each recalibration, the EPA will reset the total quantity of banked
allowances for the Group 3 trading program (``Group 3 allowances'')
held in all Allowance Management System accounts to a level computed as
a target percentage of the sum of the state emissions budgets for the
current control period. The target percentage will be 21 percent for
the 2024-2029 control periods and 10.5 percent for control periods in
2030 and later years. The recalibration procedure entails identifying
the ratio of the target bank amount to the total quantity of banked
allowances held in all accounts before the recalibration and then, if
the ratio is less than 1.0, multiplying the quantity of banked
allowances held in each account by the ratio to identify the
appropriate recalibrated amount for the account (rounded to the nearest
allowance), and deducting any allowances in the account exceeding the
recalibrated amount.
    As noted previously, recalibration of the bank for each control
period will be carried out in August of that control period. This
timing will accommodate the process of deducting allowances for
compliance for the previous control period, which cannot be completed
before sources' June 1 compliance deadline for the previous control
period, and will then provide approximately two additional months for
sources to engage in any desired allowance transactions before
recalibration occurs. However, data that can be used to estimate the
bank recalibration ratio for each control period will be available
shortly after the end of the previous control period, and the EPA will
use these data to make information on the estimated bank recalibration
ratio for each control period publicly available no later than March 1
of the year of that control period, thereby facilitating the ability of
affected EGUs to anticipate their ultimate holdings of recalibrated
banked allowances to inform their compliance planning for that control
season. Affected EGUs will also have several months following the
completed bank recalibration in August to transact allowances with
other parties as needed

before the allowance transfer deadline of June 1 of the following year.
    The EPA believes this revision to the Group 3 trading program's
banking provisions establishing an annual bank recalibration process
will complement the revisions to the budget-setting process by
preventing any surplus of allowances created in one control period from
diminishing the intended stringency and resulting emissions reductions
of the emissions budgets for subsequent control periods.
    The calibration procedure will not erase the value of unused
allowances for the holder, because the larger the quantity of banked
allowances that is held in a given account before each recalibration,
the larger the quantity of banked allowances that will be left in the
account after the recalibration for possible sale or use in meeting
future compliance requirements. Because the banked allowances will
always have value, the opportunity to bank allowances will continue to
advance the purposes served by otherwise unrestricted banking as
described previously. Opportunities to bank unused allowances can serve
all these same purposes whether a banked allowance is of partial value
(if the bank needs recalibrating to its target level) or is of full
value compared to a newly issued allowance for the next control period.
    The final rule's provisions relating to bank recalibration
generally follow the proposal except that, in response to comments, the
target percentage used to determine the recalibrated bank levels for
the 2024-2029 control periods is being set at 21 percent instead of
10.5 percent. The rationale for this change is discussed later in this
section as part of the responses to the relevant comments. Details of
the bank recalibration provisions are discussed further in section
VI.B.6 of this rule.
c. Enhancements To Improve Emissions Performance at Individual Units
    The second set of concerns about the structure of the current CSAPR
trading programs relates to the general absence of source- or unit-
specific emissions reduction requirements. Without such requirements,
the programs affect individual sources' emissions performance only to
the extent that the incentives created by allowance prices are high
enough relative to the costs of the sources' various emissions control
opportunities. In circumstances where the incentives to control
emissions are insufficient, some individual sources even idle existing
emissions controls. 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 EPA intends that the trading program enhancements described in
section VI.B.1.b of this rule will improve the Group 3 trading
program's ability to sustain emissions control incentives over time
such that needed emissions performance will be achieved by all
participating units without the need for additional requirements to be
imposed at the level of individual units. However, because obtaining
needed emissions performance at individual units is also important to
the elimination of significant contribution in keeping with the EPA's
Step 3 determinations, the EPA is supplementing the previously
discussed enhancements with two other new sets of provisions that will
apply to certain individual units within the larger context of the
Group 3 trading program. The allowance price will continue to be the
most important driver of good environmental performance for most units,
but the proposed unit-level requirements will be important supplemental
drivers of performance and will offer additional assurance that
significant contribution is eliminated on a daily basis during the
ozone season by more continuous operation of existing pollution
controls.
i. Unit-Specific Backstop Daily Emissions Rates
    The first of the trading program enhancements intended to improve
emissions performance at the level of individual units is the addition
of backstop daily NOX emissions rate provisions that will
apply to large coal-fired EGUs, defined for this purpose as units
serving electricity generators with nameplate capacities equal to or
greater than 100 MW and combusting any coal during the control period
in question. Starting with the 2024 control period, a 3-for-1 allowance
surrender ratio (instead of the usual 1-for-1 surrender ratio) will
apply to emissions during the ozone season from any large coal-fired
EGU with existing SCR controls exceeding by more than 50 tons a daily
average NOX emissions rate of 0.14 lb/mmBtu. The additional
allowance surrender requirement will be integrated into the trading
program as a new component in the calculation of each unit's primary
emissions limitation, such that the additional allowances will have to
be surrendered by the same compliance deadline of June 1 after each
control period. The amount of additional allowances to be surrendered
will be determined by computing, for each day of the control period,
any excess of the unit's reported emissions (in pounds) over the
emissions that would have resulted from combusting that day's actual
heat input at an average daily emissions rate of 0.14 lb/mmBtu, summing
the daily amounts, converting from pounds to tons, computing the amount
of any excess over 50 tons, and multiplying by two. Starting with the
second control period in which newly installed SCR controls are
operational, but not later than the 2030 control period, the 3-for-1
surrender ratio will apply in the same way to all large coal-fired EGUs
except circulating fluidized bed units, consistent with EPA's
determination that a control stringency reflecting installation and
operation of SCR controls on all such large coal-fired EGUs is
appropriate to address states' good neighbor obligations with respect
to the 2015 ozone NAAQS.
    In prior rules addressing interstate transport of air pollution,
stakeholders have noted that while seasonal cap-and-trade programs are
effective at lowering ozone and ozone-forming precursors across the
ozone season, attainment of the standard is measured on key days and
therefore it is necessary to ensure that the rule requires emissions
reductions not just seasonally, but also on those key days.\296\ They
have noted that while the trading programs established under the
NOX SIP Call, CAIR, and CSAPR have all been successful in
ensuring seasonal reductions, states must remain below daily peak
levels, not just seasonal levels, to reach attainment. These downwind
stakeholder communities have suggested that operating pollution
controls on the highest ozone days (and immediately preceding days)
during the ozone season is of critical importance. The EPA has analyzed
hourly emissions data reported in prior cap-and-trade programs and has
identified instances of sources that did not operate SCR controls for
substantial portions of recent ozone seasons. These instances are
discussed in section V.B.1.a of this document and in the EGU
NOX Mitigation Strategies Final Rule TSD in the docket.
While the EPA has in prior ozone transport actions not found sufficient
evidence of emissions control idling or non-optimization to take the
step of building in enhancements to the trading program to ensure unit-
level control operation, our review of subsequent-year data for prior
programs suggests that the non-optimization

behavior increases in the latter years of a program. Applied to this
context (e.g., a rule providing a full remedy to interstate transport
for the more protective 2015 ozone NAAQS and an extended period of
expected persistence of receptors), this data suggests this
deterioration in performance could become prevalent and problematic in
future years if not addressed. Rather than allow for the potential of
continued deterioration in the environmental performance of our trading
programs, the EPA finds the evidence of declining SCR performance in
later years of trading programs sufficient to justify prophylactic
measures in this rule to ensure the emissions control strategy selected
at Step 3 is indeed implemented at Step 4. Thus, particularly in the
context of the more protective 2015 ozone NAAQS combined with the full
remedy nature of this action and the extended timeframe for which
upwind contribution to downwind nonattainment is projected to persist,
the EPA agrees with these stakeholders that the set of measures
promulgated in this rulemaking to implement the control stringency
levels found necessary to address states' good neighbor obligations
should include measures designed to more effectively ensure that
individual units operate their emissions controls routinely throughout
the ozone season, thereby also ensuring that the controls are planned
to be in operation on the particular days that turn out to be most
critical for ozone formation and for attainment of the NAAQS. Routine
operation of emissions controls will also provide relief to
overburdened communities downwind of any units that might otherwise
have chosen not to operate their controls. In the Ozone Transport
Policy Analysis Final Rule TSD, the EPA conducted a screening analysis
that found nearly all of the EGUs included in this analysis are located
within a 24-hour transport distance of many areas with potential EJ
concerns. Thus, the EPA is adopting backstop daily rate limits at the
individual unit level because it is appropriate and justified in the
context of eliminating significant contribution under CAA section
110(a)(2)(D)(i)(I). While the former justification is sufficient to
finalize this enhancement to the trading program, we also anticipate
that this measure will deliver public health and environmental benefits
to overburdened communities (as well as the rest of the
population).\297\
---------------------------------------------------------------------------

    \296\ E.g., comments of Maryland Department of the Environment
on the proposed Revised CSAPR Update at 3, EPA-HQ-OAR-2020-0272-
0094.
    \297\ Nonetheless, the environmental justice exposure analysis
indicates that preexisting disparities among demographic groups are
likely to persist even under this final rule. See section VII of
this document.
---------------------------------------------------------------------------

    We considered whether, as some commenters suggested, it would be
appropriate to simply implement unit-specific daily emissions
limitation at all of the large, coal-fired EGUs, and forego an
emissions trading approach altogether. While this is within the EPA's
statutory authority, see CAA section 110(a)(2)(A) and 302(y), and
merits careful consideration, we are declining to do so in this action
but intend to closely monitor EGU emissions performance in response to
the trading program finalized here. The purpose of establishing a
backstop daily NOX emissions rate and implementing it
through additional allowance surrender requirements instead of as an
enforceable emissions limitation is to incentivize improved emissions
performance at the individual unit level while continuing to preserve,
to the extent possible, the advantages that the flexibility of a
trading program brings to the electric power sector. As discussed in
section VI.B.7 of this document, under the EPA's historical trading
programs without the enhancements made in this rulemaking, some
individual coal-fired units with SCR controls have chosen to operate
the controls at lower removal efficiencies than in past ozone seasons
or even to idle the controls for entire ozone seasons. In addition,
some SCR-equipped units have chosen to routinely cycle their emissions
controls off at lower load levels, such as while operating overnight,
instead of operating the controls, upgrading the units to enable the
controls to be operated under those conditions, or not operating the
units under those conditions. Collectively, this non-optimization of
existing controls has a detrimental impact on problematic receptors.
Table V.D.1-1 shows the expected air quality benefit from control
optimization (totaling nearly 1.6 ppb change across all
receptors).\298\
---------------------------------------------------------------------------

    \298\ As illustrated in the table and underlying data, a small
portion of this ppb impact is attributable to combustion control
upgrade potential.
---------------------------------------------------------------------------

    The EPA has identified sources of interstate ozone pollution such
as the New Madrid and Conemaugh plants (in Missouri and Pennsylvania,
respectively) whose SCR controls were not operating for substantial
portions of recent ozone seasons. The data included in Appendix G of
the Ozone Transport Policy Analysis Final Rule TSD, available in the
docket for this rulemaking, demonstrate that these units have operated
their SCRs better and more consistently during years with higher
NOX allowance prices. Downwind stakeholders have noted that
some of the higher emissions rates (specifically in the case of
Conemaugh Unit 2 in 2019) have occurred on the day of and the preceding
day of an ozone exceedance in bordering states.\299\
---------------------------------------------------------------------------

    \299\ EPA-HQ-OAR-2020-0272-0094.
---------------------------------------------------------------------------

    The EPA believes that the design of the daily emissions rate
provisions will be effective in addressing these types of high-emitting
behavior by significantly raising the cost of planned operator
decisions that substantially compromise environmental performance. At
the same time, the provision will not unduly penalize an occasional
unplanned exceedance, because the amount of additional allowances that
would have to be surrendered to address a single day's exceedance would
be much smaller than the amount that would have to be surrendered to
address planned poor performance sustained over longer time periods.
Moreover, the EPA believes that the inclusion of a 50-ton threshold
before the increased surrender requirements would apply is sufficient
to address virtually all instances where a unit's emissions would
exceed the 0.14 lb/mmBtu daily rate because of unavoidable startup or
shutdown conditions during which SCR equipment cannot be operated,
thereby ensuring that the provision will not penalize units for
emissions that are beyond their reasonable control.
    The EPA is applying the daily emissions rate provisions to large
coal-fired EGUs, and not to other types of units, for reasons that are
consistent with EPA's determinations regarding the appropriate control
stringency for EGUs to address states' good neighbor obligations with
respect to the 2015 ozone NAAQS. Installation and operation of SCR
controls is well-established as a common practice for the best control
of NOX emissions from coal-fired EGUs, as evidenced by the
fact that the technology is already installed on more than 60 percent
of the sector's total coal-fired capacity and installed on nearly 100
percent of the coal fired boilers in the top quartile of emissions rate
performance. In the context of addressing good neighbor obligations
with respect to the 2015 ozone NAAQS, the EPA is determining that a
control stringency reflecting universal installation and operation of
SCR technology at large coal-fired EGUs (other than circulating
fluidized bed units) is appropriate at Step 3. Finally, where SCR
controls are installed on such units, optimized operation of those
controls is an extremely cost-effective method of achieving
NOX emissions

reductions. The EPA believes these considerations support establishment
of the daily emissions rate provisions on a universal basis for large
coal-fired EGUs, with near-term application of the provisions for units
that already have the controls installed and deferred application for
other units, as discussed later.
    With regard to gas-fired steam EGUs, SCR controls are nowhere near
as prevalent, and while the EPA is including some SCR controls at gas-
fired steam units in the selected control stringency at Step 3, the EPA
is not including universal SCR controls at gas-fired steam units.
Because the EPA is not determining that universal installation and
operation of SCR controls at gas-fired steam EGUs is part of the
selected control stringency, in order not to constrain the power
sector's flexibility to choose which particular gas-fired steam EGUs
are the preferred candidates for achieving the required emissions
reductions, the EPA is not applying the daily emissions rate provisions
to large gas-fired steam EGUs. Focusing the backstop daily emissions
rates on coal-fired units is also consistent with stakeholder input
which has emphasized the need for short-term rate limits at coal units
given their relatively higher emissions rates.
    The EPA developed the level of the daily average NOX
emissions rate--0.14 lb/mmBtu--through analysis of historical data, as
described in section VI.B.7 of this document. A rate of 0.14 lb/mmBtu
represents the daily average NOX emissions rate that has
been demonstrated to be achievable on approximately 95 percent of days
covering more than 99 percent of total ozone-season NOX
emissions by coal-fired units with SCR controls that are achieving a
seasonal NOX average emissions rate of 0.08 lb/mmBtu (or
less), which is the seasonal NOX emissions rate that the EPA
has determined is indicative of optimized SCR performance by units with
existing SCR controls.
    As noted previously, the daily average emissions rate provisions
will apply beginning in the 2024 control period for large coal-fired
units with installed SCR controls, one control period later than
optimization of those controls will be reflected in the state emissions
budgets under this rule. For these units, not applying the daily
average rate provisions until 2024 serves three purposes. First, it
provides all the units with a preparatory interval to focus attention
on improving not only the average performance of their SCR controls but
also the day-to-day consistency of performance before they will be held
to increased allowance-surrender consequences for exceeding the daily
rate. Second, it provides the subset of units that exhaust to common
stacks with other units that currently lack SCR controls an opportunity
to exercise the option to install and certify any additional monitoring
systems needed to monitor the individual units' NOX
emissions rates separately; otherwise, the daily emissions rate
provisions will apply to the SCR-equipped units based on the combined
NOX emissions rates measured in the common stacks. Third, it
provides all units sufficient time to update the data handling software
in their existing monitoring systems as needed to compute and report
the additional hourly and daily data values needed for implementation
of the provisions.\300\
---------------------------------------------------------------------------

    \300\ For further discussion of emissions monitoring and
reporting requirements under the rule, including the options
available to plants where SCR-equipped and non-SCR-equipped coal-
fired units exhaust to common stacks, see section VI.B.10 of this
document.
---------------------------------------------------------------------------

    With respect to the units without existing SCR controls, the daily
average emissions rate provisions will apply starting with the second
control period in which newly installed SCR controls are operational at
the unit, but not later than the 2030 control period. This
implementation timing represents a change from the proposal, under
which the daily average emissions rate provisions would have applied to
units without existing SCR starting in the 2027 control period.
Commenters noted that for many units without SCR, replacement of the
unit within a few years, and shifting of some generation to cleaner
units in the interim, would be a more economic compliance strategy than
installation of new SCR controls. The commenters further noted that
implementation of the daily average emissions rate for these units
starting in 2027 would strongly disadvantage such an alternative
strategy if the capacity replacement and any associated transmission
improvements could not be implemented by 2027. In light of these
comments, the EPA has determined that as long as the emissions budgets
determined in this rule to eliminate significant contribution are still
being implemented as expeditiously as practicable--which in this
instance the EPA has determined requires phasing in the required
emissions reductions by 2027--it is reasonable to defer implementation
of the daily average emissions rate provisions to 2030 for units
without SCR to allow temporarily greater flexibility to pursue
compliance strategies other than installation of new controls. This lag
is permissible consistent with the obligation to eliminate significant
contribution for reasons that are further discussed in response to
comments in section VI.B.1.d of this document. However, for any units
that choose a compliance strategy of installing new SCR controls before
2030, the daily average emissions rate provisions would apply in the
second control period of operation. Specification of the second control
period rather than the first control period provides the unit operators
with an opportunity to gain operational experience with the new
equipment before the units will be held to increased allowance-
surrender consequences for exceeding the daily rate.
    The unit-specific daily emissions rate provisions are being
finalized as proposed except for two changes noted in the previous
summary: the exclusion from extra allowance surrender requirements of a
unit's first 50 tons of emissions in a control period exceeding the
backstop daily rate, and the revision of the starting date for
implementation of the requirement for units without existing SCR
controls to 2030 or the second control period of SCR operation, if
earlier. The rationale for these changes is further discussed in the
responses to comments later in this section. Additional details of the
unit-specific daily emissions rate provisions are discussed in section
VI.B.7 of this document.
ii. Unit-Specific Emissions Limitations Contingent on Assurance Level
Exceedances
    The second of the trading program enhancements intended to improve
emissions performance at the level of individual units is the addition
of unit-specific secondary emissions limitations for units with post-
combustion controls starting with the 2024 control period. The
secondary emissions limitations will be determined on a unit-specific
basis according to each unit's individual performance but will apply to
a given unit only under the circumstance where a state's assurance
level for a control period has been exceeded, the unit is included in a
group of units to which responsibility for the exceedance has been
apportioned under the program's assurance provisions, and the unit
operated during at least 10 percent of the hours in the control period.
Where these conditions for application of a secondary emissions
limitation to a given unit for a given control period are met, the
unit's secondary emissions limitation consists of a prohibition on
NOX emissions during the control

period that exceed by more than 50 tons the NOX emissions
that would have resulted if the unit had achieved an average emissions
rate for the control period equal to the higher of 0.10 lb/mmBtu or 125
percent of the unit's lowest average emissions rate for any previous
control period under any CSAPR seasonal NOX trading program
during which the unit operated for at least 10 percent of the hours.
    The secondary emissions limitation is in addition to, not in lieu
of, the primary emissions limitation applicable to each source, which
continues to take the form of a requirement to surrender a quantity of
allowances based on the source's emissions, and also in addition to the
existing assurance provisions, which similarly continue to take the
form of a requirement for the owners and operators of some sources to
surrender additional allowances when a state's assurance level is
exceeded. In contrast to these other requirements, the unit-specific
secondary emissions limitation takes the form of a prohibition on
emissions over a specified level, such that any emissions by a unit
exceeding its secondary emissions limitation would be subject to
potential administrative or judicial action and subject to penalties
and other forms of relief under the CAA's enforcement authorities. The
reason for establishing this form of limitation is that experience
under the existing CSAPR trading programs has shown that, in some
circumstances, the existing assurance provisions have been insufficient
to prevent exceedances of a state's assurance level for a control
period even when the likelihood of an exceedance has been foreseeable
and the exceedance could have been readily avoided if certain units had
operated with emissions rates closer to the lower emissions rates
achieved in past control periods. The assurance levels exist to ensure
that emissions from each state that contribute significantly to
nonattainment or interfere with maintenance of a NAAQS in another state
are prohibited. North Carolina v. EPA, 531 F.3d 896, 906-08 (D.C. Cir.
2008). The EPA's programs to eliminate significant contribution must
therefore achieve this prohibition, and the evidence of foreseeable and
avoidable exceedances of the assurance levels demonstrates that EPA's
existing approach has not been sufficient to accomplish this.
    The purpose of including assurance levels higher than the state
emissions budgets in the CSAPR trading programs is to provide
flexibility to accommodate operational variability attributable to
factors that are largely outside of an individual owner's or operator's
control, not to allow owners and operators to plan to emit at emissions
rates that could be anticipated to cause a state's total emissions to
exceed the state's emissions budget or assurance level. Conduct leading
to a foreseeable, readily avoidable exceedance of a state's assurance
level cannot be reconciled with the statutory mandate of the CAA's good
neighbor provision that emissions ``within the state'' significantly
contributing to nonattainment or interfering with maintenance of a
NAAQS in another state must be prohibited. Because the current CSAPR
regulations do not expressly prohibit such conduct and have proven
insufficient to deter it in some circumstances, the EPA is correcting
the regulatory deficiency in the Group 3 trading program by adding
secondary emissions limitations that cannot be complied with through
the use of allowances.
    The EPA notes that although the purpose of the secondary emissions
limitations is to strengthen the assurance provisions, which apply on a
statewide, seasonal basis, the unit-specific structure of the new
limitations will strengthen the incentives for individual units with
post-combustion controls to maintain their emissions performance at
levels consistent with their previously demonstrated capabilities. The
new limitations will strengthen the incentives to operate and optimize
the controls continuously, which can be expected to reduce some
individual units' emissions rates throughout the ozone season,
including on the days that turn out to be most critical for downwind
ozone levels. Better emissions performance on average across the ozone
season by individual units likely will also help address impacts of
pollution on overburdened communities downwind from some such units.
See Ozone Transport Policy Analysis Final Rule TSD, Section E.
    The unit-specific secondary emissions limitations are being
finalized as proposed except that the limitations will apply only to
units with post-combustion controls. The rationale for this change, and
additional details regarding the provisions, are discussed in section
VI.B.8 of this document.
d. Responses to General Comments on the Revisions to the Group 3
Trading Program
    This section summarizes and provides the EPA's responses to
overarching comments received on the EPA's proposal to implement the
emissions reductions required from EGUs under this rule through
expansion and enhancement of the Group 3 trading program originally
established in the Revised CSAPR Update, particularly comments on
electric system reliability. Responses to comments about individual
aspects of the enhanced trading program are addressed in the respective
subsections of this section in which those aspects are discussed.
Responses to comments concerning alleged overcontrol and the EPA's
legal authority are in sections V.D. and III. Comments not addressed in
this document are addressed in the separate RTC document available in
the docket for this action.
    Comment: Some commenters, including EGU owners, states, and several
RTOs, expressed concern that the requirements for EGUs as formulated in
the proposal could lead to a degradation in the reliability of the
electric system. As background, some of these commenters noted that the
power sector is currently undergoing rapid change, with older and less
economic fossil-fuel-fired steam generating units retiring while the
majority of the new capacity being added consists of wind and solar
capacity. They noted that fossil-fuel-fired generating capacity
provides reliability benefits not necessarily provided by other types
of generating capacity, including not only the ability to generate
electricity in the absence of wind or sunlight, but also inertia,
ramping capability, voltage support, and frequency response. Commenters
stated that past EGU retirements and the pace of change in the
generating capacity mix have already been stressing the electric system
in some regions, and that the forecasted risk of events where the
electric system would be unable to fully meet load is rising.
    For purposes of their comments, these commenters generally assumed
that the rule would lead to additional retirements of fossil-fuel-fired
generating capacity beyond the retirements that EGU owners have already
planned and announced. Some of the commenters also suggested that
remaining fossil-fuel-fired generators would be unwilling to operate
when needed because allowances might be unavailable for purchase or too
costly. In the context of an already-stressed electric system, the
commenters predicted that these assumed consequences of the rule would
threaten resource adequacy and result in degraded electric reliability.
To support their assumptions concerning additional retirements, some of
the commenters pointed to projections of incremental generating
capacity retirements

included in the results of modeling performed by the EPA to analyze the
costs and benefits of the proposed rule. Some commenters indicated that
they expected EGU owners to be interested in retiring and replacing
uncontrolled units as of the date of implementation of the backstop
daily rate requirement on uncontrolled units, and expressed concern
that the proposal to implement that requirement as of the 2027 control
period did not allow sufficient time for planning and implementation of
all the necessary generation and transmission investments to make this
a viable compliance strategy; for these commenters, 2027 and the
immediately following years were the period of greatest concern. Some
commenters appear simply to have assumed that owners of units not
already equipped with SCR controls would choose to retire the units as
of the ozone season in which the units would otherwise become subject
to the backstop daily emissions rate provisions, regardless of whether
replacement investments had been completed.
    Some of the commenters raising concerns about electric system
reliability suggested potential modifications to the proposed rule that
the commenters believed could help address their concerns. The
suggestions included various mechanisms for suspending some or all of
the trading program's requirements for certain EGUs at times when an
RTO or other entity responsible for overseeing a region of the
interconnected electrical grid determines that generation from those
EGUs is needed and the EGUs might not otherwise agree to operate. Other
suggestions focused on ways of providing EGUs with greater confidence
that allowances would be available to cover their incremental emissions
during particular events. A number of commenters used the term
``reliability safety valve,'' in some cases with reference to the types
of suggestions just mentioned and in other cases without details. Some
commenters pointed to the ``safety valve'' provision included in the
Group 2 trading program regulations under the Revised CSAPR Update.
Another commenter pointed to provisions for a ``reliability safety
valve'' included in the Clean Power Plan (80 FR 64662, Oct. 23, 2015).
    In addition to offering critiques and recommendations concerning
the proposed rule's contents, some commenters claimed that the EPA had
failed to conduct sufficient analysis of the potential implications of
the proposed rule on electrical system reliability. These commenters
called on the EPA to consult with RTOs and other entities with
responsibilities relating to electric system reliability and to perform
additional analysis. Some commenters advocated for renewed
consultations and analysis before each planned adjustment to emissions
budgets under the dynamic budget-setting process. Commenters cited the
consultation processes followed during implementation of other EPA
rules, such as the Mercury and Air Toxics Standards (MATS) (77 FR 9304,
Feb. 16, 2012).
    Response: The EPA disagrees with the comments asserting that this
rule would threaten resource adequacy or otherwise degrade electric
system reliability. The emissions reduction requirements for EGUs under
this rule are being implemented through the mechanism of an allowance
trading program. Under the trading program, no EGU is required to cease
operation. The core trading program requirements for a participating
EGU are to monitor and report the unit's NOX emissions for
each ozone season period and to surrender a quantity of allowances
after the end of the ozone season based on the reported emissions. To
address states' obligations under the good neighbor provision, some
units of course will have to take some type of action to reduce
emissions, the actions taken to reduce emissions will generally have
costs, and some EGU owners will conclude that, all else being equal,
retiring a particular EGU and replacing it with cleaner generating
capacity is likely to be a more economic option from the perspective of
the unit's customers and/or owners than making substantial investments
in new emissions controls at the unit. However, the EPA also
understands that before implementing such a retirement decision, the
unit's owner will follow the processes put in place by the relevant
RTO, balancing authority, or state regulator to protect electric system
reliability. These processes typically include analysis of the
potential impacts of the proposed EGU retirement on electrical system
reliability, identification of options for mitigating any identified
adverse impacts, and, in some cases, temporary provision of additional
revenues to support the EGU's continued operation until longer-term
mitigation measures can be put in place. No commenter stated that this
rule would somehow authorize any EGU owner to unilaterally retire a
unit without following these processes, yet some comments nevertheless
assume that is how multiple EGU owners would proceed, in violation of
their obligations to RTOs, balancing authorities, or state regulators
relating to the provision of reliable electric service. Assumptions of
this nature are simply not reasonable. Like many commenters, the EPA
does expect that retirement will be viewed as a more economic
compliance strategy for some EGUs than installing new controls, but the
Agency also expects that any resulting unit retirements will be carried
out through an orderly process in which RTOs, balancing authorities,
and state regulators use their powers to ensure that electric system
reliability is protected. The trading program inherently provides ample
flexibility to allow such an orderly transition to take place. In
addition, as discussed later in this section, the EPA has adopted
several changes in the final rule to increase flexibility specifically
for the early years of the trading program for which commenters have
indicated the greatest concerns about electric system reliability.
    As an initial matter, the EPA notes two fundamental aspects of this
rulemaking which together provide a strong foundation for the Agency's
conclusion that the emissions reductions required from EGUs can be
achieved with no adverse impacts on electric system reliability. First,
there is ample evidence indicating that the required emissions
reductions are feasible. As discussed in section V of this document,
the magnitude and timing of the EGU emissions reductions required by
this action reflect application of technologies that are already in
widespread use, on schedules that are supported by industry experience.
Second, the required emissions reductions are being implemented through
the mechanism of a trading program. The enhanced trading program under
this rule, like the trading programs established by the EPA under prior
rules, provides EGU owners with opportunities to substitute emissions
reductions from sources where achieving reductions is cheaper and
easier for emissions reductions from other sources where achieving
reductions is more costly or difficult. In general, an EGU owner has
options to operate the emissions controls identified by the EPA for
that type of unit (including installation or upgrade of controls where
necessary), operate other types of emissions controls, or adapt the
unit's levels of operation to produce less generation if the unit is a
higher-emitting EGU or more generation if the unit is a lower-emitting
EGU. The backstop daily emissions rate provisions in this rule reduce
the degree of available flexibility relative to the degree of
flexibility in the Agency's

previous trading programs under CAIR and CSAPR but by no means
eliminate it. Moreover, even the backstop rate provisions are
structured as requirements to surrender additional allowances rather
than as hard limits, providing a further element of flexibility No EGU
is required to retire or is prohibited from operating at any time under
this rule. EGUs only need to surrender of the appropriate quantities of
allowances after the end of the control period.\301\
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    \301\ The EPA has prepared a resource adequacy assessment of the
projected impacts of the final rule showing that the projected
impacts of the final rule on power system operations, under
conditions preserving resource adequacy, are modest and manageable.
See Resource Adequacy and Reliability Analysis Final Rule TSD,
available in the docket.
---------------------------------------------------------------------------

    Further, in the large number of comments submitted in this
rulemaking that assert concerns over electric system reliability, no
commenter has cited a single instance where implementation of an EPA
trading program has actually caused an adverse reliability impact.
Indeed, similar claims made in the context of the EPA's prior trading
program rulemakings have shown a considerable gap between rhetoric and
reality. For example, in the litigation over the industry's multiple
motions to stay implementation of CSAPR, claims were made that allowing
the rule to go into effect would compromise reliability. Yet in the
2012 ozone season starting just over 4 months after the rule was
stayed, EGUs covered by CSAPR collectively emitted below the overall
program budgets that the rule would have imposed in that year if the
rule had been allowed to take effect, with most individual states
emitting below their respective state budgets despite CSAPR not being
in effect.\302\ Similarly, in the litigation over the 2015 Clean Power
Plan, assertions that the rule would threaten electric system
reliability were made by some utilities or their representatives, yet
even though the Supreme Court stayed the rule in 2016, the industry
achieved the rule's emissions reduction targets without the rule ever
going into effect. See West Virginia v. EPA, 142 S. Ct. 2587, 2638
(2022) (Kagan, J., dissenting) (``[T]he industry didn't fall short of
the [Clean Power] Plan's goal; rather, the industry exceeded that
target, all on its own. . . . At the time of the repeal . . . `there
[was] likely to be no difference between a world where the [Clean Power
Plan was] implemented and one where it [was] not.' '') (quoting 84 FR
32561). The claims that these rules would have had adverse reliability
impacts were proved to be groundless.
---------------------------------------------------------------------------

    \302\ For a state-by-state comparison, see Appendix G of the
Ozone Transport Policy Analysis Final Rule TSD.
---------------------------------------------------------------------------

    Notwithstanding the long experience confirming the ability of the
EPA's trading programs to obtain emissions reductions from EGUs without
impairing the sector's ability to provide reliable electric service,
the Agency of course does not rely here solely on its experience, but
has carefully reviewed the comments on this topic for any information
that might indicate the appropriateness of modifications to the
enhanced trading program as proposed. In recognition of the important
role that RTOs play in ensuring electric system reliability, and
consistent with the requests of some commenters, the EPA has engaged in
outreach to the RTOs that commented on the proposal to better
understand their comments specifically and the reliability-related
comments of other commenters more generally.\303\ Through these
meetings, the central reliability-related concern was identified as one
of timing. In order for retirement to be a viable compliance strategy
for a unit that cannot be entirely spared until replacement investments
in generation or transmission are completed, it must be possible for
the unit to operate at critical times for a transition period. Like
other stakeholders, the RTOs perceived implementation of the backstop
daily emissions rate provisions on uncontrolled units as materially
strengthening incentives for such units to either install controls or
retire. The RTOs were concerned that the option for a coal-fired unit
without SCR controls to maintain limited operation while surrendering
allowances at a 3-for-1 ratio for all emissions exceeding the backstop
daily rate was one that EGU owners would be reluctant to pursue.
Accordingly, the RTOs expected considerable interest from EGU owners in
retiring and replacing uncontrolled units as of the date of
implementation of the backstop daily rate requirement on uncontrolled
units, and they were concerned that the proposal to implement that
requirement as of the 2027 control period did not allow sufficient time
for planning and implementation of all the necessary generation and
transmission investments to make this a viable compliance strategy. The
RTOs described their concerns as greatest through approximately the
2029 control period.
---------------------------------------------------------------------------

    \303\ The EPA also met with non-RTO balancing authorities that
submitted comments. Memoranda identifying the dates, attendees, and
topics of discussion of these meetings with RTOs and non-RTO
balancing authorities are available in the docket.
---------------------------------------------------------------------------

    The RTOs also described a concern about potentially illiquid
allowance markets. They believed it was possible that some EGUs might
claim an inability to operate at particular times when needed unless
they had confidence that they would be able obtain additional
allowances. The RTOs were particularly concerned that introduction of
dynamic budgeting as proposed would create uncertainty for some EGUs
regarding the quantities of allowances they would have available for
use, particularly given the potentially large year-to-year swings if
budgets were based on historical data from a single year. Some of the
RTOs suggested potential solutions for these issues, principally in the
form of auctions or RTO-administered allocations of allowances from
pools of supplemental allowances, with access to the supplemental
allowances triggered by certain indications of temporary stress on the
electric system.
    In the final rule, the EPA is adopting several changes from the
proposal to help address the reliability-related concerns that were
identified in comments and brought into greater focus by the
consultations with the RTOs. The first change adopted in response to
these comments is that application of the backstop daily NOX
emissions rate to units without existing SCR controls is being deferred
until the 2030 control period, or the second control period in which a
unit operates new SCR controls, if earlier. The purpose of this change
is to address the concerns that application of the backstop daily
NOX emissions rate to EGUs without existing SCR starting in
2027 would provide insufficient time for planning and investments
needed to facilitate unit retirement as a compliance pathway, which
some commenters noted they prefer or have already planned. In
particular, where an EGU owner would prefer to retire and replace an
uncontrolled EGU rather than to install new controls, and in
recognition that reliability-related needs may require some degree of
operation from such units in the period before the investments needed
to replace the unit can be completed, deferral of the backstop daily
emissions rate provisions ensures that the necessary generation can be
provided without being made subject to a 3-for-1 allowance surrender
ratio that might render that compliance strategy uneconomic compared to
the faster but less environmentally beneficial compliance strategy of
installing new controls. The EPA has considered the statutory mandate
that states' good neighbor obligations--

including this action's requirement for large coal-fired EGUs to make
emissions reductions commensurate with good SCR operation--be addressed
as expeditiously as practicable. The EPA has also considered the fact
that in this rule, the backstop daily emissions rate serves as a
supplement to the broader requirement for emissions reductions
commensurate with application of several control technologies at
several types of EGUs, encompassing the extent of emissions reductions
that would be incentivized by the backstop emissions rate requirement.
The EPA views the backstop daily emissions rate as part of the solution
to eliminating significant contribution in that it strongly
incentivizes emissions-control operation throughout each day of the
ozone season. See sections III.B.1.d, VI.B.1.b, VI.B.1.c.i. For that
reason, in general we are finalizing the daily backstop emissions rate
for units that have SCR installed or that install it in the future. It
is only as an exception to that general rule that we defer the backstop
daily emissions rate given the transition period and reliability
concerns identified by commenters. The EPA finds that in this
circumstance, as long as state emissions budgets continue to reflect
the required degree of emissions reductions, deferral of the backstop
rate requirement for uncontrolled units for a transition period can be
justified on the basis of the greater long-term environmental benefits
obtained through facilitating the replacement of these affected EGUs
with cleaner sources of generation. Beginning in the 2030 ozone season,
all coal-fired EGUs identified for SCR retrofit potential in this
action will be subject to the backstop daily emissions rate. Any such
units that remain in operation in that year can and should meet the
backstop daily emissions rate or be subject to the heightened allowance
surrender ratio.
    The second change from the proposal adopted in response to the
reliability-related comments is that the target percentage of the
states' emissions budgets used to recalibrate the target bank level
will be set at the proposed 10.5 percent starting in the 2030 control
period, and for the control periods from 2024 through 2029, a target
percentage of 21 percent will be used instead. The adoption of the
higher target percentage for use through the 2029 control period is
intended to promote greater allowance market liquidity during a period
of relatively rapid fleet transition about which commenters expressed
more focused reliability-related needs. As discussed later in this
section, the EPA expects the introduction of the bank recalibration
process in 2024 generally to boost market liquidity (by discouraging
allowance hoarding) and also considers the target percentage of 10.5
percent set forth in the proposal well supported. Nevertheless, the
Agency agrees with suggestions by commenters that, at least in the
early years of the enhanced trading program, a larger bank would
provide further liquidity and would give program participants greater
confidence that allowances would be available for purchase when needed.
Greater confidence by sources would help address RTOs' concern about
the possibility that some sources could be reluctant to operate if they
were unsure of their ability to procure allowances to cover their
emissions. In finding that this modification from proposal is
appropriate, the EPA has considered the fact that use of a higher
target percentage will not result in the creation of any additional
allowances in any control period, because under the recalibration
provisions, when the total quantity of allowances banked from the
previous control period is less than the bank target level, the
consequence is not that additional allowances are created to raise the
bank to the target level, but simply that no bank adjustment is carried
out. We also note that while including an annual bank recalibration of
any percentage is an enhancement in the trading program from prior
trading programs under the good neighbor provision established in the
CAIR, CSAPR, CSAPR Update, and Revised CSAPR Update rulemakings, it is
not unprecedented; the trading program established under the
NOX SIP Call included ``progressive flow control''
provisions that were designed differently from the bank recalibration
provisions in this rule but had the same purpose and general effect.
    The third change from the proposal adopted in response to the
reliability-related comments is that the EPA is determining preset
state emissions budgets not only for the control periods in 2023 and
2024 as proposed, but also for the control periods in 2025 through
2029. Finalizing preset state emissions budgets through 2029 will
establish predictable amounts for the minimum quantities of allowances
available during the period when commenters have expressed concern that
the reliability-related need for such predictability is greatest.
Moreover, the EPA will also determine state emissions budgets using the
final dynamic budget-setting methodology for the control periods in
2026 through 2029, and for each state and control period, the dynamic
budget to be published in the future will only supplant the preset
budget finalized in this rule for a control period in which that
dynamic budget is higher than the corresponding preset budget. The
reason for using dynamic budgets when they are higher than the
corresponding preset budgets is that the EPA recognizes that evolution
of the EGU fleet will not follow the exact path projected at the time
of the rulemaking, and that by not accounting for certain events, the
preset methodology could result in issuance of smaller quantities of
allowances than the EPA would find consistent with the quantities of
emissions from a well-controlled EGU fleet using the dynamic budget-
setting methodology. Events that could cause preset budgets to
underpredict a state's well-controlled emissions, which are more likely
in years farther in the future from the time of the rulemaking, include
deferral of a large EGU's previously planned retirement date or
increases in electricity demand that outpace the general trend of
lower-emitting or non-emitting generation replacing higher-emitting
generation. After considering the commenters' interest in greater
predictability during the early years of the amended trading program as
well as the need to protect against instances where the preset budgets
could underpredict a state's well-controlled emissions in years farther
from the year of the rulemaking, the EPA finds that the combination of
these factors justifies the approach of using the higher of the two
budgets for the control periods from 2026 through 2029.
    In addition to the changes made in response to reliability-related
comments, several other changes to the proposal being adopted primarily
for other reasons will also help address the factors identified as
reliability-related concerns. Most notably, the EPA is adopting changes
to the dynamic budget computation procedure to incorporate multiple
years of heat input data, which will reduce year-to-year variability in
the budgets determined under that procedure and should to some extent
reduce uncertainty about the quantities of allowances available for use
in instances where a dynamic budget is being used instead of preset
budget. In addition, the adoption of a 50-ton threshold before
application of the 3-for-1 surrender ratio to emissions exceeding the
backstop daily NOX emissions rate should ensure that no unit
incurs the higher surrender ratio solely because of unavoidable
emissions during startup and should help address concerns that some
units might be reluctant to operate because of the associated
emissions-

related costs. Also, the 2026-2027 phase-in of emissions reductions
commensurate with installation of new SCR controls will increase the
quantities of allowances available in the 2026 state emissions budgets
for most states in the trading program.
    To summarize: in light of the strong record supporting the
feasibility of the emissions reductions required from EGUs; the use of
a trading program as the mechanism for achieving those emissions
reductions, with multiple options for achieving compliance and no
requirements to cease operation of any individual EGU at any time; the
established processes of RTOs, other balancing authorities, and state
regulators for managing any EGU retirement requests that do occur in an
orderly manner with evaluation of potential reliability impacts and
implementation of mitigation measures where needed; the unbroken,
decades-long historical success of the EPA's trading programs at
achieving emissions reductions without any adverse reliability impacts;
the views expressed by commenters that facilitating EGU retirement and
replacement as a possible compliance strategy through 2029 would be
particularly helpful; the changes made in the final rule for control
periods through 2029 specifically to increase flexibility during this
transitional period, including deferring application of the backstop
daily emissions rate provisions for EGUs without existing SCR controls,
increasing the target percentage used to determine the target allowance
bank level for purposes of the bank recalibration provisions, and
establishing preset state emissions budgets which serve as floors
against potential dynamic budget imposition in those control periods;
and the changes made in the final rule incorporating multiple years of
heat input data into the dynamic budget-setting procedure, adding a 50-
ton threshold before application of the 3-for-1 surrender ratio to
emissions exceeding the backstop daily NOX emissions rate,
and phasing in emissions reductions requirements commensurate with new
SCR installations through 2027; the EPA concludes that this action does
not pose any material risk of adverse impact to electric system
reliability.
    The EPA has also considered the other suggestions offered by
commenters for addressing reliability-related issues. With respect to
suggestions that the rule should include provisions allowing some or
all of the trading program's requirements to be suspended at times when
an RTO or other entity with grid management responsibilities determines
there is a reliability-related need, the EPA again observes that the
rule's emissions reduction requirements are being implemented through a
trading program mechanism which makes exceptions of this nature
unnecessary. Trading programs inherently offer the flexibility to
accommodate variability in the utilization of individual units. The
``reliability safety valve'' provisions in the Clean Power Plan, which
one commenter cited as a precedent to support some form of temporary
exemption under this rule, in fact was available only in situations
where a state plan did not allow emissions trading and instead imposed
unit-specific emissions constraints. See 80 FR 64877-879. Even the 3-
for-1 allowance surrender ratio under the backstop daily NOX
emissions rate provisions can be met through the surrender of
additional allowances. The rule does not bar any EGU from operating at
any time as long as all allowance surrender requirements are met.
    With respect to suggestions that the EPA must undertake recurring
modeling of the evolving electrical system and consult with RTOs before
each planned adjustment to emissions budgets, which start from the
premise that the rule poses risk to electric system reliability that
must be continuously monitored, the EPA disagrees with the premise and
therefore also disagrees with the suggestions. As discussed in section
V of this document, the EPA has taken care to ensure that the emissions
reduction requirements applicable to EGUs under this rule are feasible
through application of the control technologies selected as the basis
of the emissions reductions. The EPA has also performed modeling in
this rulemaking to assess the benefits and costs of the rule when all
required emissions reductions are achieved. That modeling, which
incorporates a representation of electrical grid regions and
interregional constraints on energy and capacity exchange, affirms the
feasibility of the overall emissions reduction requirements and is
illustrative of a control strategy where some units retire and are
replaced instead of installing new controls. The EPA has also consulted
with the RTOs (as well as other balancing authorities) in the course of
this rulemaking to ensure that the EPA understood the concerns
expressed in their comments such that we could address those comments
in this final rule. The EPA does not agree that further modeling or
ongoing consultations with RTOs are needed in advance of the recurring
dynamic budget adjustments, which do not increase the stringency of the
rule's emissions reduction requirements established in the final rule.
The extensive consultation processes adopted by the Agency in
conjunction with the MATS rulemaking are not a relevant precedent; the
MATS rule, which was promulgated to address a different statutory
mandate, was structured in the form of unit-specific emissions
constraints, fundamentally different from the requirements of this
rule. The EPA notes that other entities responsible for maintaining
reliability and managing entry and exit of resources, including the
North American Electric Reliability Corporation (NERC) and RTOs and
other balancing authorities, already routinely assess resource adequacy
and reliability inclusive of meeting all regulatory requirements,
including environmental requirements.
    While the EPA does not agree that such consultations are a
necessary precondition for successful implementation of this rule, the
Agency remains available to engage with any affected EGU or reliability
authority requesting to meet and discuss the intersection of its power
sector regulatory programs with electric reliability planning and
operations. The EPA is also continuing its practice of meeting with the
U.S. Department of Energy and the Federal Energy Regulatory Commission
to maintain mutual awareness of how Federal actions and programs
intersect with the industry's responsibility to maintain electric
reliability.\304\
---------------------------------------------------------------------------

    \304\ See, e.g., U.S. Department of Energy and U.S.
Environmental Protection Agency, Joint Memorandum on Interagency
Communication and Consultation on Electric Reliability (March 8,
2023), available at https://www.epa.gov/power-sector/electric-reliability-mou.
---------------------------------------------------------------------------

    The EPA is not adopting the suggestion to replicate the so-called
``safety valve'' mechanism created under the Revised CSAPR Update. That
mechanism, cited by some commenters as potential precedent for an
unspecified form of ``reliability safety valve'' in this action, gave
owners of covered EGUs a one-time opportunity to voluntarily convert
allowances banked under the Group 2 trading program to allowances
useable in the Group 3 trading program at an 18-for-1 ratio for use in
the trading program's initial control period in 2021. See 82 FR 23137-
138. EGU owners chose to use the voluntary mechanism to acquire a total
of 382 allowances, representing only 0.36 percent of the sum of the
state emissions budgets and only 0.26 percent

of the total quantity of allowances available for compliance in that
control period.\305\ For the 2023 control period, the bank of
allowances carried over from the 2022 control period plus the
incremental starting bank that will be created by conversion of
additional allowances banked under the Group 2 trading program (see
section VI.B.12.b of this document) will total over 30 percent of the
full-season emissions budgets.\306\ Given the larger starting bank and
this rule's bank recalibration provisions (which will be implemented
starting with the 2024 control period, but which the EPA expects will
increase allowance market liquidity starting with the 2023 control
period), the Agency views establishment of a one-time voluntary
conversion opportunity for the 2023 control period analogous to the
Revised CSAPR Update's ``safety valve'' provision as unnecessary.
---------------------------------------------------------------------------

    \305\ Additional allowances available for compliance under the
Group 3 trading program in the 2021 control period included a
starting allowance bank created through mandatory conversion of a
portion of the allowances banked under the Group 2 trading program
as well as supplemental allowances issued to ensure that no
provisions of the Revised CSAPR Update increasing regulatory
stringency would take effect before that rule's effective date. See
86 FR 23133-137.
    \306\ The full-season emissions budgets for the 2023 control
period under the Group 3 trading program and the incremental
starting bank created in this action through conversion of
additional Group 2 allowances (but not the bank of allowances
carried over from the 2022 control period under the Group 3 trading
program) will be prorated to reflect the portion of the 2023 ozone
season occurring after the effective date of this rule. See sections
VI.B.12.a. and VI.B.12.b.
---------------------------------------------------------------------------

    Finally, in the final rule the EPA is not adopting any of the other
suggestions concerning additional mechanisms to make additional
allowances available through auctions or RTO-administered allowance
pools. For the reasons discussed throughout this section, the EPA
concludes that the trading program as established in this action
provides a flexible compliance mechanism that will allow the required
emissions reductions to be achieved without the need for creation of
additional allowances. However, the EPA also recognizes the potential
for allowance market liquidity to be further increased through some
form of auction mechanism. For instance, it may be appropriate to pair
the introduction of an auction with a reduction in the bank
recalibration percentage that begins earlier than 2030. Through a
supplemental rulemaking, the Agency intends to propose and take comment
on potential amendments to the Group 3 trading program that would add
such an auction mechanism to the regulations and make other appropriate
adjustments in the implementation framework at Step 4.\307\
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    \307\ Such a rulemaking would not reopen any determinations
which the Agency has made at Steps 1, 2, or 3 of the interstate
transport framework in this action. Nor would it reopen any aspects
of implementation of the program at Step 4 except for those in
relation to establishing an auction and associated adjustments to
ensure program stringency is maintained. In this respect, such a
rulemaking would constitute a discretionary action that is not
necessary to resolution of good neighbor obligations. Rather, these
adjustments, if finalized, would reflect a shift from one acceptable
form of implementation at Step 4 to a slightly modified but also
acceptable form of implementation at Step 4, as related to EGUs. No
legal or technical justification for this action as set forth in the
record here depends on or would be undermined by the development of
an alternative approach that includes an auction, and if the EPA for
any reason determines not to propose or finalize such a rulemaking,
no aspect of this rule would thereby be rendered infeasible or
incomplete.
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2. Expansion of Geographic Scope
    In light of the findings at Steps 1, 2, and 3 of the 4-step
interstate transport framework, the EPA is expanding the geographic
scope of the existing CSAPR NOX Ozone Season Group 3 Trading
Program to encompass additional states (and Indian country within the
borders of such states) with EGU emissions that significantly
contribute for purposes of the 2015 ozone NAAQS. Specifically, the EPA
is expanding the Group 3 trading program to include the following
states and Indian country within the borders of the states: Alabama,
Arkansas, Minnesota, Mississippi, Missouri, Nevada, Oklahoma, Texas,
Utah, and Wisconsin. Any unit located in a newly added jurisdiction
that meets the applicability criteria for the Group 3 trading program
will become an affected unit under the program, as discussed in section
VI.B.3 of this document.
    CSAPR, the CSAPR Update, and the Revised CSAPR Update also applied
to sources in Indian country, although, when those rules were issued,
no existing EGUs within the regions covered by the rules were located
on lands that the EPA understood at the time to be Indian country.\308\
In contrast, within the geographic scope of this rulemaking, the EPA is
aware of areas of Indian country within the borders of both Utah and
Oklahoma with existing EGUs that meet the program's applicability
criteria. Issues related to state, tribal, and Federal CAA
implementation planning authority with respect to sources in Indian
country in general and in these areas in particular are discussed in
section III.C.2 of this document. EPA's approach for determining a
portion of each state's budget for each control period that will be set
aside for allocation to any units in areas of Indian country within the
state not subject to the state's CAA implementation planning authority
is discussed in section VI.B.9 of this document.
---------------------------------------------------------------------------

    \308\ CSAPR and the CSAPR Update both applied to EGUs located in
areas within Oklahoma's borders that are now understood to be Indian
country, consistent with the U.S. Supreme Court's decision in McGirt
v. Oklahoma, 140 S. Ct. 2452 (2020) (and subsequent case law),
clarifying the extent of certain Indian country within Oklahoma's
borders. However, those rules were issued before the McGirt
decision. See section III.C.2.a.
---------------------------------------------------------------------------

    Units within the borders of each newly added state will join the
Group 3 trading program on one of two possible dates during the
program's 2023 control period (that is, the period from May 1, 2023,
through September 30, 2023). The reason that two entry dates are
necessary is that, as discussed in section VI.B.12.a of this document,
the effective date is expected to fall after May 1, 2023. In the case
of states (and Indian country within the states' borders) whose sources
do not currently participate in the CSAPR NOX Ozone Season
Group 2 trading program--Minnesota, Nevada, and Utah--the sources will
begin participating in the Group 3 trading program on the rule's
effective date. However, in the case of the states (and Indian country
within the states' borders) whose sources do currently participate in
the Group 2 trading program--Alabama, Arkansas, Mississippi, Missouri,
Oklahoma, Texas, and Wisconsin--the sources will begin participating in
the Group 3 trading program on May 1, 2023, regardless of the rule's
effective date, subject to transitional provisions designed to ensure
that the increased stringency of the Group 3 trading program as revised
in this rulemaking will not substantively affect the sources'
requirements prior to the rule's effective date. This approach provides
a simpler transition for the sources historically covered by the Group
2 trading program than the alternative approach of being required to
switch from the Group 2 trading program to the Group 3 trading program
in the middle of a control period, and it is the same approach that was
followed for sources that transitioned from the Group 2 trading program
to the Group 3 trading program in 2021 under the Revised CSAPR Update.
Section VI.B.12.a of this document contains further discussion of the
rationale for this approach and the specific transitional provisions.
    The EPA notes that under the rule, the expanded Group 3 trading
program will include not only 19 states for which the EPA is
determining that the required control stringency includes, among other
measures, installation of new post-combustion controls, but also three

states--Alabama, Minnesota, and Wisconsin--for which the EPA is
determining that the required control stringency does not include such
measures. In previous rulemakings, the EPA has chosen to combine states
in a single multi-state trading program only where the selected control
stringencies were comparable, to ensure that states did not effectively
shift their emissions reduction requirements to other states with less
stringent emissions reduction requirements by using net out-of-state
purchased allowances. Although the assurance provisions in the CSAPR
trading programs were designed to address the same general concern
about excessive shifting of emissions reduction activities between
states, EPA chose not to rely on the assurance provisions as sufficient
to allow for interstate trading in situations where the states were
assigned differing emissions control stringencies.
    In this rulemaking, the EPA believes the previous concern about the
possibility that certain states might not make the required emissions
reductions is sufficiently addressed through the various enhancements
to the design of the trading program, even where states have been
assigned differing emissions control stringencies. First, the existing
assurance provisions are being substantially strengthened through the
addition of the unit-specific secondary emissions limitations discussed
in sections VI.B.1.c.ii and VI.B.8. Second, by ensuring that individual
units operate their emissions controls effectively, the unit-specific
backstop daily emissions rate provisions discussed in sections
VI.B.1.c.i and VI.B.7 will necessarily also ensure that required
emissions reductions occur within the state. With these enhancements to
the design of the trading program, the EPA does not believe it is
necessary for sources in Alabama, Minnesota, and Wisconsin to be
excluded from the revised Group 3 trading program simply because their
emissions budgets reflect a different selected emissions control
stringency than the other states in the program.
    The EPA's legal and analytic bases for expansion of the Group 3
trading program to each of the additional covered states, as well as
responses to the principal related comments, are discussed in sections
III, IV, and V of this document, respectively, and responses to
additional comments are contained in the RTC document. With respect to
the proposed approach of including all states covered by the rule in a
single trading program even where the assigned control stringencies
differ, the only comments received by the EPA supported the approach,
which is finalized as proposed.
3. Applicability and Tentative Identification of Newly Affected Units
    The Group 3 trading program generally applies to any stationary,
fossil-fuel-fired boiler or stationary, fossil fuel-fired combustion
turbine located in a covered state (or Indian country within the
borders of a covered state) and serving at any time on or after January
1, 2005, a generator with nameplate capacity exceeding 25 MW and
producing electricity for sale, with exemptions for certain
cogeneration units and certain solid waste incineration units. To
qualify for an exemption as a cogeneration unit, an otherwise-affected
unit generally (1) must be designed to produce electricity and useful
thermal energy through the sequential use of energy, (2) must convert
energy inputs to energy outputs with efficiency exceeding specified
minimum levels, and (3) may not produce electricity for sale in amounts
above specified thresholds. To qualify for an exemption as a solid
waste incineration unit, an otherwise-affected unit generally (1) must
meet the CAA section 129(g)(1) definition of a ``solid waste
incineration unit'' and (2) may not consume fossil fuel in amounts
above specified thresholds. The complete text of the Group 3 trading
program's applicability provisions and the associated definitions can
be found at 40 CFR 97.1004 and 97.1002, respectively. The applicability
of this rule to MWCs and cogeneration units outside the Group 3 trading
program is discussed in sections V.B.3.a and V.B.3.c of this document,
respectively, and MWC applicability criteria are further discussed in
section VI.C.6 of this document.
    In this rulemaking, the EPA did not propose and is not finalizing
any revisions to the existing applicability provisions for the Group 3
trading program. Thus, any unit that is located in a newly added state
and that meets the existing applicability criteria for the Group 3
trading program will become an affected unit under the program. The
fact that the applicability criteria for all of the CSAPR trading
programs are identical therefore is sufficient to establish that any
units that are currently required to participate in another CSAPR
trading program in any of the additional states where such other
programs currently are in effect--Alabama, Arkansas, Minnesota,
Mississippi, Missouri, Oklahoma, Texas, and Wisconsin (including Indian
country within the borders of such states)--will also become subject to
the Group 3 trading program.
    In the additional states where other CSAPR trading programs are not
currently in effect--Nevada and Utah (including Indian country within
the borders of such states)--units already subject to the Acid Rain
Program under that program's applicability criteria (see 40 CFR 72.6)
generally also meet the applicability criteria for the Group 3 trading
program. Based on a preliminary screening analysis of the units in
these states that currently report emissions and operating data to the
EPA under the Acid Rain Program, the Agency believes that all such
units are likely to meet the applicability criteria for the Group 3
trading program.
    Because the applicability criteria for the Acid Rain Program and
the Group 3 trading program are not identical, it is possible that some
units could meet the applicability criteria for the Group 3 trading
program even if they are not subject to the Acid Rain Program. Using
data reported to the U.S. Energy Information Administration, in the
proposal the EPA identified six sources in Nevada and Utah (and Indian
country within the borders of the states) with a total of 15 units that
appear to meet the general applicability criteria for the Group 3
trading program and that do not currently report NOX
emissions and operating data to the EPA under the Acid Rain Program.
These units were listed in a table in the proposed rule, and the data
from that table for these units are reproduced as Table VI.B.3-1 of
this document. For each of these units, the table shows the estimated
historical heat input and emissions data that the EPA proposed to use
for the unit when determining state emissions budgets if the unit was
ultimately treated as subject to the Group 3 trading program.\309\ The
EPA requested comment on whether each listed unit would or would not
meet all relevant criteria set forth in 40 CFR 97.1004 and the
associated definitions in 97.1002 to qualify for an exemption from the
trading program and whether the estimated historical heat input and
emissions data identified for each unit

were representative. With respect to the listed units within the
borders of Nevada or Utah, the EPA received no comments asserting
either that the units qualified for applicability exemptions or that
the estimated data identified by the EPA were unrepresentative.\310\
For purposes of this rule, the EPA is therefore presuming that the
units listed in Table VI.B.3-1 do not qualify for applicability
exemptions and that the estimated data shown in the table for each unit
are representative. However, the owners and operators of the sources
retain the option to seek applicability determinations under the
trading program regulations at 40 CFR 97.1004(c).
---------------------------------------------------------------------------

    \309\ As discussed in section VI.B.10, any unit that becomes
subject to the Group 3 trading program pursuant to this rule and
that does not already report emissions data to the EPA in accordance
with 40 CFR part 75 will not be required to report emissions data or
be subject to allowance holding requirements under the Group 3
trading program until May 1, 2024, in order to provide time for
installation and certification of the required monitoring systems.
Such a unit will not be taken into account for purposes of
determining state emissions budgets and unit-level allocations under
the Group 3 trading program until the 2024 control period.
    \310\ One commenter expressed the view that eight of the listed
units within Nevada's borders appear to meet the CSAPR applicability
criteria but provided no comments on the specific proposed data. See
comments of Berkshire Hathaway Energy, EPA-HQ-OAR-2021-0668-0554, at
58-59. The EPA also received comments concerning sources within
Delaware's borders that were included in the proposal's request for
comment; these comments are moot because Delaware is not being added
to the Group 3 trading program in the final rule. See comments of
Calpine, EPA-HQ-OAR-2021-0668-0515; comments of Delaware City
Refining, EPA-HQ-OAR-2021-0668-0309.

 Table VI.B.3-1--Estimated Data To Be Used for Presumptively Affected Units Within the Borders of Nevada and Utah That Do Not Report Under the Acid Rain
                                                                         Program
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Estimated
                                                                                Estimated     ozone season
                              Facility                                                                            ozone season     average NOX
           State                 ID          Facility name              Unit ID                 Unit type          heat input    emissions rate   Notes
                                                                                (mmBtu)        (lb/mmBtu)

--------------------------------------------------------------------------------------------------------------------------------------------------------
Nevada.....................       2322  Clark.................  GT4....................  CT....................         190,985          0.0475  .......
Nevada.....................       2322  Clark.................  GT5....................  CT....................       1,455,741          0.0191  .......
Nevada.....................       2322  Clark.................  GT6....................  CT....................       1,455,741          0.0187  .......
Nevada.....................       2322  Clark.................  GT7....................  CT....................       1,455,741          0.0178  .......
Nevada.....................       2322  Clark.................  GT8....................  CT....................       1,455,741          0.0204  .......
Nevada.....................      54350  Nev. Cogen. Assoc. 1--  GTA....................  CT....................         660,100          0.0377        1
                                         Garnet Val.
Nevada.....................      54350  Nev. Cogen. Assoc. 1--  GTB....................  CT....................         660,100          0.0387        1
                                         Garnet Val.
Nevada.....................      54350  Nev. Cogen. Assoc. 1--  GTC....................  CT....................         660,100          0.0387        1
                                         Garnet Val.
Nevada.....................      54349  Nev. Cogen. Assoc. 2--  GTA....................  CT....................         749,778          0.0323        1
                                         Black Mtn.
Nevada.....................      54349  Nev. Cogen. Assoc. 2--  GTB....................  CT....................         749,778          0.0370        1
                                         Black Mtn.
Nevada.....................      54349  Nev. Cogen. Assoc. 2--  GTC....................  CT....................         749,778          0.0364        1
                                         Black Mtn.
Nevada.....................      56405  Nevada Solar One......  HI.....................  Boiler................         479,452          0.1667  .......
Nevada.....................      54271  Saguaro...............  CTG1...................  CT....................       1,383,149          0.0314        1
Nevada.....................      54271  Saguaro...............  CTG2...................  CT....................       1,383,149          0.0301        1
Utah.......................      50951  Sunnyside.............  1......................  Boiler................       1,888,174          0.1715  .......
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table notes:
\1\ Unit reports capability of producing both electricity and useful thermal energy.

4. State Emissions Budgets
    In this final rule, the EPA is using a combination of a ``preset''
budget calculation methodology and a ``dynamic'' budget calculation
methodology to establish state emissions budgets for the Group 3
trading program. A ``preset'' budget is one for which the absolute
amount expressed as tons per ozone season control period is established
in this final rule. It uses the latest data currently available on EGU
fleet composition at the time of this final action. A ``dynamic''
budget is one for which the formula and emissions-rate information is
finalized in this rule, but updated EGU heat input and inventory
information is used on a rolling basis to set the total tons per ozone
season for each control period. Both methods of budget calculation are
designed to set budgets reflective of the emissions control strategies
and associated stringency levels (expressed as an emissions rate of
pounds of NOX per mmBtu) identified for relevant EGU types
at Step 3--which we will refer to in this section as the ``Step 3
emissions control stringency.'' Preset budgets provide greater
certainty for planning purposes and can be reliably established in the
short-term based on known, upcoming changes in the EGU fleet. Due to
build time for new units and planning and approval processes for plant
retirements, these major fleet alterations are often known several
years in advance. This information facilitates presetting budgets that
appropriately calibrate the identified control stringency to the fleet.
Dynamic budgets better assure that the budgets remain commensurate with
the Step 3 emissions control stringency over the longer term, as
currently unknown changes in the EGU fleet occur. In this final rule,
in response to comments, we have adjusted the proposal to give a
greater role for preset budgets through 2029, while dynamic budgeting
will be phased in to provide greater certainty in the short term and
allow for a transition period to an exclusively ``dynamic'' approach
beginning in 2030.
    For the control periods from 2023 through 2025, the preset budgets
established in the rule will serve as the state emissions budgets for
the control periods in those years, with no role for dynamic budgeting.
For the control periods from 2026 through 2029, the EPA is determining
preset emissions budgets for each control period in the rule and will
also calculate and publish dynamic budgets for each state in the year
before each control period using the dynamic budget-setting methodology
finalized in this rule, applied to data available at the time of the
calculations. For these four control periods, each state's preset
budget serves as a floor and may be supplanted by the dynamic emissions
budget EPA calculates for the state for that control period only if the
dynamic budget is higher than the preset budget. For control periods in
2030 and thereafter, the state emissions budgets will be the dynamic
budgets calculated and published in the year before each control
period.
    In the dynamic budget calculation methodology, it is the fleet
composition (reflected by heat input patterns across the fleet in
service, inclusive of EGU entry and exit) that is dynamic, while the
emissions stringency finalized in this rule is constant, as reflected
in

emissions rates for various types of units. Multiplying the assumed
emissions rate for each unit (as finalized in this rule) by the
identified recent historical heat input for each unit and summing the
results to the state level would provide a given year's state dynamic
emissions budgets. Dynamic budgets are a product of the formula
promulgated in this action applied to a rolling three-year average of
reported heat input data at the state level and a rolling highest-
three-of-five-year average of reported heat input data at the unit
level. As such, the EPA is confident that dynamic budgets will more
accurately reflect power sector composition, particularly in later
years, and certainly from 2030 and beyond, than preset budgets could
and will therefore better implement the Step 3 emissions control
stringency over long time horizons.
    Starting in 2025 (for the 2026 control period), the dynamic
budgets, along with the underlying data and calculations will be
publicly announced, and this will occur approximately one year before
the relevant control period begins. These will be published in the
Federal Register through notices of data availability (NODAs), similar
to how other periodic actions that are ministerial in nature to
implement the trading programs are currently handled. And as with such
other actions, interested parties will have the opportunity to seek
corrections or administrative adjudication under 40 CFR part 78 if they
believe any data used in making these calculations, or the calculations
themselves, are in error.
    To illustrate how dynamic budgeting will work after the transition
from preset budgets, the dynamic budgets for the 2030 ozone season
control period will be identified by May 1, 2029, using the latest
available average of three years of reported operational data at that
time (i.e., the average of 2026-2028 heat input data at the state level
and 2024-2028 years of rolling data at the unit level) applied in a
simple mathematical formula finalized in this rule, which multiplies
this heat input data by the emissions rates quantified in this rule.
Therefore, if a unit retires before the start of the 2028 ozone season
but had not announced its upcoming retirement at the time of this
rule's finalization, the dynamic budget approach ensures that the
dynamic budgets for 2030 and subsequent control periods would represent
the identified control stringency applied to a fleet reflecting that
retirement.
    The two examples discussed next illustrate the implementation of
the dynamic budget during the 2026-2029 time period. During this
period, the state emissions budget for each state for a given control
period will be the preset state emissions budget unless the dynamic
budget is higher. This approach accommodates scenarios where baseline
fossil heat input may exceed levels anticipated by EPA in the preset
budgets (e.g., this could result from greater electric vehicle
penetration rates). Table VI.B.4-1 illustrates this scenario. In the
preset budget approach for 2028, the 2028 heat input is estimated based
on the latest available heat input data at the time of rule proposal
(i.e., 2021; see the subsection on preset budget methodology later in
this section), which cannot reflect a subsequent change in fleet heat
input values (column 2) due to, e.g., increased utilization to meet
increased electric load. However, the dynamic budget would use 2022-
2026 heat input values at the unit level and 2024-2026 heat input
values at the state level--as opposed to 2021 heat input values--as the
latest representative values to inform the 2028 state emissions budget.
Therefore, the heat input values in column 2 under the dynamic scenario
reflect the change in fleet utilization levels, and when multiplied by
the emissions rates reflecting the Step 3 emissions control stringency
in this final rule, the corresponding emissions (18,700 tons) summed in
column 4 constitute a state budget that more accurately reflects the
Step 3 emissions control stringency applied to the fleet composition
for that year, as opposed to the 17,000 tons identified in the preset
budget approach. As illustrated in the example, the dynamic variable is
the heat input variable, which changes over time. In this instance, the
dynamic budget value of 18,700 tons would be implemented for 2028
instead of the preset value, and thus accommodate the unforeseen
utilization changes in response to higher demand.
    In the second table, Table VI.B.4-2, the dynamic budget is lower
than the preset budget due to retirements that were not foreseen at the
time the preset budgets were determined. In the preset budget approach
for 2028, the 2028 heat input is still estimated based on the latest
available heat input data at the time of rule proposal (i.e., 2021),
which cannot reflect a subsequent fleet change in heat input values due
to an unanticipated retirement of one of the state's coal-fired units
before the start of the 2028 ozone season. However, the dynamic budget
again would use 2022-2026 heat input values at the unit level and 2024-
2026 heat input values at the state level--as opposed to 2021 heat
input values--as the latest representative values to inform the 2028
state emissions budget, which would reflect the decline in coal heat
input and replacement with natural gas heat input (capturing the coal
unit's retirement). Therefore, the heat input values under the dynamic
budget scenario reflect the change in fleet composition, and when
multiplied by the relevant emissions rates reflecting the Step 3
emissions control stringency identified in this final rule, the
corresponding emissions (15,000 tons) constitute a state budget that
reflects the identified control stringency applied to the fleet
composition for that year as opposed to the 17,000 tons in summed in
the first table. However, for the 2026-2029 period, in which the EPA
implements an approach that utilizes the higher of the dynamic budget
or preset budget, the budget implemented for 2028 in this scenario
would be the 17,000 ton preset amount.
    During the 2026-2029 transition period--during which substantial,
publicly announced utility commitments exist for higher emitting units
to exit the fleet--it is still possible that yet-to-be known, unit-
specific retirements (such as illustrated in this second scenario) may
result in dynamic budgets that are lower than the preset budgets
finalized in this rule. However, during this transition period EPA
believes that having the preset budgets serve as floors for the state
emissions budgets is appropriate for two primary reasons identified by
commenters. First, commenters repeatedly emphasized the need for
certainty and flexibility to successfully carryout plans for
significant fleet transition through the end of the decade. The 2026-
2029 period is expected to have substantial fleet turnover. Current
Form EIA-860 data, in which utilities report their retirement plans,
identify 2028 as the year with the most planned coal capacity
retirements during the 2023-2029 timeframe. Using preset budgets as
state emissions budget floors provides states and utilities with
information on minimum quantities of allowances that can be used for
planning purposes. In turn, this fosters the operational flexibility
needed while putting generation and transmission solutions into place
to accommodate such elevated levels of retirements. Second, the latter
part of the decade has a significant amount of unit-level firm
retirements already planned and announced for purposes of compliance
with other power sector regulations or fulfillment of utility
commitments. These known retirements are already

captured in the preset state budgets, with the result that the
likelihood and magnitude of instances where a state's dynamic budget
for a given control period would be lower than its preset budget for
the control period is reduced in this 2026-2029 period relative to
control periods further in the future for which retirement plans have
not yet been announced. After 2029, the dynamic budgets from 2030
forward will fully capture all prior retirements and new builds when
the fleet is entering this period where unit-specific data on such
plans is less frequently available. For instance, through the remaining
portion of the decade, the amount of coal steam retirements identified
and reported through Form EIA-860 is nearly 7 GW each year. However,
for the decade beginning in 2030--the amount of capacity currently
reported with a planned retirement is less than 2 GW each year.\311\
This yet-to-be available data and relative lack of currently known firm
retirement plans for 2030 and beyond make dynamic budget implementation
for those years essential for state emissions budgets to maintain the
Step 3 control stringency required under this rule.
---------------------------------------------------------------------------

    \311\ See 2021 Form EIA Form 860--Schedule 3, Generator Data.
Department of Energy, Energy Information Administration.

                       Table VI.B.4-1--Example of Preset and Dynamic Budget Calculation in Scenario of Increased Fossil Heat Input
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          Preset budget approach (2028)              Dynamic budget approach (2028)
                                                                  --------------------------------------------------------------------------------------
                                                                                Preset       Preset tons                                 Tons (heat
                                                                   Preset heat    emissions    (heat input x    Heat input    Emissions       input x
                                                                      input       rate (lb/   emissions rate)/    (tBtu)      rate (lb/      emissions
                                                                      (tBtu)       mmBtu)           2000                       mmBtu)       rate)/2000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Units.......................................................          600          0.05          15,000           660          0.05          16,500
Gas Units........................................................          400          0.01           2,000           440          0.01           2,200
                                                                  --------------------------------------------------------------------------------------
    State Budget (tons)..........................................  ...........  ............          17,000   ...........  ............          18,700
--------------------------------------------------------------------------------------------------------------------------------------------------------

                        Table VI.B.4-2--Example of Preset and Dynamic Budget Calculation in Scenario of Unanticipated Retirement
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          Preset budget approach (2028)              Dynamic budget approach (2028)
                                                                  --------------------------------------------------------------------------------------
                                                                                Preset       Preset tons                                 Tons (heat
                                                                   Preset heat    emissions    (heat input x    Heat input    Emissions       input x
                                                                      input       rate (lb/   emissions rate)/    (tBtu)      rate (lb/      emissions
                                                                      (tBtu)       mmBtu)           2000                       mmBtu)       rate)/2000
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Units.......................................................          600          0.05          15,000           500          0.05          12,500
Gas Units........................................................          400          0.01           2,000           500          0.01           2,500
                                                                  --------------------------------------------------------------------------------------
    State Budget (tons)..........................................  ...........  ............          17,000   ...........  ............          15,000
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In summary, for the control periods in 2023 through 2025, EPA is
providing only preset budgets in this final rule because those control
periods are in the immediate future and would not substantially benefit
from the use of future reported data. For these years, the certainty
around new builds and retirements is higher than ensuing years. For the
ozone season control periods of 2026 through 2029, EPA is providing
both preset budgets in this final rule and dynamic budgets via future
ministerial actions. For those control periods from 2026 through 2029,
the preset budgets finalized in this rule serve as floors, such that a
given state's dynamic budget ultimately calculated and published for
that control period will apply to that state's affected EGUs only if it
is higher than the corresponding preset budget finalized in this
rulemaking. This approach is in response to stakeholder comments
requesting more advance notice regarding the total quantities of
allowances available to accommodate compliance planning through the
latter half of the decade, during a period of particularly high fleet
transition expected with or without this rulemaking.
    EPA's emissions budget methodology and formula for establishing
Group 3 budgets are described in detail in the Ozone Transport Policy
Analysis Final Rule TSD and summarized later in this section.
a. Methodology for Determining Preset State Emissions Budgets for the
2023 Through 2029 Control Periods
    To compose preset state emissions budgets, the EPA is using the
best available data at the time of developing this final rule regarding
retirements and new builds. The EPA relies on a compilation of data
from Form EIA-860 (where facilities report their future retirement
plans), the PJM Retirement Tracker, utilities' integrated resource
plans, notification of compliance plans with other EPA power sector
regulatory requirements, and other information sources that EPA
routinely canvasses to populate the data fields included in the
Agency's NEEDS database. The EPA has updated this data on retirements
and new builds using the latest information available from these
sources at the time of final rule development as well as input provided
by commenters.
    For determining preset state emissions budgets, the EPA generally
uses historical ozone season data from the 2021 ozone season, the most
recent data available to EPA and to commenters responding to this
rulemaking's proposal and providing a reasonable representation of
near-term fleet conditions. This is similar to the approach taken in
the CSAPR Update and the Revised CSAPR Update, where

the EPA likewise began with data for the most recent ozone season at
the time of proposal (2015 and 2019, respectively).
    By using historical unit-level NOX emissions rates, heat
input, and emissions data in the first stage of determining preset
emissions budgets, the EPA is grounding its budgets in the most recent
representative historical operation for the covered units at the time
EPA began its final rulemaking. This data set is a reasonable starting
point for the budget-setting process as it reflects recent publicly
available and quality assured data reported by affected facilities
under 40 CFR part 75, largely using CEMS. The reporting requirements
include quality control measures, verification measures, and
instrumentation to best record and report the data. In addition, the
designated representatives of EGU sources are required to attest to the
accuracy and completeness of the data.
    The first step in deriving the future year state emissions budget
is to calibrate historical data to planned future fleet conditions. EPA
does this by adjusting this historical baseline information to reflect
the known changes (e.g., when deriving the 2023 state emissions budget,
EPA starts by adjusting 2021 unit-level data to reflect changes
announced and planned to occur by 2023). The EPA adjusted the 2021
ozone-season data to reflect committed fleet changes expected to occur
in the baseline. This includes announced and confirmed retirements, new
builds, and retrofits that occur after 2021 but prior to 2023. For
example, if a unit emitted in 2021, but retired prior to May 1, 2022,
its 2021 emissions would not be included in the 2023 baseline estimate.
For units that had no known changes, the EPA uses the actual emissions,
heat input, and emissions rates reported for 2021 as the baseline
starting point for calculating the 2023 state emissions budgets. Using
this method, the EPA arrived at a baseline emission, heat input, and
emissions rate estimate for each unit for a future year (e.g., 2023).
    The second step in deriving the preset state emissions budgets is
for EPA to take the adjusted historical data from Step 1, and adjust
the emissions rates and mass emissions to reflect the control
stringencies identified as appropriate for EGUs of that type. For
instance, if an SCR-equipped unit was not operating its SCR so as to
achieve a seasonal average emissions rate of 0.08 lb/mmBtu or less in
the historical baseline, the EPA lowered that unit's assumed emissions
rate to 0.08 lb/mmBtu and calculated the impact on the unit's mass
emissions. Note that the heat input is held constant for the unit in
the process, reflecting the same level of unit operation compared to
historical 2021 data. The improved emissions rate of 0.08 lb/mmBtu is
applied to this constant heat input, reflecting control optimization.
In this manner, the unit-level totals from Step 1 are adjusted to
reflect the additional application of the assumed control technology at
a given control stringency. This is illustrated in Table VI.B.4.a-1.
Row 1 reflects the 2021 historical data for this SCR-controlled unit.
Row 2 reflects no change (as there are no known changes such as planned
retirement or coal-to-gas conversion). Row 3 reflects application of
the Step 3 stringency (i.e., a 0.08 lb/mmBtu emissions rate from SCR
optimization). The resulting impact on emissions is a reduction from
the historical 4,700 tons to an expected future level of 615 tons. A
state's preset budget for a given control period is the sum of the
amounts computed in this manner for each unit in the state for the
control period.

         Table VI.B.4.a-1--Example of Unit-Level Data Calculations for Deriving State Emissions Budgets
----------------------------------------------------------------------------------------------------------------
                                                                    Heat input     Emission rate     Emissions
                                                                      (tBtu)        (lb/mmBtu)        (tons)
----------------------------------------------------------------------------------------------------------------
Historical Data (2021)..........................................          15.384            0.61           4,700
Step 1 (Baseline)--Historical data adjusted for planned changes.          15.384            0.61           4,700
Step 2--Baseline further adjusted for Step 3 stringency.........          15.384            0.08             615
----------------------------------------------------------------------------------------------------------------

    For each control period from 2026 onward, the unit-specific
emissions rates assumed for all affected states except Alabama,
Minnesota, and Wisconsin will reflect the selected control stringency
that incorporates post-combustion control retrofit opportunities for
the relevant units identified in the state emissions budgets and
calculations appendix to the Ozone Transport Policy Analysis Final Rule
TSD. The emissions rates assigned to large coal-fired EGUs for 2026
state emissions budget computations only reflect 50 percent of the SCR
retrofit emissions reduction potential at each of those units, to
capture the phase-in approach EPA is taking for this control as
described in section VI.A of this document. The EPA calculates these
unit-level emissions rates in 2026 as the sum of the unit's baseline
emissions rate and its controlled emissions rate divided by two (i.e.,
50 percent of the emissions reduction potential of that pollution
control measure). The emissions rates assigned to these large coal-
fired EGUs for 2027 state emissions budget computations reflect the
full assumed SCR retrofit emissions potential at those units, by
applying the controlled emissions rate only. For example, a coal steam
unit greater than or equal to 100 MW currently lacking a SCR and
emitting at 0.20 lb/mmBtu would be assumed to reduce its emissions rate
to 0.125 lb/mmBtu rate in 2026 and 0.050 lb/mmBtu rate in 2027 for
purposes of deriving its preset state emissions budgets in those years.
    Comment: Some commenters suggested that EPA should not reflect
planned retirements in its preset budgets. The suggestion stems from
commenters' observation that those retirement decisions may yet change.
    Response: The effectiveness of EPA's future year preset state
emissions budgets depends on how well they are calibrated to the
expected future fleet. Therefore, EPA believes it is important to
incorporate expected new builds, retirements, and unit changes already
slated to occur. Ignoring these factors would dilute, rather than
strengthen, the ability of preset budgets to capture the most
representative fleet of EGUs to which they will be applied. Omitting
scheduled retirements and new builds from state emissions budgets would
reflect units that power sector operators and planning authorities do
not expect to exist, while failing to reflect units that are expected
to exist.
    EPA notes it is using the best available data at the time of the
final rule. EPA relies on a compilation of data from Form EIA-860 where
facilities report their future retirement plans. In addition, EPA is
using data from regional transmission organizations who are cataloging,
evaluating, and approving such retirement plans and data; data from
notifications submitted directly to EPA by the utility themselves

through comments; and retirement notifications submitted to permitting
authorities. This information is highly reliable, real-world
information that provides EPA with the high confidence that such
retirements will in fact occur.
    If a unit's future retirement does not occur on the currently
scheduled date, EPA observes that such an unexpected departure from the
currently available evidence would still not undermine the ability of
affected EGUs to comply with their applicable state budgets. EPA's
approach of using historical data and incorporation only of announced
fleet changes in estimating its future engineering analytics baseline
means that its future year baseline generation and retirement outlook
for higher emitting sources is more likely to understate future
retirements (rather than overstate as suggested by commenter), as EPA
does not assume for the purpose of preset budget quantification any
retirements beyond those that are already planned. In other words, in
the 2023 through 2029 timeframe for which EPA is establishing preset
state emissions budgets in this rulemaking, there are more likely to be
additional future EGU retirements beyond those scheduled prior to the
finalization of this rule than there are to be reversed or
substantially delayed changes to already announced EGU retirement
plans. For instance, subsequent to the EPA's finalization of the
Revised CSAPR Update Rule budgets for 2023 (rule finalized in March
2021), the owners of Sammis Units 5-7 and Zimmer Unit 1 in Ohio
(totaling nearly 3 GW of coal capacity) announced that the units would
retire by 2023--nearly 5 years earlier than previously
planned.312 313 These coal retirements were not captured in
Ohio's 2023 or 2024 state emissions budgets established under the
Revised CSAPR Update. Meanwhile, there have been no announcements of
previously announced retirement plans being rescinded or delayed for
other Ohio units. Similarly, the Joppa Power Plant in Illinois
accelerated its retirement from 2025 to 2022 shortly after the Revised
CSAPR Update Rule was signed.\314\
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    \312\ Available at https://www.prnewswire.com/news-releases/energy-harbor-transitions-to-100-carbon-free-energy-infrastructure-company-in-2023-301501879.html.
    \313\ Available at https://www.spglobal.com/commodityinsights/en/market-insights/latest-news/coal/071921-vistra-plans-to-retire-13-gw-zimmer-coal-plant-in-ohio-five-years-early.
    \314\ Available at https://www.prnewswire.com/news-releases/joppa-power-plant-to-close-in-2022-as-company-transitions-to-a-cleaner-future-301263013.html.
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    We further observe that the commenters' concern is only materially
meaningful for the 2023 through 2025 preset budget periods, where the
currently known information is generally the most reliable. For the
2026-2029 control periods, if an anticipated fleet change such as an
EGU retirement does not actually occur, the dynamic budget setting
methodology would, all else being equal, generate a budget reflective
of that unit's continued operation (as the budget would be based on the
preceding years of historical data), and that dynamic budget will
supplant the preset budget for that state (if it represents a total
quantity of emissions higher than the preset budget).
    Because the future is inherently uncertain, all analytic tools and
information resources used in any estimation of future EGU emissions
will yield some differences between the projected future and the
realized future. Such potential differences may either increase or
decrease future emissions in practice, and the unavoidable existence of
such differences does not, on its own, render the EPA's inclusion of
currently announced retirements an unreasonable feature of the
methodology for determining future year preset emissions budgets. To
the contrary, if the EPA failed to include these announced retirements,
the rule would knowingly authorize amounts of additional, sustained
pollution that are not currently expected to occur. If those
retirements largely or entirely occur as currently scheduled, the
overestimated state budgets would allow other EGUs to emit additional
pollution in place of the emissions from the retired EGUs instead of
maintaining or improving their emissions performance to eliminate
significant contribution with nonattainment and interference with
maintenance of the NAAQS.\315\
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    \315\ Some of these announced retirements reflect the operator's
reported intention to EPA to retire the affected capacity by that
time as part of their compliance with effluent limitation guidelines
or with the coal combustion residuals rule.
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    Additionally, as noted elsewhere, EPA's use of a market-based
program, a starting bank of converted allowances, and variability
limits are all features that will readily accommodate whatever
relatively limited differences in emissions may occur if a currently
scheduled EGU retirement is ultimately postponed during the preset
budget years of 2023 through 2025. Therefore, EPA's resulting preset
state emissions budgets--inclusive of expected fleet turnover--are
robust to the inherent uncertainty in future year baseline conditions
for the period in which they are applied.
    Comment: Some commenters suggested that EPA should use a multi-year
baseline for all of its state budget derivations, including preset
budgets, to control for outlier years that may not be representative of
future years due to major weather events or other fleet disruptions
(such as a large nuclear unit outage).
    Response: For preset state emissions budget derivation, EPA is
finalizing use of the same single-year \316\ historical baseline
approach it used in the proposed rule. This approach is similar to the
Revised CSAPR Update, where EPA also relied on a single-year historical
baseline to inform its Step 3 approach. EPA's interest in a historical
data set to inform this part of the analysis is to capture the most
representative view of the power sector. For estimating preset state
budgets, EPA finds that, particularly at the state level, more recent
data is a better representation and basis for future year baselines
rather than incorporating older data. Taking as an example preset
budget estimation for the 2023 through 2025 ozone seasons, the EPA is
able to compare its single-year base line to an alternative multi-year
baseline (e.g., a 3-year baseline encompassing 2020-2022) and determine
that the single year baseline better reflects future fleet operation
expectation than a multi-year baseline that incorporates units which
have since retired as well as outlier patterns in load during pandemic-
related shutdowns.
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    \316\ For the purposes of this rulemaking, when describing a
``year'' or ``years'' of data utilized in state emission budget
computations, the EPA is actually utilizing the relevant data from
May 1 through September 30 of the referenced year(s), consistent
with the control period duration of this rule's EGU trading program.
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    EPA recognizes that 2021 is the latest available historical data as
of the preparation of this rulemaking, and therefore the most up-to-
date picture of the fleet at the time EPA began its analysis. EPA then
further evaluates the 2021 historical data at the state level to
determine whether it was a representative starting point for estimating
future year baseline levels and subsequently deriving the preset state
emissions budgets. If the Agency finds any state-level anomalies, it
makes necessary adjustments to the data. While unit-level variation may
occur from year-to-year, those variations are often offset by
substitute generation from other units within the state. Therefore, EPA
conducts its first screening at the state level by identifying any
states where 2021 heat

input and 2021 emissions were the lowest year for heat input and
emissions relative to the past several years (2018-2022, excluding 2020
due to shut downs and corresponding reduced utilization related to the
pandemic onset).317 318 Then, for that limited number of
states (AL, LA, MS, and TX) in which 2021 reflects the minimum fossil
fuel heat input and minimum emissions over the baseline evaluation
period, EPA--similar to prior rules--evaluated whether any unit-level
anomalies in operation were driving this lower heat input at the state
level. EPA examined unit-level 2021 outages to determine where an
individual unit-level outage might yield a significant difference in
state heat input, corresponding emissions baseline and resulting state
emissions budgets. When applying this test to all of the units in the
previously identified states (and even when applying to EGUs in all
states for whom Federal implementation plans are finalized in this
rulemaking), the EPA determined that the only unit with a 2021 outage
that (1) decreased its output relative to preceding or subsequent years
by 75 percent or more (signifying an outage), and (2) could potentially
impact the state's emissions budget substantially as it constituted
more than 5 percent of the state's heat input in a non-outage year was
Daniel Unit 2 in Mississippi. EPA therefore adjusted this state's
baseline heat input and NOX emissions to reflect the
operation of this unit based on its 2019 data--which was the second
most recent year of data available at the time of proposal (excluding
2020 given atypical impacts from pandemic-related shutdowns) for which
this unit operated. The EPA then applied the Step 3 mitigation
strategies as appropriate to this unit (i.e., combustion controls
upgrade in 2024, SCR retrofit in 2026/2027) to derive this portion of
Mississippi's budget. This test, and subsequent adjustment as
necessary, enables EPA to utilize the latest, most representative data
in a manner that is robust to any substantial state-level or region-
level outlier events within that dataset and further validates EPA's
comprehensive approach to using the most recent single year of data for
preset budgets.
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    \317\ EPA identified states for which 2021 both heat input and
emissions were the low year among the examined baseline period as a
preliminary screen to identify potential instances where reduced
utilization may lead to an understated emissions baseline value.
    \318\ EPA also conducted a similar test to identify states in
which 2021 heat input and emissions were the high year among the
examined baseline period and found that it was for both Utah and
Pennsylvania. However, for both states the elevated heat input trend
persisted into 2022 (at slightly lower levels and was correlated
with retirements elsewhere in the region--indicating that some of
this heat input increase may be representative of the future fleet
and that planned retirements factored into preset budget will remove
any unrepresentative heat input from 2021.
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b. Methodology for Determining Dynamic State Emissions Budgets for
Control Periods in 2026 onwards
    In this final rule, the EPA is finalizing an approach of using
multi-year baseline data for purposes of dynamic budget computation.
The aforementioned testing of the representative nature of a single
year of baseline data for purposes of preset budget setting is not
possible in the dynamic budget process as that data will not be
available until a later date. Further, the EPA generally agrees with
commenters that use of a multi-year period will be more robust to any
unrepresentative outlier years in fleet operation and thus better
suited for purposes of dynamic budgets. The methodology for determining
dynamic state emissions budgets for later control periods (2026 and
beyond) relies on a nearly identical methodology for applying unit-
level emissions rate assumptions as the preset budget methodology. But
it uses more recent heat input data that will become available by that
future time, employing a multi-year approach for identifying the heat
input data so as to ensure representativeness.
    For dynamic budgets, EPA uses more years of baseline data to
control for any state-level and unit-level variation that may occur in
a future single year that is not possible to identify at present.
First, for each unit operating in the most recent ozone season for
which data have been reported, EPA identifies the average of the three
highest unit-level heat input values from the five ozone seasons ending
with that ozone season to get a representative unit-level heat input.
Ozone seasons for which a unit reported zero heat input are excluded
from the averaging of the three highest heat input values for that
unit. These representative unit-level heat input values established for
each unit individually are then summed for all units in each state.
Each unit's representative unit-level heat input is then divided into
this state-level sum to get that unit's representative percent of the
aggregated average heat input values for all affected EGUs in that
state.
    Next, EPA calculates a representative state-level heat input by
taking the average state-level total heat input across affected EGUs
from the most recent three ozone seasons for which data have been