reported, to which the above-derived representative unit-level
percentages of heat input are applied. The EPA uses a three-year
baseline period for state-level heat input versus the five-year
baseline period noted previously for unit-level heat input because
there is less variation from year to year at the state level compared
to the unit level. Multiplying the representative unit-level
percentages of heat input by the representative state-level heat input
yields a normalized unit-level heat input value for each affected EGU.
This step assures that the total heat input being reflected in a
dynamic state budget does not exceed the average total heat input
reported by affected EGUs in that state from the three most recent
years. Finally, each normalized unit-level heat input value is
multiplied by the emissions rate reflecting the assumed unit-specific
control stringency for each particular year (determined at Step 3) to
get a unit-level emissions estimate. These unit-level emissions
estimates are then summed to the state level to identify the dynamic
budget for that year. This procedure to derive normalized unit-level
heat input is captured in the following table:

                                            Table VI.B.4.b-1--Derivation of Normalized Unit-Level Heat Input
                                                                     [Illustrative]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           Representative unit-                      Representative state
                                2022     2023     2024     2025     2026     level heat input     Representative   level heat input (avg 3   Normalized
                                Heat     Heat     Heat     Heat     Heat   (avg of 3 highest of     unit-level        most recent state      unit--level
                               input    input    input    input    input          past 5)             percent              totals)           heat input
--------------------------------------------------------------------------------------------------------------------------------------------------------
Unit A......................      100      200      150      200      300                   233               41%                      483           199
Unit B......................       50      100      200       50      100                   133                24                      483           114
Unit C......................      250      150      150      200      100                   200                35                      483           170
                             ---------------------------------------------------------------------------------------------------------------------------

    State Total.............      400      450      500      450      500                   567  ................  .......................  ............
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The EPA will issue these dynamic budget quantifications
approximately 1 year before the relevant control period. We view such
actions as ministerial in nature in that no exercise of agency
discretion is required. For instance, starting in early 2025, the EPA
would take the most recent three years of state-level heat input data
and the most recent five years of unit-level heat input data and
calculate 2026 state emissions budgets using the methodology described
previously. For 2026-2029, EPA is establishing the preset state
emissions budgets finalized in this rulemaking and will only supplant
those preset emissions budgets with the to-be-published dynamic
emissions budgets if, for a given state and a given control period,
that dynamic budget yields a higher level of emissions than the
corresponding preset budget finalized in this rulemaking. For 2030 and
beyond, the EPA solely uses the dynamic budget process.
    By March 1 of 2025, and each year thereafter, the EPA will make
publicly available through a NODA the preliminary state emissions
budgets for the subsequent control period and will provide stakeholders
with a 30-day opportunity to submit any objections to the updated data
and computations. (This process will be similar to the releases of data
and preliminary computations for allocations from new unit set-asides
that is already used in existing CSAPR trading programs.) By May 1 of
2025, and each year thereafter, the EPA will publish the dynamic
budgets for the ozone-season control period in the following calendar
year. Through the 2029 ozone season control period, these budgets will
only be imposed if the applicable dynamic state budget is higher than
the corresponding preset state budget finalized in this rulemaking.
Preliminary and final unit-level allowance allocations for the units in
each state in each control period will be published on the same
schedule as the dynamic budgets for the control period. For the control
periods from 2026 through 2029, the allocations will reflect the higher
of the preset or dynamic budget for each state, and after 2030, the
allocations will reflect the dynamic budgets. Additional details,
corresponding data and formulas, and examples for the dynamic budget
are described in the Ozone Transport Policy Analysis Final Rule TSD.
    Comment: Multiple commenters claimed that designing a dynamic
budget process that relies on a single year of yet-to-be known heat
input data may produce an unrepresentative view of fleet operations for
the immediate ensuing years. Commenters pointed to the hypothetical of
another pandemic-like year (e.g., 2020) occurring in the future, noting
that 2020 would have been a poor choice for estimating 2022 fleet
operation and the same would likely hold true if a similar event
occurred, for example, in 2025--that would consequently make that year
a poor choice as a representative of 2027 baseline. They further
pointed out that severe weather events and operating disruptions (a
large nuclear plant outage) can similarly render a single year baseline
a risky choice to inform future expectations.
    Response: Insofar as the commenters are addressing the reference
period for dynamic budget computation regarding years of data that have
not yet occurred and therefore not currently available for evaluating
their representative nature, EPA agrees and is incorporating a rolling
3-year baseline at the state level and a rolling 5-year baseline at the
unit level for determining dynamic budgets in this final rule. These
multi-year rolling baseline (or reference periods) will minimize any
otherwise undue impact from individual years where fleet-level or unit-
level heat input was uncharacteristically high or low. EPA determined
that such an approach, while not needed for preset budgets, is
necessary in the case of dynamic budgets because the baseline in that
instance is occurring in a future year and therefore is not knowable
and available to test for representativeness at the time of the final
rule. To control for this type of uncertainty, the EPA finds it
appropriate to use a multi-year baseline in this instance per commenter
suggestion. While a multi-year baseline may have a slight drawback of
using a slightly more dated past fleet performance (including emissions
from higher emitting EGUs that may have subsequently reduced
utilization by the target year for which the dynamic budget is being
calculated) to estimate the expected future fleet performance at the
emissions performance levels determined by the Step 3 result in this
rulemaking, that drawback is worth the advantage of protecting against
instances where atypical circumstances in the most recent single year
may occur and not be representative of the subsequent year for which
the dynamic budget is being estimated. This singular drawback of moving
to a multi-year baseline is most pronounced in the early years of
dynamic budgeting. Therefore, EPA is able to lessen the impact of this
drawback of the multi-year baseline by extending the earliest start
date of dynamic budgets from 2025 (as proposed) to 2026 in the final
rule.
    Comment: Commenters suggested that the dynamic budget procedure
would not provide enough advance notice of state budget and unit level
allocation for sources to adequately plan future year operation.
    Response: EPA disagrees with the notion that the timing of the
dynamic budget determination would occur too close to the control
period to allow adequate operations planning for compliance. As
described previously, the dynamic budget level would be provided
approximately 1 year in advance of the start of the control period
(i.e., around May 1), and the allowance allocations would occur on July
1, approximately 10 months prior to the start of the compliance period.
Not only is this an adequate amount of time as demonstrated by the
successful implementation of past rules that have been finalized and
implemented within several months of the beginning of the first
affected compliance period (e.g., Revised CSAPR Update), but EPA notes
it is maintaining similar trading program flexibility and banking
flexibilities of past programs which provide further opportunities for
sources to procure allowances and plan for any future operating
conditions. Finally, as noted previously, the EPA is providing preset
budgets for the years 2023-2029, which serve as an effective floor on
the state's ultimate emissions budget level for years 2026-2029, as

states will receive the higher of the preset or dynamic budget for
those years. This provision of certain preset state emissions budgets
serving as a floor level for 2026-2029 should further assuage
commenters' concerns regarding planning certainty about allowance
allocations and state emissions budget levels during this period of
power sector transition to cleaner energy sources.
    Comment: Commenters raised concerns that there is a two-year lag in
the dynamic budgets in that, for example, for the dynamic budget in the
2026 control period, the calculations will be based on heat input and
inventory information reflective of data through 2024. Commenters
contend that, if there is a much greater need for allowances for
compliance due to unavoidable or unforeseen need for a higher amount of
heat input than reflected in prior years' data, the budget for that
control period will not reflect this need, and the allowances will only
become available when the dynamic budget is calculated using that
information (i.e., 2025 data would be reflected starting in the 2027
dynamic budget). According to commenters, this lag could present a
serious compliance challenge. Other commenters raised a concern in the
opposite direction about the potential ``slack'' created by the lag
time--meaning that as high-emitting units retire, their emissions and
operation will still inform the state emissions budgets for additional
years beyond their retirement due to the lag.
    Response: The EPA recognizes there will be a data lag inherent in
the computation of future year dynamic emissions budgets, because the
dynamic budgets will reflect fleet composition and utilization data
from recent previous control periods rather than the control periods
for which the dynamic budgets are being calculated. This means that the
resulting dynamic budgets will reflect a limited lag behind the actual
pace of the EGU fleet's trends. However, on the whole, those trends are
clearly toward more efficient and cleaner generating resources. Thus,
the data lag on the whole will inure to the compliance benefit of EGUs
by resulting in dynamic budgets that are generally calculated at levels
likely to be somewhat higher than what a dynamic budget calculation
reflecting real-time EGU operations would produce. The EPA believes
this data lag is worthwhile to provide more compliance planning
certainty and advance notice to affected EGUs of the dynamic budget
applicable to an upcoming control period. Furthermore, this data lag in
dynamic budget computation is comparable to the data lag of quantifying
preset state budgets for 2023 through 2025 based upon 2021 data, and at
no point in the long history of EPA's trading programs has such a data
lag in state budget computation yielded any compliance problems for
affected EGUs. Without dynamic budgeting, the data lag inherent in
calculating preset budgets would grow unabated with the passage of
time, as a fixed reference year of heat input levels would continually
apply regardless of potentially higher heat input levels farther and
farther into the future. By eliminating the increase in the length of
the data lag, this new dynamic budgeting approach is a substantial
improvement in performance of the program relative to previous
approaches that were not capable of capturing changes over time in the
fleet and its utilization beyond the scheduled changes known to the EPA
at the time of establishing preset budgets.
    The EPA disagrees that this lag will in fact pose compliance
challenges for EGUs even if the unlikely scenario described by
commenters were to occur. Several factors influence this. First, the
change in methodology to preset budgets serving as a floor on budgets
through 2029 means that the dynamic budget methodology can only produce
an increase in the budget from this final rule through that year.
Second, the adoption of a multi-year approach for identifying the heat
input used to calculate the dynamic budgets will smooth the year-to-
year budget changes and effectively eliminate the possibility of
greatest concern, which was that a single year of unusually low heat
input would be used to set the budget for a subsequent year that turned
out to have unusually high heat input. While a year of unusually high
heat input for a given state may still occur, the state's budgets for
those years will never be based on heat input from an anomalously low
year, but instead will always be based on an average of several years'
heat input. Third, because the Group 3 trading program is an interstate
program implemented over a wide geographic region, and it is unlikely
that all regions of the country would uniformly experience a marked
increase in fossil fuel heat input necessitating an additional supply
of allowances, it is likely that allowances will be available for trade
from one area of the country where there is less demand to another area
where there is greater demand. Fourth, as explained in section VI.B.5
of this document, each state's assurance level will adjust to reflect
actual heat input in that year. Specifically, the EPA will determine
each state's variability limit for a given control period so that the
percentage value used will be the higher of 21 percent or the
percentage (if any) by which the total reported heat input of the
state's affected EGUs in the control period exceeds the total reported
heat input of the state's affected EGUs as reflected in the state's
emissions budget for the control period. Thus, if in year 2030, for
example, a state's actual heat input levels increase to a level that is
not reflected in the dynamic budget calculation using earlier years of
data, the assurance level (which absent the unusually high heat input
would be 121 percent of the state's budget) will be calculated by the
EPA following the 2030 ozone season, using that higher reported heat
input. This will avoid imposing a three-for-one allowance surrender
penalty on sources except where emissions exceed the assurance level
even factoring in the increase in heat input in that year. Finally, as
some commenters observed, the inherent data lag in dynamic budget
quantification means that a state budget for the year 2030 will
continue to reflect emissions from any EGU that retires before the 2030
control period but is still operating anytime during the 2026-2028
reference years from which the 2030 dynamic budget will be calculated.
Given the likely ongoing trend of relatively high-emitting EGU
retirements over time, this method for determining dynamic budgets
should further assist the ability of remaining EGUs to obtain
sufficient allowances to cover future heat input levels.
    With respect to the comments expressing concern that dynamic
budgets would create too much slack because of the lag in incorporating
retirements, the EPA observes that dynamic budgets will yield a closer
representation of Step 3 control stringency across the future fleet
than preset budgets for years in which retirement plans are currently
relatively unknown. Moreover, any risk that the lag would lead to an
unacceptably large surplus of allowances is limited by EPA's
finalization of the annual bank recalibration to 21 percent and 10.5
percent of the budget beginning in 2024 and 2030 respectively. The
corresponding risk that a lag will lead sources to not operate
emissions controls, due to a surplus of allowances, is also limited by
the backstop daily emissions rates that start in 2024 (for sources with
existing SCR controls) and no later than 2030 for other coal-fired
sources.
    Comment: Commenters allege that the dynamic budget methodology is
effectively a ``one-way ratchet'' because, if EGUs pursue compliance
strategies

such as reduced utilization or generation shifting to comply with the
rule rather than install or optimize pollution controls pursuant to the
identified Step 3 emissions control strategies, the effect will be that
the dynamic budget calculated in a future year will reflect that
reduced heat input, but the applied emissions rate assumption will be
the same. Thus, the approach according to commenters actually
``punishes'' sources for achievement of emissions reductions
commensurate with EPA's Step 3 determinations through alternative
compliance means, by producing a smaller budget in later years (less
heat input multiplied by the same emissions rate). If the source again
reduces utilization or shifts generation to comply with this budget,
then budgets in later years will again ratchet down, and so on.
    Response: First, the claims of dynamic budgeting being a one-way
ratchet are incorrect. As pointed out at proposal, the dynamic budget
process would allow for increased utilization to result in increased
budgets. Moreover, this concern is entirely mooted for the period 2026
through 2029 with the shift to preset budgets serving as a floor;
dynamic budgeting can only increase the budget used in any given year
in this time period. Additionally, the use of a multi-year average heat
input in the budget-setting calculations will, on the whole, modulate
the dynamic budgets such that the budgets over time will only gradually
change with changes in the operating profile of the EGU fleet.
    For the control periods 2030 and later, this rule is premised on
the expectation that all large coal-fired EGU sources identified for
SCR-retrofit potential will, if they continue operating in 2030 or
later, have installed the requisite post-combustion controls. Thus, the
backstop daily emissions rate applies for all such sources beginning in
the 2030 ozone season. In this latter period (post-2030), the EPA
disagrees that the dynamic budget will punish fleet segments seeking to
continue to pursue a strategy of reduced utilization. Rather, the
dynamic budget will simply continue to reflect the Step 3 emissions
control stringency. For instance, if there are two otherwise high-
emitting sources in a state that can reduce emissions by operating SCR,
this rule's control stringency finds it cost effective for both sources
to operate their controls. If one source retires and is replaced by new
lower-emitting generation, it is not a punishment to have the budgets
adjust in a way that still incentivize remaining units to operate their
controls. This is simply right-sizing the budget to an evolving fleet.
It is a feature of the rule, not a flaw, and is designed to address
observed instances in prior rules where market-driven reduced
utilization resulted in non-binding (i.e., overly slack) budgets and
corresponding conditions where the incentive to operate a control
dissipated over time. In the event that sources reduce utilization
whether for compliance purposes or market-driven reasons, that also
does not obviate the importance of continuing to incentivize the Step 3
emissions control stringency at identified sources.
c. Final Preset State Emissions Budgets
    For affected EGUs in each covered state (and Indian country within
the state's borders), this final rule establishes preset budgets for
the control periods 2023 through 2029. For control periods 2026 through
2029, any of those preset budgets may be supplanted by the
corresponding dynamic budget that will be tabulated at later date, if
and only if that dynamic budget yields a higher amount. For 2030 and
beyond, the dynamic budget formula promulgated in this rule will be
applied to future year data to quantify state emissions budgets for
those control periods. The procedures for allocating the allowances
from each state budget among the units in each state (and Indian
country within the state's borders) are described in section VI.B.9 of
this document. The amounts of the final preset state emissions budgets
for the 2023 through 2029 control periods are shown in Table VI.B.4.c-
1.

    Table VI.B.4.c-1--CSAPR NOX Ozone Season Group 3 Preset State Emissions Budgets for the 2023 Through 2029
                                                 Control Periods
                                                 [Tons] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                 Final       Final       Final      Preset      Preset      Preset      Preset
                               emissions   emissions   emissions   emissions   emissions   emissions   emissions
            State               budgets     budgets     budgets     budgets     budgets     budgets     budgets
                               for 2023    for 2024    for 2025    for 2026    for 2027    for 2028    for 2029
----------------------------------------------------------------------------------------------------------------
Alabama.....................       6,379       6,489       6,489       6,339       6,236       6,236       5,105
Arkansas....................       8,927       8,927       8,927       6,365       4,031       4,031       3,582
Illinois....................       7,474       7,325       7,325       5,889       5,363       4,555       4,050
Indiana.....................      12,440      11,413      11,413       8,410       8,135       7,280       5,808
Kentucky....................      13,601      12,999      12,472      10,190       7,908       7,837       7,392
Louisiana...................       9,363       9,363       9,107       6,370       3,792       3,792       3,639
Maryland....................       1,206       1,206       1,206         842         842         842         842
Michigan....................      10,727      10,275      10,275       6,743       5,691       5,691       4,656
Minnesota...................       5,504       4,058       4,058       4,058       2,905       2,905       2,578
Mississippi.................       6,210       5,058       5,037       3,484       2,084       1,752       1,752
Missouri....................      12,598      11,116      11,116       9,248       7,329       7,329       7,329
Nevada......................       2,368       2,589       2,545       1,142       1,113       1,113         880
New Jersey..................         773         773         773         773         773         773         773
New York....................       3,912       3,912       3,912       3,650       3,388       3,388       3,388
Ohio........................       9,110       7,929       7,929       7,929       7,929       6,911       6,409
Oklahoma....................      10,271       9,384       9,376       6,631       3,917       3,917       3,917
Pennsylvania................       8,138       8,138       8,138       7,512       7,158       7,158       4,828
Texas.......................      40,134      40,134      38,542      31,123      23,009      21,623      20,635
Utah........................      15,755      15,917      15,917       6,258       2,593       2,593       2,593
Virginia....................       3,143       2,756       2,756       2,565       2,373       2,373       1,951
West Virginia...............      13,791      11,958      11,958      10,818       9,678       9,678       9,678
Wisconsin...................       6,295       6,295       5,988       4,990       3,416       3,416       3,416
                             -----------------------------------------------------------------------------------

    Total...................     208,119     198,014     195,259     151,329     119,663     115,193     105,201
----------------------------------------------------------------------------------------------------------------
Table Notes:
\a\ The state emissions budget calculations pertaining to Table VI.B.4.c-1 are described in greater detail in
  the Ozone Transport Policy Analysis Final Rule TSD. Budget calculations and underlying data are also available
  in Appendix A of that TSD.
\b\ In the event this final rule becomes effective after May 1, 2023, the emissions budgets and assurance levels
  for the 2023 control period will be adjusted under the rule's transitional provisions to ensure that the
  increased stringency of the new budgets would apply only after the rule's effective date. The 2023 budget
  amounts shown in Table VI.B.4.c-1 do not reflect these possible adjustments. The transitional provisions are
  discussed in section VI.B.12 of this document.

5. Variability Limits and Assurance Levels
    Like each of the other CSAPR trading programs, the Group 3 trading
program includes assurance provisions designed to limit the total
emissions from the sources in each state (and Indian country within the
state's borders) in each control period to an amount close to the
state's emissions budget for the control period, consistent with the
principle that each state's sources must be held to the elimination of
significant contribution within that state, while allowing some
flexibility beyond the emissions budget to accommodate year-to-year
operational variability beyond sources' reasonable ability to control.
For each state, the assurance provisions establish an assurance level
for each control period, defined as the sum of the state's emissions
budget for the control period plus a variability limit, which under the
Group 3 trading program regulations in effect before this rulemaking
was 21 percent of the relevant state emissions budget. The purpose of
the variability limit is to account for year-to-year variability in EGU
operations, which can occur for a variety of reasons including changes
in weather patterns, changes in electricity demand, and disruptions in
electricity supply from other units or from the transmission grid.
Because of the need to account for such variability in operations of
each state's EGUs, the fact that emissions from the state's EGUs may
exceed the state's emissions budget for a given control period is not
treated as inconsistent with satisfaction of the state's good neighbor
obligations as long as the total emissions from the EGUs remain below
the state's assurance level. Emissions from a state's EGUs above the
state's emissions budget but below the state's assurance level are
treated in the same manner as emissions below the state's emissions
budget in that such emissions are subject to the same requirement to
surrender allowances at a ratio of one allowance per ton of emissions.
In contrast, emissions above the state's assurance level for a given
control period are strongly discouraged as inconsistent with the
state's good neighbor obligations and are subject to an overall 3-for-1
allowance surrender ratio. The establishment of assurance levels with
associated extra allowance surrender requirements was intended to
respond to the D.C. Circuit's holding in North Carolina requiring the
EPA to ensure within the context of an interstate trading program that
sources in each state are required to address their good neighbor
obligations within the state and may not simply shift those obligations
to other states by failing to reduce their own emissions and instead
surrendering surplus allowances purchased from sources in other
states.\319\
---------------------------------------------------------------------------

    \319\ 531 F.3d at 908.
---------------------------------------------------------------------------

    In this rulemaking, the EPA did not propose and is not making
changes to the basic structure of the Group 3 trading program's
assurance provisions, which will continue to set an assurance level for
each control period equal to the state's emissions budget for the
control period plus a variability limit and will continue to apply a 3-
for-1 surrender ratio to emissions exceeding the state's assurance
level.\320\ Each assurance level also will continue to apply to the
collective emissions of all units within the state and Indian country
within the state's borders.\321\ However, the EPA is making a change to
the methodology for determining the variability limits. Specifically,
the EPA will determine each state's variability limit for a given
control period so that, instead of always multiplying the state's
emissions budget for the control period by a value of 21 percent, the
percentage value used will be the higher of 21 percent or the
percentage (if any) by which the total reported heat input of the
state's affected EGUs in the control period exceeds the total
historical heat input of the state's affected EGUs as reflected in the
state's emissions budget for the control period. For example, if the
total reported heat input of the state's covered sources for the 2025
control period is 130 percent of the historical heat input used in
computing the state's 2025 budget, then the state's variability limit
for the 2025 control period will be 30 percent of the state's emissions
budget instead of 21 percent of the state's emissions budget. The EPA
expects that the minimum 21 percent will apply in almost all instances,
and that the alternative, higher percentage value will apply only in
control periods where operational variability causes an unusually large
increase relative to the historical data used in setting the state's
emissions budget, which would be a situation meriting a temporarily
higher variability limit and assurance level. The revised methodology
for determining the variability limits will apply both with respect to
control periods when a state's emissions budget is a preset budget
established in this final rule and with respect to control periods when
a state's emissions budget is a dynamically-determined budget computed
using the procedures laid out in the regulations, and it will apply
starting with the 2023 control period rather than starting with the
2025 control period as proposed.
---------------------------------------------------------------------------

    \320\ As discussed in section VI.B.8, the EPA is also
establishing a new secondary emissions limitation for individual
units that will apply in situations where an exceedance of the
relevant state's assurance level has occurred.
    \321\ See 40 CFR 97.1002 (definitions of ``common designated
representative,'' ``common designated representative's assurance
level'' and ``common designated representative's share''),
97.1006(c)(2), and 97.1025.
---------------------------------------------------------------------------

    The purpose of the revision to the variability limits is to better
align the variability limits for successive control periods with the
heat input data used in setting the state emissions budgets. Under the
final rule, each dynamically

determined emissions budget will be computed using the latest available
reported heat input, which for each budget set for a control period in
2026 or a later year will be the average state-level heat input for the
control periods two, three, and four years before the control period
whose budget is being determined (for example, the dynamic state
emissions budgets for the 2026 control period will be computed in early
2025 using the reported state-level heat input for the 2022-2024
control periods). The revised variability limits will be well
coordinated with the budgets established using this dynamic budgeting
process, because the percentage change in the actual heat input for the
control period relative to the earlier multi-year average heat input
used in computing the state's emissions budget will be an appropriate
measure of the degree of operational variability actually experienced
by the state`s EGUs in the control period relative to the assumed
operating conditions reflected in the state's budget. Setting a
variability limit in this manner is thus entirely consistent with the
overall purpose of including variability limits in the assurance
provisions.
    As discussed in sections VI.B.1.b.i and VI.B.4, for the 2023-2025
control periods the state emissions budget for a given control period
will be the preset budget determined in this rule, and for the 2026-
2029 control periods, the state emissions budget for a given control
period will be the preset budget determined in this rule rather than
the dynamically determined budget computed in the year before the
control period unless the dynamic budget is higher than the preset
budget. If the state emissions budget is the preset budget, the
historical heat input data reflected in that budget will be the heat
input data for the 2021 control period, adjusted to reflect projected
changes in fleet composition over time that are known at the time of
this rulemaking, but not adjusted to reflect changes in fleet
composition that are not known at the time of the rulemaking or changes
in the utilization of individual units.\322\ In this case, the
variability limit for the control period would be the higher of 21
percent or the percentage change in the actual heat input for the
control period relative to the heat input for the 2021 control period
as adjusted to reflect the projected changes in fleet composition. The
EPA believes it is reasonable to apply the same principle in setting
the variability limit in control periods where the preset floor budgets
are used as in control periods where the dynamically determined budgets
are used, because the preset floor budgets are computed using the same
principles as the dynamically determined budgets, with the major
difference being that the available heat input data used in computing
the preset budgets are necessarily less current. Accordingly, because
preset budgets established in this manner are used starting with the
2023 control period, the EPA believes it is also reasonable to begin
implementing the revised methodology for determining variability limits
starting with the 2023 control period.
---------------------------------------------------------------------------

    \322\ The total heat input amount used in computing each state's
preset emissions budget for each control period from 2023 through
2029 is included in Appendix A of the Ozone Transport Policy
Analysis Final Rule TSD at column I of the ``State 2023''-``State
2029'' worksheets.
---------------------------------------------------------------------------

    The reason the EPA is using the higher of a fixed 21 percent or the
percentage change in heat input computed as just described is that the
EPA believes that, for operational planning purposes, it can be useful
for sources to know in advance of the control period a minimum value
for what the variability limit could turn out to be. Because a state's
actual total heat input for a control period is not known until after
the end of the control period, this revision will have the consequence
that the state's final variability limit and assurance level for the
control period also will not be known until after the control period.
However, because the rule provides that the variability limit will
always be at least 21 percent, the sources in a state will be able to
rely for planning purposes on the knowledge that the assurance level
will always be at least 121 percent of the state's emissions budget for
the control period. Advance knowledge of the minimum possible amount of
the assurance level can be useful to sources, because one way a fleet
owner can be confident that it will never incur the 3-for-1 allowance
surrender ratio owed for emissions exceeding its state's assurance
level is to plan its operations so as to never allow the emissions from
its fleet to exceed the fleet's aggregated share of the state's
assurance level for the control period. Knowing that the variability
limit will always be at least 21 percent will provide sources with
minimum values they could use for such planning purposes.
    The EPA believes that 21 percent is a reasonable value to use as
the minimum variability limit. To determine appropriate variability
limits for the trading programs established in CSAPR, the EPA analyzed
historical state-level heat input variability over the period from 2000
through 2010 as a proxy for emissions variability, assuming constant
emissions rates. See 76 FR 48265. Based on that analysis, the
variability limits for ozone season NOX in both CSAPR and
the CSAPR Update were set at 21 percent of each state's budget, and
these variability limits for the NOX ozone season trading
programs were then codified in 40 CFR 97.510 and 97.810, along with the
respective state budgets.\323\ For the Revised CSAPR Update, the EPA
performed an updated variability analysis for the twelve states being
moved into the Group 3 trading program in that rulemaking, evaluating
historical state-level heat input variability over the period from 2000
through 2019. The updated analysis again resulted in a variability
estimate of 21 percent. The EPA also considered shorter time periods
for the updated analysis and found that the resulting variability
estimates were not especially sensitive to the particular time period
analyzed.\324\ A further updated analysis for this rulemaking again
results in a variability estimate of 21 percent for most states, and
although the historical analysis indicates a higher percentage for the
covered state with the smallest total heat input figures in this
analysis--New Jersey--the EPA does not consider it appropriate to raise
the minimum variability limit percentage beyond 21 percent for all
other covered states based on the analytic results for one state, where
small absolute heat input figures have resulted in a larger variability
percentage.\325\ (Moreover, because of the provision allowing a state's
variability limit for a given control period to be higher than 21
percent if the state's actual heat input exceeds the heat input used to
set the state's emissions budget by more than 21 percent, there is no
need to set a minimum variability limit higher than 21 percent
specifically for New Jersey.) Based on the consistent conclusions of
these multiple analyses, the EPA is continuing to use 21 percent as the

minimum value in the revised approach for establishing variability
limits for all control periods under this rule.
---------------------------------------------------------------------------

    \323\ Briefly, the 21 percent variability limit was determined
in the analysis by identifying, for all the states in the region
covered by the ozone season NOX trading program, and at a
95 percent confidence level, the maximum expected deviation in any
state's total heat input for any single control period in the data
sample from that state's trend-adjusted mean total heat input for
all the control periods in the data sample. For details on the
original variability analysis for 26 states over the 2000-2010
period, including a description of the methodology, see the Power
Sector Variability Final Rule TSD from the CSAPR (EPA-HQ-OAR-2009-
0491-4454), available in the docket for this rule.
    \324\ For the updated variability analysis for twelve states for
the 2000-2019 period, see the Excel file ``Historical Variability in
Heat Input 2000 to 2019.xls'', available in the docket for this
rule.
    \325\ See the Excel document, ``OS Heat Input--Variability 2000
to 2021.xls'' for updated data, application of the CSAPR variability
methodology, and results applied to heat input for 2000 through 2021
for all states and for the region collectively.
---------------------------------------------------------------------------

    The provisions of the final rule relating to assurance levels and
variability limits are unchanged from proposal, with the exception that
the provision establishing a higher variability limit for a state in a
given control period where the state's actual heat input exceeds the
heat input used in computing the state emissions budget for that
control period by more than 21 percent will be implemented starting
with the 2023 control period instead of the 2025 control period.
    Comment: Some commenters supported the EPA's proposal to raise a
state's variability limit above 21 percent for a given control period
if the state's actual heat input for the control period was more than
121 percent of the historical heat input used to set the state's budget
for that control period. These commenters agreed with the EPA that
making this adjustment is consistent with the assurance provisions'
purpose of strongly incentivizing each state to achieve its required
emissions reductions within the state while also accounting for year-
to-year variability in electric system operations.
    One commenter stated that the EPA should not finalize the proposed
revision to the variability limit provisions, claiming that by allowing
sources in some states to increase utilization and heat input so as to
exceed the state's budget by more than 21 percent in a given year, the
adjustment would then cause the state's subsequent dynamically
determined budgets to be higher, allowing greater emissions over time.
    Response: The EPA disagrees with the comment advocating against
finalization of the proposed change to the variability limit
provisions. The Agency continues to view the proposed change as useful
for accommodating instances where, because of electrical system
operating needs, a state's actual total heat input in a control period
exceeds the historical heat input used to set the state emissions
budget for the control period, potentially causing increased emissions
even when all EGUs in a state are achieving emissions rates consistent
with the Step 3 emissions control stringency. Moreover, the EPA does
not believe that the provision would lead to higher overall program-
wide budgets. No extra allowances would be created by the increase in a
state's variability limit, so with or without the adjustment, any
allowances to cover the emissions in excess of the state's budget would
still need to be obtained through acquisition of allowances issued to
sources in other states or the use of banked allowances. Thus, to the
extent that the change in the variability limit provisions facilitates
shifting of generation from some states to other states, increased heat
input in the first set of states would generally be offset by decreased
heat input in the second set of states, such that any increases in
future dynamic budgets for the first set of states would be offset by
decreases in future dynamic budgets for the second set of states. In
addition, the final rule's use of multiple years of historical heat
input data to compute the dynamically-determined state budgets will
moderate the effect of any single year's heat input on the dynamically-
determined budgets for future control periods.
6. Annual Recalibration of Allowance Bank
    As discussed in section VI.B.1.b of this document, the EPA is
making two revisions to the Group 3 trading program designed to better
maintain the Step 3 emissions control stringency over time. The first
proposed revision, discussed in section VI.B.4 of this document, is to
adopt a dynamic budget-setting methodology that will allow state
emissions budgets in future years to reflect more accurate information
about the composition and utilization of the EGU fleet. The second,
complementary, revision is to recalibrate the bank of unused allowances
each control period to prevent allowance surpluses from accumulating
and adversely impacting the ability of the trading program in future
control periods to maintain the Step 3 emissions control stringency.
    As proposed and now finalized in this rule, the bank recalibration
process will start with the 2024 control period, after the compliance
process for the 2023 control period for all current and newly added
states in the Group 3 trading program has been completed. The
recalibration process for each control period will be carried out on or
shortly after August 1 of that control period, two months after the
compliance deadline for the previous control period, making the date of
the first recalibration August 1, 2024. The recalibrations take place
on August 1 each year because compliance for the previous control
period would not be completed until after June 1. However, because data
on the amounts of allowances held are publicly available and the total
quantity of allowances needed for compliance for the previous control
period will be known shortly after the end of that control period,
sources and other market participants will be able to ascertain with
reasonable accuracy shortly after the end of each control period what
degree of recalibration to expect for the next control period, even if
the recalibration would not actually be carried out until the following
August. The EPA will make an estimate of the applicable calibration
ratio for each control period publicly available no later than March 1
of the year of the control period for which the bank will be
recalibrated.
    Before undertaking a recalibration process each control period, the
EPA will first determine whether the total amount of all banked Group 3
allowances from previous control periods held in all facility accounts
and general accounts in the Allowance Management System exceeds the
target bank amount. (For this purpose, no distinction will be made
between banked Group 3 allowances issued from the state emissions
budgets for previous control periods and banked Group 3 allowances
issued through the conversion of previously banked Group 2 allowances.)
If the total amount of banked Group 3 allowances does not exceed the
target bank amount, the EPA will not carry out any recalibration for
that control period. If the total amount of unused allowances does
exceed the target bank amount, the EPA will determine for each account
with holdings of banked Group 3 allowances the account-specific
recalibrated amount of allowances, computed as the account's total
holdings of banked Group 3 allowances immediately before the
recalibration multiplied by the target bank amount and divided by the
total amount of banked Group 3 allowances in all accounts, rounded up
to the nearest allowance. Finally, the EPA will deduct from each
account any banked Group 3 allowances exceeding the account's
recalibrated amount of banked allowances.
    As the target bank amount used in the recalibration process for
each control period, the EPA will use an amount determined as a
percentage of the sum of the state emissions budgets for the control
period. For the control periods from 2024 through 2029, the target
percentage will be 21 percent, which is the sum of the states' minimum
variability limits.\326\ For control periods in 2030 and later years,
the target percentage will be 10.5 percent, or half of the sum of the
states' minimum

variability limits. In the proposal, the EPA cited two reasons for
proposing the 10.5 percentage amount. First, in the transition from
CSAPR to the CSAPR Update, where the EPA set a target bank amount 1.5
times the sum of the variability limits, and in the transition from the
CSAPR Update to the Revised CSAPR Update, where the EPA set a target
bank amount of 1.0 times the sum of the variability limits, in each
case the initial bank proved larger than necessary, as total emissions
of all sources in the program were less than the budgets. Second, an
analysis of year-to-year variability of heat input for the region
covered by this rule suggests that the regional heat input for an
individual year can be expected to vary by up to 10.5 percent above or
below the central trend with 95 percent confidence. This variability
analysis is an application to the entire region of the variability
analysis EPA has performed for individual states to establish the
minimum variability limit of 21 percent for the states in the trading
program.\327\ When the analysis is performed at the regional level, the
data show less year-to-year variation than when the analysis is
performed at the individual state level. Within the trading program
structure, it is reasonable to use variability analyzed at the level of
individual states to set the variability limits, which apply at the
level of individual states, while using variability analyzed at the
level of the overall region to set a target level for a bank, which
will apply at the level of the overall program.
---------------------------------------------------------------------------

    \326\ As discussed in section VI.B.5, an individual state's
variability limit can be higher than 21 percent in a given control
period if the state's actual heat input for that control period is
more than 121 percent of the historical heat input used in computing
the state emissions budget for the control period.
    \327\ See the Power Sector Variability Final Rule TSD from
CSAPR, available at https://www.epa.gov/csapr/power-sector-variability-final-rule-tsd for a description of the methodology.
Also see the Excel document ``OS Heat Input--Variability 2000 to
2021.xls'' for updated data, application of the CSAPR variability
methodology, and results applied to heat input for 2000 through 2021
for all states and for the region collectively.
---------------------------------------------------------------------------

    In the final rule, in response to comments, the EPA has determined
to maintain the 10.5 target percentage for the reasons discussed in
previous paragraphs, but to defer application of this target percentage
until the 2030 control period. For the control periods from 2024
through 2029, the EPA will instead use a target percentage of 21
percent. The reason for using a higher target percentage for the 2024-
2029 control periods is to provide additional support for allowance
market liquidity during these years, which both the EPA and commenters
view as an important period of generating fleet transition for the
power industry.
    The annual bank recalibrations, at either ratio, are an important
enhancement to the trading program that will help maintain the control
stringency determined to be necessary to address states' good neighbor
obligations for the 2015 ozone NAAQS over time. Moreover, the
recalibrations are less complex than alternative approaches would be.
For example, the NOX Budget Trading Program established in
the NOX SIP Call also contained provisions designed to
prevent excessive accumulations of banked allowances on program
stringency, but those provisions--under the name ``progressive flow
control''--introduced uncertainty as to whether banked allowances would
be usable to offset one ton of emissions or less than one ton of
emissions in the current control period. As a consequence of this
uncertainty, in some control periods, allowances banked from earlier
control periods traded at lower prices than allowances issued for the
current control period.\328\ The EPA considers the recalibration
mechanism established in this rule to be simpler with less associated
uncertainty. Following each bank recalibration, all allowances usable
for compliance in the control period will have known, equal compliance
values for the remainder of the control period and until the deadline
for surrendering allowances after the control period.
---------------------------------------------------------------------------

    \328\ For more discussion of the progressive flow control
mechanism, as well as allowance price data showing a discounted
value for banked allowances, see ``NOX Budget Trading
Program: 2005 Program Compliance and Environmental Results''
(September 2006) at 28-30, https://www.epa.gov/sites/default/files/2015-08/documents/2005-nbp-compliance-report.pdf.
---------------------------------------------------------------------------

    Finally, the EPA observes that the recalibration mechanism is
entirely consistent with the Agency's existing authority under 40 CFR
97.1006(c)(6) to ``terminate or limit the use and duration'' of any
Group 3 allowance ``to the extent the Administrator determines is
necessary or appropriate to implement any provision of the Clean Air
Act.'' The Administrator is determining that the recalibrations are
both necessary and appropriate to ensure that the control stringency
selected in this rulemaking is maintained and states' good neighbor
obligations with respect to the 2015 ozone NAAQS are addressed. The
recalibration process will complement the revised budget-setting
process by preventing any surplus of allowances created in one control
period from diminishing the intended stringency and resulting emissions
reductions of the emissions budgets for subsequent control periods. For
further discussion of the reasons for bank recalibration, see section
VI.B.1.b.ii of this document.
    The bank recalibration mechanism finalized in this rule is
unchanged from the proposal except for the final rule's adoption of a
target percentage of 21 percent rather than 10.5 percent for the
control periods from 2024 through 2029. The EPA's responses to comments
on the bank recalibration mechanism are discussed in the remainder or
this section and in section 5 of the RTC document. Further discussion
of the reasons for adopting a higher target percentage for the 2024-
2029 control periods is included in section VI.B.1.d of this document.
    Comment: Some commenters acknowledged the EPA's authority to manage
the quantities of allowances carried over from one control period to
the next as banked allowances, including some commenters who as a
policy matter did not support such an approach. Other commenters
claimed that any removal from the program of allowances banked in
earlier control periods would constitute an unlawful taking of property
or would constitute unlawful overcontrol.
    Response: The EPA disagrees with comments contending that the
proposed bank recalibration provisions would be unlawful, either as
asserted takings of property or as over-control for purposes of the
Good Neighbor provision. With respect to the claim that removing
allowances would constitute takings of property, the commenters
misconstrue the nature of an allowance. The allowances used in the
Group 3 trading program are created under the program's regulations,
which expressly provide that the allowances are not property rights but
are limited authorizations to emit NOX in accordance with
the provisions of the Group 3 trading program.\329\ These provisions of
the Group 3 trading program regulations have been in existence since
the Revised CSAPR Update and were not reopened in this action. This
approach of creating limited authorizations to engage in particular
forms of conduct within a regulatory program extends back to the Acid
Rain Program, where the approach was mandated by Congress, and has been
followed by EPA in each subsequent allowance trading program for the
electric power sector.\330\ Moreover, as noted earlier in this section,
the Group 3 trading program regulations provide the EPA

Administrator with the authority to terminate or limit the use and
duration of such authorization to the extent the Administrator
determines is necessary or appropriate to implement any provision of
the Clean Air Act, and the Administrator is making such a determination
in this rule.
---------------------------------------------------------------------------

    \329\ 40 CFR 97.1006(c)(6)-(7).
    \330\ See, e.g., 42 U.S.C. 7651b(f) and 40 CFR 72.9(c)(6)-(7)
(Acid Rain Program example); 40 CFR 97.6(c)(6)-(7) (Federal
NOX Budget Trading Program example); 40 CFR 97.106(c)(5)-
(6) (CAIR NOX Annual Trading Program example).
---------------------------------------------------------------------------

    The EPA also disagrees that bank recalibration would constitute
overcontrol. The emissions that are permissible in a given control
period consistent with the Step 3 control stringency are quantified in
the state emissions budgets for the control period. Banked allowances
from previous control periods are necessarily surplus to the state
emissions budgets for the current control period. As noted in section
VI.B.1, in an allowance trading program, banking provisions can serve
several useful purposes, including 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.
However, these useful purposes do not include allowing sources to plan
to emit in excess of the Step 3 control stringency as represented by
the state emissions budgets for the control period. Accordingly, in the
overcontrol analysis discussed in section V.D.4, the EPA analyzed
whether the emissions reductions necessary to meet the state emissions
budgets without relying for compliance purposes on any allowances
banked in earlier control periods would result in overcontrol and
determined there would be no overcontrol. (That is, the modeling of the
effects of the Group 3 emissions budgets in 2026 did not include an
assumption that there would be any banked allowances.) Thus, even if
the Agency had finalized regulatory provisions removing all banked
allowances from the trading program between control periods--in
contrast to the actual bank recalibration provisions, which permit
substantial quantities of banked allowances to remain in the trading
program--the information available to the Agency suggests such
provisions would not constitute over-control. With respect to some
commenters' assertions that bank recalibration would over-control by
``writing off'' emission reductions that may have gone beyond the
reductions necessary to address the Good Neighbor provision or would
make it more difficult to create surplus allowances in one control
period to offset excess emissions in later control periods, EPA notes
that the NAAQS apply continuously, and the possibility that the sources
in a state may have done more than the minimum necessary to meet the
state's Good Neighbor obligations in one control period does not create
a right for the state to do less than is necessary to meet the state's
Good Neighbor obligations in subsequent control periods.
    Comment: Some commenters expressed concern that excessive
quantities of banked allowances, like excessive quantities of budgeted
allowances, can lead to lower allowance prices. The commenters observed
that with lower allowance prices, some units would likely operate their
controls less effectively, resulting in a greater likelihood that the
emissions stringency found necessary in this rule would not be
sustained. Other commenters expressed the view that other provisions of
the rule, including more stringent state emissions budgets, the
backstop daily NOX emissions rate provisions, and the
assurance provisions would be sufficient to incentivize EGUs to operate
their controls effectively, making allowance bank recalibration
superfluous for this purpose.
    Response: The EPA agrees with the comments explaining that without
bank recalibration, the quantities of banked allowances can grow,
leading to lower allowance prices, diminished incentives for sources to
optimize control operation, and greater risk of failure to sustain the
Step 3 control stringency, and disagrees with the comments arguing that
other rule provisions would make bank recalibration unnecessary. The
suggestion that the assurance provisions can maintain program
stringency regardless of allowance quantities ignores the fact that the
emission levels consistent with the Group 3 control stringency in a
given control period are the state emissions budgets, not the higher
assurance levels. If the quantities of banked allowances in the program
grow to the point where sources collectively can plan to emit above the
collective state emissions budgets, then the trading program would be
unable to ensure that the Group 3 control stringency is being achieved,
even if emissions do not rise further than the assurance levels.
Further, there are now examples from the Group 2 trading program of
sources emitting in excess of the state-wide assurance levels, because
a glut of banked allowances which was not prevented by the regulations
for that trading program rendered even the three-to-one surrender ratio
ineffective. Suggestions that the backstop emissions rate provisions
can maintain program stringency regardless of the quantities of banked
allowances are similarly mistaken, because rather than reducing overall
emissions of all sources in the trading program, the backstop rate
provisions are designed to ensure that the largest individual sources
of potential emissions operate their controls consistently. If the
quantities of banked allowances are allowed to grow to the point where
sources collectively can plan to emit above the collective state
emissions budgets, the backstop rate provisions would do nothing to
constrain emissions from the sources not subject to the backstop rate.
    With respect to the suggestion that state emissions budgets
reflecting sufficient control stringency can avoid the need for bank
recalibration, the EPA observes that the budget-setting and bank
recalibration provisions in this rule are complements, not substitutes.
If in a given year sources collectively emit against the collective
state emissions budgets such that the ending allowance bank--that is,
the allowances remaining after deduction of the allowances required for
compliance--is less than the bank target amount, then the bank will not
be recalibrated for the following control period. However, in the event
that sources collectively emit against the collective state emissions
budgets such that the ending allowance bank is above the bank target
amount, then the recalibration provisions will ensure that the
recalibrated allowance bank does not introduce an excessive overall
quantity of allowances into the trading program for the following
control period when combined with the state emissions budgets
calculated for that control period. Without the recalibration
provisions, the trading program would lack any mechanism for removing
excess allowances that are inconsistent with maintaining the Step 3
emissions control stringency which the Step 4 trading program is
designed to implement.
    Comment: Some commenters claimed that the recalibration process
itself would have undesirable consequences. First, some said that
because bank recalibration would be executed partway through the
control period, it would introduce uncertainty concerning the
quantities of allowances each source would have available, impeding
efforts to plan. Second, some commenters claimed that the prospect of
bank recalibration would create counterproductive incentives for
allowance holders. According to the commenters, allowances holders
would be incentivized to ``use or lose'' their allowances (to reduce
the number of allowances that would be removed from

their accounts in the recalibration process), thereby causing increased
emissions, or alternatively would be incentivized to refuse to sell
allowances (to allow the holders to have more allowances after the next
recalibration), thereby reducing allowance market liquidity.
    Response: The EPA disagrees with these comments. As discussed
previously in this section, the recalibration process has been
scheduled for August 1 of each control period because compliance for
the previous control period (and the associated allowance trading
activities) would not be completed until after June 1. However, the
information needed to project the degree of recalibration will be
available by early November of the previous year, and the EPA will make
an estimate publicly available no later than March 1, two months before
the start of the control period. Further, at least 80 percent of the
allowances for use in a given control period will be the allowances
allocated from the state emissions budgets (with the recalibrated
banked allowances from the prior control period comprising the
remainder), and the emissions budgets and unit-level allocations
amounts will be known approximately a year before the start of the
control period.
    The comments claiming that the introduction of a bank recalibration
process would create incentives to ``use or lose'' allowances or to
hoard allowances are not persuasive. By reducing the supply of
allowances carried over from previous control periods, bank
recalibration would tend to raise the price of allowances in the
current control period, making it more cost-effective and therefore in
sources' interest to further reduce their emissions than to increase
their emissions. Higher allowance prices would also increase the cost
of hoarding allowances just as higher fuel prices raise the cost of
maintaining large fuel inventories. Moreover, the EPA expects that the
prospect of having banked allowances recalibrated after the end of the
control period is much more likely to discourage hoarding than to
encourage it. Given the choice between holding an allowance which may
be removed as part of an upcoming recalibration process or instead
selling the allowance for cash, the sale option will become more
attractive. By creating a ``sell or lose'' incentive for holders of
surplus allowances, the recalibration process should increase allowance
market liquidity. At the same time, by ensuring a banked allowance will
always have some value for use in a future control period, the bank
recalibration mechanism in this program will continue to incentivize
early emissions reductions.
    Comment: Turning to the level of the bank recalibration target,
some commenters objected to the target bank percentage of 10.5 percent,
saying that a larger bank would be needed to ensure that sufficient
allowances would be available to enable sources to run as needed to
provide reliable electricity service, particularly with the large year-
to-year swings in budgets that the commenters anticipated could occur
with dynamic budgets computed using a single rolling historical year
and with anticipated growth in renewable generation. Some commenters
recommended a target bank percentage of 21 percent. Some commenters
stated that even if the overall quantity of allowances available for
use was greater than the total amount of emissions, a larger bank of
allowances would facilitate trading and promote greater allowance
market liquidity, citing reports of high allowance prices in 2022.
    Response: As discussed in sections VI.B.1.d and VI.B.4 and earlier
in this section, the EPA does not agree with comments suggesting that
annual bank recalibration in itself poses a risk to electric grid
reliability. Nevertheless, the Agency has made several changes from
proposal in the final rule designed to address concerns expressed about
reliability by increasing compliance flexibility through the 2029
control period. These changes through the 2029 control period include
the use of a target bank percentage of 21 percent and the promulgation
of preset budgets that will serve as the state emissions budgets unless
the dynamic budgets for the control periods are higher. In addition, to
reduce year-to-year variability under the budget-setting methodology,
dynamic budgets will be calculated using multiple years of historical
heat input data instead of heat input data from a single year. The EPA
views these changes as responsive to the principal reasons that
commenters gave for their claims that the target bank percentage should
be higher than 10.5 percent. Regarding the claim that a higher target
bank percentage is needed because increased renewable generation makes
the demand for fossil generation more variable, commenters did not
provide evidence demonstrating that the overall quantities of fossil
generation throughout the multi-state region covered by this rule--as
opposed to the operating patterns of some individual units--are
becoming more variable, and the Agency declines to make an adjustment
for such a reason at this time.
    With respect to the comments advocating for an even higher bank
target percentage to facilitate trading and promote market liquidity,
the Agency observes that any such advantage of larger allowance banks
must be balanced with the disadvantages of excess allowance supply--
specifically, reduced allowance prices, diminished incentives for
sources to optimize control operation, and greater risk of failure to
sustain the Step 3 control stringency. In the final rule, the EPA finds
that a reasonable balance between these opposing considerations is
struck by temporarily adopting a higher bank target percentage of 21
percent (consistent with the initial bank targets used in this rule and
previous rules) and deferring implementation of the 10.5 percent target
bank percentage identified by the Agency's analysis as a sustainable
percentage in the longer term until the 2030 control period.
7. Unit-Specific Backstop Daily Emissions Rates
    While the identified EGU emissions reductions in section V of this
document (i.e., the Step 3 emissions control stringency) are
incentivized and secured primarily through the corresponding seasonal
state emissions budgets (expressed as a seasonal tonnage limit for all
covered EGUs within a state's borders) described earlier, the EPA is
also incorporating a backstop daily emissions rate of 0.14 lb/mmBtu
applied to coal-fired steam units serving generators with nameplate
capacity greater than or equal to 100 MW in covered states, except
circulating fluidized bed units. This is important for ensuring the
elimination of significant contribution on a more consistent basis from
the relevant sources and over each day of the ozone season.
    Starting with the 2024 control period, a 3-for-1 allowance
surrender ratio (instead of the usual 1-for-1 surrender ratio) will
apply to emissions during the ozone season from any large coal-fired
EGU with existing SCR controls exceeding by more than 50 tons a daily
average NOX emissions rate of 0.14 lb/mmBtu. The daily
average emissions rate provisions will apply to large coal-fired EGUs
without existing SCR controls (except circulating fluidized bed units)
starting with the second control period in which newly installed SCR
controls are operational at the unit, but not later than the 2030
control period. See Appendix A of the Ozone Transport Policy Analysis
Final Rule

TSD for a list of coal-fired steam units serving generators larger than
or equal to 100 MW in covered states for which the identified backstop
emissions rate will apply.
    For each unit subject to the backstop daily emissions rate
provisions for a given control period, the amount of emissions subject
to the 3-for-1 surrender ratio will be determined as follows, generally
on an automated basis using the unit's data acquisition and handling
system (DAHS) required under 40 CFR part 75. For each day of the
control period where the unit's average emissions rate for that day was
higher than 0.14 lb/mmBtu, the owner or operator will compute what the
unit's reported emissions on that day would have been (given the unit's
reported heat input for the day) at an emissions rate of 0.14 lb/mmBtu.
The difference between the unit's emissions for the day as actually
reported and the emissions that would have been reported if the unit's
emissions rate was 0.14 lb/mmBtu is the unit's daily exceedance. The
amount of emissions subject to the 3-for-1 surrender ratio for the
control period is the sum of the unit's daily exceedances for all days
of the control period minus 50 tons (but not less than zero).\331\ All
calculations will rely on the data monitored and reported for the unit
in accordance with 40 CFR part 75.
---------------------------------------------------------------------------

    \331\ In the regulatory text at 40 CFR 97.1024 defining the
total quantity of allowances that must be surrendered for a source's
emissions in a control period, these amounts of emissions for all
the units at the source are subject to a requirement to surrender
two extra allowances per ton in addition to the usual 1-for-1
allowance surrender requirement, yielding a total surrender ratio of
3-for-1 for emissions over the 50-ton threshold.
---------------------------------------------------------------------------

    The EGU NOX Mitigation Strategies Final Rule TSD
describes the methodology for deriving the 0.14 lb/mmBtu daily rate
limit in more detail. The methodology is summarized as follows. First,
consistent with stakeholders' focus on providing daily assurance of
control operation, which is consistent with the 8-hour form of the 2015
ozone NAAQS and the tendency for ozone levels to spike on a diurnal
cycle, the EPA determined that daily (as opposed to hourly or monthly)
was an appropriate time metric for backstop emissions rate limits
instituted to ensure operation of controls on high ozone days. The EPA
derived the 0.14 lb/mmBtu daily rate limit by determining the
particular level of a daily rate that would be comparable in stringency
to the 0.08 lb/mmBtu seasonal emissions rate that the Agency has
identified as reflecting SCR optimization at existing units.\332\ The
EPA first conducted an empirical exercise using reported daily
emissions rate data from existing, SCR-controlled coal units that were
emitting at or below 0.08 lb/mmBtu on a seasonal average basis. This
seasonal rate reflects the average across a unit's range of varying
daily rates reflecting different operation conditions. When the EPA
examined the daily emissions rate pattern for these units considered to
be optimizing their SCRs on a seasonal basis, the EPA observed that
over 95 percent of the time, their daily rates were below 0.14 lb/
mmBtu. In addition, for these units, less than 1 percent of their
seasonal emissions would exceed this daily rate limit.
---------------------------------------------------------------------------

    \332\ See page 24 of ``Guidance for 1-hour SO2
Nonattainment Area SIP Submission'' at https://www.epa.gov/sites/default/files/2016-06/documents/20140423guidance_nonattainment_sip.pdf. ``A limit based on the 30-
day average of emissions, for example, at a particular level is
likely to be a less stringent limit than a 1-hour limit at the same
level 1 since the control level needed to meet a 1-hour limit every
hour is likely to be greater than the control level needed to
achieve the same limit on a 30-day average basis.''
---------------------------------------------------------------------------

    The EPA conducted this analysis to be consistent with the
methodology developed in the 2014 1-hr SO2 attainment area
guidance for identifying ``comparably stringent'' emissions rates over
varying time-periods.\333\ Appendix C of that guidance describes a
series of steps that involve: (1) compiling emissions data to reflect a
distribution of emissions rates with various averaging times, (2)
determining the 99th percentile of the average emissions values
compiled in the previous step, and then (3) applying ``adjustment
factors'' or ratios of the 99th percentile values to emissions rates to
convert them (usually from a short-term rate to a longer-term rate). In
this case, the EPA applied the methodology in reverse to convert a
longer-term limit (the seasonal rate of 0.08 lb/mmBtu which was assumed
to be equivalent to a 30-day rate of 0.08 lb/mmBtu for purposes of this
comparison of rates across averaging times) to a comparably stringent
short-term limit (a daily rate of 0.14 lb/mmBtu).
---------------------------------------------------------------------------

    \333\ See Guidance for 1-Hour SO2 Nonattainment Area
SIP Submissions available at https://www.epa.gov/sites/default/files/2016-06/documents/20140423guidance_nonattainment_sip.pdf.
---------------------------------------------------------------------------

    The inclusion of a 50-ton threshold for emissions exceeding the
backstop daily emissions rate before the 3-for-1 surrender applies is a
change from the proposal. As discussed in section VI.B.1.d of this
document, the EPA made this change in response to comments concerning
the possibility that the 3-for-1 surrender ratio could otherwise have
applied to emissions outside an EGU operator's control, with the most
important example being the emissions during unit startup before SCR
equipment can be brought into service, and to a lesser extent the
emissions during unit shutdown. The analysis used by the EPA to derive
the 50-ton threshold is described in detail in the Ozone Transport
Policy Analysis Final Rule TSD. Briefly, for a set of 164 SCR-equipped
units with seasonal average NOX emissions rates at or below
0.08 lb/mmBtu in 2021, the EPA evaluated the total amounts of emissions
that would have been determined to exceed a daily average emissions
rate of 0.14 lb/mmBtu in the 2021 and 2022 ozone seasons. In the 2021
ozone season, only 572 tons out of these units' total emissions of
60,350 tons, or 0.9 percent, would have been considered exceedances,
with an average exceedance per unit of less than 4 tons. The highest
amount for any of the 164 individual units in either ozone season was
48 tons. Based on this analysis, the EPA concludes that adding a 50-ton
threshold to the backstop daily emissions rate provisions will ensure
that substantially all emissions outside the control of an SCR-equipped
unit's operator will not be subject to the 3-for-1 surrender ratio.
Because there is no reason to expect the range of emissions during
conditions when SCR controls cannot be operated to differ between SCR-
equipped units and units without SCR, inclusion of the 50-ton threshold
effectively prevents application of the 3-for-1 ratio to emissions
during startup and shutdown by units without SCR as well.
    At the same time, the EPA believes the 50-ton threshold is not
large enough to eliminate the intended incentive to achieve emissions
rates consistent with good SCR performance under conditions other than
startup and shutdown. For a set of 124 SCR-equipped units with seasonal
average NOX emissions rates above 0.08 lb/mmBtu, the total
amount of emissions exceeding a daily average emissions rate of 0.14
lb/mmBtu in the 2021 ozone season was 18,629 tons. Of this total
amount, 15,374 tons would have been in excess of the 50-ton thresholds
for the various units, indicating that even after application of the
threshold, the 3-for-1 surrender ratio would have applied to over 80
percent of the daily exceedance amounts.
    The backstop daily NOX emissions rate provisions
finalized in this rule are unchanged from the proposal except for the
inclusion of a 50-ton threshold for emissions exceeding the backstop
emissions rate before the 3-for-1 surrender ratio applies and the
deferral of the application of the provisions to units without existing
SCR controls

until the 2030 control period or, if earlier, the second control period
in which new SCR controls are operated at a unit. The EPA's responses
to comments on the backstop daily NOX emissions rate
provisions, including the reasons for these changes, are discussed in
the remainder of this section and in section 5 of the RTC document.
    Comment: Some commenters strongly supported the backstop daily
emissions rate provisions, noting their benefit to downwind receptors
on potential nonattainment days, their benefit to neighboring
communities, and evidence of deterioration in SCR performance in the
absence of such provisions. Other commenters stated that the backstop
daily emissions rate provisions are unnecessary, either because SCR-
equipped EGUs would already be sufficiently incentivized to operate and
optimize their controls by the stringency of the state emissions
budgets and the resulting allowance prices or because most SCR-equipped
EGUs are already required to operate and optimize their SCRs by
conditions in their operating permits. Some commenters cited previous
EPA analyses showing that it is unusual for SCR-equipped units to turn
off their SCRs only on high electricity demand days (HEDD).
    Commenters suggested diverse possible changes to the types of EGUs
that would be covered by the backstop daily emissions rate provisions.
Some commenters stated that the provisions should apply to all EGUs or
to all SCR-equipped EGUs, including non-coal-fired units. Other
commenters stated that exemptions should be provided for units
operating at capacity factors below 10 percent or for emissions during
emergencies.
    Some commenters stated that implementation of the backstop daily
emissions rate provisions would cause unintended and counterproductive
consequences. Some of these commenters claimed that by requiring the
surrender of extra allowances, the backstop emissions rate provisions
would create shortages of allowances for the program overall. Other
commenters claimed that the disincentives to operate units subject to
the backstop emissions rate provisions would cause load to shift to
higher-emitting generators not covered by the trading program (such as
sources in states outside the program's geographic region, EGUs smaller
than 25 MW, and sources considered demand-side resources, including
end-user-sited diesel generator units), potentially resulting in higher
overall emissions.
    Response: The EPA agrees that backstop daily emissions rate
provisions should be implemented and disagrees with comments suggesting
that the need for the backstop daily emissions rate provisions is
contradicted by previous EPA analyses or is already adequately
addressed by other provisions of this rule or other legal requirements.
As discussed in sections V.D.1 and VI.B.1.c of this document, the EPA
has determined that a control stringency reflecting universal
installation and operation of SCR technology at large coal-fired EGUs
is appropriate. There are several important differences between this
rule and previous actions addressing interstate ozone transport where
the Agency did not include such provisions. First, this rule
constitutes a full remedy, unlike some prior actions. Second, this rule
is the first rule in which the EPA is addressing good neighbor
obligations with respect to the more protective 2015 ozone NAAQS.
Third, the EPA has examined the most recent data over a broader
geographic and temporal footprint specific to the coverage of this
rule, and it illustrates a greater degree of SCR performance erosion
than in the prior years in which EPA conducted such analysis. Fourth,
nonattainment and maintenance for this NAAQS are projected to persist
well into the future in EPA's baseline, making enhancements and
safeguards such as the backstop daily emissions rate provisions
essential for securing elimination of significant contribution in
future periods for which fleet configuration is inherently more
uncertain.
    With respect to claims that inclusion of the backstop daily
emissions rate provisions is contradicted by the EPA's earlier analyses
concerning SCR operational changes specific to high electricity demand
days, the EPA disagrees. Historical data reported to the EPA show that
multiple SCR-equipped units across the states covered by this action
have chosen not to operate their SCRs, or to operate them at materially
less than their full removal capability, for entire ozone seasons. The
apparent infrequency of one type of behavior--i.e., instances of units
running their controls on most days but turning the controls off
specifically on high electricity demand days--does not contradict the
evidence concerning another type of behavior--i.e., non-operation or
suboptimal operation of controls for entire ozone seasons. The evidence
from previous trading programs demonstrates that reliance solely on the
incentives created by allowance prices and corresponding static state
emissions budgets has been insufficient to cause all SCR-equipped units
to operate and optimize their controls for entire ozone seasons.
    The EPA acknowledges that some SCR-equipped units are likely
already subject to other legal requirements calling for their SCR
controls to be operated and optimized such that their seasonal average
NOX emissions rates will generally not exceed 0.08 lb/mmBtu
(the level of seasonal SCR performance that the EPA used to derive the
equivalent 0.14 lb/mmBtu level of daily SCR performance for the
backstop daily NOX emissions rate). However, commenters do
not claim, and the EPA does not believe, that all SCR-equipped units
are subject to other legal requirements calling for an equivalent
degree of SCR operation and optimization. In the context of a multi-
state trading program, it is more efficient and equitable, and far more
transparent, for the EPA to establish rule provisions uniformly
incentivizing all large coal-fired EGUs to install and operate SCR
controls than to attempt to establish differentiated requirements for
various units according to the EPA's analysis of the effectiveness of
their pre-existing permit conditions. Further, to the extent that a
given unit's permits already require SCR performance that would meet
the backstop emissions rate established in this rule, or to the extent
that allowance prices would incentivize the unit to operate the SCR
anyway, the EPA expects that the backstop daily emissions rate
provisions (as finalized with a 50-ton threshold to address emissions
outside an EGU's control before the 3-for-1 surrender ratio applies)
will cause no incremental cost for the unit.
    The EPA disagrees with the suggested changes to applicability of
the backstop emissions rate provisions. With respect to the comments
advocating broader coverage, the EPA discusses its reasons for applying
the provisions only to coal-fired EGUs in section VI.B.1.c of this
document, including the fact that operation of SCR controls is a well-
established practice among the best performing coal-fired boilers but
not for non-coal-fired units.\334\ The comments indicate a preference
for a less flexible trading program design than the EPA has found
appropriate but do not demonstrate that EPA's decision to allow greater
flexibility is either impermissible or unreasonable; our reasoning in
this regard is further explained in section VI.B.1.c.i of this

document. With respect to the comments advocating narrower coverage,
the commenters have provided no information indicating that the sources
for which exemptions are sought could not comply with the provisions,
including through the surrender of additional allowances if necessary.
The EPA notes that emissions from coal-fired units operating at low
capacity factors may be concentrated around days of high electricity
demand when incentives to minimize such emissions may be most helpful
in mitigating downwind air quality problems. The EPA also notes that to
the extent the comments are intended to support exemptions for units
without existing SCR controls, the final rule defers application of the
backstop emissions rate provisions to such units until the 2030 control
period, providing additional flexibility to develop alternatives to the
use of such units if the owners choose not to equip them with SCR
controls.
---------------------------------------------------------------------------

    \334\ Nationwide and among operating units in 2021, EPA
identified the best performing quartile (i.e., lowest ozone season
emissions rate) of coal-fired EGU boilers (excluding CFB units).
Nearly 100 percent of these units (159 of 160 units) were equipped
with SCR controls.
---------------------------------------------------------------------------

    Finally, the EPA also disagrees with the comments asserting that
the backstop emissions rate provisions would cause unintended and
counterproductive consequences. With respect to units already equipped
with SCR controls, the EPA expects that by far the most important
effect of the provisions will be to incentivize the units to operate
and optimize their controls. The EPA sees no basis for speculation that
such units would choose to operate in a manner that would result in
large amounts of emissions becoming subject to the 3-for-1 allowance
surrender ratio or in generation being shifted to sources outside the
trading program. The results of the EPA's modeling of benefits and
costs of the rule show little leakage of emissions to non-covered
sources, and commenters have presented no analysis to the contrary. For
instance, as shown in Table 4.6 of the RIA, non-covered state ozone
season NOX emissions increased on average by 1 percent over
the 2023-2030 time period between the base and final rule scenarios,
while covered state emissions fell by 14 percent on average over the
same period. With respect to units without existing SCR controls, the
EPA expects the backstop emissions rate provisions, when they would
take effect for such units, to provide a strong incentive against
extensive operation (unless and until such controls are installed),
again not resulting in large amounts of emissions becoming subject to
the 3-for-1 allowance surrender ratio.
    Comment: For units with existing SCR controls, the aspect of the
backstop daily emissions rate provisions that received the most
attention in comments was how emissions outside the operator's control
should be treated. Multiple commenters expressed concern that the
backstop daily emissions rate would be exceeded on days when the SCR
equipment cannot be operated for all or a portion of the day. The most
commonly cited example of a situation where SCR equipment cannot be
operated was unit startups, although some commenters also mentioned
unit shutdowns, boiler or emissions control malfunctions, and unit
maintenance or tests. The commenters expressed the view that emissions
that cannot be controlled by SCR equipment should be exempted from the
backstop emissions rate provisions and suggested a variety of
approaches for implementing an exemption.
    Some commenters also stated that the backstop emissions rate
provisions would not sufficiently accommodate sustained low-load
operation, such as where an SCR-equipped unit operates for extended
periods at a load level too low to permit SCR operation so that the
unit is ready to ramp up to higher load levels in less time than would
be required for a startup. The commenters suggested that implementation
of a backstop daily rate would reduce the ability to operate the units
in this manner, generally reducing system flexibility. Some noted that
the need for flexibility of this nature is increasing because of the
rapid growth in intermittent renewable generation.
    Additional comments on the backstop daily emissions rate provisions
for units with existing SCR controls addressed the level of the daily
emissions rate and the implementation timing. With respect to the rate
level, various commenters suggested rates from 0.08 to 0.20 lb/mmBtu.
With respect to implementation timing, some commenters stated that
because immediate compliance was possible, the good neighbor provision
required implementation as of the 2023 control period rather than the
2024 control period as proposed. Other commenters expressed the view
that units with existing SCR controls should not be required to comply
with the backstop emissions rate provisions earlier than units without
existing SCR controls. Some owners of SCR-equipped EGUs that exhaust to
stacks shared with EGUs without SCR suggested that their particular
units with existing SCR controls should not be required to comply with
the backstop emissions rate provisions earlier than units without
existing SCR controls in order to avoid the cost of upgrading their
emissions monitoring equipment.
    Response: With respect to the topic of emissions outside an
operator's control, as a general matter the EPA agrees that the
backstop daily emissions rate provisions are intended to incentivize
good SCR operation and that it was not the Agency's intent to apply a
higher surrender ratio to emissions that are truly unavoidable, such as
emissions occurring before an operator could reasonably initialize SCR
operation when a unit is started up. As explained elsewhere in this
section, the EPA selected the level of the backstop rate based on
analysis of 2021 emissions data showing that for SCR-equipped coal-
fired units achieving seasonal average NOX emissions rates
at or below 0.08 lb/mmBtu, more than 99 percent of the units' emissions
would fall below a backstop daily emissions rate of 0.14 lb/mmBtu. In
response to the comments summarized previously, the EPA has further
analyzed 2021 and 2022 emissions data to determine what if any
modifications to the proposal might be appropriate to limit the
imposition of a 3-to-1 allowance surrender requirement for emissions
caused by circumstances outside an operator's control while preserving
the intended incentive to operate and optimize SCR controls whenever
possible. The analysis showed that for the same set of units achieving
seasonal average emissions rates at or below 0.08 lb/mmBtu, the highest
total amount of emissions exceeding the backstop daily emissions rate
in either the 2021 or 2022 control period for any unit was 48 tons. The
Agency views this amount as a reasonable upper bound on the quantity of
emissions that might contribute to an exceedance of the backstop
emissions rate arising from circumstances outside an operator's control
for any coal-fired unit, not just the well-controlled units in the data
set analyzed, because the amount generally encompasses all of a unit's
emissions occurring in hours when an SCR could not be operated over an
ozone season.
    Based on this analysis, the backstop daily emissions rate
provisions in this final rule exclude the first 50 tons of a unit's
emissions in a given control period exceeding the backstop daily
emissions rate from incremental allowance surrender requirements. The
EPA finds that establishing a threshold of this nature will provide an
appropriate maximum exclusion to all coal-fired units for unavoidable
emissions caused by circumstances outside the operator's control while
maintaining the incentives for less well-controlled units to improve
their emissions performance on all days of

the ozone season. Well-controlled units will likely have no emissions
over the threshold that will be subject to incremental allowance
surrender requirements, while for SCR-equipped units not already
achieving a seasonal average emissions rates sufficiently low to
routinely operate at daily average emissions rates of 0.14 lb/mmBtu or
less, the incentive to reduce daily emissions rates will remain in
place, because the 50-ton threshold is not expected to encompass all
emissions exceeding the backstop daily emissions rate for such units.
In contrast to more complicated exceptions suggested by commenters, the
50-ton threshold can be easily integrated into the overall trading
program structure with minimal additional recordkeeping and reporting
requirements.
    With respect to the comments claiming that the inability of some
SCR-equipped units to operate their SCR controls at sustained low load
levels likewise merits alteration of the backstop daily emissions rate
provisions, the EPA disagrees. There is no dispute concerning the
technical need for a unit to attain and maintain a certain range of
exhaust gas temperatures at the SCR inlet in order to achieve optimal
SCR performance and no dispute concerning the general relationship
between a unit's load level in a given hour and its ability to attain
and maintain that exhaust gas temperature range in that hour. However,
the EPA is also aware that at least in some cases, units whose role in
the integrated electric system currently calls for them to operate at
low load levels for sustained periods (such as overnight) in fact may
be able to operate at slightly higher load levels that would
accommodate SCR operation during those periods and still meet the needs
of the integrated electric system, thereby avoiding operation of the
unit for sustained periods with the SCR out of service. Figure B.5 in
the EGU NOX Mitigation Strategies Final Rule TSD illustrates
this opportunity using data reported for the 2021 and 2022 ozone
seasons by a large SCR-equipped EGU in Pennsylvania. In both ozone
seasons, the unit often cycled daily between its maximum load of
approximately 900 MW during the daytime and a lower load level
overnight, and in both ozone seasons the unit's typical daytime
emissions rate was between 0.05 and 0.07 lb/mmBtu. However, while in
the 2021 ozone season, the unit cycled down to a load level of
approximately 440 MW overnight and did not operate its SCR, in the 2022
ozone season, when allowance prices were considerably higher, the unit
cycled down to a load level of approximately 540 MW overnight and did
operate its SCR. Despite the higher nighttime generation levels, the
result was a decrease of roughly 50 percent in the unit's seasonal
average NOX emissions rate, from approximately 0.14 lb/mmBtu
to approximately 0.07 lb/mmBtu, and a comparable reduction in
NOX mass emissions. This unit is not uniquely situated;
operating data for several other large SCR-equipped EGUs in
Pennsylvania show the same past pattern of cycling down to low load
levels at which the SCR controls cannot be operated, and these other
units have similar opportunities to cycle down to somewhat higher load
levels (necessarily subject to the needs and constraints of the
integrated electric system) at which their SCR controls can be
operated.\335\ No commenter has submitted data to the contrary.
Furthermore, this example demonstrates the need for this rule's
backstop emissions rate provision, which (had it been in place) would
have motivated this facility to operate its SCR overnight during the
2021 ozone season when the prevailing allowance price provided an
insufficient incentive to do so.
---------------------------------------------------------------------------

    \335\ See the spreadsheet ``Conemaugh and Keystone unit 2021 to
2022 hourly ozone season data'' in the docket.
---------------------------------------------------------------------------

    The EPA disagrees with the comments advocating for a backstop daily
emissions rate lower or higher than 0.14 lb/mmBtu. In general, these
comments simply represent disagreements with the EPA's conclusions
regarding the identification of required emissions reductions under
this rule, as reflected in part by the EPA's conclusion that a seasonal
average emissions rate of 0.08 lb/mmBtu reasonably reflects the
seasonal average emissions rate achievable through optimization of
controls by existing SCR-equipped units that are not already achieving
a lower seasonal average emissions rate. Comments concerning the
selection of the 0.08 lb/mmBtu seasonal average emissions rate are
addressed in section V of this document. Commenters did not challenge
the EPA's analysis identifying a daily emissions rate of 0.14 lb/mmBtu
as comparable in stringency to a seasonal average emissions rate of
0.08 lb/mmBtu (see further discussion elsewhere in this section).
    The EPA also disagrees with the comments stating that the backstop
daily emissions rate provisions should apply to units with existing SCR
controls starting in a control period earlier or later than the 2024
control period. The EPA does not consider implementation of the
provisions in the 2023 control period feasible because it is currently
unknown whether the necessary updates to the emissions recordkeeping
and reporting software for all the affected sources could be completed
and tested before July 30, 2023, which is the first quarterly reporting
deadline for the 2023 control period. Moreover, as discussed in section
VI.B.1.c.i of this document, implementing the requirements starting in
2024 will provide a window for EGUs to improve the consistency of SCR
operation or in some cases to optionally install additional emissions
monitoring equipment. As for the suggestion that implementation timing
of the backstop daily emissions rate provisions for units with existing
SCR controls should be synchronized with the later implementation
timing for units without existing SCR controls, the EPA is not
persuaded that there is any inequity in implementing provisions
intended to incentivize operation of SCR controls first at sources that
already have such controls and later at sources that do not already
have such controls, allowing time for the latter sources to install the
controls. In any event, in this instance, where some upwind sources
have an immediate and highly cost-effective option for controlling
their emissions, the statutory requirement for significant contribution
to be eliminated as expeditiously as practicable so as to provide
downwind states with the protection intended by the Good Neighbor
provision overrides these sources' claim of inequity relative to
sources whose emissions control options would take longer and have
higher cost. We conclude that the backstop daily emissions rate is an
important aspect of the elimination of significant contribution and
should be applied at the relevant units. It is only out of recognition
of unique circumstances associated with facilitating power-sector
transition as identified by commenters, that we defer the application
of the rate for the minority of units that have not yet installed SCR
controls.
    Finally, with respect to the SCR-equipped units that share common
stacks with units that do not have SCR, the EPA disagrees that
monitoring cost considerations merit a later implementation date for
the backstop daily emissions rate provisions. As discussed in section
VI.B.10 of this document, five plants with this configuration are
covered by the rule (one of which has announced plans to retire in
2023). Under this rule, as proposed, the owner of a plant with this

configuration can choose between either upgrading the plant's
monitoring systems so as to obtain unit-specific NOX
emissions rate data for each unit subject to the backstop daily
emissions rate or else using the NOX emissions rate data
from the common stack, recognizing that the common stack emissions rate
would generally be biased upwards relative to the emissions rate that
could be reported for the SCR-equipped unit if that unit's emissions
were monitored separately. Commenters have suggested a third option of
a temporary exemption from the backstop emissions rate to avoid the
cost of upgrading their monitoring systems. With the timing for
implementation of the backstop emissions rate provisions for currently
uncontrolled units in the proposal, the temporary exemption for the
SCR-equipped units would have been in place for three control periods,
from 2024 through 2026. With the final rule's deferral of the
implementation of the backstop emissions rate provisions for the
uncontrolled units for up to three years, the suggested temporary
exemption for the SCR-equipped units would be in effect for up to six
control periods, from 2024 through 2029. The EPA does not consider it
reasonable to allow these SCR-equipped units an exemption from the
backstop rate provisions for six years to avoid the cost of upgrading
their monitoring systems, particularly given that the additional costs
of monitoring at the individual-unit level are already borne by the
large majority of other plants and the rule already provides these
plants with an alternative to the monitoring system upgrades, if
desired, by allowing the plants to use the emissions rate data from the
common stack.\336\
---------------------------------------------------------------------------

    \336\ The owner of one of the five plants with common stacks
submitted comments stating that no location in the plant's ductwork
could meet the criteria for a unit-specific monitoring location. As
discussed in section VI.B.10 of this document, EPA staff have
reviewed the comment and do not believe the commenter has provided
sufficient information to reach such a conclusion.
---------------------------------------------------------------------------

    Comment: With respect to units without existing SCRs, some
commenters viewed the backstop daily emissions rate provisions as
likely to make units without SCR altogether unwilling or unable to
operate and characterized the provisions as a mandate for such units to
install such controls or retire as of the control period when the
provisions are implemented. Other commenters acknowledged that the
provisions are not actually hard limits but stated that the higher
allowance surrender ratio for emissions in excess of the backstop daily
rate would nevertheless reduce the ability of such units to operate as
needed to back up intermittent renewable generation. Some commenters
claimed that inclusion of the backstop daily emissions rate provisions
would substantially eliminate the potential benefits of allowance
trading, because all units would have to meet the same emissions rate.
    Some commenters stated that the proposed application of the daily
backstop emissions rate provisions in the 2027 control period in some
cases would occur only slightly before the units' otherwise planned
retirement dates, and that short-term reliability considerations could
create the need to make substantial investments in new controls at the
units, which in turn could result in deferral of the units' retirement
plans. In the proposal, the EPA requested comment on the possibility of
deferring the application of the backstop emissions rate provisions to
units without existing SCR controls until the 2029 control period if
the owners provided the EPA with information indicating with sufficient
certainty that the units would retire by the end of 2028. Commenters in
favor of this concept suggested longer deferral periods, ranging from
2029 through 2032, and some also suggested that the EPA should
simultaneously enlarge the emissions budgets to provide more allowances
for units subject to the deferred requirement. Other commenters opposed
any deferral of the applicability of the backstop rate provisions.
    Response: The EPA disagrees that implementation of the backstop
daily emissions rate provisions for EGUs without existing SCR controls
constitutes a mandate for such units to install controls or retire but
agrees that, as intended, the provisions would create strong incentives
to minimize operation of the units unless and until controls are
installed, and further agrees that in some instances retirement and
replacement may be a more economically attractive option for the unit's
customers and/or owners than installation of new controls. The EPA's
rationale for determining at Step 3 that the control stringency
required to address states' good neighbor obligations includes
achievement of emissions rates consistent with good SCR performance at
all large coal-fired EGUs (other than circulating fluidized bed
boilers) is discussed in section V.D.1 of this document, and the EPA's
rationale for determining at Step 4 that the trading program should
include strong unit-level incentives to implement these controls is
discussed in section VI.B.1.c. of this document. As noted in section
VI.B.1.c of this document, the backstop daily emissions rate provisions
are structured as incremental allowance surrender requirements rather
than as directly enforceable emissions limits 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. The EPA
appreciates that, in comparison to previous transport rules using a
trading program mechanism for the power sector, the degree of
flexibility available under this rule is reduced both by the greater
stringency of the overall emissions reduction requirements, which leave
less room to accommodate emissions from high-emitting units such as
uncontrolled coal-fired units, and by the backstop daily emissions rate
provisions. However, the EPA maintains that the trading program
structure still is significantly more flexible than an array of
directly enforceable emissions limits imposed on all EGUs or even on
all coal-fired EGUs, and the comments do not show otherwise.
    With respect to the comments concerning the timing for application
of the backstop daily emissions rate provisions to EGUs without
existing SCR controls, in the final rule the provisions will apply to
these units starting with the second control period in which newly
installed SCR controls are operational at the unit, but not later than
the 2030 control period. As discussed in section VI.B.1.d of this
document, the purpose of this change from the proposal is to address
concerns expressed by RTOs and other commenters that application of the
backstop daily NOX emissions rate to EGUs without existing
SCR controls starting in the 2027 control period would provide
insufficient time for planning and investments needed to facilitate the
unit retirements they viewed as likely to be a preferred compliance
pathway for some owners. The EPA recognizes that retrofitting new
emissions controls on aging coal-fired EGUs may be less environmentally
efficient than the alternative of retirement and replacement, which
could yield lower cumulative emissions of NOX and multiple
other pollutants over time. The EPA also recognizes that several coal-
fired EGUs have already been considering retirement in 2028 (or
earlier) under compliance pathways available under the Clean Water Act
effluent guidelines \337\ and the coal combustion residuals rule under
the

Resource Conservation and Recovery Act.\338\ The year 2028 also
represents the end of the second planning period under the Regional
Haze program, and thus is a significant year in states' planning of
strategies to make reasonable progress towards natural visibility at
Class I areas.\339\ In addition, other regulatory actions at the state
or Federal level are being or recently have been proposed. This
includes among other things a proposed revision to the PM NAAQS for
which transport SIPs would be due later in the 2020s. We understand
that EGUs may wish to take the entire regulatory and market landscape
into account when deciding whether to invest in SCR or pursue other
NOX reduction strategies. To facilitate a unit-level
compliance alternative under this rule that maintains the
NOX reductions corresponding to SCR-level emissions control
performance required by the state budgets from 2026 forward and that is
potentially superior both economically and environmentally across
multiple regulatory programs than installation of new, capital-
intensive, post-combustion controls, the EPA is providing the fleet
more flexibility in how to achieve those emissions reductions in the
years through 2029. Relatedly, the deferral of the application of the
backstop emissions rate provisions to uncontrolled units also addresses
commenters' concerns that the provisions otherwise would reduce the
ability of uncontrolled units to operate as needed to back up
intermittent renewable generation (subject of course to the allowance-
holding requirements to cover emissions). The deferral addresses this
concern directly for the period through 2029, by eliminating
application of the backstop provisions to uncontrolled EGUs through
this period, and also indirectly after 2029, by ensuring the
availability of sufficient time for owners and operators to complete
other investments that may be needed to back up renewable generation
after that point.
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    \337\ See 40 CFR 423.11(w).
    \338\ See 40 CFR 257.103(b).
    \339\ See 40 CFR 51.308(f).
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    The EPA disagrees with the comments stating that application of the
backstop daily emissions rate provisions to uncontrolled units should
not be deferred and also disagrees with the comments stating that
deferral should be accompanied by increases in the state emissions
budgets reflecting higher assumed emissions rates for these units. The
responses to these two comments are related. This rule complies with
the mandate for the EPA to address good neighbor obligations as
expeditiously as practicable and is based on a demonstration that
emissions reductions commensurate with the overall emissions control
strategy at Step 3 can be achieved beginning in the 2027 ozone season
(following a two-year phase in of emissions reductions associated with
installation of SCR retrofits). In the RIA, we demonstrate that EGUs
will have multiple pathways to meeting the state budgets even if they
choose not to install the SCR controls--thus no relaxation in the
stringency of these budgets has been demonstrated to be warranted based
on feasibility, necessity, or impossibility. The EGU economic modeling
discussed in the RIA illustrates that many sources identified as
currently having SCR retrofit potential elect not to install a SCR, and
those that do retrofit SCR make no such installation until 2030. Yet,
the fleet is able to comply with 2026 state emissions budgets (whose
emissions reductions are premised in large part on assumed SCR
retrofits) through reduced utilization (many of these units are
projected to retire, and thus reduce emissions). While these changes in
coal fleet utilization are not required or imposed through the EPA's
state emissions budgets, they are projected to be an economic
preference for a substantial portion of the unretrofitted fleet owing
to future market and policy conditions. If sources do ultimately elect
this pathway, then compliance will occur with significantly less demand
on SCR retrofit labor and material markets than assumed at Step 3. The
daily emissions rates are a backstop to the broader emissions reduction
requirements, which we view as an important and necessary component to
the elimination of significant contribution. But we also recognize that
the objectives to be accomplished by the backstop must be balanced with
larger economic and environmental conditions facing EGUs for which a
deferral of the backstop rate ultimately is the most reasonable
approach given these competing concerns. See Wisconsin, 938 F.3d at 320
(``EPA, though, possesses a measure of latitude in defining which
upwind contribution `amounts' count as `significant[ ]' and thus must
be abated.''). As noted in section VI.B.1.d of this document, the EPA
finds that as long as state emissions budgets continue to reflect the
required degree of emissions reductions at least for an interim period
until the backstop rate would apply more uniformly, deferral of the
backstop rate requirement for uncontrolled units in recognition of the
transition period identified by commenters can be justified on the
basis of the greater long-term environmental benefits obtained through
greater compliance flexibility.
8. Unit-Specific Emissions Limitations Contingent on Assurance Level
Exceedances
    As emphasized by the D.C. Circuit in its decision invalidating
CAIR, under the CAA's good neighbor provision, emissions ``within the
State'' that contribute significantly to nonattainment or interfere
with maintenance of a NAAQS in another state must be prohibited. North
Carolina v. EPA, 531 F.3d 896, 906-08 (D.C. Cir. 2008). The CAIR
trading programs contained no provisions limiting the degree to which a
state could rely on net purchased allowances as a substitute for making
in-state emissions reductions, an omission which the court found was
inconsistent with the requirements of the good neighbor provision. Id.
In response to that holding, the EPA established the CSAPR trading
programs' assurance provisions to ensure that, in the context of a
flexible trading program, the emissions reductions required under the
good neighbor provision in fact will take place within the state. The
EPA believes the assurance provisions have generally been successful in
achieving that objective, as evidenced by the fact that since the
assurance provisions took effect in 2017, out of the nearly 300
instances where a given state's compliance with the assurance
provisions of a given CSAPR trading program for a given control period
has been assessed, a state's collective emissions have exceeded the
applicable assurance level only four times.
    Unfortunately, the EPA also recognizes that the assurance
provisions' very good historical compliance record is not good enough.
The four past exceedances all occurred under the Group 2 trading
program: sources in Mississippi collectively exceeded their applicable
assurance levels in the 2019 and 2020 control periods, and sources in
Missouri collectively exceeded their applicable assurance levels in the
2020 and 2021 control periods.\340\ Both of the exceedances by Missouri
sources could easily have been avoided if the owner and operator of
several SCR-equipped,

coal-fired steam units had not chosen to idle the units' controls and
rely instead on net out-of-state purchased allowances. The exceedances
were large, and ample quantities of allowances to cover the resulting
3-for-1 allowance surrender requirements were purchased in advance,
suggesting that the assurance level exceedances may have been
anticipated as a possibility. In the case of the Mississippi
exceedances, the exceedances were smaller, operational variability
(manifesting as increased heat input) appears to have been a material
contributing factor, and the EPA has not concluded that the owners and
operators anticipated the exceedances. However, an additional
contributing factor was the fact that several large, gas-fired steam
units without SCR controls emitted NOX at average rates much
higher than the average emissions rates the same units had achieved in
previous control periods. In short, while the Missouri exceedances
appear far more significant, the EPA's analysis indicates that all four
past exceedances could have been avoided if the units most responsible
had achieved emissions rates more comparable to the same units'
previous performance. In the EPA's view, the operation of the Missouri
units in particular--although not prohibited by the current regulatory
requirements--cannot be reconciled with the statutory requirements of
the good neighbor provision. The fact that such operation is not
prohibited by the current regulations therefore indicates a deficiency
in the current regulatory requirements.
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    \340\ Information on the assurance level exceedances in the
2019, 2020, and 2021 control periods is available in the final
notices concerning EPA's administration of the assurance provisions
for those control periods. 85 FR 53364 (August 28, 2020); 86 FR
52674 (September 22, 2021); 87 FR 57695 (September 21, 2022).
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    To correct the deficiency in the regulatory requirements, the EPA
in this rulemaking is revising the Group 3 trading program regulations
to establish an additional emissions limitation to more effectively
deter avoidable assurance level exceedances starting with the 2024
control period. Because the pollutant involved is ozone season
NOX and the particular sources for which deterrence is most
needed are located in states that are transitioning from the Group 2
trading program to the Group 3 trading program, the EPA is promulgating
the strengthening provisions as revisions to the Group 3 trading
program regulations rather than the Group 2 trading program
regulations.\341\
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    \341\ The EPA believes that the occurrence of avoidable
assurance level exceedances under the Group 2 trading program,
combined with the express statutory directive that good neighbor
obligations must be addressed ``within the state,'' and through
``prohibition,'' would also provide a sufficient legal basis for the
Agency to promulgate the same revisions to the assurance provisions
for all the other CSAPR trading programs. The EPA is not doing so at
this time because the Agency has seen no reason to expect
exceedances of the assurance levels under any of the other CSAPR
trading programs by any of the states that will remain subject to
the respective trading programs after this rulemaking, except
possibly by Missouri under the CSAPR NOX Annual Trading
Program. The EPA expects that reductions in Missouri's seasonal
NOX emissions sufficient to comply with the proposed
provisions of the revised Group 3 trading program, including the
secondary emissions limitations, would also prevent exceedances of
Missouri's currently applicable assurance level for annual
NOX emissions.
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    The two historical emissions-related compliance requirements in the
Group 3 trading program regulations are both structured in the form of
requirements to hold allowances. The first requirement applies at the
source level: specifically, at the compliance deadline after each
control period, the owners and operators of each source covered by the
program must surrender a quantity of allowances that is determined
based on the emissions from the units at the source during the control
period. The second requirement applies at the designated representative
level (which typically is the owner or operator level): if the state's
sources collectively emit in excess of the state's assurance level, the
owners and operators of each set of sources determined to have
contributed to the exceedance must surrender an additional quantity of
allowances. As long as a source's owners and operators comply with
these two allowance surrender requirements (and meet certain other
requirements not related to the amounts of the sources' emissions),
they are in compliance with the program.
    In light of the operation of the Missouri sources, the EPA is
doubtful that strengthening the assurance provisions by increasing
allowance surrender requirements at the unit, source, or designated
representative level would create a sufficient deterrent. Accordingly,
the EPA is instead adding a new, unit-level emissions limitation
structured as a prohibition to emit NOX in excess of a
defined amount. A violation of the prohibition will not trigger
additional allowance surrender requirements beyond the surrender
requirements that would otherwise apply, but will trigger the possible
application of the CAA's enforcement authorities. The new emissions
limitation will be in addition to, not in lieu of, the other
requirements of the Group 3 trading program. This point is being made
explicit by relabeling the source-level allowance holding requirement,
currently called the ``emissions limitation,'' as the ``primary
emissions limitation'' and labeling the new unit-level requirement as
the ``secondary emissions limitation.'' (The regulations label the
designated representative-level requirement as ``compliance with the .
. . assurance provisions.'')
    Because the purpose of the new unit-level secondary emissions
limitation is to deter conduct causing exceedances of a state's
assurance level, the EPA is conditioning applicability of the new
limitation on (1) the occurrence of an exceedance of the state's
assurance level for the control period, and (2) the apportionment of at
least some of the responsibility for the assurance level exceedance to
the set of units represented by the unit's designated representative.
Apportionment of responsibility for the assurance level exceedance will
be carried out according to the existing assurance provision procedures
and will therefore depend on the designated representative's shares of
both the state's total emissions for the control period and the state's
assurance level for the control period. To ensure that the secondary
emissions limitation is focused on units where the need for improved
incentives is greatest, and also to ensure that the limitation will not
apply to units used only to meet peak electricity demand, the
limitation applies only to units that are equipped with post-combustion
controls (i.e., SCR or SNCR) and that operated for at least ten percent
of the hours in the control period in question and in at least one
previous control period.
    For units to which a secondary emissions limitation applies in a
given control period based on the conditions just summarized, the
limitation is defined by a formula in the regulations. The formula is
generally designed to compute the potential amount the unit would have
emitted during the control period, given its actual heat input during
the control period, if the unit had achieved an average emissions rate