductions through the mitigation
measures for industrial sources will generally go into effect in 2026;
however, as explained in section VI.C of this document, we have
provided for case-by-case extensions of up to one year based on a
demonstration of necessity (with the potential for up to an additional
two years based on a further demonstration). The full suite of
emissions reductions is generally anticipated to take effect by the
2027 ozone season, which is aligned with the August 3, 2027, attainment
date for areas classified as Serious nonattainment under the 2015 ozone
NAAQS. This rule constitutes a full remedy for interstate transport for
the 2015 ozone NAAQS for the states covered; the EPA does not
anticipate further rulemaking to address good neighbor obligations
under this NAAQS will be required for these states with the
finalization of this rule.
    EPA's determinations regarding the timing of this rule are informed
by and in compliance with several recent court decisions. The D.C.
Circuit has reiterated several times that, under the terms of the Good
Neighbor Provision, upwind states must eliminate their significant
contributions to downwind areas ``consistent with the provisions of
[title I of the Act],'' including those provisions setting attainment
deadlines for downwind areas.\259\ In North Carolina, the D.C. Circuit
found the 2015 compliance deadline that the EPA had established in CAIR
unlawful in light of the downwind nonattainment areas' 2010 deadline
for attaining the 1997 NAAQS for ozone and PM2.5.\260\
Similarly, in Wisconsin, the Court found the CSAPR Update unlawful to
the extent it allowed upwind states to continue their significant
contributions to downwind air quality problems beyond the downwind
states' statutory deadlines for attaining the 2008 ozone NAAQS.\261\ In
Maryland, the Court found the EPA's selection of a 2023 analysis year
in evaluating state petitions submitted under CAA section 126 unlawful
in light of the downwind Marginal nonattainment areas' 2021 deadline
for attaining the 2015 ozone NAAQS.\262\ The Court noted in Wisconsin
that the statutory command--that compliance with the Good Neighbor
Provision must be achieved in a manner ``consistent with'' title I of
the CAA--may be read to allow for some deviation from the mandate to
eliminate prohibited transport by downwind attainment deadlines,
``under particular circumstances and upon a sufficient showing of
necessity,'' but concluded that ``[a]ny such deviation would need to be
rooted in Title I's framework'' and would need to ``provide a
sufficient level of protection to downwind States.'' \263\
---------------------------------------------------------------------------

    \259\ North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008),
Wisconsin v. EPA, 938 F.3d 303 (D.C. Cir. 2019), and Maryland v.
EPA, 958 F.3d 1185 (D.C. Cir. 2020).
    \260\ North Carolina, 531 F.3d at 911-913.
    \261\ Wisconsin, 938 F. 3d at 303, 3018-20.
    \262\ Maryland, 958 F.3d at 1203-1204. Similarly, in New York v.
EPA, 964 F.3d 1214 (D.C. Cir. 2020), the Court found the EPA's
selection of a 2023 analysis year in evaluating New York's section
126 petition unlawful in light of the New York Metropolitan Area's
2021 Serious area deadline for attaining the 2008 ozone NAAQS. 964
F.3d at 1226 (citing Wisconsin and Maryland).
    \263\ Wisconsin, 938 F. 3d at 320 (citing CAA section 181(a)
(allowing one-year extension of attainment deadlines in particular
circumstances) and North Carolina, 531 F.3d at 912).
---------------------------------------------------------------------------

1. 2023-2025: EGU NOX Reductions Beginning in 2023
    The near-term EGU control stringencies and corresponding reductions
in this rulemaking cover the 2023, 2024, and 2025 ozone seasons. This
is the period in which some reductions will be available, but the
portion of full remedy reductions related to post combustion control
installation identified in sections V.B through V.D of this document
are not yet available. The EGU NOX mitigation strategies
available during these initial 3 years are the optimization of existing
post-combustion controls (SCRs and SNCRs) and combustion control
upgrades. As described in sections V.B through V.D of this document and
in accompanying TSDs, these mitigation measures can be implemented in
under two months in the case of existing control optimization and in 6
months in the case of combustion control upgrades. These timing
assumptions account for planning, procurement, and any physical or
structural modification necessary. The EPA provides significant
historical data, including the implementation of the most recent
Revised CSAPR Update, as well as engineering studies and input factor
analysis documenting the feasibility of these timing assumptions.
However, these timing assumptions are representative of fleet averages,
and the EPA has noted that some units will likely overperform their
installation timing assumptions, while others may have unit
configuration or operational considerations that result in their
underperforming these timing assumptions. As in prior interstate
transport rules, the EPA is implementing these EGU reductions through a
trading program approach. The trading program's option to buy
additional allowances provides flexibility in the program for outlier
sources that may need more time than what is representative of the
fleet average to implement these mitigation strategies while providing
an economic incentive to outperform rate and timing assumptions for
those sources that can do so. In effect, this trading program
implementation operationalizes the mitigation measures as state-wide
assumptions for the EGU fleet rather than unit-specific assumptions.
    However, starting in 2024, as described in section VI.B.7 of this
document, unit-specific backstop daily emissions rates are applied to
coal units with existing SCR at a level consistent with operating that
control. The EPA believes that implementing these emissions reductions
through state emissions budgets starting in 2023 while imposing the
unit-specific backstop emissions rates in 2024 achieves the necessary
environmental

performance as soon as possible while accommodating any heterogeneity
in unit-level implementation schedules regarding daily operation of
optimized SCRs.
    Additionally, as in prior rules, the EPA assumes combustion control
upgrade implementation may take up to 6 months. In the Revised CSAPR
Update, covering 12 of the 22 states for which emissions reduction
requirements for EGUs are established under this action, the EPA
finalized the rule in March of 2021 and thus did not require these
combustion control-based emissions reductions in ozone-season state
emissions budgets until 2022 (year two of that program).\264\ The EPA
is applying the same timing assumption regarding combustion control
upgrades for this rulemaking. Given the same relationship here between
the date of final action and the year one ozone season, the EPA is not
assuming the implementation of any additional combustion control
upgrades in state emissions budgets until year two (i.e., the 2024
ozone season). Any identified combustion control upgrade emissions
reductions are reflected beginning in the 2024 ozone-season budgets for
all covered states. For the 12 states covered under the Revised CSAPR
Update, any identified emissions reduction potential from combustion
control upgrade is included and reflected in those state budgets
beginning in 2024--which means EGUs in those states have even more time
than the 14 months between finalization of this rule and the 2024 ozone
season if they started any planning or installation earlier in response
to the Revised CSAPR Update.
---------------------------------------------------------------------------

    \264\ 86 FR 23093.
---------------------------------------------------------------------------

2. 2026 and Later Years: EGU and Stationary Industrial Source
NOX Reductions Beginning in 2026
    The EPA finds that it is not possible to implement all necessary
emissions controls across all of the affected EGU and non-EGU sources
by the August 3, 2024, Moderate area attainment date. In accordance
with the good neighbor provision and the downwind attainment schedule
under CAA section 181 for the 2015 ozone NAAQS, the EPA is aligning its
analysis and implementation of the emissions reductions addressing
significant contribution from EGU and non-EGU sources that require
relatively longer lead time at a sectoral scale with the 2026 ozone
season. The 2026 ozone season is the last full ozone season that
precedes the August 3, 2027, Serious area attainment date for the 2015
ozone NAAQS.\265\ The EPA proposed to require compliance with all of
the remaining EGU and non-EGU control requirements beginning in the
2026 ozone season. The EPA continues to find 2026 to be the relevant
analytic year for purposes of its Step 3 analysis, including its
analysis of overcontrol, as discussed in section V.D.4 of this
document. However, many commenters argued that full implementation of
the EGU and industrial source control strategies is not feasible for
every source by the 2026 ozone season. The EPA addresses these
technical comments specifically in sections V.B and VI.C of this
document. The EPA also commissioned a study to develop a better
understanding of the time needed for installation of emissions controls
for the industrial sector units covered in this rule, which is included
in the docket and discussed in section VI.A.2.b of this document. While
the EPA does not agree with all of the commenters' assertions regarding
the time they claim is needed for control installation, in other
respects the concerns raised were sufficient to justify some
adjustments to the compliance schedule for the final rule. We have
provided for the emissions reductions commensurate with assumed EGU
post-combustion emissions control retrofits to be phased in over the
2026 and 2027 ozone season emissions budgets, and we have provided a
process in the final regulations for individual non-EGU industrial
sources to seek limited compliance extensions extending no later than
2029 based on a case-by-case demonstration of necessity. This
compliance schedule delivers substantial emissions reductions in the
2026 and 2027 ozone seasons and before the 2027 Serious area attainment
date, and it only allows compliance extensions beyond that attainment
date based on a rigorous, source-specific demonstration of need for the
additional time.\266\
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    \265\ For each nonattainment area classified under CAA section
181(a) for the 2015 ozone NAAQS, the attainment date is ``as
expeditiously as practicable'' but not later than the date provided
in table 1 to 40 CFR 51.1303(a). Thus, for areas initially
designated nonattainment effective August 3, 2018 (83 FR 25776), the
latest permissible attainment dates are: August 3, 2021 (for
Marginal areas), August 3, 2024 (for Moderate areas), August 3, 2027
(for Serious areas), and August 3, 2033 (for Severe areas).
    \266\ While we generally use the term ``necessity'' to describe
the showing that non-EGU facilities must meet in seeking compliance
extensions, the elements for this showing are designed to allow the
EPA to make a judgment that comports with the standard of
``impossibility'' established in case law such as Wisconsin. In
other words, the ``necessity'' for additional time is effectively a
showing by the source that it would be ``impossible'' for it to meet
the compliance deadline.
---------------------------------------------------------------------------

    The timing of this final rule provides three to four years for EGU
and non-EGU sources to install whatever controls they deem suitable to
comply with required emissions reductions by the start of the 2026 and
2027 ozone seasons. In addition, the publication of the proposal
provided roughly an additional year of notice to these source owners
and operators that they should begin engineering and financial planning
(steps that can be taken prior to any capital investment) to be
prepared to meet this implementation timetable.
    The EPA views this timeframe for retrofitting post-combustion
NOX emissions controls and other non-EGU controls to be
reasonable and achievable. A 3-year period for installation of control
technologies is consistent with the statutory timeframe for
implementation of the controls required to address interstate pollution
under section 110(a)(2)(D) and 126 of the Act, the statutory timeframes
for implementation of RACT in ozone nonattainment areas classified as
Moderate or above, and other statutory provisions that establish
control requirements for existing stationary sources of pollution.
    For example, section 126 of the CAA authorizes a downwind state or
tribe to petition the EPA for a finding that emissions from ``any major
source or group of stationary sources'' in an upwind state contribute
significantly to nonattainment in, or interfere with maintenance by,
the downwind state. If the EPA makes a finding that a major source or a
group of stationary sources emits or would emit pollutants in violation
of the relevant prohibition in CAA section 110(a)(2)(D), the source(s)
must shut down within three months from the finding unless the EPA
directly regulates the source(s) by establishing emissions limitations
and a compliance schedule extending no later than three years from the
date of the finding, to eliminate the prohibited interstate transport
of pollutants as expeditiously as practicable.\267\ Thus, in the
provision that allows for direct Federal regulation of sources
violating the good neighbor provision, Congress established three years
as the maximum amount of time available from a final rule to when
emissions reductions need to be achieved at the relevant source or
group of sources. Because this action is not taken under CAA section
126(c), the mandatory timeframe for implementation of emissions
controls

under that provision is not directly applicable, but it is informative.
---------------------------------------------------------------------------

    \267\ CAA 110(a)(2)(D)(i) and 126(c).
---------------------------------------------------------------------------

    In response to arguments from sources that more time than has been
provided in the final rule is necessary, this provision strongly
indicates that allowing time beyond a three-year period must be based
on a substantial showing of impossibility. Our analysis based on
comments and considering additional information is that the additional
time we have provided in the final rule is both justified and
sufficient in light of the statutory objective of expeditious
compliance.
    Additionally, for ozone nonattainment areas classified as Moderate
or higher, the CAA requires states to implement RACT requirements less
than three years after the statutory deadline for submitting these
measures to the EPA.\268\ Specifically, for these areas, CAA sections
182(b)(2) and 182(f) require that states implement RACT for existing
VOC and NOX sources as expeditiously as practicable but no
later than May 31, 1995, approximately 30 months after the November 15,
1992, deadline for submitting RACT SIP revisions. For purposes of the
2015 ozone NAAQS, the EPA has interpreted these provisions to require
implementation of RACT SIP revisions as expeditiously as practicable
but no later than January 1 of the fifth year after the effective date
of designation, which is less than three years after the deadline for
submitting RACT SIP revisions.\269\ For areas initially designated
nonattainment with a Moderate or higher classification effective August
3, 2018 (83 FR 25776), that implementation deadline falls on January 1,
2023, approximately 29 months after the August 3, 2020 submission
deadline.\270\ Moderate ozone nonattainment areas must also implement
all reasonably available control measures (including RACT) needed for
expeditious attainment within three years after the statutory deadline
for states to submit these measures to the EPA as part of a Moderate
area attainment demonstration.\271\ Nonattainment areas for the 2015
ozone NAAQS that were reclassified to Moderate nonattainment in October
2022 face this same regulatory schedule, meaning that their sources are
required to implement RACT controls in 2023. With the exception of the
Uinta Basin, which is not an identified receptor in this action, no
Marginal nonattainment area met the conditions of CAA section 181(a)(5)
to obtain a one-year extension of the Moderate area attainment date. 87
FR 60899 (Oct. 7, 2022). Thus, all Marginal areas (other than Uinta)
that failed to attain have been reclassified to Moderate. Id. In the
October 2022 final rulemaking EPA made determinations that certain
Marginal areas failed to attain by the attainment date, reclassified
those areas to Moderate, and established SIP submission deadlines and
RACM and RACT implementation deadlines. EPA set the attainment SIP
submission deadlines for the bumped up Moderate areas to be January 1,
2023. See 87 FR 60897, 60900. The implementation deadline for RACM and
RACT is also January 1, 2023. Id.
---------------------------------------------------------------------------

    \268\ See, e.g., 40 CFR 51.1112(a)(3) and 51.1312(a)(3)(i)
(requiring implementation of RACT required pursuant to initial
nonattainment area designations no later than January 1 of the fifth
year after the effective date of designation, which is less than 3
years after the SIP submission deadline under 40 CFR 51.1112(a)(2))
and 51.1312(a)(2)(i), respectively).
    \269\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP
revisions no later than 24 months after the effective date of
designation) and 40 CFR 51.1312(a)(3)(i) (requiring implementation
of RACT SIP revisions as expeditiously as practicable, but no later
than January 1 of the fifth year after the effective date of
designation). For reclassified areas, states must implement RACT SIP
revisions as expeditiously as practicable, but no later than the
start of the attainment year ozone season associated with the area's
new attainment deadline, or January 1 of the third year after the
associated SIP revision submittal deadline, whichever is earlier; or
the deadline established by the Administrator in the final action
issuing the area reclassification. 40 CFR 51.1312(a)(3)(ii); see
also 83 FR 62989, 63012-63014.
    \270\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP
revisions no later than 24 months after the effective date of
designation).
    \271\ See, e.g., 40 CFR 51.1108(d) (requiring implementation of
all control measures (including RACT) needed for expeditious
attainment no later than the beginning of the attainment year ozone
season, which, for a Moderate nonattainment area, occurs less than 3
years after the deadline for submission of reasonably available
control measures under 40 CFR 51.1112(c) and 51.1108(a)) and 40 CFR
51.1308(d) (requiring implementation of all control measures
(including RACT) needed for expeditious attainment no later than the
beginning of the attainment year ozone season, which, for a Moderate
nonattainment area, occurs less than three years after the deadline
for submission of reasonably available control measures under 40 CFR
51.1312(c) and 51.1308(a)). Because the attainment demonstration for
a Moderate nonattainment area (including RACT needed for expeditious
attainment) is due three years after the effective date of the
area's designation (40 CFR 51.1308(a) and 51.1312(c)), and all
Moderate nonattainment areas must attain the NAAQS as expeditiously
as practicable but no later than 6 years after the effective date of
the area's designation (40 CFR 51.1303(a)), the beginning of the
``attainment year ozone season'' (as defined in 40 CFR 51.1300(g))
for such an area is less than three years after the due date for the
attainment demonstration.
---------------------------------------------------------------------------

    The EPA notes that the types and sizes of the EGU and non-EGU
sources that the EPA includes in this rule, as well as the types of
emissions control technologies on which the EPA bases the emissions
limitations that would take effect for the 2026 and 2027 ozone seasons,
generally are consistent with the scope and stringency of RACT
requirements for existing major sources of NOX in downwind
Moderate nonattainment areas and some upwind areas, which many states
have already implemented in their SIPs.\272\ Thus, the timing Congress
allotted for sources in downwind states to come into compliance with
RACT requirements bears directly on the amount of time that should be
allotted here and indicates, as does CAA section 126, that three years
is an outer limit on the time that should be given sources to come into
compliance where possible. In light of the January 1, 2023, deadline
for implementation of RACT in Moderate nonattainment areas, the EPA
finds that a May 1, 2026 deadline for full implementation of the
emissions control requirements in this final rule would generally
provide adequate time for any individual source to install the
necessary controls, barring the circumstances of necessity discussed
further in this section.
---------------------------------------------------------------------------

    \272\ See the Final Non-EGU Sectors TSD for a discussion of SIP-
approved RACT rules in effect in downwind states.
---------------------------------------------------------------------------

    Finally, with respect to emissions standards for hazardous air
pollutants, section 112(i)(3) of the CAA requires the EPA to establish
compliance dates for each category or subcategory of existing sources
subject to an emissions standard that ``provide for compliance as
expeditiously as practicable, but in no event later than 3 years after
the effective date of such standard,'' with limited exceptions. CAA
section 112(i)(3)(B) authorizes the EPA to grant an extension of up to
1 additional year for an existing source to comply with emissions
standards ``if such additional period is necessary for the installation
of controls,'' and sections 112(i)(4) through (7) provide for limited
compliance extensions where other conditions are met.\273\ Here again,
where Congress was concerned with addressing emissions of pollutants
that impact public health, a 3-year time period was allotted as the
time needed for existing sources to come into compliance where
possible. As discussed further in section VI.A.2.b of this document,
the process for obtaining a compliance extension for industrial sources
in this rule is generally modeled on 40 CFR 63.6(i)(3), which
implements

the extension provision for existing sources under CAA section
112(i)(3)(B).
---------------------------------------------------------------------------

    \273\ See, e.g., CAA section 112(i)(4), which provides for
limited compliance extensions granted by the President based on
national security interests.
---------------------------------------------------------------------------

    All of these statutory timeframes for implementation of new control
requirements on existing stationary sources indicate that Congress
considered 3 years to be not only a sufficient amount of time but an
upper bound of time allowable (barring instances of impossibility) for
existing stationary sources to install or begin the installation of
pollution controls as necessary for expeditious attainment, to
eliminate prohibited interstate transport of pollutants, and to protect
public health.
    Further, the EPA notes that, given the number of years that have
passed since EPA's promulgation of the 2015 ozone NAAQS and related
nonattainment area designations in 2018, and in light of the Maryland
court's holding that good neighbor obligations for the 2015 ozone NAAQS
should have been implemented by the Marginal area attainment date in
2021,\274\ the implementation of good neighbor obligations for these
NAAQS is already delayed, and the sources subject to NOX
emissions control in this rule have continued to operate for several
years without the controls necessary to eliminate their significant
contribution to ongoing and persistent ozone nonattainment and
maintenance problems in other states. Under these circumstances, we
find it reasonable to require compliance with the control requirements
for all non-EGUs and the EGU reductions related to post-combustion
control retrofit identified in section V.B.1.b of this document
beginning in the 2026 ozone season (with full implementation by the
2027 ozone season for EGUs, and the availability of source-specific
extensions based on a demonstration of necessity for non-EGUs).
---------------------------------------------------------------------------

    \274\ 958 F.3d at 1203-1204 (remanding the EPA denial of section
126 petition based on the EPA analysis of downwind air quality in
2023 rather than 2021, the year containing the Marginal area
attainment date).
---------------------------------------------------------------------------

    As the D.C. Circuit noted in Wisconsin, the good neighbor provision
requires upwind states to ``eliminate their substantial contributions
to downwind nonattainment in concert with the attainment deadlines'' in
the downwind states, even where those attainment deadlines occur before
EPA's statutory deadline under CAA section 110(c) to promulgate a
FIP.\275\ Referencing the Supreme Court's description of the attainment
deadlines as ``the heart'' of the CAA, the Wisconsin court noted that
some deviation from the mandate to eliminate prohibited transport by
downwind attainment deadlines may be allowed only ``under particular
circumstances and upon a sufficient showing of necessity.'' \276\
---------------------------------------------------------------------------

    \275\ 938 F.3d at 317-318. For example, the court observed that
the EPA may shorten the deadline for SIP submissions under CAA
section 110(a)(1) and may issue FIPs soon thereafter under CAA
section 110(c)(1), to align the upwind states' deadline for
satisfying good neighbor obligations with the downwind states'
deadline for attaining the NAAQS. Id. at 318.
    \276\ Id. at 316 and 319-320 (noting that any such deviation
must be ``rooted in Title I's framework'' and ``provide a sufficient
level of protection to downwind States'').
---------------------------------------------------------------------------

    For the reasons provided in the following sub-sections, the EPA
finds that installation of certain EGU controls and all non-EGU
controls is not possible by the Moderate area attainment date for the
2015 ozone NAAQS (i.e., August 3, 2024),\277\ and, for certain sources,
may not be possible by the 2026 ozone season or even the August 3,
2027, Serious area attainment date. While the EPA's technical analysis
demonstrates that for any individual source, control installation could
be accomplished by the start of the 2026 ozone season, in light of the
scope of this rule coupled with current information on the present
economic capacity of sources, control-installation vendors, and
associated markets for labor and material, it is the EPA's judgment
that a three-year timeframe is not possible for all sources subject to
this rule collectively to come into compliance. Therefore, additional
time beyond 2026 will be allowed for certain facilities in recognition
of these constraints on the processes needed for installation of
controls across all of the covered sources.
---------------------------------------------------------------------------

    \277\ Compliance by the August 3, 2021, Marginal area attainment
date is also impossible as that date has passed.
---------------------------------------------------------------------------

a. EGU Schedule for 2026 and Later Years
    As discussed in sections V.B through V.D of this document,
significant emissions reduction potential exists and is included in
EPA's quantification of significant contribution based on the potential
to install post-combustion controls (SCR and SNCRs) at EGUs. However,
as discussed in detail in those sections, the assumption for
installation of this technology on a region-wide scale is 36-48 months
in this final rule. This amount of time allows for all necessary
procurement, permitting, and installation milestones across multiple
units in the covered region. Therefore, the EPA finds that these
emissions reductions are not available any earlier than the 2026
compliance period. Starting in 2026, state emissions budgets will
reflect full implementation of assumed SNCR mitigation measures and
implementation of half the emissions reduction potential identified for
assumed SCR mitigation measures. For each year in 2027 and beyond,
state emissions budgets include all of the emissions reductions
commensurate with these post-combustion control technologies identified
for covered units in Step 3. The EPA notes that similar compliance
schedules and post-combustion control retrofit installations have been
realized successfully in prior programs allowing similar timeframes.
Subsequent to the NOX SIP Call and the parallel Finding of
Significant Contribution and Rulemaking on Section 126 Petitions (which
became effective December 28, 1998, and February 17, 2000, respectively
\278\), nearly 19 GW of SCR retrofit came online in 2002 and another 42
GW of SCR retrofit came online for steam boilers in 2003, illustrating
that a considerable volume of SCR retrofit capacity is possible within
a 36-month period.
---------------------------------------------------------------------------

    \278\ See 63 FR 57356 (October 27, 1998); 65 FR 2674 (January
18, 2000). The D.C. Circuit stayed the NOX SIP Call by an
order issued May 25, 1999. After upholding the rule in most respects
in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000), the court lifted
the stay by an order issued June 22, 2000.
---------------------------------------------------------------------------

    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 assumed SCR
installation 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 many of the
remaining coal units lacking SCR pose more site-specific installation
challenges than those that were already retrofitted on a quicker
timeframe.
    Response: EPA is making several changes in this final rule to
address these concerns. First, EPA is phasing in emissions reductions
commensurate with assumed SCR installations consistent with a 36-to-48-
month time frame in this final rule, instead of a 36-month time frame
as proposed. EPA is implementing half of this emissions reduction
potential in 2026 ozone-season NOX budgets for states
containing these EGUs and the other half of this emissions reduction
potential in 2027 ozone-season NOX budgets for those states.
This phase-in approach to implementing SCR retrofit reduction potential
over a three to four year period is in response to comments, including
those from third-party full-service engineering firms. These commenters
highlighted that while the

proposed 36-month time frame is viable at the plant level, it would be
``very unlikely'' that the collective volume of SCR capacity could be
installed in a three-year time frame based on a variety of factors.
First, the commenters identified constraints on labor needed to
retrofit 32 GW of capacity, highlighting that the Bureau of Labor and
Statistics projects that there will be a decline in boilermaker
employment over the decade and that the Associated Builders and
Contractors (ABC) identifies the need for 650,000 additional skilled
craft professionals on top of the normal hiring pace to meet the
economy-wide demand created by infrastructure investment and other
clean energy projects (e.g., carbon capture and storage). They
highlighted the decline in companies serving this type of large-scale
retrofit project as the lack of new coal units and the retirement of
coal units has curtailed activity in this area over the past five
years. They also identified supply bottlenecks for key SCR components
that would slow the ability to implement a large volume of SCR within 3
years, affecting electrical conduits, transformers, piping, structural
and plate steel, and wire (with temporary price increases ranging from
30 percent to 200 percent). Finally, commenters note that site-specific
conditions can make retrofits for individual units a lengthier process
than historical averages (e.g., under prior rules more accommodating
sites retrofitted first) and that four years may be necessary for some
projects, accordingly. EPA found the technical justification submitted
in comment consistent with its prior assessments that a range of 39-48
months is appropriate for SCR-retrofit timing within regional-scale
programs.\279\ Therefore, EPA is adjusting the timeframe to still
incentivize these reductions by the attainment date while accommodating
the potential for some SCR retrofits to require between 36-48 months
for installation.
---------------------------------------------------------------------------

    \279\ 86 FR 23102.
---------------------------------------------------------------------------

    Some commenters requested more than 48 months for SCR installation
based on past projects that took five or more years. EPA disagrees with
these commenters for two reasons. First, while EPA is identifying SCR
retrofit potential to define significant contribution at Step 3, the
rule only requires emissions reductions commensurate with that
technology, implemented through a trading program, meaning that
operators of EGUs eligible for SCR retrofit may pursue a variety of
strategies for reducing emissions. Such compliance flexibility will
accommodate extreme or unique circumstances in which a desired SCR
retrofit is not achieved by the 2027 ozone season, although EPA finds
such a circumstance exceedingly unlikely. Second, the historical
examples that exceeded 48 months do not necessarily demonstrate that
such projects are impossible to execute in less than 48 months, but
rather that they can extend beyond that timeframe if no requirements or
incentives are in place for a faster installation. As the D.C. Circuit
has recognized, historical data on the amount of time sources have
taken to install pollution controls do not in themselves establish the
minimum amount of time in which those controls could be installed if
sources are subject to a legal mandate to do so. See Wisconsin, 938
F.3d at 330 (``[A]ll those anecdotes show is that installation can drag
on when companies are unconstrained by the ticking clock of the
law.'').
b. Non-EGU or Industrial Source Schedule for 2026 and Later Years
    The EPA proposed to require that all emissions reductions
associated with the requirements for non-EGU industrial sources go into
effect by the start of the 2026 ozone season, but also requested
comment on its control-installation timing estimates for non-EGUs and
requested comment on the possibility of providing for limited
compliance extensions based on a showing of necessity. See 87 FR 20104-
05.
    Comment: The EPA received numerous comments regarding the inability
of various non-EGU industries to install controls to comply with the
emissions limits by 2026. Specifically, commenters raised concerns
regarding the ability to meet these deadlines due to the ongoing
geopolitical instability triggered by the war in Ukraine, COVID-19
pandemic-driven disruptions, and supply chain delays and shortages.
Commenters also claimed that the EPA's three-year installation
timeframe for non-EGUs does not account for the time needed to obtain
necessary permits. Commenters stated that even where controls are
feasible for a source, some sources would need to shut down due to
their inability to install controls by 2026 and requested that the EPA
provide additional time for sources to come into compliance. Commenters
from multiple non-EGU industries stated that the proposed applicability
criteria will require controls to be installed on thousands of non-EGU
emissions units. Because of the number of emissions units, commenters
raised concerns with permitting delays and the unavailability of
skilled labor and necessary components. Commenters suggested various
timelines for control installation timing ranging from one additional
year to seven years. Other commenters asserted that the data supported
the conclusion that all non-EGU sources, or at least some non-EGU
sources, could install controls by 2026 or earlier, and that EPA has a
legal obligation to impose good neighbor requirements as expeditiously
as practicable by such sources, including earlier than 2026 if
possible.
    Response: After reviewing the information received during the
public comment period and the additional information presented in the
Non-EGU Control Installation Timing Report, the EPA has concluded that
the majority of non-EGUs can install and operate the required controls
by the 2026 ozone season. For the non-EGU control requirements on which
the EPA has based its Step 3 findings as described in section V of this
document, the emissions limits will generally go into effect starting
with the 2026 ozone season (except where an individual source qualifies
for a limited extension of time to comply based on a specific
demonstration of necessity, as described in this section). The EPA
finds that meeting the emissions limitations of this final rule through
installation of necessary controls by an ozone season before 2026 is
not expected to be possible for the industrial sources covered by this
final rule.
    The EPA recognizes that labor shortages, supply shortages, or other
circumstances beyond the control of source owner/operators may, in some
cases, render compliance by 2026 impossible for a particular industrial
source. Therefore, the final rule contains provisions allowing source
owner/operators to request limited compliance extensions based on a
case-by-case demonstration of necessity. Under these provisions, the
owner or operator of a source may initially apply for an extension of
up to one year to comply with the applicable emissions control
requirements, which if approved by the EPA, would require compliance no
later than the 2027 ozone season. The EPA may grant an additional case-
based extension of up to two additional years for full compliance,
where specific criteria are met.
    The EPA initiated a study to examine the time necessary to install
the potential controls identified in the final rule's cost analysis for
all of the non-EGU industries subject to the final rule, including
SNCR, low NOX burners, layered combustion, NSCR, SCR, fluid
gas recirculation, and SNCR/advanced selective noncatalytic reduction

(ASNCR). The resulting report, which we refer to as the ``Non-EGU
Control Installation Timing Report,'' identified a range of estimated
installation times with minimum estimated installation times ranging
from 6-27 months without any supply chain delays and 6-40 months with
potential supply chain delays depending on the industry.\280\ The Non-
EGU Control Installation Timing Report also identified maximum
estimated installation times ranging from 12-28 months without any
supply chain delays and 12-72 months with potential supply chain delays
depending on the industry. As indicated in the Non-EGU Control
Installation Timing Report, the installation of layered combustion and
NSCR control technology, in particular, could take between 9 and 72
months depending on supply chain delays.\281\ The report also indicated
that permitting processes may take 6 to 12 months but noted that these
processes typically can proceed concurrent with other steps of the
installation process.\282\
---------------------------------------------------------------------------

    \280\ See generally SC&A, NOX Emission Control Technology
Installation Timing for Non-EGU Sources (March 14, 2023) (``Non-EGU
Control Installation Timing Report'').
    \281\ See Non-EGU Control Installation Timing Report, Executive
Summary (March 14, 2023).
    \282\ Id. at Section 5.6.
---------------------------------------------------------------------------

    We find that the potential time needed for permitting processes is
generally unlikely to significantly affect installation timeframes of
at least three years given that a source that has three or more years
to comply is expected, in most cases, to have adequate time to apply
for and secure the necessary permits during that time. Permitting
processes may, however, impact shorter installation times ranging from
12-28 months. Given the 12-28 month estimate for minimum and maximum
installation times without supply chain delays and permitting
timeframes typically ranging from 6-12 months, the EPA finds that the
controls for non-EGU sources needed to comply with this final rule are
generally not expected to be installed significantly before the 2026
ozone season.
    Generally, the Non-EGU Control Installation Timing Report indicated
that all non-EGU unit types subject to the final rule could install
controls within 28 months if there are no supply chain delays. Thus,
the Non-EGU Control Installation Timing Report confirms that for any
individual facility, meeting the emissions limitations of this final
rule through installation of controls can be completed by the start of
the 2026 ozone season. It is only when the number of units in the U.S.
potentially affected by the rule is taken into account, coupled with
broader considerations of economic capacity including current
information on supply-chain delays, that the potential need for
additional time beyond 2026 becomes a possibility. Under ideal economic
conditions (i.e., no supply-chain delays or other constraints),
affected units are estimated to be capable to install both combustion
and post-combustion controls before the 2026 ozone season. Many
commenters, however, provided information on installation timing
estimates based on current supply chain delays and labor constraints.
These commenters generally stated that installation of the necessary
controls for some units would take longer than three years if supply
chain delays similar to those that have occurred over the past few
years continue. The Non-EGU Control Installation Timing Report
reflected this information, together with additional information
gathered from pollution control vendors, to develop ranges of estimates
of possible installation times given current (i.e., 2022) labor market
conditions and material supplies. The Non-EGU Control Installation
Timing Report also discussed how the installation and optimization of
post-combustion controls over a similar timeframe at both EGUs and non-
EGUs subject to this final rule would, considered cumulatively,
potentially affect the installation timing needs of the covered non-EGU
sources.
    Based on information provided by commenters and vendors, the Non-
EGU Control Installation Timing Report indicated that if current supply
chain delays continue, control installations could take as long as 61
months for most non-EGU industries and possibly as long as 64-112
months in difficult cases. Notably, however, the conclusions in the
Non-EGU Control Installation Timing Report reflect three key
assumptions that could result in the relatively lengthy timing
estimates at the outer end of this range: (1) the current state of
supply chain delays and disruptions would continue without any increase
in labor supply, materials, or reduction in fabrication timing; (2) the
labor and materials markets would not adjust in response to this rule
in the timeframe needed to meet the increased demand for control
installations; and (3) the Report was unable to account for some of the
flexibilities built into the final rule that will allow owners and
operators to install controls on the most cost-effective units with
shorter installation times.
    As presented in the Non-EGU Control Installation Timing Report,
supply chain delays and disruptions have generally been lessening since
they peaked in 2020 during the COVID-19 pandemic, and many economic
indicators have showed some improvement towards pre-pandemic levels,
including freight transportation, inventory to sales ratios, interstate
miles traveled, U.S. goods imports, and supply chain indices.\283\ If
these economic indicators continue to improve and the availability of
fabricators and materials continues to trend upward, the control timing
estimates identified in the Non-EGU Control Installation Timing Report
could prove to be overstated for some industries and control
technologies. In addition, the Non-EGU Control Installation Timing
Report did not account for the labor and supply market adjustments that
would be anticipated to occur to meet increased demand for control
technologies and related materials and labor over the next several
years in response to the rule. Cf. Wisconsin, 938 F.3d at 330 (``[A]ll
those anecdotes [of elongated control installation times] show is that
installation can drag on when companies are unconstrained by the
ticking clock of the law.''). For example, some of the longer
installation timeframes identified in the Non-EGU Control Installation
Timing Report are based on assumed limits on the current availability
of skilled labor needed to install combustion controls and post
combustion controls. If the market adjusts in response to increasing
demand for this type of skilled labor in the timeframe needed for
compliance (e.g., there is an increase in boilermaker and engine
controls labor), the installation timing estimates in the Non-EGU
Control Installation Timing Report again could be overstated.
---------------------------------------------------------------------------

    \283\ Id. at Section 6.1.
---------------------------------------------------------------------------

    The Non-EGU Control Installation Timing Report also did not account
for flexibilities provided in this final rule that will enable owners
and operators of certain affected units to identify the most cost-
effective and efficient means for installing any necessary controls.
For example, one concern highlighted by commenters was the amount of
time necessary to install controls on engines that have been in
operation for 50 or more years. The requirements that we are finalizing
for engines in the Pipeline Transportation of Natural Gas industry
include an exemption for emergency engines and provisions allowing
source owner/operators to request the EPA approval of facility-wide
emissions averaging plans, both of which enable owners and operators of
affected units to take costs, installation timing needs,

and other considerations into account in deciding which engines to
control.
    In response to industry concern about the number and size of units
captured by the proposed applicability criteria, the EPA has made
several changes to the applicability criteria in the final rule to
focus the control requirements on impactful non-EGU units. As explained
further in section VI.C of this document, the EPA is establishing
exemptions for low-use boilers and engines where it would not be cost-
effective to require controls at this time. Finally, as discussed in
section VI.C.3 of this document, the EPA is not finalizing the proposed
requirements for most emissions unit types in the Iron and Steel Mills
and Ferroalloy Manufacturing industry given the EPA does not currently
have a sufficient technical basis for finalizing those proposed
requirements. These changes reduce the number of non-EGU units that
will actually need to install controls and should reduce the strain on
the labor and supply chain and permitting processes. For example, for
engines, the EPA estimates that the facility-wide emissions averaging
provision would, in many cases, allow facilities to install controls on
only one-third of their engines, on average (see section VI.C.1 of this
document for further discussion).
    Taking all of these considerations into account, the EPA finds that
the outer range of timing estimates presented in the Non-EGU Control
Installation Timing Report generally reflects a conservative set of
installation timing estimates and that the factors described previously
could result in installation timeframes that fall toward the shorter
end of the ranges of time that factor in supply-chain delays or could
obviate those supply-chain delay issues entirely.
    Based on all of these considerations, the EPA has concluded that
three years is generally an adequate amount of time for the non-EGU
sources covered by this final rule to install the controls in the 20
states that remain linked in 2026. The EPA also recognizes, however,
that some sources may not be able to install controls by the 2026 ozone
season despite making good faith efforts to do so, due to the
aforementioned supply chain delays or other circumstances entirely
beyond the owner or operator's control. Therefore, the final FIPs
require compliance with the emissions control requirements for non-EGUs
by the beginning of the 2026 ozone season, with limited exceptions
based on a showing of necessity for individual sources that meet
specific criteria. Where an individual owner or operator submits a
satisfactory demonstration that an extension of time to comply is
necessary, due to circumstances entirely beyond the owner or operator's
control and despite all good faith efforts to install the necessary
controls by May 1, 2026, the EPA may determine that installation by
2026 is not possible and thereby grant an extension of up to one year
for that source to fully implement the required controls. If, after the
EPA has granted a request for an initial compliance extension, the
source remains unable to comply by the extended compliance date due to
circumstances entirely beyond the owner or operator's control and
despite all good faith efforts to install the necessary controls by the
extended compliance date, the owner or operator may request and the EPA
may grant a second extension of up to two additional years for full
compliance, where specific criteria are met. This application process
is generally in accordance with the concept on which the Agency
requested comment in the proposal, see 87 FR 20104-05, and is modeled
on a similar process provided for industrial sources subject to CAA
section 112 NESHAPs, found at 40 CFR 63.6(i)(3).
    The EPA intends to grant a request for an initial compliance
extension only where a source demonstrates that it has taken all steps
possible to install the necessary controls by the applicable compliance
date and still cannot comply by the 2026 ozone season, due to
circumstances entirely beyond its control. Any request for a compliance
extension must be received by the EPA at least 180 days before the May
1, 2026, compliance date. The request must include all information
obtained from control technology vendors demonstrating that the
necessary controls cannot be installed by the applicable compliance
date, any permit(s) secured for the installation of controls or
information from the permitting authority on the timeline for issuance
of such permit(s) if the source has not yet obtained the required
permit(s); and any contracts entered into by the source for the
installation of the control technology or an explanation as to why no
contract is necessary. The EPA may also consider documentation of a
source owner's/operator's plans to shut down a source by the 2027 ozone
season in determining whether a source is eligible for a compliance
extension. The owner or operator of an affected unit remains subject to
the May 1, 2026 compliance date unless and until the Administrator
grants a compliance extension.
    The EPA intends to grant a request for a second compliance
extension beyond 2027 only where a source owner/operator submits
updated documentation showing that it is not possible to install and
operate controls by the 2027 ozone season, despite all good faith
efforts to comply and due to circumstances entirely beyond its control.
The request must be received by the EPA at least 180 days before the
extended compliance date and must include, at minimum, the same types
of information as that required for the initial extension request. The
owner or operator of an affected unit remains subject to the initial
extended compliance date unless and until the Administrator grants a
second compliance extension. A denial will be effective on the date of
denial.
    As discussed earlier in section VI.A, in Wisconsin the court held
that some deviation from the CAA's mandate to eliminate prohibited
transport by downwind attainment deadlines may be allowed only ``under
particular circumstances and upon a sufficient showing of necessity.''
\284\ This standard is met when, in the EPA's judgment, compliance by
the attainment date amounts to an impossibility. The EPA cannot allow a
covered industrial source to avoid timely compliance with the emissions
control requirements established in this final rule unless the source
owner/operator can demonstrate that compliance by the 2026 ozone season
is not possible due to circumstances entirely beyond their control. The
criteria that must be met to qualify for limited extensions of time to
comply are designed to meet this statutory mandate. The EPA anticipates
that the majority of the industrial sources covered by this final rule
will not qualify for a compliance extension.
---------------------------------------------------------------------------

    \284\ Wisconsin, 938 F.3d at 316 and 319-320 (noting that any
such deviation must be ``rooted in Title I's framework'' and
``provide a sufficient level of protection to downwind States'').
---------------------------------------------------------------------------

B. Regulatory Requirements for EGUs

    To implement the required emissions reductions from EGUs, the EPA
is revising the existing CSAPR NOX Ozone Season Group 3
Trading Program (the ``Group 3 trading program'') established in the
Revised CSAPR Update both to expand the program's geographic scope and
to enhance the program's ability to ensure favorable environmental
outcomes. The EPA is using a trading program for EGUs because of the
inherently greater flexibility that a trading program can provide
relative to more prescriptive, ``command-and-control'' forms of
regulation of sufficient stringency to achieve the necessary emissions
reductions. In the electric

power sector, EGUs' extensive interconnectedness and coordination
create the ability to shift both electricity production and emissions
among units, providing a closely related ability to achieve emissions
reductions in part by shifting electricity production from higher-
emitting units to lower-emitting or non-emitting units. Thus, while the
Step 3 control-stringency determination for EGUs to eliminate
significant contribution is based on strategies that do not require
generation shifting or reduced utilization of EGUs, the sector's
unusual flexibility with respect to how emissions reductions can be
achieved makes the flexibility of a trading program particularly useful
as a means of lowering the overall costs of obtaining such reductions.
In addition, it is essential for the electric power sector to retain
short-term operational flexibility sufficient to allow electricity to
be produced at all times in the quantities needed to meet demand
simultaneously, and the flexibility of a trading program can be helpful
in supporting this aspect of the industry as well.
    To ensure emissions reductions necessary to eliminate significant
contribution are maintained, in this rulemaking, the EPA is making
certain enhancements to the current provisions of the Group 3 trading
program addressing emissions-control performance by some kinds of
individual units that will necessarily reduce the flexibility of the
program to some extent for those units. In analyzing significant
contribution at Step 3, once a linkage has been established between an
upwind state and a downwind receptor, we identify an appropriate set of
emissions control strategies, considering cost and other factors, that
would eliminate significant contribution from the upwind state without
leading to undercontrol or overcontrol at the downwind linked
receptors. At Step 4, for EGUs, we develop emissions budgets based on
consistent application of the identified strategies to the sources.
This level of emission control at each source identified in Step 3 is
what the EPA deems to eliminate significant contribution, while the
design of emission budgets that successfully implement that level of
emission control is determined at Step 4. See section III.B and V.
    The trading program enhancements discussed in this section are
designed to ensure that sources actually achieve that level of emission
control and thereby eliminate significant contribution on a permanent
basis at Step 4. The enhancements ensure that the emissions budgets for
EGUs continue to secure the level of emission control identified at
Step 3 at the sources active in the trading program on a more
consistent basis throughout each ozone season than prior transport
trading programs (including those that did not provide complete
remedies for interstate pollution transport) have required. An
alternative form of implementation at Step 4 would be to implement
source-specific emissions limitations (e.g., rate-based standards
expressed as mass per unit of heat input) reflecting the control
strategies identified at Step 3. This is a very common form of
implementation for many other CAA requirements and is indeed the manner
of implementation selected in this very rulemaking for other affected
industrial sources. See sections III.B, V.D.4, and VI.C. But doing so
would require loss of the flexibilities inherent in a trading program,
inclusive of these enhancements, that facilitate orderly and timely
achievement of the required emission reductions in the power sector.
    Prior to this rule, the Group 3 trading program has applied to EGUs
meeting the program's applicability criteria within the borders of
twelve states: Illinois, Indiana, Kentucky, Louisiana, Maryland,
Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West
Virginia. Affected EGUs in these twelve states will continue to
participate in the Group 3 trading program as revised in this
rulemaking, with some revised provisions taking effect in the 2023
control period and other revised provisions taking effect later as
discussed elsewhere in this document. The EPA is expanding the Group 3
trading program's geographic scope to include all of the additional
states for which EGU emissions reduction requirements are being
established in this rulemaking. Affected EGUs within the borders of
seven states currently covered by the CSAPR NOX Ozone Season
Group 2 Trading Program (the ``Group 2 trading program'')--Alabama,
Arkansas, Mississippi, Missouri, Oklahoma, Texas, and Wisconsin--will
transition from the Group 2 trading program to the revised Group 3
trading program at the beginning of the 2023 control period,\285\ and
affected EGUs within the borders of the three states not currently
covered by any CSAPR trading program for seasonal NOX
emissions--Minnesota, Nevada, and Utah--will enter the Group 3 trading
program in the 2023 control period on the effective date of this rule.
As discussed in section VI.B.12.a of this document, because the
effective date of the rule will likely be sometime during the 2023
ozone season, special transitional provisions have been developed to
allow for efficient administration of the rule's EGU requirements
through the Group 3 trading program while not imposing any new
substantive obligations on parties prior to the rule's effective date,
similar to the transitional provisions implemented under the Revised
CSAPR Update.
---------------------------------------------------------------------------

    \285\ Affected EGUs in the three other states currently covered
by the Group 2 trading program--Iowa, Kansas, and Tennessee--will
continue to participate in that program.
---------------------------------------------------------------------------

    As is the case for the states already in the Group 3 trading
program, for each state added to the program, the set of affected EGUs
will include new units as well as existing units and will also include
units located in Indian country within the state's borders. Sections
VI.B.2 and VI.B.3 of this rule provide additional discussion of the
geographic expansion of the Group 3 trading program and the units in
the expanded geography that will become subject to the program under
the program's existing applicability provisions.
    In addition to expanding the Group 3 trading program's geographic
scope, the EPA is modifying the program's regulations prospectively to
include certain enhancements to improve environmental outcomes. Two of
the proposed enhancements will adjust the overall quantities of
allowances available for compliance in the trading program in each
control period so as to maintain the rule's selected control stringency
and related EGU effective emissions rate performance level as the EGU
fleet evolves. First, instead of establishing emissions budgets for all
future years under the program at the time of the rulemaking, which
cannot reflect future changes in the EGU fleet unknown at the time of
the rulemaking, the EPA is revising the trading program regulations to
include a dynamic budgeting procedure. Under this procedure, the EPA
will calculate emissions budgets for control periods in 2026 and later
years based on more current information about the composition and
utilization of the EGU fleet, specifically data available from the 2024
ozone season and following (e.g., for 2026, data from periods through
2024; for 2027, data from periods through 2025; etc.). Through the 2029
control period, the dynamically determined budgets will apply only if
they are higher than preset budgets established in the rule.
(Associated revisions to the program's variability limits and unit-
level allowance allocation procedures will coordinate these provisions
with the revised budget-setting procedures.) Second,

starting with the 2024 control period, the EPA will annually
recalibrate the quantity of accumulated banked allowances under the
program to prevent the quantity of allowances carried over from each
control period to the next from exceeding the target bank level, which
would be revised to represent a preset percentage of the sum of the
state emissions budgets for each control period. The preset percentage
will be 21 percent for control periods through 2029 and 10.5 percent
for control periods in 2030 and later years. Together, these
enhancements will protect the intended stringency of the trading
program against potential erosion caused by EGU fleet turnover and will
better sustain over time the incentives created by the trading program
to achieve the degree of emissions control for EGUs that the EPA has
determined is necessary to address states' good neighbor obligations.
    Two further enhancements to the Group 3 trading program establish
provisions designed to promote more consistent emissions control by
individual EGUs within the context of the trading program. First,
starting with the 2024 control period for coal-fired EGUs with existing
SCR controls and the earlier of the 2030 control period or the control
period after which an SCR is installed for other large coal-fired EGUs,
a daily NOX emissions rate of 0.14 lb/mmBtu will apply as a
backstop to the seasonal emissions budgets (which are based on an
assumed seasonal average emissions rate of 0.08 lb/mmBtu for EGUs with
existing SCR controls). Each ton of emissions exceeding a unit's
backstop daily emissions rate, after the first 50 such tons, in a given
control period will incur a 3-for-1 allowance surrender ratio instead
of the usual 1-for-1 allowance surrender ratio. Second, also starting
with the 2024 control period, the trading program's existing assurance
provisions, which require extra allowance surrenders from sources that
are found responsible for contributing to an exceedance of the relevant
state's ``assurance level'' (i.e., typically 121 percent of the state's
emissions budget), will be strengthened by the addition of another
backstop requirement. Specifically, for any unit equipped with post-
combustion controls that is found responsible for contributing to an
exceedance of the state's assurance level, the revised regulations will
prohibit the unit's seasonal emissions from exceeding by more than 50
tons the emissions that would have resulted if the unit had achieved a
seasonal average emissions rate equal to the higher of 0.10 lb/mmBtu or
125 percent of the unit's lowest previous seasonal average emissions
rate under any CSAPR seasonal NOX trading program.\286\
---------------------------------------------------------------------------

    \286\ The requirement would not apply for control periods during
which the unit operated for less than 10 percent of the hours, and
emissions rates achieved in such previous control periods would be
excluded from the comparison.
---------------------------------------------------------------------------

    These two enhancements are designed to ensure that all individual
units with SCR controls have strong incentives to continuously operate
and optimize their controls, and also to ensure that all units with
post-combustion controls have strong incentives to optimize their
emissions performance when a state's assurance level might otherwise be
exceeded. These enhancements are generally designed to ensure
consistency with the EPA's determination regarding the emissions
control stringency needed from EGUs to eliminate significant
contribution under the Step 3 multifactor analysis as discussed in
section V of this document. Further, these enhancements are designed to
provide greater assurance that emissions controls will be operated on
all days of the ozone season and therefore necessarily on the days that
turn out to be most critical for downwind ozone levels. The EPA expects
that promoting more consistently good emissions performance by
individual EGUs will better ensure that each state's significant
contribution is fully eliminated by this action, see North Carolina,
531 F.3d at 919-21. In addition to addressing the statutory
requirements of eliminating significant contribution, the EPA
anticipates that these enhancements will also deliver public health and
environmental benefits to underserved and overburdened communities.
    The revisions to the Group 3 trading program being finalized in
this rule are very similar to the proposed revisions. The changes from
proposal to the set of states covered are driven largely by updates to
the air quality modeling performed for the final rule, as described in
section IV of this document. The changes from proposal to the trading
program enhancements are generally being made in response to comments
on the proposal, as discussed in more detail in the remainder of
section VI.B of this document.
1. Trading Program Background and Overview of Revisions
a. Current CSAPR Trading Program Design Elements and Identified
Concerns
    The use of allowance trading programs to achieve required emissions
reductions from the electric power sector has a long history, rooted in
the Clean Air Act Amendments of 1990. In Title IV of those amendments,
Congress specified the design elements for a 48-state allowance trading
program to reduce SO2 emissions and the resulting acid
precipitation. Building on the success of that first allowance trading
program as a tool for addressing multi-state air pollution issues,
since 1998 EPA has promulgated and implemented multiple allowance
trading programs for SO2 or NOX emissions to
address the requirements of the CAA's good neighbor provision with
respect to successively more protective NAAQS for fine particulate
matter and ozone. Most of these trading programs have applied either
exclusively or primarily to EGUs.
    The EPA currently administers six CSAPR trading programs for EGUs
(promulgated in CSAPR, the CSAPR Update, and the Revised CSAPR Update)
that differ in the pollutants, geographic regions, and time periods
covered and in the levels of stringency, but that otherwise have been
nearly identical in their core design elements and their regulatory
text.\287\ The principal common design elements currently reflected in
all of the programs are as follows:
---------------------------------------------------------------------------

    \287\ The six current CSAPR trading programs are the CSAPR
NOX Annual Trading Program, CSAPR NOX Ozone
Season Group 1 Trading Program, CSAPR SO2 Group 1 Trading
Program, CSAPR SO2 Group 2 Trading Program, CSAPR
NOX Ozone Season Group 2 Trading Program, and CSAPR
NOX Ozone Season Group 3 Trading Program. The regulations
for the six programs are set forth at subparts AAAAA, BBBBB, CCCCC,
DDDDD, EEEEE, and GGGGG, respectively, of 40 CFR part 97.
---------------------------------------------------------------------------

     An ``emissions budget'' is established for each state for
each control period, representing the EPA's quantification of the
emissions that would remain under certain projected conditions after
elimination of the emissions prohibited by the good neighbor provision
under those projected conditions. For each control period of program
operation, a quantity of newly issued ``allowances'' equal to the
amount of each state's emissions budget is allocated among the state's
sources. (States have options to replace the EPA's default allocations
or to institute an auction process.) Total emissions in a given control
period from all sources in the program are effectively

capped at a level no higher than the total quantity of allowances
available for use in the control period, consisting of the sum of all
states' emissions budgets for the control period plus any unused
allowances carried over from previous control periods as ``banked''
allowances.
     ``Assurance provisions'' in each program establish an
``assurance level'' for each state for each control period, defined as
the sum of the state's emissions budget plus a specified ``variability
limit.'' The purpose of the assurance provisions is to limit the total
emissions from each state's sources in each control period to an amount
close to the state's emissions budget for the control period,
consistent with the good neighbor provision's mandate that required
emissions reductions must be achieved within the state, while allowing
some flexibility beyond the emissions budget to accommodate year-to-
year operational variability. In the event a state's assurance level is
exceeded, responsibility for the exceedance is apportioned among the
state's sources through a procedure that accounts for the sources'
shares of the state's total emissions for the control period as well as
the sources' shares of the state's assurance level for the control
period.
     At the program's compliance deadlines after each control
period, sources are required to hold for surrender specified quantities
of allowances. The minimum quantities of allowances that must be
surrendered are based on the sources' reported emissions for the
control period at a 1-for-1 ratio of allowances to tons of emissions
(or 2-for-1 in instances of late compliance). In addition, two more
allowances must be surrendered for each ton of emissions exceeding a
state's assurance level for a control period, yielding an overall 3-
for-1 surrender ratio for those emissions (or 4-for-1 in instances of
late compliance). Failure to timely surrender all required allowances
is potentially subject to penalties under the CAA's enforcement
provisions.
     To continuously incentivize sources to reduce their
emissions even when they already hold sufficient allowances to cover
their expected emissions for a control period, and to promote
compliance cost minimization, operational flexibility, and allowance
market liquidity, the programs allow trading of allowances--both among
sources in the program and with non-source entities--and also let
allowances that are unused in one control period be carried over for
use in future control periods as banked allowances. Although the CSAPR
programs do not limit trading of allowances, and prior to this rule
have not limited banking of allowances within a given trading program,
the 3-for-1 surrender ratio imposed by the assurance provisions on any
emissions exceeding a state's assurance level disincentivizes sources
from relying on either in-state banked allowances or net out-of-state
purchased allowances to emit over the assurance level.\288\
---------------------------------------------------------------------------

    \288\ As discussed in section VI.B.6 of this document, while
allowance banking has not previously been limited under any of the
CSAPR trading programs, limits on the use of banked allowances were
included in the earlier NOX Budget Trading Program in the
form of ``flow control'' provisions.
---------------------------------------------------------------------------

     Finally, other common design elements ensure program
integrity, source accountability, and administrative transparency. Most
notably, each unit must monitor and report emissions and operational
data in accordance with the provisions of 40 CFR part 75; all allowance
allocations or auction results, transfers, and deductions must be
properly recorded in the EPA's Allowance Management System; each source
must have a designated representative who is authorized to represent
all of the source's owners and operators and is responsible for
certifying the accuracy of the source's reports to the EPA and
overseeing the source's Allowance Management System account; and
comprehensive data on emissions and allowances are made publicly
available.
    The EPA continues to believe that the historical CSAPR trading
program structure established by the common design elements just
described has important positive attributes, particularly with respect
to the exceptional degree of compliance flexibility it can provide to a
sector such as the electric power sector where such flexibility is
especially useful and valuable. However, the EPA also shares many
stakeholders' concerns about whether the historical structure, without
enhancements, is capable of adequately addressing states' good neighbor
obligations with respect to the 2015 ozone NAAQS in light of the
rapidly evolving EGU fleet and the protectiveness and short-term form
of the ozone standard. One set of concerns relates to the historically
observed tendency under the trading programs for the supply of
allowances to grow over time while the demand for allowances falls,
reducing allowance prices and eroding the consequent incentives for
sources to effectively control their emissions. A second, overlapping
set of concerns relates to the general absence of source- or unit-
specific emissions reduction requirements, allowing some individual
sources to idle or run less optimally existing emissions controls even
when a linkage between the sources' state and a receptor persists. For
example, certain units in Ohio and Pennsylvania have been found to have
operated their controls below target emissions performance levels used
for budget setting under the CSAPR Update in the 2019-2021 period, even
though the Revised CSAPR Update found that these states remained linked
through at least 2021 to receptors for the 2008 ozone NAAQS, and the
CSAPR Update itself was only a partial remedy. See 86 FR 23071, 23083.
While this unit-level behavior may have been permissible under the
prior program, emissions from these individual sources can contribute
to increased pollution concentrations downwind on the particular days
that matter for downwind exceedances of the relevant air quality
standard. This indicates that the prior program design was not
effectively ensuring the elimination of significant contribution.\289\
---------------------------------------------------------------------------

    \289\ We also observe that these sources' emissions have the
potential to impact downwind overburdened communities. See Ozone
Transport Policy Analysis Final Rule TSD, Section E. The EPA
conducted a screening-level analysis to determine whether there may
be impacts on overburdened communities resulting from those EGUs
receiving backstop emissions rates under this rule. This analysis
identified a greater potential for these sources to affect areas of
potential concern than the national coal-fired EGU fleet on average.
However, this analysis is distinct from the more comprehensive
exposure analysis conducted as discussed in section VII of this
document and the RIA. In addition, we note that our conclusions
regarding the EGU trading program enhancements in this final rule
are wholly supportable and justified under the good neighbor
provision, even in the absence of any potential benefits to
overburdened communities.
---------------------------------------------------------------------------

    The EPA has analyzed hourly emissions data reported in prior cap-
and-trade programs and identified instances of sources that did not
operate SCR controls for substantial portions of recent ozone seasons.
In an effort to ensure emissions control on critically important
highest ozone days, guard against non-operation of emissions controls
under a more protective NAAQS, and provide assurance of elimination of
significant contribution to downwind areas, while also maintaining
appropriate compliance and operational flexibility for EGUs, the EPA in
this rule is implementing a suite of enhancements to the trading
program. These will help to ensure reductions occur on the highest
ozone days commensurate with our Step 3 determinations, in addition to
maintaining a mass-based seasonal requirement. To meet the statutory
mandate to eliminate significant contribution and interference with

maintenance on the critically important days, this combination of
provisions will strongly incentivize sources to plan to run controls
all season, including on the highest ozone days, while giving
reasonable flexibility for occasional operational needs.\290\
---------------------------------------------------------------------------

    \290\ Deferral of the backstop daily emissions rate for certain
EGUs, for reasons discussed in section VI.B.7 of this document, does
not alter this finding that this trading program enhancement is an
important part of the solution to eliminating significant
contribution from EGUs under CAA section 110(a)(2)(D)(i)(I).
---------------------------------------------------------------------------

    In this rulemaking, the EPA is revising the Group 3 trading program
to include enhancements designed to address both sets of concerns
described previously. The principles guiding the various revisions and
the relationships of the revisions to one another are discussed in
sections VI.B.1.b and VI.B.1.c of this document. The individual
revisions are discussed in more detail in sections VI.B.4 through
VI.B.9 of this document.
b. Enhancements To Maintain Selected Control Stringency Over Time
    The first set of concerns noted about the current CSAPR trading
program structure relates to the programs' ability to maintain the
rule's selected control stringency and related EGU effective emissions
performance level as the EGU fleet evolves over time. Under the
historical structure of the CSAPR trading programs, the effectiveness
of the programs at maintaining the rule's selected control stringency
depends entirely on how allowance prices over time compare to the costs
of sources' various emissions reduction opportunities, which in turn
depends on the relationship between the supply for allowances and the
demand for allowances. In considering possible ways to address concerns
about the ability to enhance the historical trading program structure
to better sustain incentives to control emissions over time, the EPA
has focused on the trading program design elements that determine the
supply of allowances, specifically the approach for setting state
emissions budgets and the rules concerning the carryover of unused
allowances for use in future control periods as banked allowances.
i. Revised Emissions Budget-Setting Process
    In each of the previous rulemakings establishing CSAPR trading
programs, the EPA has evaluated the emissions that could be eliminated
through implementation of certain types of emissions control strategies
available at various cost thresholds to achieve certain rates of
emissions per unit of heat input (i.e., the amount of fuel consumed)
and the effects of the resulting emissions reductions on downwind air
quality. After determining the emissions control strategies and
associated emissions reductions that should be required under the good
neighbor provision by considering these factors in a multifactor test
at Step 3, the EPA has then for purposes of Step 4 implementation
program design projected the amounts of emissions that would remain
after the assumed implementation of the selected emissions control
strategies at various points in the future and has established the
projected remaining amounts of emissions as the state emissions budgets
in trading programs.
    Projecting the amounts of emissions remaining after implementation
of selected emissions controls necessarily requires projections not
only for sources' future emissions rates but also for other factors
that influence total emissions, notably the composition of the future
EGU fleet (i.e., the capacity amounts of different types of sources
with different emissions rates) and their future utilization levels
(i.e., their heat input). To the extent conditions unfold in practice
that differ from the projections made at the time of a rulemaking for
these other factors, over time the emissions budgets may not reflect
the intended stringency of the emissions control strategies identified
in the rulemaking as consistent with addressing states' good neighbor
obligations. Further, projecting EGU fleet composition and utilization
beyond the relatively near-term analytic years of 2023 and 2026 given
particular attention in this rulemaking has become increasingly
challenging in light of the anticipated continued evolution of the
electric power sector toward more efficient and cleaner sources of
generation, including as driven by incentives provided by the
Infrastructure Investment and Jobs Act as well as the Inflation
Reduction Act.
    A consequence of using a trading program approach with preset
emissions budgets that do not keep pace with the trends in EGU fleet
composition and heat input is that the preset emissions budgets
maintain the supply of allowances at levels that increasingly exceed
the emissions that would occur even without implementation of the
emissions control strategies used as the basis for determining the
emissions budgets, causing decreases in allowance prices and hence the
incentives to implement the control strategies. As an example, although
the emissions budgets in the CSAPR Update established in 2016 reflected
implementation of the emissions control strategy of operating and
optimizing existing SCR controls, within four years the EPA found that
EGU retirements and changes in utilization not anticipated in EPA's
previous budget-setting computations had made it economically
attractive for at least some sources to idle or reduce the
effectiveness of their existing controls (relying on purchased
allowances instead).\291\ While the EPA has provided analysis
indicating that, on average, sources operate their controls more
effectively on high electric demand days, it has also identified cases
where units fail to optimize their controls on these days. Downwind
states have suggested this type of reduced pollution control
performance has occurred on the day and preceding day of an ozone
exceedance.\292\ \293\ While the EPA had previously provided analysis
focusing on the year of initial program implementation, when allowance
prices were high (i.e., 2017 for the CSAPR Update), to demonstrate that
on average, sources operate their controls more effectively on high
electric demand days, even in that case it had identified situations
where particular units failed to optimize their controls on these days.
In later years, when allowance prices had fallen, more sources,
including some identified by commenters, had idled or reduced the
effectiveness of their controls. Such an outcome undermined the ongoing
achievement of emissions rate performance consistent with the control
strategies identified in the CSAPR Update to eliminate significant
contribution to nonattainment and interference with maintenance,
despite the fact that the mass-based budgets were being met.
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    \291\ The price of allowances in CSAPR Update states started at
levels near $800 per ton in 2017 but declined to less than $100 per
ton by 2019 and were less than $70 per ton in July 2020 (data from
S&P Global Market Intelligence).
    \292\ 86 FR 23117.
    \293\ See EPA-HQ-OAR-2020-0272-0094 (``[This] is demonstrated
through examination of Maryland's ozone design value days for June
26th-28th, 2019. On those days, Maryland recorded 8-hour ozone
levels of 75, 85 and 83 ppb at the Edgewood monitor. Maryland
Department of the Environment evaluated the daily NOX
emission rate for units in Pennsylvania that were found to influence
the design values on the 3 exceedance days (and 1 day prior to the
exceedance) against the past-best ozone season 30-day rolling
average optimized NOX rate (which tends to be higher than
the absolute lowest seasonal average rate).'').
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    In the Revised CSAPR Update, the EPA took steps to better address
the rapid evolution of the EGU fleet, specifically by setting updated
emissions budgets for individual future

years though 2024 that reflect future EGU fleet changes known with
reasonable certainty at the time of the rulemaking. Some commenters in
that rulemaking requested that the EPA also update the year-by-year
emissions budgets to reflect future fleet changes that might become
known after the time of the rulemaking, but the EPA declined to do so,
in part because no methodology for making future emissions budget
adjustments in response to post-rulemaking data had been included in
the proposal for the rulemaking.
    Based on information available as of December 2022, it appears that
the emissions budgets set for the first two control periods covered by
the Revised CSAPR Update generally succeeded at creating incentives to
operate emissions controls under the Group 3 trading program for those
control periods. However, the EPA recognizes that the lack of emissions
budget adjustments after 2024 in conjunction with industry trends
toward more efficient and cleaner resources will likely lead to a
surplus of allowances after the adjustments end. This prospect for the
existing Group 3 trading program should be avoided by the changes being
made in this rulemaking. In this rulemaking, besides establishing new
preset emissions budgets for the 2023 through 2029 control periods, the
EPA is also extending the Group 3 trading program budget-setting
methodology used in the Revised CSAPR Update to routinely calculate
dynamic emissions budgets for each future control period from 2026 on,
to be published in the year before that control period, with each
dynamic emissions budget generally reflecting the latest available
information on the composition and utilization of the EGU fleet at the
time that dynamic emissions budget is determined. For the control
periods in 2026 through 2029, each state's final emissions budget will
be the preset budget determined for the state in this rulemaking except
in instances when the dynamic budget determined for the state (and
published approximately one year before the control period using the
dynamic budget-setting methodology) is higher. For control periods in
2030 and thereafter, the emissions budgets will be the amounts
determined for each state in the year before the control period using
the dynamic budget-setting methodology.
    The current budget-setting methodology established in the Revised
CSAPR Update and the revisions being made to that methodology are
discussed in detail in section VI.B.4 of this document and the Ozone
Transport Policy Analysis Final Rule TSD. To summarize here, the
methodology used to determine the preset budgets largely follows the
Revised CSAPR Update's emissions budget-setting methodology, which
included three primary steps: (1) establishment of a baseline inventory
of EGUs adjusted for known retirements and new units, with heat input
and emissions rate data for each EGU in the inventory based on recent
historical data; (2) adjustment of the baseline data to reflect assumed
emissions rate changes resulting from known new controls, known gas
conversions, and implementation of the emissions control strategies
used to determine states' good neighbor obligations; and (3)
application of an increment or decrement to reflect the effect on
emissions from projected generation shifting among the units in a state
at the emissions reduction cost associated with the selected emissions
control strategies. In this rulemaking, the EPA has determined the
preset state emissions budgets for the control periods from 2023
through 2029 by using the Revised CSAPR Update's budget-setting
methodology, except that the step of that methodology intended to
reflect the effects of generation shifting has been eliminated.
    The dynamic budget-setting methodology used to determine dynamic
state emissions budgets in the year before each control period starting
with the 2026 control period is set forth in the revised Group 3
trading program regulations at 40 CFR 97.1010(a). This methodology
modifies the Revised CSAPR Update's budget-setting methodology in two
ways. First, the baseline EGU inventory and heat input data, but not
the emissions rate data, will be updated for each control period using
the most recent available reported data in combination with reported
data from the four immediately preceding years. For example, in early
2025, using the final data reported for 2020 through 2024, the EPA will
update the baseline inventory and heat input data used to determine
dynamic state emissions budgets for the 2026 control period.\294\
Second, the EPA will not apply an increment or decrement to any state
emissions budget for projected generation shifting associated with
implementation of the selected control strategies, because any such
shifting should already be reflected in the reported heat input data
used to update the baseline.
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    \294\ As discussed in section VI.B.4 of this document, the
state-level data used to determine the overall state-level heat
input for computing a state's dynamic budget will be a three-year
average (e.g., 2022-2024 state-level data will be used in 2025 to
set the 2026 dynamic budgets). The unit-level data used to determine
individual units' shares of the state-level heat input in the
computations will be the average of the three highest non-zero heat
input amounts for the respective units over the most recent five
years (e.g., 2020-2024 unit-level data will be used in 2025 to set
the 2026 dynamic budgets).
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    The EPA believes that the revisions to the emissions budget-setting
process will substantially improve the ability of the emissions budgets
to keep pace with changes in the composition and utilization of the EGU
fleet. The dynamic budget-setting methodology will account for the
electric power sector's overall trends toward more efficient and
cleaner resources, both of which tend to decrease total heat input at
affected EGUs, and through 2029 the preset budgets established in the
rule will also account for these factors to the extent known. The
dynamic budget-setting methodology will also account for other factors
that could lead to increased heat input in some states, such as
generation shifting from other states or increases in electricity
demand caused by rising electrification. The dynamic budget-setting
procedure is specified in this final rule's trading program regulations
and the computations, which are straightforward, can be performed in a
spreadsheet to deliver reliable results. The EPA will provide public
notice of the preliminary calculations and the data used by March 1 of
the year preceding the control period and will provide an opportunity
for submission of any objections to the data and preliminary
calculations before finalizing the dynamic budgets for each control
period by May 1 of the year before the control period to which those
dynamic budgets apply. Thus, for example, sources and other
stakeholders will have certainty by May 1, 2025, of the dynamic
emissions budgets that will be calculated for the 2026 control period
that starts May 1, 2026. Moreover, as of the issuance of this final
rule, stakeholders will know the state-level preset emissions budgets
for the 2026-2029 control periods, which serve as floors that will only
be supplanted by dynamic budgets calculated for those control periods
if such a dynamic budget yields a higher amount of tons than the
corresponding preset budget established in this action.
    It bears emphasis that the annually updated information used in the
dynamic budget-setting computations will concern only the composition
and utilization of the EGU fleet and not the emissions rate data also
used in those computations. The dynamically determined emissions budget
computations for all years will reflect only the specific emissions
control

strategies used to determine states' good neighbor obligations as
determined in this rulemaking, along with fixed historical emissions
rates for units that are not assumed to implement additional control
strategies, thereby ensuring that the annual updates will eliminate
emissions as determined to be required under the good neighbor
provision. The stringency of the emissions budgets will simply reflect
the stringency of the emissions control strategies determined in the
Step 3 multifactor analysis and will do so more consistently over time
than the EPA's previous approach of computing emissions budgets for all
future control periods at the time of the rulemaking.
    The rule's revisions relating to state emissions budgets and the
budget-setting process generally follow the proposal except for two
changes we are making in response to comments, specifically: we will
use historical data from multiple years rather than a single year in
the dynamic budget-setting process, and we are establishing preset
emissions budgets for the 2026-2029 control periods such that the
dynamic budgets for those control periods will only be imposed where
they exceed the corresponding preset budgets finalized in this rule.
The rationale for these changes is discussed later in this section as
part of the responses to the relevant comments. Details of the final
budget-setting methodology and responses to additional comments are
discussed further in section VI.B.4 of this document.
    The final rule's provisions relating to the determination of state-
level variability limits and assurance levels and unit-level allowance
allocations are coordinated with the budget-setting methodology. These
provisions generally follow the proposal except that the change to the
methodology for determining variability limits is implemented starting
with the 2023 control period instead of the 2025 control period and the
final methodology for determining unit-level allocations of allowances
to coal-fired units considers the controlled emissions rate assumptions
applicable to the same units in the budget-setting process. Details of
these provisions, including the rationales for the changes from
proposal, are discussed in sections VI.B.5 and VI.B.9, respectively.
ii. Allowance Bank Recalibration
    Besides the levels of the emissions budgets, the second design
element of the trading program structure that affects the supply of
allowances in each control period, and that consequently also affects
the ability of a trading program to maintain the rule's selected
control stringency as the EGU fleet evolves over time, is the set of
rules concerning the carryover of unused allowances for use in future
control periods as banked allowances. As noted previously, trading and
banking of allowances in the CSAPR trading programs can serve a variety
of purposes: continuously incentivizing sources to reduce their
emissions even when they already hold sufficient allowances to cover
their expected emissions for a control period, facilitating compliance
cost minimization, accommodating necessary operational flexibility, and
promoting allowance market liquidity. All of these purposes are
advanced by rules that allow sources to trade allowances freely (both
with other sources and with non-source entities such as brokers). All
of these purposes are also advanced by rules that allow unused
allowances to be carried over for possible use in future control
periods, thereby preserving a value for the unused allowances. However,
while the EPA considers it generally advantageous to place as few
restrictions on the trading of allowances as possible,\295\
unrestricted banking of allowances has a potentially significant
disadvantage offsetting its advantages, namely that it allows what
might otherwise be temporary surpluses of allowances in some individual
control periods to accumulate into a long-term allowance surplus that
reduces allowance prices and weakens the trading program's incentives
to control emissions. With weakened incentives, some operators would be
more likely to choose not to continuously operate and optimize their
emissions controls, imperiling the ongoing achievement of emissions
rate performance consistent with the control strategies defined as
eliminating significant contribution to nonattainment and interference
with maintenance.
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    \295\ The advantages of trading programs discussed earlier in
this section--providing continuous emissions reduction incentives,
facilitating compliance cost minimization, and supporting
operational flexibility--depend on the existence of a marketplace
for purchasing and selling allowances. Broader marketplaces
generally provide greater market liquidity and therefore make
trading programs better at providing these advantages. The EPA
recognizes that unrestricted use of net purchased allowances--
meaning quantities of purchased allowances that exceed the
quantities of allowances sold--by a source or group of sources as an
alternative to making emissions reductions can interfere with the
achievement of the desired environmental outcome. Therefore, section
VI.B.1.c of this document discusses the enhancements to the Group 3
trading program that the EPA is making in this rulemaking to reduce
reliance on net purchased allowances by incentivizing or requiring
better environmental performance at individual EGUs. However, the
concern arises from the use of an excessive quantity of net
purchased allowances for a particular purpose, not from the
existence of a marketplace where allowances may be freely bought and
sold.
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    As discussed in detail in section VI.B.6 of this rule, the EPA is
revising the Group 3 trading program by adding provisions that
establish a routine recalibration process for banked allowances that
will be carried out in August 2024 and each subsequent August, after
the compliance deadline for the control period in the previous year. In