information about this assessment, refer to the Ozone Transport Policy
Analysis Proposed Rule TSD and the Ozone AQAT.
    Based on these results, under no scenario does EPA's AQAT analysis
for this proposal indicate that including all identified EGU reductions
would constitute over-control. Rather, if these results hold for a
final rule, the potential over-control for Arkansas and Mississippi can
be avoided by not requiring Tier 2 non-EGU reductions, and over-control
for Wyoming can be avoided by not requiring any non-EGU reductions.
    Nonetheless, while acknowledging these preliminary analytic
results, the EPA is proposing that all of the selected EGU and non-EGU
NOX reduction strategies selected in EPA's Step 3 analysis
be applied to all linked states in 2026--including to Arkansas,
Mississippi, and Wyoming--to eliminate significant contribution to
nonattainment and interference with maintenance of the 2015 ozone
NAAQS. The Supreme Court has directed the EPA to avoid both over-
control and under-control in addressing good neighbor obligations. In
addition, the D.C. Circuit has reinforced that over-control must be
established based on particularized, record evidence on an as-applied
basis. As noted previously, even slight changes in analytics based on
comments or new information between proposal and final could result in
the Brazoria, Texas site remaining either a nonattainment or
maintenance receptor. Further, with respect to Wyoming, its linkage
only resolves based on an unenforceable assumption regarding a certain
level of emissions reduction in Colorado. The proposed determination
that the stringency of this proposal does not constitute over-control
for any linked state is further reinforced by EPA's observation in
Section IV.A.1 of this proposed rule regarding the nature of ozone, and
in particular, that future ozone concentrations and the formation of
ground level ozone, may be impacted by climate change in future years.
    Under these circumstances, the EPA cannot conclude based on the
current record that any aspect of its selected Step 3 level of control
stringency constitutes unnecessary over-control for any of the 23
states found to be linked in 2026. The EPA requests comment on this
proposed conclusion. The EPA requests comment on an alternative
conclusion that, if this same analysis were to persist for a final
rule, it must limit non-EGU reduction requirements for Arkansas and
Mississippi to only the Tier 1 industries, and for Wyoming to limit the
stringency of the rule to only the EGU reduction strategies.

VII. Implementation of Emissions Reductions

A. NOX Reduction Implementation Schedule

    This proposal, if finalized, will ensure that emissions reductions
necessary to eliminate significant contribution will be achieved as
``as expeditiously as practicable'' as required under CAA section
181(a). The EPA's anticipated timing will provide for all possible
emissions reductions to go into effect beginning in the 2023 ozone
season, which is aligned with the next upcoming attainment date of
August 3, 2024, for areas classified as Moderate nonattainment under
the 2015 ozone standard. Additional emissions reductions that the EPA
finds not possible to implement by that attainment date are proposed to
take effect as expeditiously as practicable, with the full suite of
emissions reductions taking effect by the 2026 ozone season, which is
aligned with the August 3, 2027, attainment date for areas classified
as Serious nonattainment under the 2015 ozone NAAQS. This schedule of
emissions reductions meets the requirement in the Good Neighbor
Provision that it must be

implemented ``consistent with the provisions of [title I of the CAA.]''
CAA section 110(a)(2)(D)(i). Finally, the timing of this proposed
rulemaking is designed to achieve reductions as expeditiously as
practicable while adhering to the procedural requirements of CAA
section 110. The EPA proposes this rule to constitute a full remedy for
interstate transport for the 2015 ozone NAAQS for the states covered by
this proposal; the EPA does not anticipate further rulemaking to
address good neighbor obligations will be required for these states
with the finalization of this rule.
    EPA's proposed determinations regarding the timing of this proposed
rule are informed by and in compliance with several recent court
decisions. The D.C. Circuit has reiterated several times since 2008
that, under the terms of the Good Neighbor Provision, upwind states
must eliminate their significant contributions to downwind areas
``consistent with the provisions of [title I of the Act],'' including
those provisions setting attainment deadlines for downwind areas.\207\
In North Carolina, the D.C. Circuit found the 2015 compliance deadline
that the EPA had established in CAIR unlawful in light of the downwind
nonattainment areas' 2010 deadline for attaining the 1997 NAAQS for
ozone and PM2.5.\208\ Similarly, in Wisconsin, the Court
found the CSAPR Update unlawful to the extent it allowed upwind states
to continue their significant contributions to downwind air quality
problems beyond the downwind states' statutory deadlines for attaining
the 2008 ozone NAAQS.\209\ More recently, in Maryland, the Court found
the EPA's selection of a 2023 analysis year in evaluating state
petitions submitted under CAA section 126 unlawful in light of the
downwind Marginal nonattainment areas' 2021 deadline for attaining the
2015 ozone NAAQS.\210\ The Court noted in Wisconsin that the statutory
command--that compliance with the Good Neighbor Provision must be
achieved in a manner ``consistent with'' title I of the CAA--may be
read to allow for some deviation from the mandate to eliminate
prohibited transport by downwind attainment deadlines, ``under
particular circumstances and upon a sufficient showing of necessity,''
but concluded that ``[a]ny such deviation would need to be rooted in
Title I's framework'' and would need to ``provide a sufficient level of
protection to downwind States.'' \211\
---------------------------------------------------------------------------

    \207\ North Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 2008),
Wisconsin v. EPA, 938 F.3d 303 (D.C. Cir. 2019), and Maryland v.
EPA, 958 F.3d 1185 (D.C. Cir. 2020).
    \208\ North Carolina, 531 F.3d at 911-913.
    \209\ Wisconsin, 938 F. 3d at 303, 3018-20.
    \210\ Maryland, 958 F.3d at 1203-1204. Similarly, in New York v.
EPA, 964 F.3d 1214 (D.C. Cir. 2020), the Court found the EPA's
selection of a 2023 analysis year in evaluating New York's section
126 petition unlawful in light of the New York Metropolitan Area's
2021 Serious area deadline for attaining the 2008 ozone NAAQS. 964
F.3d at 1226 (citing Wisconsin and Maryland).
    \211\ Wisconsin, 938 F. 3d at 320 (citing CAA section 181(a)
(allowing one-year extension of attainment deadlines in particular
circumstances) and North Carolina, 531 F.3d at 912).
---------------------------------------------------------------------------

1. 2023-2025: EGU NOX Reductions Beginning in 2023
    The near-term EGU control stringencies and corresponding reductions
in this proposed rulemaking cover the 2023, 2024, and 2025 ozone
seasons. This is the period in which some reductions will be available,
but the large portion of full remedy reductions--mainly those
reductions that are driven by post combustion control installation--
identified in Sections VI.B through VI.D of this proposed rule are not
yet available. The EGU NOX mitigation strategies available
during these initial 3 years are the optimization of existing post-
combustion controls (SCRs and SNCRs) and combustion control upgrades.
As described in Sections VI.B through VI.D of this proposed rule and in
accompanying TSDs, these mitigation measures can be implemented in
under two months in the case of existing control optimization and in 6
months in the case of combustion control upgrades.
    As described in Section VI.B of this proposed rule and in the
identified TSDs, these timing assumptions account for planning,
procurement, and any physical or structural modification necessary. The
EPA provides significant historical data, including the implementation
of the most recent Revised CSAPR Update, as well as engineering studies
and input factor analysis documenting the feasibility of these timing
assumptions. However, these timing assumptions are representative of
fleet averages, and the EPA has noted that some units will likely
overperform their installation timing assumptions, while others may
have unit configuration or operational considerations that result in
their underperforming these timing assumptions. As in prior interstate
transport rules, the EPA is implementing these EGU reductions through a
trading program approach. The trading program's option to buy
additional allowances provides flexibility in the program for outlier
sources that may need more time than what is representative of the
fleet average to implement these mitigation strategies while providing
an economic incentive to outperform rate and timing assumptions for
those sources that can do so. In effect, this trading program
implementation operationalizes the mitigation measures as state-wide
assumptions for the EGU fleet rather than unit-specific assumptions.
    However, starting in 2024, as described in Section VII.B.7 of this
proposed rule, unit-specific daily emissions rate limits are applied to
coal units with existing SCR at a level consistent with operating that
control. The EPA believes that implementing these emissions reductions
at the state level starting in 2023 (through state emissions budgets)
while imposing the unit-specific emissions rate limits in 2024 achieves
the necessary environmental performance as soon as possible while
accommodating any heterogeneity in unit-level implementation schedules
regarding daily operation of optimized SCRs.
    Additionally, as in prior rules, the EPA assumes combustion control
upgrade implementation may take up to 6 months. In the Revised CSAPR
Update, covering 12 of the 25 states for which emissions reduction
requirements for EGUs are established under this proposed action, the
EPA finalized the rule in March of 2021 and thus did not require these
combustion control-based emissions reductions in ozone-season state
emissions budgets until 2022 (year two of that program).\212\ The EPA
is applying the same timing assumption regarding combustion control
upgrades for this proposed rulemaking given the expected similar window
between an anticipated final action date and the start of the year one
ozone season. The EPA is not assuming the implementation of any
additional combustion control upgrades in state emissions budgets until
2024. Therefore, those 13 states covered in this action for EGU
emissions reductions that were not covered in the Revised CSAPR Rule
have 2023 emissions budgets that only reflect optimization of existing
controls. Any identified combustion control upgrade emissions
reductions are reflected beginning in the 2024 ozone-season budgets for
these states. For the 12 states covered under the Revised CSAPR Update,
any identified emissions reduction potential from combustion control
upgrade was included and reflected in those state budgets beginning in
2022 under the Revised CSAPR Update. Therefore, the

EPA is assuming that this combustion control upgrade potential is
available, if not already realized, by the first year of this action
(i.e., 2023) in this proposed rule.
---------------------------------------------------------------------------

    \212\ 86 FR 23093.
---------------------------------------------------------------------------

2. 2026 and Later Years: EGU and Non-EGU NOX Reductions
Beginning in 2026
    In accordance with the good neighbor provision and the downwind
attainment schedule under CAA section 181 for the 2015 ozone NAAQS, the
EPA is proposing to align its analysis and implementation of the
emissions reductions addressing significant contribution from EGU and
non-EGU sources that require relatively longer lead time at a sectoral
scale with the 2026 ozone season, which is the last full ozone season
preceding the August 3, 2027, Serious area attainment date for the 2015
ozone NAAQS.\213\ The EPA proposes to find that this compliance
deadline is the most expeditious date practicable and would achieve the
required emissions reductions prior to the next applicable attainment
date by which such reductions are, in fact, possible. The EPA proposes
to find that it is not possible to require implementation of all
necessary emissions controls across all of the affected EGU and non-EGU
sources by the August 3, 2024, Moderate area attainment date.
---------------------------------------------------------------------------

    \213\ For each nonattainment area classified under CAA section
181(a) for the 2015 ozone NAAQS, the attainment date is ``as
expeditiously as practicable'' but not later than the date provided
in table 1 to 40 CFR 51.1303(a). Thus, for areas initially
designated nonattainment effective August 3, 2018 (83 FR 25776), the
latest permissible attainment dates are: August 3, 2021 (for
Marginal areas), August 3, 2024 (for Moderate areas), August 3, 2027
(for Serious areas), and August 3, 2033 (for Severe areas).
---------------------------------------------------------------------------

    Thus, the EPA is proposing to require compliance with the control
requirements for all non-EGUs and the EGU reductions related to post-
combustion control retrofit identified in this section no later than
the 2026 ozone season (May through September). If finalized in early
2023, the final rule would provide more than three years for EGU and
non-EGU sources to install whatever controls they deem suitable to
comply with required emissions reductions by the 2026 ozone season. In
addition, the publication of this proposal provides roughly an
additional year of notice to these source owners and operators that
they should begin engineering and financial planning now to be prepared
to meet this implementation timetable.
    The EPA views this timeframe for retrofitting post-combustion
NOX emissions controls and other non-EGU controls to be
presumptively reasonable and achievable. A 3-year period for
installation of post-combustion control technologies is consistent with
the statutory timeframe for implementation of the controls required to
address interstate pollution under section 110(a)(2)(D) and 126 of the
Act, the statutory timeframes for implementation of RACT in ozone
nonattainment areas classified as Moderate or above, and other
statutory provisions that establish control requirements for existing
stationary sources of pollution.
    For example, section 126 of the CAA authorizes a downwind state or
tribe to petition the EPA for a finding that emissions from ``any major
source or group of stationary sources'' in an upwind state contribute
significantly to nonattainment in, or interfere with maintenance by,
the downwind state. If the EPA makes a finding that a major source or a
group of stationary sources emits or would emit pollutants in violation
of the relevant prohibition in CAA section 110(a)(2)(D), the source(s)
must shut down within 3 months from the finding unless the EPA directly
regulates the source(s) by establishing emissions limitations and a
compliance schedule extending no later than three years from the date
of the finding, to eliminate the prohibited interstate transport of
pollutants as expeditiously as practicable.\214\ Thus, in the provision
that allows for direct federal regulation of sources violating the good
neighbor provision, Congress established 3 years as the maximum amount
of time available from a final action to when emissions reductions need
to be achieved at the relevant source or group of sources.
---------------------------------------------------------------------------

    \214\ CAA 110(a)(2)(D)(i) and 126(c).
---------------------------------------------------------------------------

    Additionally, for ozone nonattainment areas classified as Moderate
or higher, the CAA requires states to implement RACT requirements less
than three years after the statutory deadline for submitting these
measures to the EPA.\215\ Specifically, for these areas, CAA sections
182(b)(2) and 182(f) require that states implement RACT for existing
VOC and NOX sources as expeditiously as practicable but no
later than May 31, 1995, approximately 30 months after the November 15,
1992, deadline for submitting RACT SIP revisions. For purposes of the
2015 ozone NAAQS, the EPA has interpreted these provisions to require
implementation of RACT SIP revisions as expeditiously as practicable
but no later than January 1 of the fifth year after the effective date
of designation, which is less than 3 years after the deadline for
submitting RACT SIP revisions.\216\ For areas initially designated
nonattainment with a Moderate or higher classification effective August
3, 2018 (83 FR 25776), that implementation deadline falls on January 1,
2023, approximately 29 months after the August 3, 2020 submission
deadline.\217\ Moderate ozone nonattainment areas must also implement
all reasonably available control measures (including RACT) needed for
expeditious attainment within three years after the statutory deadline
for states to submit these measures to the EPA as part of a Moderate
area attainment demonstration.\218\
---------------------------------------------------------------------------

    \215\ See, e.g., 40 CFR 51.1112(a)(3) and 51.1312(a)(3)(i)
(requiring implementation of RACT required pursuant to initial
nonattainment area designations no later than January 1 of the fifth
year after the effective date of designation, which is less than 3
years after the submission deadline under 40 CFR 51.1112(a)(2)) and
51.1312(a)(2)(i), respectively).
    \216\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP
revisions no later than 24 months after the effective date of
designation) and 51.1312(a)(3)(i) (requiring implementation of RACT
SIP revisions as expeditiously as practicable, but no later than
January 1 of the fifth year after the effective date of
designation). For reclassified areas, states must implement RACT SIP
revisions as expeditiously as practicable, but no later than the
start of the attainment year ozone season associated with the area's
new attainment deadline, or January 1 of the third year after the
associated SIP revision submittal deadline, whichever is earlier; or
the deadline established by the Administrator in the final action
issuing the area reclassification. 40 CFR 51.1312(a)(3)(ii); see
also 83 FR 62989, 63012-63014.
    \217\ 40 CFR 51.1312(a)(2)(i) (requiring submission of RACT SIP
revisions no later than 24 months after the effective date of
designation).
    \218\ See, e.g., 40 CFR 51.1108(d) (requiring implementation of
all control measures (including RACT) needed for expeditious
attainment no later than the beginning of the attainment year ozone
season, which, for a Moderate nonattainment area, occurs less than 3
years after the deadline for submission of reasonably available
control measures under 40 CFR 51.1112(c) and 51.1108(a)) and 40 CFR
51.1308(d) (requiring implementation of all control measures
(including RACT) needed for expeditious attainment no later than the
beginning of the attainment year ozone season, which, for a Moderate
nonattainment area, occurs less than three years after the deadline
for submission of reasonably available control measures under 40 CFR
51.1312(c) and 51.1308(a)). Because the attainment demonstration for
a Moderate nonattainment area (including RACT needed for expeditious
attainment) is due three years after the effective date of the
area's designation (40 CFR 51.1308(a) and 51.1312(c)), and all
Moderate nonattainment areas must attain the NAAQS as expeditiously
as practicable but no later than 6 years after the effective date of
the area's designation (40 CFR 51.1303(a)), the beginning of the
``attainment year ozone season'' (as defined in 40 CFR 51.1300(g))
for such an area is less than three years after the due date for the
attainment demonstration.
---------------------------------------------------------------------------

    The EPA notes that the types and sizes of the EGU and non-EGU
sources that the EPA proposes to include in this proposed rule, as well
as the types of emissions control technologies on which the EPA
proposes to base the

emissions limitations that would take effect for the 2026 ozone season,
generally are intended to be consistent with the scope and stringency
of RACT requirements for existing major sources of NOX in
downwind Moderate nonattainment areas and some upwind areas, which many
states have already implemented in their SIPs.\219\ Thus, the timing
Congress allotted for sources in downwind states to come into
compliance with RACT requirements bears directly on the amount of time
that should be allotted here and indicates, as does CAA section 126,
that 3 years is an outer limit on the time that should be given sources
to come into compliance.
---------------------------------------------------------------------------

    \219\ See the Non-EGU Sectors TSD for a discussion of SIP-
approved RACT rules in effect in downwind states.
---------------------------------------------------------------------------

    Finally, with respect to emissions standards for hazardous air
pollutants, section 112(i)(3) of the CAA requires the EPA to establish
compliance dates for each category or subcategory of existing sources
subject to an emissions standard that ``provide for compliance as
expeditiously as practicable, but in no event later than 3 years after
the effective date of such standard,'' with limited exceptions.\220\
Here again, where Congress was concerned with addressing emissions of
pollutants that impact public health, a 3-year time period was allotted
as the time needed for existing sources to come into compliance.
---------------------------------------------------------------------------

    \220\ CAA section 112(i)(3)(B) generally authorizes the EPA to
grant an extension of up to 1 additional year for an existing source
to comply with emissions standards ``if such additional period is
necessary for the installation of controls,'' and sections 112(i)(4)
through (8) provide for limited extensions granted by the President
where certain conditions are met, for existing sources that have
installed the best available control technology (BACT) or technology
required to meet a lowest achievable emissions rate (LAER), and for
new sources for which construction or reconstruction is commenced by
certain dates.
---------------------------------------------------------------------------

    All of these statutory timeframes for implementation of new control
requirements on existing stationary sources indicate that Congress
considered 3 years to be not only a sufficient amount of time but a
maximum amount of time allowable for existing stationary sources to
install pollution controls as necessary for expeditious attainment, to
eliminate prohibited interstate transport of pollutants, and to protect
public health.
    Further, the EPA notes that, given the number of years that have
passed since EPA's promulgation of the 2015 ozone NAAQS and related
nonattainment area designations in 2018, and in light of the Maryland
court's holding that good neighbor obligations for the 2015 ozone NAAQS
should have been implemented by the Marginal area attainment date in
2021,\221\ many states are substantially delayed in implementing their
good neighbor obligations for these NAAQS, and the sources proposed for
NOX emissions control in this rule have continued to operate
for several years without the controls necessary to eliminate their
significant contribution to ongoing and persistent ozone nonattainment
and maintenance problems in other states. Under these circumstances, we
find it more than reasonable to require compliance with the control
requirements for all non-EGUs and the EGU reductions related to post-
combustion control retrofit identified in Section VI.B.1.b of this
proposed rule by the beginning of the 2026 ozone season (i.e., by May
1, 2026). May 1, 2026, is more than 3 years after the date by which the
EPA currently anticipates promulgating a final FIP for the covered
states, more than three years after the January 1, 2023, deadline for
implementation of section 182 RACT SIP provisions in areas classified
as Moderate or higher, and almost 8 years after the October 1, 2018,
deadline for submission of good neighbor SIPs that prohibit significant
contribution to nonattainment or interference with maintenance in
downwind states.\222\
---------------------------------------------------------------------------

    \221\ 958 F.3d at 1203-1204 (remanding the EPA denial of section
126 petition based on the EPA analysis of downwind air quality in
2023 rather than 2021, the year containing the Marginal area
attainment date).
    \222\ CAA sections 110(a)(1) and 110(a)(2)(D)(i) (requiring
states to submit, within 3 years after EPA's promulgation of a new
or revised NAAQS, SIP provisions adequate to satisfy the Good
Neighbor Provision). As the Supreme Court noted in EME Homer City I,
``nothing in the statute places EPA under an obligation to provide
specific metrics to States before they undertake to fulfill their
good neighbor obligations.'' 572 U.S. 489, 510.
---------------------------------------------------------------------------

    As the D.C. Circuit noted in Wisconsin, the good neighbor provision
requires upwind states to ``eliminate their substantial contributions
to downwind nonattainment in concert with the attainment deadlines'' in
the downwind states, even where those attainment deadlines occur before
EPA's statutory deadline to promulgate a FIP.\223\ Referencing the
Supreme Court's description of the attainment deadlines as ``the
heart'' of the CAA, the Wisconsin court noted that some deviation from
the mandate to eliminate prohibited transport by downwind attainment
deadlines may be allowed only ``under particular circumstances and upon
a sufficient showing of necessity,'' e.g., when compliance with the
statutory mandate amounts to an impossibility.\224\
---------------------------------------------------------------------------

    \223\ 938 F.3d at 317-318. For example, the court observed that
the EPA may shorten the deadline for SIP submissions under CAA
section 110(a)(1) and may issue FIPs soon thereafter under CAA
section 110(c)(1), to align the upwind states' deadline for
satisfying good neighbor obligations with the downwind states'
deadline for attaining the NAAQS. Id. at 318.
    \224\ Id. at 316 and 319-320 (noting that any such deviation
must be ``rooted in Title I's framework'' and ``provide a sufficient
level of protection to downwind States'').
---------------------------------------------------------------------------

    For the reasons provided below in this section, the EPA is
proposing to find that installation of certain EGU controls and all
non-EGU controls is not possible by the Moderate area attainment date
for the 2015 ozone NAAQS (i.e., August 3, 2024),\225\ and that the 2026
ozone season, which corresponds to the August 3, 2027, Serious area
attainment date for these NAAQS, is the earliest downwind attainment
date by which the required emissions reductions from these strategies
are possible.
---------------------------------------------------------------------------

    \225\ Compliance by the August 3, 2021, Marginal area attainment
date is also impossible as that date has passed.
---------------------------------------------------------------------------

a. EGU Schedule for 2026 and Later Years
    As discussed in Sections VI.B through VI.D of this proposed rule,
significant emissions reduction potential exists and is included in
EPA's quantification of significant contribution based on the potential
to install post-combustion controls (SCR and SNCRs) at EGUs. However,
as discussed in detail in those sections, the assumption for
installation of this technology on a region-wide scale is 36 months in
this proposed rule. This amount of time allows for all necessary
procurement, permitting, and installation milestones across multiple
units in the covered region. Therefore, the EPA proposes to find that
these emissions reductions are not available any earlier than the 2026
compliance period. For each year in 2026 and beyond, state emissions
budgets include reductions commensurate with these post-combustion
control technologies identified for covered units in Step 3. The EPA
notes that similar compliance schedules and post-combustion control
retrofit installations have been realized successfully in prior
programs allowing similar timeframes. Subsequent to the NOX
SIP Call and the parallel Finding of Significant Contribution and
Rulemaking on Section 126 Petitions (which became effective December
28, 1998, and February 17, 2000, respectively \226\), nearly 19 GW of
SCR

retrofit came online in 2002 and another 42 GW of SCR retrofit came
online for steam boilers in 2003, illustrating that a considerable
volume of SCR retrofit capacity is possible in a 36 month period.
---------------------------------------------------------------------------

    \226\ See 63 FR 57356 (October 27, 1998); 65 FR 2674 (January
18, 2000). The D.C. Circuit stayed the NOX SIP Call by an
order issued May 25, 1999. After upholding the rule in most respects
in Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000), the court lifted
the stay by an order issued June 22, 2000.
---------------------------------------------------------------------------

    However, the EPA is not proposing to apply daily emissions rates on
coal-fired steam EGUs assumed to retrofit SCR until 2027 (as described
in Section VII.B.1.c.i of this proposed rule). The EPA believes that
implementing these emissions reductions at the state level starting in
2026 (through state emissions budgets) while imposing the unit-specific
emissions rate limits in 2027 achieves the necessary environmental
performance as soon as possible while accommodating any heterogeneity
in unit-level implementation schedules regarding installation of new
SCR.\227\
---------------------------------------------------------------------------

    \227\ However, as discussed in Section VII.B.1.c.i of this
proposed rule, EPA's determinations in this regard are not based on
a finding that the retrofit of post-combustion controls would not be
feasible in the 2026 ozone season for all relevant units. The EPA
finds that such retrofits are available and feasible on a fleetwide
scale starting in the 2026 ozone season.
---------------------------------------------------------------------------

b. Non-EGU Schedule for 2026 and Later Years
    For the suite of non-EGU controls on which the EPA has based its
Step 3 findings as described in Section VI of this proposed rule, the
EPA proposes to require that these controls be installed and
operational by the 2026 ozone season and to find that any earlier date
is not possible. The EPA previously examined the time necessary to
install the controls identified for several non-EGU industries.
Although the information on installation times for most NOX
controls applied to glass and cement manufacturing was uncertain, the
EPA identified minimum estimated installation times for a number of
other non-EGU source categories that ranged from several weeks to
slightly over a year. This included timeframes of 42-51 weeks for SNCR
applied to dry cement manufacturing facilities and cement kilns/dryers
burning bituminous coal, 28-58 weeks for SCR applied to boilers and
process heaters, 28-58 weeks for SCR applied to iron and steel in-
process combustion, and 6-8 months for low NOX burners and
flue gas recirculation at iron and steel mills.\228\ Taking into
account necessary scale-up of construction services for multiple
control installations at several emissions units, the time needed to
have NOX monitoring installed and operating, and other
necessary steps in the permitting and construction processes (e.g.,
review of vendor bids), the EPA estimates an additional period of 6 to
18 months may be necessary for existing non-EGU sources to install the
necessary controls, depending on the number of control installations at
a facility.\229\
---------------------------------------------------------------------------

    \228\ Final Technical Support Document (TSD) for the Final
Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment
of Non-EGU NOX Emissions Controls, Cost of Controls, and
Time for Compliance Final TSD (``CSAPR Update Non-EGU TSD''), August
2016 (Table 3), available at https://www.epa.gov/csapr/assessment-non-egu-NOX-emission-controls-cost-controls-and-time-compliance-
final-tsd. See also Institute of Clean Air Companies, SNCR
Committee, ``White Paper, Selective Non-Catalytic Reduction (SNCR)
For Controlling NOX Emissions,'' at 5 (noting that ``SNCR
retrofits typically do not require extended source shutdowns'').
    \229\ 63 FR 57356, 57448 (October 27, 1998). EPA generally
anticipates that any required permitting processes may run
concurrent with other steps in the installation processes and thus
may not significantly lengthen the total time needed for
installation.
---------------------------------------------------------------------------

    Additionally, the EPA previously considered the installation timing
needs for NOX controls (including SCR, SNCR, and combustion
controls) at both EGU and non-EGU sources as part of the 1998
NOX SIP Call.\230\ With respect to combustion controls
(e.g., low-NOX burners, overfire air, etc.), the EPA found
that sources should be able to complete control technology
installations and obtain relevant permits in relatively short
timeframes given considerable experience at that time among sources and
permitting agencies with the implementation of such controls, the fact
that combustion controls are constructed of commonly available
materials (steel, piping, etc.) and do not require reagent during
operation, and the then availability of many vendors of combustion
control technology.\231\
---------------------------------------------------------------------------

    \230\ Id. at 57447-57449.
    \231\ Id. at 57447, 57449.
---------------------------------------------------------------------------

    With respect to post-combustion controls (primarily SCR and SNCR),
the EPA considered three basic factors in assessing installation timing
needs: (1) Availability of materials and labor, (2) the time needed to
implement controls at plants with single or multiple retrofit
requirements, and (3) the potential for interruptions in power supply
resulting from outages needed to complete installations on EGUs.\232\
Assuming adequate supplies of both off-the-shelf hardware (such as
steel, piping, nozzles, pumps, and related equipment) and the catalyst
used in the SCR process, as well as sufficient vendor capacity to
supply retrofit SCR catalyst to sources, and taking into account the
additional time needed for facility engineering review, developing
control technology specifications, awarding a procurement contract,
obtaining a construction permit, completing control technology design,
installation, and testing, and obtaining an operating permit, the EPA
found that (a) about 21 months would be needed to implement an SCR
retrofit on a single unit and (b) about 19 months would be needed to
implement an SNCR retrofit on a single unit.\233\ The EPA also examined
several particularly complicated implementation efforts and found that
34 months would be needed for a plant to install a maximum of 6 SCRs
while 24 months would be needed for a plant to install a maximum of 10
SNCRs.\234\ Finally, the EPA found that the necessary controls could be
installed on EGUs without any disruptions in the supply of electricity
because connections between a NOX control system and a
boiler can generally be completed in 5 weeks or less and thus could
occur during the 5-week planned outage that each EGU typically has each
year.\235\
---------------------------------------------------------------------------

    \232\ Id. at 57448.
    \233\ Id.
    \234\ Id.
    \235\ Id.
---------------------------------------------------------------------------

    Thus, for both EGUs and non-EGUs, EPA's technical analysis for the
1998 NOX SIP Call indicated that a 3-year period would be
sufficient for installation of both combustion and post-combustion
controls, from the planning and specification of controls to completion
of control technology implementation.\236\ EPA's evaluation of the
timeframes for post-combustion controls was based on the Agency's
projection that 639 retrofit installations at EGU sources and 235
retrofit installations at non-EGU industrial sources would be necessary
for existing sources in the covered states to comply with the
NOX SIP Call.\237\ Although the scope of types of non-EGU
sources covered by this proposed FIP is broader, and the estimated
number of emissions units is greater (potentially including as many as
490 emissions units), than the scope and number of non-EGU sources
evaluated in the 1998 NOX SIP Call, and although a later
analysis of timeframes for installation of post-combustion controls at
EGUs produced a more refined estimate for that sector only,\238\ EPA's
prior analyses nonetheless inform the evaluation in this proposal of
the necessary implementation schedule for non-EGU sources given they
generally address NOX control technologies similar to those
that the EPA anticipates non-EGU sources may install to comply with the
provisions of the proposed FIP

(e.g., SCR, SNCR, low-NOX burners and ultra-low
NOX burners).
---------------------------------------------------------------------------

    \236\ Id. at 57449.
    \237\ Id. at 57448 (Table V-1 and Table V-2).
    \238\ See Final Report, ``Engineering and Economic Factors
Affecting the Installation of Control Technologies for
Multipollutant Strategies,'' EPA-600/R-02/073 (October 2002).
---------------------------------------------------------------------------

    Additionally, as part of EPA's evaluation of installation timing
needs in the proposed CAIR (69 FR 4566), the EPA projected that it
would take on average 21 months to install an SCR on one EGU unit, 27
months to install a scrubber on one EGU unit, and 3 years to install
seven SCRs at a single EGU.\239\ The EPA also noted that some EGUs
could install SCR controls in as short of a period as 13 months.\240\
This information and EPA's general experience indicate that a two-year
installation timeframe for a rule requiring installation of new control
technologies across a variety of emissions sources in several
industries on a regional basis is a relatively fast installation
timeframe, but that a 3-year installation timeframe should be feasible
for most if not all of the identified industries. A shorter
installation timeframe of approximately one year would likely raise
significant challenges for sources, suppliers, contractors, and other
economic actors, potentially including customers relying on the
products or services supplied by the regulated sources. Thus, if the
EPA finalizes this proposed rule in 2023, implementation of the
necessary emissions controls across all of the affected non-EGU sources
by the August 3, 2024, Moderate area attainment date would not be
possible.
---------------------------------------------------------------------------

    \239\ 69 FR 4566, 4617 (January 30, 2004) (citing Final Report,
``Engineering and Economic Factors Affecting the Installation of
Control Technologies for Multipollutant Strategies,'' EPA-600/R-02/
073 (October 2002)).
    \240\ Final Report, ``Engineering and Economic Factors Affecting
the Installation of Control Technologies for Multipollutant
Strategies,'' EPA-600/R-02/073 (October 2002), at 21.
---------------------------------------------------------------------------

    For purposes of this proposed rule, the EPA estimates that the
required controls for non-EGU source categories would take up to 3
years to install across the affected industries in the 23 states that
remain linked in 2026. Therefore, based on the available information,
the EPA proposes to require compliance with these non-EGU control
requirements by the beginning of the 2026 ozone season.
    The EPA requests comment on the time needed to install the various
control technologies across all of the emissions units in the Tier 1
and Tier 2 industries. In particular, the EPA solicits comment on the
time needed to obtain permits (including the potential applicability of
NSR requirements), the availability of vendors and materials, design,
construction, and the earliest possible installation times for SCR on
glass furnaces; SNCR or SCR on cement kilns; ultra-low NOX
burners, low NOX burners, and SCR on ICI boilers (coal-
fired, gas-fired, or oil-fired); low NOX burners on large
non-EGU ICI boilers; and low emissions combustion, layered emissions
combustion, NSCR, and SCR on reciprocating rich-burn or lean-burn IC
engines.
    With respect to emissions monitoring requirements, EPA requests
comment on the costs of installing and operating CEMS at non-EGU
sources without NOX emissions monitors; the time needed to
program and install CEMS at non-EGU sources; whether monitoring
techniques other than CEMS, such as predictive emissions monitoring
systems (PEMS), may be sufficient for certain non-EGU facilities, and
the types of non-EGU facilities for which such PEMS may be sufficient;
and the costs of installing and operating monitoring techniques other
than CEMS.
    The EPA also requests comment on whether the FIP should provide a
limited amount of time beyond the 2026 ozone season for individual non-
EGU sources to meet the emissions limitations and associated compliance
requirements, based on a facility-specific demonstration of necessity.
As the D.C. Circuit stated in Wisconsin, the good neighbor provision
may be read to allow for some deviation from the mandate to eliminate
prohibited transport by downwind attainment deadlines, ``under
particular circumstances and upon a sufficient showing of necessity,''
provided such deviation is ``rooted in Title I's framework [and]
provide[s] a sufficient level of protection to downwind States.'' \241\
Consistent with this directive, and recognizing that in general, the
EPA aligns good neighbor obligations in the first instance with the
last full ozone season before the downwind attainment date, the EPA
requests comment on whether individual non-EGU sources should be
allowed to request an extension of the May 1, 2026, compliance deadline
by no more than 1 year (i.e., to May 1, 2027) based on a sufficient
showing of necessity. Any such comments should be supported by a
detailed discussion of the facility-specific economic, technological,
and other circumstances that may justify such an extension. The EPA
notes that claims about infeasibility of controls are generally
insufficient to justify an extension of time to comply, given the
Wisconsin court's holding that the good neighbor provision requires
upwind states to eliminate their significant contribution in accordance
with the downwind states' attainment deadlines, without regard to
questions of feasibility.\242\
---------------------------------------------------------------------------

    \241\ Wisconsin, 938 F. 3d at 320 (citing CAA section 181(a)
(allowing one-year extension of attainment deadlines in particular
circumstances) and North Carolina, 531 F.3d at 912).
    \242\ Wisconsin, 938 F.3d at 313-314, 319 (``When an agency
faces a statutory mandate, a decision to disregard it cannot be
grounded in mere infeasibility''). We note also that in the CSAPR
Close-Out Rule (83 FR 65878, December 21, 2018), the EPA required no
further reductions from upwind states beyond those set forth in the
prior CSAPR Update based, in part, on the Agency's conclusion that
it was not feasible to implement cost-effective emissions controls
before 2023, 2 years after the 2021 attainment deadline for the
downwind serious areas. The D.C. Circuit vacated the Close-Out Rule
for its reliance on the same interpretation of the Good Neighbor
Provision that the court had rejected in Wisconsin. New York v. EPA,
781 F. App'x 4 (D.C. Cir. 2019) (unpublished opinion).
---------------------------------------------------------------------------

    The EPA solicits comment on the specific criteria that the EPA
should apply in evaluating requests for extension of the 2026
compliance deadline for non-EGU sources. Such criteria could include
documentation of inability, despite best efforts, to procure necessary
materials or equipment (e.g., equipment manufacturers are not able to
deliver equipment before a specific date) or hire labor as needed to
install the emissions control technology by 2026; documentation of
installation costs well in excess of the highest representative cost-
per ton threshold identified for any source (including EGUs) discussed
in Section VI of this proposed rule (e.g., vendor estimate showing
equipment cost); documentation of a source owner or operator's
inability to secure necessary financing, due to circumstances beyond
the owner/operator's control, in time to complete the installation of
controls by 2026; or documentation of extreme financial or
technological constraints that would require the subject non-EGU
emissions unit or facility to significantly curtail its operations or
shut down before it could comply with the requirements of this proposed
rule by 2026. Finally, the EPA requests comment on the process through
which the EPA should review and act on an extension request--e.g., the
appropriate deadline for submitting a request, and whether the EPA
should provide an opportunity for public comment before granting or
denying a request.
    The EPA anticipates that the owner or operator of the facility
would bear the burden of establishing the necessity of an extension of
time to comply, based on particular circumstances described and
sufficiently documented in the submitted request. Claims of generalized
financial or economic hardship or any claim that controls are not
necessary to eliminate significant contribution would

not suffice to justify an extension. If the EPA finalizes a provision
allowing sources to request limited extensions of time to comply, the
Agency would review each request on a case-by-case basis as necessary
to ensure consistency with the provisions of title I of the CAA.

B. Regulatory Requirements for EGUs

    To implement the required emissions reductions from EGUs, the EPA
proposes to revise the existing CSAPR NOX Ozone Season Group
3 Trading Program (the ``Group 3 trading program'') established in the
Revised CSAPR Update both to expand the program's geographic scope and
to enhance the program's ability to ensure favorable environmental
outcomes.\243\ The EPA proposes to use a trading program for EGUs
because of the inherently greater flexibility that a trading program
can provide relative to more prescriptive, ``command-and-control''
forms of regulation of sufficient stringency to achieve the necessary
emissions reductions. In the electric power sector, EGUs' extensive
interconnectedness and coordination create the ability to shift both
electricity production and emissions among units, providing a closely
related ability to achieve emissions reductions in part by shifting
electricity production from higher-emitting units to lower-emitting or
non-emitting units. The sector's unusual flexibility with respect to
how emissions reductions can be achieved makes the flexibility of a
trading program particularly useful as a means of lowering the overall
costs of obtaining such reductions. In addition, it is essential for
the electric power sector to retain short-term operational flexibility
sufficient to allow electricity to be produced at all times in the
quantities needed to meet demand simultaneously, and the flexibility of
a trading program can be helpful in supporting this aspect of the
industry as well. As discussed later, to provide improved environmental
outcomes, in this rulemaking, the EPA is proposing certain enhancements
to the current provisions of the Group 3 trading program addressing
environmental performance that will necessarily reduce the flexibility
of the individual units participating in the program to some extent.
However, with the proposed enhancements, the EPA believes the
inherently greater flexibility of a trading program continues to favor
the use of this form of regulation, relative to more prescriptive forms
of regulation, as a vehicle for achieving the emissions reductions from
the electric power sector found to be necessary in this rulemaking.
---------------------------------------------------------------------------

    \243\ If any of the states whose sources currently participate
in the Group 3 trading program is determined in the final rule to
not have additional emissions reduction requirements for EGUs, the
EPA proposes in the alternative to establish a new trading program
substantially similar to the revised Group 3 trading program
described in this proposal that would cover units within the borders
of all the states determined to have emissions reduction
requirements for EGUs in the final rule.
---------------------------------------------------------------------------

    The Group 3 trading program currently applies to EGUs meeting the
program's applicability criteria within the borders of twelve states:
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey,
New York, Ohio, Pennsylvania, Virginia, and West Virginia. Affected
EGUs in these twelve states would continue to participate in the Group
3 trading program as revised in this rulemaking, with some revised
provisions taking effect in the 2023 control period and other revised
provisions taking effect later as discussed elsewhere in this document.
The EPA proposes to expand the Group 3 trading program's geographic
scope to include all of the additional states for which EGU emissions
reduction requirements are being established in this rulemaking.
Affected EGUs within the borders of eight states currently covered by
the CSAPR NOX Ozone Season Group 2 Trading Program (the
``Group 2 trading program'')--Alabama, Arkansas, Mississippi, Missouri,
Oklahoma, Tennessee, Texas, and Wisconsin--would transition from the
Group 2 program to the revised Group 3 trading program at the beginning
of the 2023 control period,\244\ and affected EGUs within the borders
of the five states not currently covered by any CSAPR trading program
for seasonal NOX emissions--Delaware, Minnesota, Nevada,
Utah, and Wyoming--would enter the Group 3 trading program in the 2023
control period following the effective date of a final rule in this
rulemaking. As is the case for the states already in the Group 3
trading program, for each state added to the program, the set of
affected EGUs would include new units as well as existing units and
units located in Indian country within the state's borders as well as
units not located in Indian country. Sections VII.B.2 and VII.B.3 of
this proposed rule provide additional discussion of the proposed
geographic expansion of the Group 3 trading program and the units in
the expanded geography that would likely become subject to the program
under the program's existing applicability provisions.
---------------------------------------------------------------------------

    \244\ Affected EGUs in the two other states currently covered by
the Group 2 trading program--Iowa and Kansas--would continue to
participate in that program.
---------------------------------------------------------------------------

    In addition to expanding the Group 3 trading program's geographic
scope, the EPA proposes to modify the program's regulations
prospectively to include certain enhancements to improve environmental
outcomes. Two of the proposed enhancements would adjust the overall
quantities of allowances available for compliance in the trading
program in each control period so as to maintain the rule's selected
control stringency and related EGU effective emissions rate performance
level as the EGU fleet evolves. First, instead of establishing
emissions budgets for all future years under the program at the time of
the rulemaking, which cannot reflect future changes in the EGU fleet
unknown at the time of the rulemaking, the EPA proposes to revise the
trading program regulations to include a dynamic budgeting procedure.
This procedure would calculate emissions budgets for control periods in
2025 and later years based on more current information about the
composition and utilization of the EGU fleet, specifically data
available from the 2023 ozone season and following (e.g., for 2025,
data from 2023; for 2026, data from 2024; etc.). (Associated revisions
to the program's variability limits and unit-level allowance allocation
procedures would coordinate these provisions with the revised budget-
setting procedures.) Second, starting with the 2024 control period, the
EPA proposes to annually recalibrate the quantity of accumulated banked
allowances under the program to prevent the quantity of allowances
carried over from each control period to the next from exceeding the
target bank level, which would be revised to represent 10.5 percent of
the sum of the state emissions budgets. Together, these enhancements
would protect the intended stringency of the trading program against
potential erosion caused by EGU fleet turnover and would better sustain
over time the incentives created by the trading program to apply
continuously the degree of emissions control the EPA determines is
necessary to address states' good neighbor obligations.
    Two further enhancements to the Group 3 trading program proposed in
this rulemaking would establish provisions designed to promote more
consistent emissions control by individual EGUs within the context of
the trading program. First, starting with the 2024 control period for
most coal-fired EGUs with existing SCR controls and the 2027 control
period for most other coal-fired EGUs, a daily NOX emissions
rate of 0.14 lb/mmBtu would

apply as a backstop to the more stringent seasonal emissions budgets.
Each ton of emissions exceeding a unit's backstop daily emissions rate
would incur a 3-for-1 allowance surrender ratio instead of the usual 1-
for-1 allowance surrender ratio. Second, also starting with the 2024
control period, the trading program's existing assurance provisions,
which require extra allowance surrenders from sources that are found
responsible for contributing to an exceedance of the relevant state's
``assurance level'' (i.e., currently 121 percent of the state's
emissions budget), would be strengthened by the addition of another
backstop requirement. Specifically, for any unit found responsible for
contributing to an exceedance of the state's assurance level, the
revised regulations would prohibit the unit's seasonal emissions from
exceeding by more than 50 tons the emissions that would have resulted
if the unit had achieved a seasonal average emissions rate equal to the
higher of 0.10 lb/mmBtu or 125 percent of the unit's lowest previous
seasonal average emissions rate under any CSAPR seasonal NOX
trading program.\245\
---------------------------------------------------------------------------

    \245\ The requirement would not apply for control periods during
which the unit operated for less than 10 percent of the hours, and
emissions rates achieved in such previous control periods would be
excluded from the comparison.
---------------------------------------------------------------------------

    These two enhancements are designed to ensure that all individual
units with SCR controls have strong incentives to continuously operate
and optimize their controls, and also to ensure that even units without
SCR controls have strong incentives to optimize their emissions
performance when a state's assurance level might otherwise be exceeded.
These enhancements are generally designed to ensure consistency with
EPA's determination regarding the emissions control stringency needed
from EGUs to eliminate significant contribution under the Step 3
multifactor analysis as discussed in Section VI of this proposed rule.
Further, these enhancements are designed to provide greater assurance
that emissions controls will be operated on all days of the ozone
season and therefore necessarily on the days that turn out to be most
critical for downwind ozone levels. The EPA expects that promoting more
consistently good emissions performance by individual EGUs will also
help address disparate impacts of pollution on overburdened communities
from individual units that might otherwise have chosen not to optimize
their emissions performance.
1. Trading Program Background and Overview of Proposed Revisions
a. Current CSAPR Trading Program Design Elements and Identified
Concerns
    The use of allowance trading programs to achieve required emissions
reductions from the electric power sector has a long history, rooted in
the Clean Air Act Amendments of 1990. In Title IV of those amendments,
Congress specified the design elements for a 48-state allowance trading
program to reduce SO2 emissions and the resulting acid
precipitation. Building on the success of that first allowance trading
program as a tool for addressing multi-state air pollution issues,
since 1998 EPA has promulgated and implemented multiple allowance
trading programs for SO2 or NOX emissions to
address the requirements of the CAA's good neighbor provision with
respect to successively more stringent NAAQS for fine particulate
matter and ozone. Most of these trading programs have applied either
exclusively or primarily to EGUs.
    The EPA currently administers six CSAPR trading programs for EGUs
(promulgated in CSAPR, the CSAPR Update, and the Revised CSAPR Update)
that differ in the pollutants, geographic regions, and time periods
covered and in the levels of stringency, but that otherwise are nearly
identical in their core design elements and their regulatory text.\246\
The principal common design elements currently reflected in all of the
programs are as follows:
---------------------------------------------------------------------------

    \246\ The six current CSAPR trading programs are the CSAPR
NOX Annual Trading Program, CSAPR NOX Ozone
Season Group 1 Trading Program, CSAPR SO2 Group 1 Trading
Program, CSAPR SO2 Group 2 Trading Program, CSAPR
NOX Ozone Season Group 2 Trading Program, and CSAPR
NOX Ozone Season Group 3 Trading Program. The regulations
for the six programs are set forth at subparts AAAAA, BBBBB, CCCCC,
DDDDD, EEEEE, and GGGGG, respectively, of 40 CFR part 97.
---------------------------------------------------------------------------

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

assurance provisions on any emissions exceeding a state's assurance
level disincentivizes sources from relying on either in-state banked
allowances or net out-of-state purchased allowances to emit over the
assurance level.
     Finally, other common design elements ensure program
integrity, source accountability, and administrative transparency. Most
notably, each unit must monitor and report emissions and operational
data in accordance with the provisions of 40 CFR part 75; all allowance
allocations or auction results, transfers, and deductions must be
properly recorded in EPA's Allowance Management System; each source
must have a designated representative who is authorized to represent
all of the source's owners and operators and is responsible for
certifying the accuracy of the source's reports to the EPA and
overseeing the source's Allowance Management System account; and
comprehensive data on emissions and allowances are made publicly
available.
    The EPA continues to believe that the current CSAPR trading program
structure established by the common design elements described
previously has important positive attributes, particularly with respect
to the exceptional degree of compliance flexibility it can provide to a
sector such as the electric power sector where such flexibility is
especially useful and valuable. However, the EPA also shares some
stakeholders' concerns about whether the current structure, without
enhancements, is capable of adequately addressing states' good neighbor
obligations with respect to the 2015 ozone NAAQS in light of the
rapidly evolving EGU fleet and the stringency and short-term form of
the standard. One set of concerns relates to the observed tendency
under the current trading programs for the supply of allowances to grow
over time while the demand for allowances falls, reducing allowance
prices and eroding the consequent incentives for sources to effectively
control their emissions. A second, overlapping set of concerns relates
to the general absence of source- or unit-specific emissions reduction
requirements, allowing some individual sources to idle 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 and also have the potential to cause
disproportionate adverse impacts on downwind overburdened communities.
The EPA has analyzed hourly emissions data reported in prior cap-and-
trade programs and identified instances of sources that did not operate
SCR controls for substantial portions of recent ozone seasons. In an
effort to maintain as much compliance and operational flexibility as
possible, ensure controls happen on critically important highest ozone
days, guard against this behavior under a more stringent NAAQS, and
provide relief to overburdened communities, the EPA would require
control operation every day through a unit-level emission rate designed
to ensure reductions occur on the highest ozone days in addition to
maintaining a mass-based seasonal requirement. To meet the statutory
requirement to eliminate significant contribution and interference with
maintenance on the critically important days, this combination of
requirements would require sources to plan to run controls all season,
including the highest ozone days, while giving reasonable flexibility
for occasional operational needs.
    In this rulemaking, the EPA is proposing to revise the Group 3
trading program to include enhancements designed to address both sets
of concerns described above.\247\ The principles guiding the various
proposed revisions and the relationships of the revisions to one
another are discussed in Sections VII.B.1.b and VII.B.1.c of this
proposed rule. The individual proposed revisions are discussed in more
detail in Sections VII.B.4 through VII.B.9 of this proposed rule.
---------------------------------------------------------------------------

    \247\ With the exception of the proposed conforming revisions to
allowance recordation schedules discussed in Section VII.B.12 of
this proposed rule, the EPA is not proposing in this rulemaking to
extend the enhancements proposed for the Group 3 trading program to
the other CSAPR trading programs.
---------------------------------------------------------------------------

b. Enhancements To Maintain Selected Control Stringency Over Time
    The first set of concerns noted about the current CSAPR trading
program structure relates to the programs' ability to maintain the
rule's selected control stringency and related EGU effective emissions
rate performance level as the EGU fleet evolves over time. Under the
structure of the current CSAPR trading programs, the effectiveness of
the programs at maintaining the rule's selected control stringency
depends entirely on how allowance prices over time compare to the costs
of sources' various emissions reduction opportunities, which in turn
depends on the relationship between the supply for allowances and the
demand for allowances. In considering possible ways to address concerns
about the ability to enhance the current trading program structure to
better sustain incentives to control emissions over time, the EPA has
focused on the trading program design elements that determine the
supply of allowances, specifically the approach for setting state
emissions budgets and the rules concerning the carryover of unused
allowances for use in future control periods as banked allowances.
i. Revised Emissions Budget-Setting Process
    In each of the previous rulemakings establishing CSAPR trading
programs, the EPA has evaluated the emissions that could be eliminated
through implementation of certain types of emissions control strategies
available at various cost thresholds to achieve certain rates of
emissions per unit of heat input (i.e., the amount of fuel consumed)
and the effects of the resulting emissions reductions on downwind air
quality. After determining the emissions control strategies and
associated emissions reductions that should be required under the good
neighbor provision by considering these factors in a multifactor test,
the EPA has then projected the amounts of emissions that would remain
after the assumed implementation of the selected emissions control
strategies at various points in the future and has established the
projected remaining amounts of emissions as the state emissions budgets
in trading programs.
    Projecting the amounts of emissions remaining after implementation
of selected emissions controls necessarily requires projections not
only for sources' future emissions rates but also for other factors
that influence total emissions, notably the composition of the future
EGU fleet (i.e., the capacity amounts of different types of sources
with different emissions rates) and their future utilization levels
(i.e., their heat input). To the extent the projections made at the
time of a rulemaking for these other factors prove inaccurate, over
time the emissions budgets may not reflect the intended stringency of
the emissions control strategies identified in the rulemaking as
consistent with addressing states' good neighbor obligations. Further,
projecting EGU fleet composition and utilization has become
increasingly challenging in light of the rapid evolution of the
electric power sector toward more efficient and cleaner sources of
generation, driven by factors including lower prices for natural gas
and wind and solar generation.

    A consequence of using a trading program approach with preset
emissions budgets that do not keep pace with the trends in EGU fleet
composition and heat input is that the preset emissions budgets
maintain the supply of allowances at levels that increasingly exceed
the emissions that would occur even without implementation of the
emissions control strategies used as the basis for determining the
emissions budgets, causing decreases in allowance prices and hence the
incentives to implement the control strategies. As an example, although
the emissions budgets in the CSAPR Update established in 2016 reflected
implementation of the emissions control strategy of operating and
optimizing existing SCR controls, within 4 years the EPA found that EGU
retirements and changes in utilization not anticipated in EPA's
previous budget-setting computations had made it economically
attractive for at least some sources to idle or reduce the
effectiveness of their existing controls (relying on purchased
allowances instead).\248\ While the EPA has provided analysis
indicating that, on average, sources operate their controls more
effectively on high electric demand days, it has also identified cases
where units fail to optimize their controls on these days. Downwind
states have suggested this type of reduced pollution control
performance has occurred on the day and preceding day of an ozone
exceedance.249 250 Such an outcome undermined the ongoing
achievement of emissions rate performance consistent with the control
strategies defined to eliminate significant contribution to
nonattainment and interference with maintenance, including continuous
operation and optimization of existing controls.
---------------------------------------------------------------------------

    \248\ The price of allowances in CSAPR Update states started out
at levels near $800 per ton in 2017 but declined to less than $100
per ton by 2019 and were less than $70 per ton in July 2020 (data
from S&P Global Market Intelligence).
    \249\ 86 FR 23117.
    \250\ See EPA-HQ-OAR-2020-0272-0094. ``. . . is demonstrated
through examination of Maryland's ozone design value days for June
26th-28th, 2019. On those days, Maryland recorded 8-hour ozone
levels of 75, 85 and 83 ppb at the Edgewood monitor. Maryland
Department of the Environment evaluated the daily NOX
emission rate for units in Pennsylvania that were found to influence
the design values on the 3 exceedance days (and 1 day prior to the
exceedance) against the past-best ozone season 30-day rolling
average optimized NOX rate (which tends to be higher than
the absolute lowest seasonal average rate).''
---------------------------------------------------------------------------

    In the Revised CSAPR Update, the EPA took steps to better address
the rapid evolution of the EGU fleet, specifically by setting updated
emissions budgets for individual future years though 2024 that reflect
future EGU fleet changes known with reasonable certainty at the time of
the rulemaking. Some commenters requested that the EPA also update the
year-by-year emissions budgets to reflect future fleet changes that
might become known after the time of the rulemaking, but the EPA
declined to do so, in part because no methodology for making future
emissions budget adjustments in response to post-rulemaking data had
been included in the proposal for the rulemaking.
    Based on information available as of December 2021, it appears that
the emissions budgets set for the first control period covered by the
Revised CSAPR Update generally succeeded at creating incentives to
operate emissions controls under the Group 3 trading program for the
programs' first control period. However, the EPA recognizes that the
lack of emissions budget adjustments after 2024 in conjunction with
industry trends toward more efficient and cleaner resources would
likely lead to a surplus of allowances after the adjustments end. In
this rulemaking, besides setting new emissions budgets for the 2023 and
2024 control periods, the EPA also proposes to extend the Group 3
trading program budget-setting methodology used in the Revised CSAPR
Update to routinely set emissions budgets for each future control
period in the year before that control period, with each emissions
budget reflecting the latest available information on the composition
and utilization of the EGU fleet at the time that emissions budget is
determined.
    The current budget-setting methodology established in the Revised
CSAPR Update and the proposed revisions are discussed in detail in
Section VII.B.4 of this proposed rule and the Ozone Transport Policy
Analysis Proposed Rule TSD. To summarize here, the Revised CSAPR
Update's emissions budget-setting methodology includes three primary
steps: (1) Establishment of a baseline inventory of EGUs adjusted for
known retirements and new units, with heat input and emissions rate
data for each EGU in the inventory based on recent historical data; (2)
adjustment of the baseline data to reflect assumed emissions rate
changes resulting from known new controls, known gas conversions, and
implementation of the emissions control strategies used to determine
states' good neighbor obligations; and (3) application of an increment
or decrement to reflect the effect on emissions from projected
generation shifting among the units in a state at the emissions
reduction cost associated with the selected emissions control
strategies. In this rulemaking, the EPA proposes to modify this
methodology in two ways. First, the baseline EGU inventory and heat
input data, but not the emissions rate data, would be updated for each
control period using the most recent available reported data. For
example, in early 2024, using the final data reported for 2023, the EPA
would update the baseline inventory and heat input data used to
determine state emissions budgets for the 2025 control period. Second,
the EPA would not apply an increment or decrement to any state
emissions budget for projected generation shifting associated with
implementation of the selected control strategies, because any such
shifting should already be reflected in the heat input data used to
update the baseline.\251\
---------------------------------------------------------------------------

    \251\ Emission reductions derived from generation shifting will
be captured in the dynamic budgets in all cases. For the pre-set
budget years it is estimated and incorporated through an additional
calculation step. For dynamic budget years, it is directly
incorporated through the inclusion of updated heat input data
reflecting observed, compliance period generation shifting.
---------------------------------------------------------------------------

    The EPA believes that the proposed revisions to the emissions
budget-setting process would substantially improve the ability of the
emissions budgets to keep pace with changes in the composition and
utilization of the EGU fleet. The revised methodology would account for
the electric power sector's overall trends toward more efficient and
cleaner resources, both of which tend to decrease total heat input at
affected EGUs. The revised methodology would also account for other
factors that could lead to increased heat input in some states, such as
generation shifting from other states or increases in electricity
demand caused by rising electrification. The updating procedure would
be specified in the program regulations and the computations, which
would be straightforward, could be performed in a spreadsheet to
deliver reliable results. EPA would provide public notice of the
preliminary calculations and the data used by March 1 of the year
preceding the control period and would provide an opportunity for
submission of any objections to the data and preliminary calculations
before finalizing the budgets for each control period by May 1 of the
year before the control period to which those budgets apply. Thus, for
example, sources and other stakeholders will have certainty by May 1,
2024, of the emissions budgets that will be set for the 2025 control
period that starts May 1, 2025.

    It bears emphasis that the annually updated information would
concern only the composition and utilization of the EGU fleet and not
the emissions rate data also used in the emissions budget computations.
The emissions budget computations for all years would reflect only the
specific emissions control strategies used to determine states' good
neighbor obligations as determined in this rulemaking, along with fixed
historical emissions rates for units that are not assumed to implement
additional control strategies, thereby ensuring that the annual updates
would eliminate emissions as determined to be required under the good
neighbor provision. The stringency of the emissions budgets would
simply reflect the stringency of the emissions control strategies
determined in the Step 3 multifactor analysis and would do so more
consistently over time than EPA's previous approach of computing
emissions budgets for all future control periods at the time of the
rulemaking.
    The proposed revisions to state emissions budgets and the budget-
setting process are discussed further in Section VII.B.4 of this
proposed rule. Proposed coordinated revisions to the determination of
state-level variability limits and assurance levels and to unit-level
allowance allocations are discussed in Sections VII.B.5 and VII.B.9 of
this proposed rule, respectively.
ii. Allowance Bank Recalibration
    Besides the levels of the emissions budgets, the second design
element of the trading program structure that affects the supply of
allowances in each control period, and that consequently also affects
the ability of a trading program to maintain the rule's selected
control stringency and related EGU effective emissions rate performance
level as the EGU fleet evolves over time, is the set of rules
concerning the carryover of unused allowances for use in future control
periods as banked allowances. As noted previously, trading and banking
of allowances in the CSAPR trading programs can serve a variety of
purposes: Continuously incentivizing sources to reduce their emissions
even when they already hold sufficient allowances to cover their
expected emissions for a control period, facilitating compliance cost
minimization, accommodating necessary operational flexibility, and
promoting allowance market liquidity. All of these purposes are
advanced by rules that allow sources to trade allowances freely (both
with other sources and with non-source entities such as brokers). All
of these purposes are also advanced by rules that allow unused
allowances to be carried over for possible use in future control
periods, thereby preserving a value for the unused allowances. However,
while the EPA considers it generally advantageous to place as few
restrictions on the trading of allowances as possible,\252\
unrestricted banking of allowances has a potentially significant
disadvantage offsetting its advantages, namely that it allows what
might otherwise be temporary surpluses of allowances in some individual
control periods to accumulate into a long-term allowance surplus that
reduces allowances prices and weakens the trading program's incentives
to control emissions. With weakened incentives, some operators would be
more likely to choose not to continuously operate and optimize their
emissions controls, imperiling the ongoing achievement of emissions
rate performance consistent with the control strategies defined as
eliminating significant contribution to nonattainment and interference
with maintenance.
---------------------------------------------------------------------------

    \252\ The advantages of trading programs discussed earlier in
this section--providing continuous emissions reduction incentives,
facilitating compliance cost minimization, and supporting
operational flexibility--depend on the existence of a marketplace
for purchasing and selling allowances, and broader marketplaces
generally provide greater market liquidity and therefore make
trading programs better at providing these advantages. The EPA
recognizes that unrestricted use of net purchased allowances--
meaning quantities of purchased allowances that exceed the
quantities of allowances sold--by a source or group of sources as an
alternative to making emissions reductions can interfere with the
achievement of the desired environmental outcome, and Section
VII.B.1.c of this proposed rule discusses the enhancements to the
Group 3 trading program that the EPA is proposing in this rulemaking
to reduce reliance on net purchased allowances by incentivizing or
requiring better environmental performance at individual EGUs.
However, the concern arises from the use of an excessive quantity of
net purchased allowances for a particular purpose, not from the
existence of a marketplace where allowances may be freely bought and
sold.
---------------------------------------------------------------------------

    As discussed in detail in Section VII.B.6 of this proposed rule,
the EPA is proposing to revise the Group 3 trading program by adding
provisions that would establish a routine recalibration process for
banked allowances that would be carried out in August 2024 and each
subsequent August, after the compliance deadline for the control period
in the previous year. In each recalibration, the EPA would 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 target level of 10.5 percent of the sum of the state
emissions budgets for the current control period. The procedure would
entail identifying the ratio of the target bank amount to the total
quantity of banked allowances held in all accounts before the
conversion and then, if the ratio was 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.
    The EPA believes this revision to the Group 3 trading program's
banking provisions would complement the proposed revisions to the
budget-setting process by ensuring that the annual bank recalibration
would prevent 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.\253\
---------------------------------------------------------------------------

    \253\ The EPA recognizes there will be a data lag inherent in
the future year emissions budgets, because the budgets would reflect
fleet composition and utilization data reported for a previous
control period. This means that the budgets for some individual
control periods may fail to fully keep pace with the EGU fleet's
trends toward more efficient and cleaner resources. Nonetheless, the
new approach is a substantial improvement in environmental
performance of the program compared to a more unlimited approach to
allowance banking.
---------------------------------------------------------------------------

    The calibration procedure would 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 would be left in the
account after the recalibration for possible sale or use in meeting
future compliance requirements. Because the banked allowances would
always have value, the opportunity to bank allowances would continue to
advance the purposes served by otherwise unrestricted banking as
described above. 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 proposal to routinely recalibrate the allowance bank is
discussed further in Section VII.B.6 of this proposed rule.
d. 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 and also have the potential to cause
disproportionate adverse impacts on downwind overburdened communities.
    This EPA intends that the trading program enhancements described in
Section VII.B.1.b of this proposed rule would improve the Group 3
trading program's ability to sustain emissions control incentives over
time such that needed emissions performance would 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, the
EPA proposes to supplement the previously discussed enhancements with
two other new sets of provisions that would apply to certain individual
units within the larger context of the Group 3 trading program. The
allowance price would continue to be the most important driver of good
environmental performance for most units, but the proposed unit-level
requirements would be important supplemental drivers of performance and
would offer additional assurance that significant contribution is
eliminated on a daily basis during the ozone season by continuous
operation of existing pollution controls.
i. Unit-Specific Backstop Daily Emissions Rates
    The first of the proposed 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 would 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) would apply to emissions during the ozone season from any large
coal-fired EGU with existing SCR controls exceeding a daily average
NOX emissions rate of 0.14 lb/mmBtu. The additional
allowance surrender requirement would 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 would have to
be surrendered by the same compliance deadline of June 1 after each
control period. The amount of additional allowances to be surrendered
would 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, and multiplying by
two. Starting with the 2027 control period, the 3-for-1 surrender ratio
would apply in the same way to all large coal-fired EGUs, consistent
with EPA's proposed determinations, first, that a control stringency
reflecting installation and operation of SCR controls on all large
coal-fired EGUs is appropriate to address states' good neighbor
obligations with respect to the 2015 ozone NAAQS, and second, that such
controls could reasonably be installed by the 2026 control period.
    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.\254\ 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 below and in the EGU NOX Mitigation Strategies
Proposed Rule TSD in the docket. While the EPA has in prior ozone
transport actions not found sufficient evidence of emissions control
idling or non-operation to take the step of building in enhancements to
the trading program to ensure unit-level control operation, our review
of that information applied to this context suggests this problem could
become more prevalent in future years relevant to this action. 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 proposal
to ensure the emissions control strategy selected at Step 3 is indeed
implemented at Step 4. Thus, particularly in the context of the more
stringent 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
emission 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.\255\ 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 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. The EPA is proposing to adopt backstop daily
rate limits at the individual unit level for this purpose, implemented
in the context of a trading program (i.e., through enhanced allowance
surrender ratios), as an alternative to adopting enforceable rate
limits.
---------------------------------------------------------------------------

    \254\ EPA-HQ-OAR-2020-0272. Comment submitted by Ben Grumbles,
Secretary, Maryland Department of the Environment (MDE).
    \255\ The CSAPR Update was a partial remedy and the Revised
CSAPR Update addressed downwind nonattainment and maintenance issues
that were projected to be resolved within a 4 year window. In
contrast, this rule reflects a full remedy and is addressing
downwind nonattainment and maintenance issues that are projected to
persist for more than a decade.
---------------------------------------------------------------------------

    The purpose of establishing a backstop daily NOX
emissions rate and implementing it through additional

allowance surrender requirements instead of as an enforceable rate
limit 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 VII.B.7 of
this proposed rule, under existing trading programs without the
enhancements proposed 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.
    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 in Figures 1 and 2 to
Section VII.B.1.c.i, included in Appendix G of the Ozone Transport
Policy Analysis Proposed 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 emission 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.\256\
---------------------------------------------------------------------------

    \256\ EPA-HQ-OAR-2020-0272-0094.
---------------------------------------------------------------------------

    The EPA believes that the design of the proposed daily emissions
rate provisions would 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 would 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.\257\
---------------------------------------------------------------------------

    \257\ While the proposed design of the daily emissions rate
provision would not deter another theoretical type of poor emissions
control behavior--i.e., turning off emissions controls at times of
peak electricity demand in order to sell the additional electricity
that otherwise would have been used to run the control equipment--
EPA's analysis of hourly emissions data does not show that this
behavior is actually occurring. The data actually suggest the
opposite--that emissions controls are generally operated better on
peak demand days than on other days. See the Ozone Policy Analysis
Proposed Rule TSD for additional details about the assessment of the
tons and the Discussion of Short-term Emissions Limit document for
an assessment of control operation on peak demand days.
---------------------------------------------------------------------------

    The EPA proposes to apply 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 best practice for
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. In the context of
the need for states to address their good neighbor obligations with
respect to the 2015 ozone NAAQS, the EPA is proposing to determine that
a control stringency reflecting universal installation and operation of
SCR technology at large coal-fired EGUs is appropriate, based on a
multi-factor test that includes consideration of cost-effectiveness
along with air quality factors. Finally, where SCR controls are
installed, 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 proposed
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 proposing to include some SCR
controls at gas-fired steam units in the selected control stringency,
the EPA is not proposing to include universal SCR controls at gas-fired
steam units. Because the EPA does not propose to determine 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 proposing to apply 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 proposed level of the daily average
NOX emissions rate--0.14 lb/mmBtu--through analysis of
historical data, as described in Section VII.B.7 of this proposed rule.
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
are proposed to 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 would be reflected in the state
emissions budgets under the proposal. Likewise, the daily average
emissions rate provisions are proposed to apply beginning in the 2027
control period for other large coal-fired units, one control period
later than emissions reductions consistent with the installation and
operation of SCR controls for such units would be reflected in the
state emissions budgets under the proposal. With respect to the units
with existing SCR controls, not applying the daily average rate
provisions until 2024 would serve two purposes. First, it would provide
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 would be
held to increased allowance-surrender consequences for exceeding the
daily rate. Second, it would provide 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 would apply to the SCR-equipped units based
on the combined

NOX emissions rates measured in the common stacks.\258\
---------------------------------------------------------------------------

    \258\ Based on the information reported by sources to the EPA in
their monitoring plans under 40 CFR part 75, five plants subject to
this proposal have SCR-equipped and non-SCR-equipped coal-fired EGUs
that exhaust together to common stacks: The Clifty Creek plant in
Indiana; the Cooper, Ghent, and Shawnee plants in Kentucky; and the
Sammis plant in Ohio.
---------------------------------------------------------------------------

    With respect to the units without existing SCR controls, not
applying the daily average emissions rate provisions until 2027 would
also serve two purposes. First, it would provide a window for plant
personnel to gain experience operating any new SCR controls, and
second, it would provide some timing flexibility for any individual
unit operators who fail to complete SCR control installations before
the start of the 2026 control period. With respect to both sets of
units, the EPA believes that the lag in applicability of one control
period is permissible because the emissions budget provisions are the
principal provisions intended to drive the emissions reductions
required under the proposal, while the daily average emissions rate
provisions are included only to backstop those provisions.
    The EPA believes that the proposed unit-specific daily emissions
rate provisions would strengthen the incentives for individual coal-
fired units with SCR controls to operate and optimize performance of
the controls. Continuous operation and optimization of post-combustion
controls at individual units would help address individual days that
prove in real time to be most critical for downwind ozone levels.
Better continuous emissions performance by individual units would also
help address disparate impacts of pollution on overburdened communities
downwind from the units.
    The proposed unit-specific target daily emissions rates are
discussed further in Section VII.B.7 of this proposed rule.
ii. Unit-Specific Emissions Limitations Contingent on Assurance Level
Exceedances
    The second of the proposed trading program enhancements intended to
improve emissions performance at the level of individual units is the
addition of unit-specific secondary emissions limitations. The
secondary emissions limitations would be determined on a unit-specific
basis according to each unit's individual performance but would 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% 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 would consist 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 proposed secondary emissions limitation would be in addition
to, not in lieu of, the primary emissions limitation applicable to each
source, which would continue 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
would 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 proposed unit-specific secondary emissions limitation
would take 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 proposing 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, 906-908 (D.C. Cir. 2008). EPA's programs to
eliminate significant contribution must therefore achieve this
prohibition, and the new evidence of exceedances of the assurance
provisions demonstrate that EPA's existing approach may not be
sufficient to accomplish this statutory mandate.
    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 proposing to
correct 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 principal purpose of the proposed
secondary emissions limitations is to strengthen the assurance
provisions, which apply on a statewide, seasonal basis, the unit-
specific structure of the new limitations would strengthen the
incentives for individual units to maintain their emissions performance
at levels consistent with their previously demonstrated capabilities.
For units with existing post-combustion emissions controls, the new
limitations would strengthen the incentives to operate and optimize the
controls continuously, and for units without such existing controls,
the new limitations would strengthen the incentives to minimize
NOX emissions rates through other possible measures such as
improved maintenance and optimization of combustion parameters.
Continuous operation of post-combustion controls and greater attention
to the combustion process at individual units 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 would also help address disparate impacts of
pollution on overburdened communities downwind from some such units.
    The proposed unit-specific secondary emissions limitations are
discussed further in Section VII.B.8 of this proposed rule.
2. Expansion of Geographic Scope
    As part of the proposed approach for implementing the
NOX emissions reductions from EGUs identified as necessary
to address various states' obligations under the good neighbor
provision with respect to the 2015 ozone NAAQS, the EPA is proposing to
expand the existing geographic scope of the existing CSAPR
NOX Ozone Season Group 3 Trading Program to encompass the
additional states (and Indian country within the borders of such
states) found to have such obligations with respect to EGUs.
Specifically, the EPA is proposing to expand the Group 3 trading
program to include the following states and Indian country within the
borders of the states: Alabama, Arkansas, Delaware, Minnesota,
Mississippi, Missouri, Nevada, Oklahoma, Tennessee, Texas, Utah,
Wisconsin, and Wyoming. Any unit located in a newly added jurisdiction
that meets the existing applicability criteria for the Group 3 trading
program would become an affected unit under the program, as discussed
in Section VII.B.3 of this proposed rule.
    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.\259\
In contrast, within the proposed 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 would meet the program's
applicability criteria. Issues related to state, tribal, and federal
jurisdiction with respect to sources in Indian country in general and
in these areas in particular are discussed in Section IV.C.2 of this
proposed rule. EPA's proposed approach for determining a portion of
each state's budget for each control period that would 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 VII.B.9 of this proposed rule.
---------------------------------------------------------------------------

    \259\ 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 IV.C.2.a.
---------------------------------------------------------------------------

    Units in each state would 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 possible is that, as discussed in
Section VII.B.11 of this proposed rule, the effective date of a final
rule in this rulemaking may 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--Delaware, Minnesota, Nevada, Utah, and
Wyoming--EPA proposes that the sources would begin participating in the
Group 3 trading program on the later of May 1, 2023, or the final
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, Tennessee, Texas, and Wisconsin--EPA
proposes that the sources would begin participating in the Group 3
trading program on May 1, 2023, regardless of the final 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 would not substantively affect the sources'
requirements prior to the rule's effective date. This approach provides
a simpler transition for the sources currently 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 VII.B.11 of this proposed rule contains further discussion of
the rationale for this approach and the specific proposed transitional
provisions.
    The EPA notes that under the proposed rule, the expanded Group 3
trading program would include not only the 22 states for which the EPA
is proposing to determine that the required control stringency
includes, among other measures, installation of new post-combustion
controls, but also the three states--Alabama, Delaware, and Tennessee--
for which the EPA is proposing to determine 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,
in order 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 proposed
enhancements to the design of the trading program, even where states
have been assigned differing emissions control stringencies. First, the
existing assurance provisions would be substantially strengthened
through the addition of the unit-specific secondary emissions
limitations discussed in Sections VII.B.1.c.ii and VII.B.8 of this
proposed rule. Second, by ensuring that individual units operate their
emissions controls effectively, the unit-specific backstop daily
emissions rate provisions discussed in Sections VII.B.1.c.i and VII.B.7
of this proposed rule would 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 would be
necessary for sources in Alabama, Delaware, and Tennessee to be
excluded from the revised Group 3 trading program simply because their
emissions budgets would reflect a different selected emissions control
stringency than the other states in the program.
    The EPA requests comment on the proposed expansion of the
geographic scope of the Group 3 trading program to include the states
and areas of Indian country identified above. The EPA also requests
comment on the proposed timing under which the two sets of states and
Indian country within the

respective states' borders would be added to the program.
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 EPA is not proposing in this rulemaking to revise 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 would 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 proposed
additional states where such other programs currently are in effect--
Alabama, Arkansas, Minnesota, Mississippi, Missouri, Oklahoma,
Tennessee, Texas, and Wisconsin (including Indian country within the
borders of such states)--would also become subject to the Group 3
trading program.
    In the proposed additional states where other CSAPR trading
programs are not currently in effect--Delaware, Nevada, Utah, and
Wyoming (including Indian country within the borders of such states)--
units already subject to the Acid Rain Program generally would also
meet the applicability criteria for the Group 3 trading program,
especially if the units are not capable of producing both electricity
and useful thermal energy. 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 and that do not report the
capability to produce both electricity and useful thermal energy, 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 one program but not the
other. Using data reported to the U.S. Energy Information
Administration, the EPA has identified 10 sources in Delaware, Nevada,
Utah, and Wyoming (and Indian country within the borders of the states)
with 27 units that appear to meet the general applicability criteria
for the Group 3 trading program and that either (1) do not currently
report NOX emissions and operating data to the EPA under the
Acid Rain Program or (2) currently report NOX emissions and
operating data to the EPA under the Acid Rain Program and also report
the capability to produce both electricity and useful thermal energy.
These units are listed in Table VII.B.3-1 of this proposed rule. For
each of these units, the table shows the estimated historical heat
input and emissions data that the EPA proposes to use for the unit when
determining state emissions budgets if the unit is ultimately treated
as subject to the Group 3 trading program.\260\ The EPA currently lacks
sufficient information to determine whether any of the units listed in
the table meets all of the relevant criteria to qualify for an
exemption from the Group 3 trading program as a cogeneration unit or a
solid waste incineration unit.
---------------------------------------------------------------------------

    \260\ As discussed in Section VII.B.10.b of this proposed rule,
the EPA expects that any unit that becomes subject to the Group 3
trading program pursuant to a final rule in this rulemaking and that
does not already report emissions data to the EPA in accordance with
40 CFR part 75 would not be required to report emissions data or be
subject to allowance holding requirements under the Group 3 trading
program until May 1, 2024, because of the minimum time interval
allowed for installation and certification of the required
monitoring systems. Such a unit would 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. As indicated in the notes to Table VII.B.3-1 of this
proposed rule, six of the listed units have reported to the Energy
Information Administration that they plan to retire in 2023.

                                     Table VII.B.3-1--Selected Existing Units That Could Be Affected Under Proposal
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Estimated
                                                                                Estimated     ozone season
                                                                                ozone season     average NOX
             State                Facility ID     Facility name            Unit ID               Unit type          heat input    emissions rate   Notes
                                                                                (mmBtu)       (lb/mmBtu)

--------------------------------------------------------------------------------------------------------------------------------------------------------
Delaware......................             591  Christiana.......  11....................  CT...................           1,974          0.2594       1
Delaware......................             591  Christiana.......  14....................  CT...................           1,816          0.2027       1
Delaware......................           52193  Delaware City      DCPP2.................  Boiler...............         872,824          0.0176       2
                                                 Refinery.
Delaware......................           52193  Delaware City      DCPP3.................  Boiler...............       2,380,430          0.0169       2
                                                 Refinery.
Delaware......................           52193  Delaware City      DCPP4.................  Boiler...............       1,374,817          0.0438    2, 3
                                                 Refinery.
Delaware......................           52193  Delaware City      MECCU1................  CT...................       1,679,396          0.0070       2
                                                 Refinery.
Delaware......................           52193  Delaware City      MECCU2................  CT...................       1,679,396          0.0062       2
                                                 Refinery.
Delaware......................            7153  Hay Road.........  1.....................  CT...................       1,354,272          0.0685       1
Delaware......................            7153  Hay Road.........  2.....................  CT...................       1,311,286          0.0663       1