control period are recalibrated for consistency with the state
emissions budgets. The EPA therefore proposes that, starting with
allowances allocated for the 2024 control period, any incorrectly
allocated allowances that are recovered after the deadline for
allocating allowances from the new unit set-aside for that control
period (i.e., May 1 of the year following the control period) would be
transferred to a surrender account instead of being reallocated to
other units in the state.
    The EPA requests comment on the proposed revision to the provisions
for disposition of incorrectly allocated allowances that are recovered
after the deadline for allocating allowances from the new unit set-
asides for the control periods for which the recovered allowances were
issued.
10. Other Trading Program Provisions
    This section discusses how certain existing provisions of the Group
3 trading program regulations would apply to sources that become
subject to the program as a result of a final rule in this rulemaking
as well as certain proposed changes to reporting requirements
associated with the proposed backstop daily NOX emissions
rates for coal-fired units.
a. Designated Representative Requirements
    As noted in Section VII.B.1.a of this document, a core design
element of all the CSAPR trading programs is the requirement that each
source must have a designated representative who is authorized to
represent all of the source's owners and operators and is responsible
for certifying the accuracy of the source's reports to the EPA and
overseeing the source's Allowance Management System account. The
necessary authorization of a designated representative is certified to
the EPA in a certificate of representation. The EPA is not proposing
any change to the Group 3 trading program's designated representative
provisions in this rulemaking.
    The existing designated representative provisions in the Group 3
trading program regulations already provide that EPA will interpret
references to the Group 2 trading program in certain documents--
including a certificate of representation as well as a notice of
delegation to an agent or an application for a general account--as if
the documents referenced the Group 3 trading program instead of the
Group 2 trading program. For these reasons, sources that currently
participate in the Group 2 trading program and that transition to the
Group 3 trading program because of a final rule in this rulemaking will
not need to submit any new forms as part of the transition, because
previously submitted forms will be valid for purposes of the Group 3
trading program.
    Designated representatives for sources that are newly affected
under the Group 3 trading program and that are not currently affected
under the Group 2 trading program would need to submit new or updated
certificates of representation. If the source is also affected under
other CSAPR trading programs or the Acid Rain Program, the source's
designated representative for all of the programs must be the same
individual. The EPA will not record any Group 3 allowances allocated to
a source in the source's compliance account until the source has a
properly authorized designated representative.
b. Monitoring and Reporting Requirements
    The Group 3 trading program requires monitoring and reporting of
emissions and heat input data in accordance with the provisions of 40
CFR part 75. In this rulemaking, the EPA is not proposing any change to
these provisions of the Group 3 trading program except with respect to
the monitor certification deadline for certain units. The EPA is also
not proposing any changes to the monitoring requirements in 40 CFR part
75 for units subject to such requirements. However, because of the
proposed geographic expansion of the Group 3 trading program, certain
units that were not previously subject to monitoring requirements under
40 CFR part 75 would become subject to such requirements. Also, the EPA
is proposing certain additional recordkeeping and reporting
requirements that would be met using some of the data that are already
collected by the required monitoring systems.\289\
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    \289\ The EPA is not proposing to amend the existing provisions
of the Group 3 trading program regulations that govern whether units
covered by the program must record and report required data on a
year-round basis or may elect to record and report required data on
an ozone season-only basis. See 40 CFR 97.1034(d)(1); see also 40
CFR 75.74(a)-(b). Thus, for units that are required or elect to
report other data on a year-round basis, the proposed additional
recordkeeping and reporting requirements would also apply year-
round, while for units that are allowed and elect to report other
data on an ozone season-only basis, the proposed additional
requirements would also apply for the ozone season only.

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    Under 40 CFR part 75, a unit has several options for monitoring and
reporting, including the use of continuous emissions monitoring systems
(CEMS), excepted monitoring methodologies for qualifying gas- or oil-
fired units that rely in part on fuel-flow metering in combination with
CEMS-based or testing-based NOX emissions rate data, low-
mass emissions monitoring for certain non-coal-fired, low emitting
units, and alternative monitoring systems approved by the Administrator
through a petition process. In addition, sources can submit petitions
to the Administrator for alternatives to individual monitoring,
recordkeeping, and reporting requirements specified in 40 CFR part 75.
Each CEMS must undergo rigorous initial certification testing and
periodic quality assurance testing thereafter, including the use of
relative accuracy test audits and 24-hour calibrations. In addition,
when a monitoring system is not operating properly, standard substitute
data procedures are applied to produce a conservative estimate of
emissions for the period involved. Further, 40 CFR part 75 requires
electronic submission of quarterly emissions reports to the
Administrator, in a format prescribed by the Administrator. The reports
would contain all of the data required concerning ozone season
NOX emissions.
    For units exhausting to common stacks, 40 CFR part 75 includes
options that often allow monitoring to be conducted at the common stack
on a combined basis for all the units as an alternative to installing
separate monitoring systems for the individual units in the ductwork
leading to the common stack. The units then keep records and report
hourly and cumulative NOX mass emissions and in many cases
heat input data on a combined basis for all units exhausting to the
common stack. With respect to heat input data, but not NOX
mass emissions data, most such units are also required to record and
report hourly and cumulative data on an individual-unit basis, and
where necessary they typically compute the necessary unit-level hourly
heat input values by apportioning the combined hourly heat input values
for the common stack in proportion to the individual units' recorded
hourly output of electricity or steam. See generally 40 CFR 75.72.
    In this rulemaking, the proposed provisions governing default unit-
level allowance allocations, backstop daily NOX emissions
rates for certain coal-fired units, and secondary emissions limitations
for units contributing to assurance level exceedances would all require
the use of unit-level reported data on NOX mass emissions
(or unit-level NOX emissions rates computed in part based on
unit-level reported data on NOX mass emissions). To
facilitate the implementation of these proposed provisions, the EPA is
proposing to require all units covered by the Group 3 trading program
exhausting to common stacks to record and report unit-level hourly and
cumulative NOX mass emissions data starting with the 2024
control period. To obtain the necessary unit-level hourly mass
emissions values, the EPA proposes to allow the units to apportion
hourly mass emissions values determined at the common stack in
proportion to the individual units' recorded hourly heat input. The
proposed apportionment procedure would be very similar to the
apportionment procedure that most such units already apply to compute
reported unit-level heat input data. Because the additional required
data values would be obtained through apportionment, implementation of
the proposed additional recordkeeping and reporting requirements would
necessitate a one-time update to the units' data acquisition and
handling systems but would not require any changes to the monitoring
systems already needed to meet other requirements under 40 CFR part 75.
In most cases, the EPA expects that the reported values computed
through these apportionment procedures would reasonably approximate the
values that could be obtained through installation and operation of
separate monitoring systems for the individual units, because the units
exhausting to the common stack would be expected to have similar
NOX emissions rates. However, the EPA also recognizes that
at some plants, unit-level values determined through apportionment
based on electricity or steam output could overstate the reported
NOX mass emissions for some units and correspondingly
understate the reported NOX mass emissions for other units.
While the EPA has not at this time identified any reason to expect such
potential overstatement and understatement to cause the proposed
requirements in this rule to be less stringent overall, the Agency
requests comment on whether units in particular situations should be
required to obtain the necessary hourly mass emissions values through
installation and operation of monitoring systems at the individual-unit
level.\290\
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    \290\ For example, as noted in Section VII.B.7 of this proposed
rule, there are currently five plants in the states covered by this
proposal where SCR-equipped coal-fired units and non-SCR-equipped
coal-fired units exhaust to common stacks. If the owners and
operators of these plants choose to report apportioned
NOX mass emissions data in preference to installing and
operating separate monitoring systems, the likely effect would be to
overstate reported NOX mass emissions for the SCR-
equipped units and correspondingly understate reported
NOX mass emissions for the non-SCR equipped units. This
would make compliance with the proposed backstop daily
NOX emissions rate more challenging for the SCR-equipped
units. If the EPA does not require the owners and operators to
install and operate separate monitoring systems for the individual
units in a final rule in this rulemaking, the owners and operators
would still have the option to do so if they believed it would be to
their benefit.
---------------------------------------------------------------------------

    In addition, to implement the proposed backstop daily
NOX emissions rates during the ozone season for certain
coal-fired units, the EPA is proposing to require additional
recordkeeping and reporting requirements for these units. Specifically,
starting in 2024 for coal-fired units with existing SCR controls
serving generators larger than 100 MW, and starting in 2027 for other
coal-fired units serving generators larger than 100 MW (except
circulating fluidized bed units), the units would be required to record
and report total daily NOX emissions and total daily heat
input, daily average NOX emissions rate, and daily
NOX emissions exceeding the applicable backstop daily
NOX emissions rates. The units would also be required to
record and report cumulative NOX emissions exceeding the
backstop daily NOX emissions rates for the ozone season.
These data would be used to determine the allowance surrender
requirements related to the backstop daily NOX emissions
rates. As with the additional recordkeeping and reporting requirements
discussed above for units exhausting to common stacks, implementation
of the additional recordkeeping and reporting requirements for coal-
fired units would necessitate a one-time update to the units' data
acquisition and handling systems but would not require any changes to
the monitoring systems already needed to meet other requirements under
40 CFR part 75.
    In states whose sources currently participate in the Group 3
trading program, as well as states whose sources participate in the
Group 2 trading program and would transition to the

Group 3 trading program under this proposal, units that are not subject
to the proposed backstop daily NOX emissions rates would not
need to make any changes to their current monitoring and reporting as a
result of the transition. The sources in states currently in the Group
2 trading program would be required to begin monitoring and reporting
of NOX emissions and operational data for purposes of the
Group 3 trading program as of May 1, 2023, the start of the 2023
control period.
    In states whose sources do not currently participate in the Group 2
trading program, any sources that currently report ozone season
NOX mass emissions according to 40 CFR part 75 to comply
with SIP requirements and that are not subject to the proposed backstop
daily NOX emissions rates similarly would not need to make
any changes to their current monitoring and reporting as a result of
the transition. Other sources in these states that currently report
SO2 and NOX emissions data according to 40 CFR
part 75 under other CSAPR trading programs or the Acid Rain Program
would not need to certify new monitoring systems for purposes of the
Group 3 trading program but would need to update their monitoring plans
and possibly update the software in their data acquisition and handling
systems to compute certain additional values from the measurements that
are already being recorded. All the sources in these states that
already have monitoring systems certified under 40 CFR part 75 would be
required to begin monitoring and reporting of NOX emissions
and operational data for purposes of the Group 3 trading program as of
the later of May 1, 2023, or the effective date of the final rule.\291\
---------------------------------------------------------------------------

    \291\ For units that currently report under 40 CFR part 75 only
for annual programs and that use the optional low mass emissions
methodology in 40 CFR 75.19, an additional consideration could
arise. Specifically, eligibility to use the low mass emissions
methodology for reporting ozone season NOX mass emissions
is restricted to units demonstrating that they have not exceeded or
will not exceed a maximum of 50 tons of NOX per ozone
season. In theory, some units that would be eligible to use the low
mass emissions methodology for purposes of annual programs only
might lose that eligibility because of the 50-ton ozone season cap
(which does not apply to units reporting for annual programs only).
Based on the emissions reports submitted for the 2018-2020 control
periods under the Acid Rain Program and the CSAPR annual programs,
none of the existing units that currently report under 40 CFR part
75 for annual programs only and that would be added to the Group 3
trading program under the proposal are presently in this theoretical
situation.
---------------------------------------------------------------------------

    Finally, any sources that meet the applicability criteria of the
Group 3 trading program and that do not currently report NOX
emissions data to the EPA under 40 CFR part 75 would need to certify
new monitoring systems in accordance with part 75 before they would be
required to monitor and report emissions for purposes of the Group 3
trading program. The units the EPA has been able to identify as
potentially affected under this proposal that may need to certify new
monitoring systems are listed in Table VII.B.3-1 (along with some other
units that are potentially affected under this proposal and that
already have certified monitoring systems). Because each of the listed
units commenced commercial operation more than 180 days before the date
when a final rule in this rulemaking would become effective, under the
current Group 3 trading program regulations (i.e., without the
revisions proposed in this section), each unit's monitor certification
deadline would generally be the effective date of the final rule. To
ensure that the final rule does not impose monitor installation and
certification requirements on these units before the effective date of
the final rule, the EPA is proposing to revise the Group 3 trading
program's monitor certification deadline provisions to establish a 180-
day window for certification of the new monitoring systems after the
effective date of a final rule in this rulemaking for units that do not
already have monitoring systems certified under 40 CFR part 75, similar
to the 180-day window already provided to units commencing commercial
operation after (or less than 180 days before) the final rule's
effective date. The 180th day for units in this situation would likely
fall after the end of the 2023 ozone season, with the result that the
certification deadline would be extended until May 1, 2024, the first
day of the 2024 ozone season. Because the program's allowance holding
requirements apply to a given unit only after that unit's monitor
certification deadline, the units in this situation consequently would
become subject to allowance holding requirements as of the 2024 ozone
season rather than the 2023 ozone season.\292\
---------------------------------------------------------------------------

    \292\ Table VII.B.3-1 of this proposed rule lists 22 existing
units in Delaware, Nevada, Utah, and Wyoming that appear to meet the
Group 3 trading program's general applicability criteria and that do
not already report NOX emissions data to the EPA under 40
CFR part 75 pursuant to any other existing regulatory requirements.
As noted in Section VII.B.3 of this proposed rule, six of the 22
listed units have reported that they may retire before the 2023
ozone season, and the possibility exists that up to nine of the
remaining listed units could qualify for an exemption from the Group
3 trading program available to certain cogeneration units. EPA
therefore projects that the revision to the monitor certification
deadline proposed in this section, and the related delay in
allowance holding requirements from 2023 to 2024, could apply to
between seven and 22 units, with the total estimated 2021 ozone
season NOX emissions for all such units ranging between
250 and 450 tons. During the period before allowance holding
requirements apply to the units--i.e., the period from the effective
date of a final rule in this rulemaking until the start of the 2024
control period--other requirements of the program would still apply,
such as the requirement for submission of a certificate of
representation by a designated representative and the requirements
related to installation and certification of required monitoring
systems.
---------------------------------------------------------------------------

    The EPA requests comment on the proposed revisions to the
recordkeeping and reporting provisions in 40 CFR part 75 and the
proposed establishment of a 180-day window for certification of new
monitoring systems after the effective date of a final rule in this
rulemaking for units that do not already have monitoring systems
certified under 40 CFR part 75. As discussed above, with respect to
units exhausting to common stacks, the EPA also requests comment on
whether units in particular situations should be required to obtain
hourly NOX mass emissions values through installation and
operation of monitoring systems at the individual-unit level instead of
being allowed to obtain values for individual units through
apportionment of the combined values for the units exhausting to the
common stack.
11. Transitional Provisions
    This section discusses several provisions that the EPA proposes to
implement in order to address the transition of sources into the Group
3 trading program as revised. The purposes of the proposed transitional
provisions are generally the same as the purposes of the analogous
transitional provisions promulgated in the Revised CSAPR Update: First,
accounting for the possibility that the effective date of a final rule
in this rulemaking will fall after the starting date of the first
affected ozone season (which in this case is, May 1, 2023); second,
establishing an appropriately-sized initial allowance bank through the
conversion of previously banked allowances; and third, preserving the
intended stringency of the Group 2 trading program for the sources that
will continue to be subject to that program.\293\ However, the sources
that would be participants in the revised Group 3 trading program under
this proposal are transitioning from several different starting
points--with some sources already in the Group 3 trading

program under its current regulations, some sources coming from the
Group 2 trading program, and some sources not currently participating
in any seasonal NOX trading program. EPA is therefore
proposing transitional provisions that differ across the sets of
potentially affected sources based on the sources' different starting
points.
---------------------------------------------------------------------------

    \293\ The EPA is not proposing to create a ``safety valve
mechanism'' in this rulemaking analogous to the safety valve
mechanism established under the Revised CSAPR Update.
---------------------------------------------------------------------------

a. Prorating Emissions Budgets, Assurance Levels, and Unit-Level
Allowance Allocations in the Event of an Effective Date After May 1,
2023
    While it is EPA's intent for a final rule in this rulemaking to
take effect before the start of the Group 3 trading program's 2023
control period on May 1, 2023, it is possible that the final rule's
effective date will fall after that date. The EPA proposes to address
this contingency by determining the amounts of emissions budgets and
unit-level allowance allocations on a full-season basis in the
rulemaking and by also including provisions in the revised regulations
to prorate the full-season amounts as needed to ensure that no sources
become subject to new or more stringent regulatory requirements before
the final rule's effective date.\294\ Variability limits and assurance
levels for 2023 would be computed using the appropriately prorated
emissions budgets amounts, and unit-level allocations would also be
prorated.\295\
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    \294\ As discussed in Sections VII.B.7 and VII.B.8 of this
proposed rule, the proposed revisions establishing unit-specific
backstop daily emissions rates and, for units contributing to
assurance level exceedances, secondary unit-specific emissions
limitations, would not take effect until the 2024 control period or
later.
    \295\ The EPA notes that transitional provisions similar to the
prorating provisions proposed in this section were finalized and
implemented under the Revised CSAPR Update.
---------------------------------------------------------------------------

    As discussed in Section VII.B.2 of this proposed rule, in the case
of states (and Indian country within the states' borders) whose sources
do not currently participate in either the Group 2 trading program or
the Group 3 trading program--Delaware, Minnesota, Nevada, Utah, and
Wyoming--the sources would begin participating in the Group 3 trading
program on the later of May 1, 2023, or the final rule's effective
date. For these states, in the rulemaking the EPA would compute the
full-season emissions budgets that would apply for the entire 2023
control period if the final rule becomes effective no later than May 1,
2023, and is therefore in effect for the entire 153-day control period
from May 1, 2023, through September 30, 2023. If the final rule becomes
effective after May 1, 2023, the EPA would determine prorated emissions
budgets by multiplying each full-season emissions budget by the number
of days from the rule's effective date through September 30, 2023,
dividing by 153 days, and rounding to the nearest allowance. The
prorated variability limits would be computed as 21 percent of the
prorated emissions budgets, rounded to the nearest allowance, yielding
prorated assurance levels that equal 121 percent of the prorated
emissions budgets. To determine unit-level allocation amounts from the
prorated emissions budgets, the EPA would determine full-season
allocation amounts in the rulemaking and would determine preliminary
prorated allocation amounts in the same manner as described for the
emissions budgets previously. The preliminary prorated amounts of the
largest unit-level allowance allocations for each state would then each
be adjusted up or down by one allowance as needed to cause the sum of
the final prorated unit-level allowance allocations for the state to
equal the state's prorated emissions budget. All calculations required
to determine the prorated emissions budgets and variability limits and
the unit-level allocations for the 2023 control period would be carried
out as soon as possible after the EPA learns the effective date of a
final rule in this rulemaking (which is expected to be approximately 60
days after the date of the final rule's publication in the Federal
Register). The unit-level allocations for both the 2023 and 2024
control periods would be recorded in facilities' compliance accounts
approximately 30 days after the final rule's effective date, as
discussed in Section VII.B.9.b of this proposed rule.
    In the case of states (and Indian country within the states'
borders) whose sources currently participate in the Group 3 trading
program--Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan,
New Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia--
the sources would continue to participate in the Group 3 trading
program for the 2023 control period, subject to prorating procedures
designed to ensure that the changes in 2023 emissions budgets and
assurance levels would not substantively affect the sources'
requirements prior to the rule's effective date. For these states, in
the rulemaking the EPA would compute the full-season emissions budgets
that would apply for the entire 2023 control period if the final rule
becomes effective no later than May 1, 2023, but the EPA would not
remove from the regulations the full-season emissions budgets for the
2023 control period that were established in the Revised CSAPR Update
rulemaking. Instead, the EPA would include both sets of emissions
budgets and variability limits in the regulations, along with a
provision indicating that the emissions budgets promulgated in the
Revised CSAPR Update would apply on a prorated basis for the portion of
the 2023 control period before the final rule's effective date and the
emissions budgets established in this rulemaking would apply on a
prorated basis for the portion of the 2023 control period on and after
the final rule's effective date. Under this provision, the EPA would
determine a blended emissions budget for each state for the 2023
control period, computed as the sum of the appropriately prorated
amounts of the state's current and revised emissions budgets. (For
example, if the final rule became effective on the eleventh day of the
153-day 2023 control period, the blended emissions budget would equal
the sum of 10/153 times the current emissions budget plus 143/153 times
the revised emissions budget, rounded to the nearest allowance.)
Blended variability limits for the 2023 control period would be
computed as 21% of the blended emissions budgets, yielding blended
assurance levels equal to 121 percent of the blended emissions budgets.
Unit-level allocations would be determined by applying the allocation
procedure described in Section VII.B.9 of this proposed rule to the
blended budgets. In the case of states (and Indian country within the
states' borders) whose sources currently participate in the Group 2
trading program--Alabama, Arkansas, Mississippi, Missouri, Oklahoma,
Tennessee, Texas, and Wisconsin--the sources would begin to participate
in the Group 3 trading program as of May 1, 2023, regardless of the
final rule's effective date, as discussed in Section VII.B.2 of this
proposed rule, subject to prorating procedures designed to ensure that
the transition from the Group 2 trading program to the Group 3 trading
program would not substantively affect the sources' requirements prior
to the rule's effective date. The prorating procedures for these states
would mirror the procedures for the states currently in the Group 3
trading program, except that because no emissions budgets currently
appear in the Group 3 trading program regulations for the states that
are currently covered by the Group 2 trading program, the EPA would add
two sets of emissions budgets for these states to the Group 3 trading
program regulations: First, the states' emissions budgets for the 2023
control period that currently appear in the Group 2 trading

program regulations, which would be included in the revised Group 3
trading program regulations to represent the states' emissions budgets
for the portion of the 2023 control period before the final rule's
effective date, and second, the emissions budgets for the 2023 control
period established for the states in this rulemaking, which would be
included in the revised Group 3 trading program regulations to
represent the state's emissions budgets for the portion of the 2023
control period on and after the final rule's effective date. The
procedures for determining blended emissions budgets, variability
limits and assurance levels, and unit-level allowance allocations would
be the same as for the states currently in the Group 3 trading program.
Again, all calculations required to determine the prorated emissions
budgets and variability limits and the unit-level allocations for the
2023 control period would be carried out as soon as possible after the
EPA learns the effective date of a final rule in this rulemaking (which
is expected to be approximately 60 days after the date of the final
rule's publication in the Federal Register). The unit-level allocations
for both the 2023 and 2024 control periods would be recorded in
facilities' compliance accounts approximately 30 days after the final
rule's effective date, as discussed in Section VII.B.9.b of this
proposed rule.
    The reason for proposing that sources currently in the Group 2
trading program would begin to participate in the Group 3 trading
program on May 1, 2023 even if the final rule's effective date is after
May 1, 2023, is that it would serve the public interest and greatly aid
in administrative efficiency for most elements of the Group 3 trading
program--specifically, all elements of the trading program other than
the elements designed to establish more stringent emissions limitations
for the sources coming from the Group 2 trading program--to apply to
the sources starting on May 1, 2023. This would facilitate
implementation of the Group 3 trading program in an orderly manner for
the entire 2023 ozone season and reduce compliance burdens and
potential confusion. Each of the CSAPR trading programs for ozone
season NOX is designed to be implemented over an entire
ozone season. Implementing the transition from the Group 2 trading
program to the Group 3 trading program in a manner that required the
covered sources to participate in the Group 2 trading program for part
of the 2023 ozone season and the Group 3 trading program for the
remainder of that ozone season would be complex and burdensome for
sources. Attempting to address the issue by splitting the Group 2 and
Group 3 requirements for these sources into separate years is not a
viable approach, because EPA has no legal basis for releasing the
transitioning Group 2 sources from the emissions reduction requirements
found to be necessary in the CSAPR Update for a portion of the 2023
ozone season, and EPA similarly has no legal basis for deferring
implementation of the 2023 emissions reduction requirements found to be
necessary under this rule for the transitioning Group 2 sources until
2024. Moreover, the requirements of the current Group 2 trading program
and the revised Group 3 trading program for the 2023 control period are
substantively identical as to almost all provisions, such that with
respect to those provisions, a source will not need to alter its
operations in any manner or face different compliance obligations as a
consequence of a transition from the Group 2 trading program to the
Group 3 trading program. Thus, the EPA believes that no substantive
concerns regarding retroactivity arise from transitioning the sources
currently in the Group 2 trading program to the Group 3 trading program
starting on May 1, 2023, as long as those aspects of the revised Group
3 trading program for the 2023 control period that do meaningfully
differ from the analogous aspects of the Group 2 trading program--that
is, the relative stringencies of the two trading programs, as reflected
in the emissions budgets and associated assurance levels--are applied
only as of the effective date of the final rule.
    In all respects other than prorating the emissions budgets,
variability limits and assurance levels, and unit-level allowance
allocations, with respect to the sources currently participating in the
Group 2 trading program or the Group 3 trading program, the EPA
proposes to implement the revised Group 3 trading program for the 2023
control period in a uniform manner for the entire control period. Thus,
emissions would be monitored and reported for the entire 2023 ozone
season (i.e., May 1, 2023, through September 30, 2023), and as of the
allowance transfer deadline for the 2023 control period (i.e., June 1,
2024) each source would be required to hold in its compliance account
vintage-year 2023 Group 3 allowances not less than the source's
emissions of NOX during the entire 2023 ozone season. Any
efforts undertaken by one of these sources to reduce its emissions
during the portion of the 2023 ozone season before the effective date
of the rule would aid the source's compliance by reducing the amount of
Group 3 allowances that the source would need to hold in its compliance
account as of the allowance transfer deadline, increasing the range of
options available to the source for meeting its compliance obligations
under the revised Group 3 trading program. In the case of the sources
that do not currently participate in the Group 2 trading program or the
Group 3 trading program, the EPA similarly proposes to implement the
revised Group 3 trading program for the 2023 control period in a
uniform manner for the entire control period, except that the 2023
control period for these sources may be shorter than the normal 153-day
length.
    The EPA requests comment on this approach for implementing the
Group 3 trading program in a manner that would apply the substantive
increases in stringency of the emissions budgets and assurance levels
established under the final rule on and after, but not before, the
final rule's effective date.
b. Creation of Additional Group 3 Allowance Bank for 2023 Control
Period
    In the CSAPR Update, where the EPA established the Group 2 trading
program and transitioned over 95% of the sources that had been
participating in what is now the CSAPR NOX Ozone Season
Group 1 Trading Program (the ``Group 1 trading program'') to the new
program, the EPA determined that it was reasonable to establish an
initial bank of allowances for the Group 2 trading program by
converting almost all allowances banked under the Group 1 trading
program at a conversion ratio determined by a formula. In the Revised
CSAPR Update, where EPA established the Group 3 trading program and
transitioned approximately 55% of the sources that had been
participating in the Group 2 trading program to the new program, the
EPA similarly determined that it was reasonable to establish an initial
bank of allowances for the Group 3 trading program by converting
allowances banked under the Group 2 trading program at a conversion
ratio determined by a formula, using a conversion procedure that was
modified to leave much of the Group 2 allowance bank available for use
by the approximately 45% of sources then in the Group 2 trading program
that would remain in that program. Any conversion of banked allowances
from a previous trading program for use in a new trading program must
ensure that implementation of the new trading program will result in
NOX emissions

reductions sufficient to address significant contribution by all states
that would be participating in the new trading program, while also
providing industry certainty (and obtaining an environmental benefit)
through continued recognition of the value of saving allowances through
early reductions in emissions. EPA's approach to balancing these
concerns in the CSAPR Update through the conversion of banked
allowances from the Group 1 trading program to the Group 2 trading
program was upheld in Wisconsin v. EPA, see 938 F.3d at 321.
    In the current rulemaking, applying the same balancing principle as
in the CSAPR Update and the Revised CSAPR Update, the EPA proposes to
carry out a further conversion of allowances banked for control periods
before 2023 under the Group 2 trading program into allowances usable in
the Group 3 trading program in control periods in 2023 and later years.
Because the EPA is proposing to transition over 90% of the remaining
sources in the Group 2 trading program to the Group 3 trading program--
much closer to the situation in the CSAPR Update than the situation in
the Revised CSAPR Update--in this rulemaking EPA proposes to apply a
conversion procedure similar to the procedure followed in the CSAPR
Update. Under the proposed conversion procedure, in the final rule in
this rulemaking the EPA would not set a predetermined conversion ratio
but instead would set provisions defining the types of accounts whose
holdings of Group 2 allowances would be converted to Group 3 allowances
and establishing the target amount of new Group 3 allowances that would
be created. The proposed conversion date would be August 1, 2023, which
is 2 months after the compliance deadline for the 2022 control period
under the Group 2 trading program and ten months before the compliance
deadline for the 2023 control period under the Group 3 trading program.
The actual conversion ratio would be determined as of the conversion
date and would be the ratio of the total amount of Group 2 allowances
held in the identified types of accounts prior to the conversion to the
total amount of Group 3 allowances being created. Consistent with the
approach taken in the CSAPR Update, the EPA proposes to define the
types of accounts included in the conversion to include all accounts
except the facility accounts of sources in states that would remain in
the Group 2 trading program.\296\ Thus, the accounts whose holdings of
Group 2 allowances would be converted to Group 3 allowances would
include (1) the facility accounts of all sources in the states
transitioning from the Group 2 trading program to the Group 3 trading
program, (2) the facility accounts of all sources in the states already
participating in the Group 3 trading program, (3) the facility accounts
of all sources in any other states not covered by the Group 2 trading
program that happen to hold Group 2 allowances as of the conversion
date, and (4) all general accounts (that is, accounts that are not
facility accounts, including other accounts controlled by source owners
as well as accounts controlled by non-source entities such as allowance
brokers). Creating the new Group 3 allowances through conversion of
previously banked Group 2 allowances would also help preserve the
stringency of the Group 2 trading program for the states that remain
covered by that trading program at levels consistent with the
stringency found to be appropriate to address those states' good
neighbor obligations with respect to the 2008 ozone NAAQS in the CSAPR
Update.
---------------------------------------------------------------------------

    \296\ If the proposed expansion of geographic scope for the
Group 3 trading program is unchanged in the final rule, the states
whose sources would continue to participate in the Group 2 trading
program would be Iowa and Kansas.
---------------------------------------------------------------------------

    With respect to setting the target amount of Group 3 allowances
that would be created in the conversion process, the EPA proposes to
follow the same approach that was used in the Revised CSAPR Update for
creation of the initial Group 3 allowance bank. Specifically, the
target amount of Group 3 allowances to be created would be computed as
the sum of the variability limits for the 2024 control period \297\
established in the final rule for the states being transitioned to the
Group 3 trading program from the Group 2 trading program, prorated to
reflect the portion of the 2023 control period occurring on and after
the effective date of the final rule. Based on the amounts of the
proposed state emissions budgets and variability limits, the full-
season target amount for the conversion would be 18,517 Group 3
allowances. The quantity of banked Group 2 allowances currently held in
accounts other than the facility accounts of sources in Iowa and Kansas
exceeding the quantity of allowances likely to be needed for 2021
compliance is approximately 110,000 allowances. If the quantities of
banked Group 2 allowances did not change between now and the conversion
date, and if there was no prorating adjustment, the conversion ratio
would be approximately 5.9-to-1, meaning that one Group 3 allowance
would be created for every 5.9 Group 2 allowances deducted in the
conversion process.\298\
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    \297\ Similar to the approach taken in the Revised CSAPR Update,
because emissions reductions from some of the emissions controls
that EPA has identified as appropriate to use in setting budgets are
first reflected in the 2024 state budgets rather than the 2023 state
budgets, the EPA is proposing to base the bank target amount on the
sum of the states' 2024 variability limits rather than the 2023
variability limits.
    \298\ By comparison, the analogous conversion ratio under the
Revised CSAPR Update was 8-to-1.
---------------------------------------------------------------------------

    As noted in Section VII.B.11.a of this proposed rule, it is
possible that the effective date of this rule will occur after the
start of the 2023 ozone season, and provisions are being proposed to
ensure that the increased stringency of this rule's state budgets and
state assurance levels (i.e., the sums of the budgets and variability
limits) would take effect only after the rule's effective date.
Consistent with these other procedures, the EPA is proposing to
similarly prorate the bank target amount used in the conversion
process. For example, if the effective date of the final rule is the
eleventh day of the 153-day 2023 ozone season, the full-season initial
bank target amount of 18,517 allowances would be prorated to an initial
bank target amount of 17,307 allowances.\299\ The EPA notes that
prorating the bank amount in this manner would not reduce sources'
compliance flexibility for the 2023 ozone season, because the amounts
of Group 3 allowances that sources would receive for the portion of the
2023 ozone season before the rule's effective date would be based on
the current trading program budgets for the 2023 control period before
this rulemaking. The current trading program budgets exceed the
sources' collective 2021 emissions by approximately 18,600 tons,
indicating potentially surplus allowances roughly equal to the full-
season bank conversion target amount of 18,517 allowances. Thus,
although the prorating procedure would reduce the amount of Group 3
allowances that would be available to sources in the form of an initial
bank, the reduction in the quantity of these allowances would be offset
by the quantities of Group 3 allowances that would be allocated in
excess of sources' recent historical emissions levels for the portion
of the ozone season before the final rule's effective date.
---------------------------------------------------------------------------

    \299\ 18,517 x (153-10) / 153 = 17,307.
---------------------------------------------------------------------------

    As in the CSAPR Update and the Revised CSAPR Update, EPA's overall
objective in establishing the target amount for the allowance
conversion would be to achieve a total target amount for the bank at a
level high enough to accommodate year-to-year

variability in operations and emissions, as reflected in states'
variability limits, but not high enough to allow sources collectively
to plan to emit in excess of the collective state budgets. EPA believes
that a well-established trading program would be able to function with
an allowance bank lower than the full amount of the covered states'
variability limits, as discussed in section VII.B.6 with respect to the
proposed bank recalibration process that would begin with the 2024
control period. However, EPA also believes there are several compelling
reasons in this instance to use a bank target higher than the minimum
practicable level.
    First, making an allowance bank available for use in the 2023
control period that is somewhat higher than the minimum practicable
level would help to address concerns that might otherwise arise
regarding the transition to a new set of compliance requirements, for
some sources, and the transition to compliance requirements based on
revised emissions budgets different from the emissions budgets that the
sources had reason to anticipate under previous rulemakings, for the
remaining sources. Although the EPA is confident that the emissions
budgets being proposed in this rulemaking for the 2023 control period
are readily achievable, the EPA also believes that the existence of a
somewhat larger allowance bank at this transition point will promote
sources' confidence in their ability to meet their 2023 compliance
obligations in general and in a liquid allowance market in particular.
Second, because the large majority of the remaining Group 2 allowances
that would be converted to Group 3 allowances in this rulemaking are
held by the sources currently in the Group 2 trading program, while the
large majority of the initial bank of Group 3 allowances previously
created in the conversion under the Revised CSAPR Update are held by
the sources already in the Group 3 trading program, basing the
conversion in this rulemaking on a target bank amount set in the same
manner as the target bank amount used in the Revised CSAPR Update is
expected to result in a less concentrated distribution of holdings of
banked Group 3 allowances following the conversion than would be the
case if a more stringent target bank amount were used under this
rulemaking than was used in the Revised CSAPR Update. A lower
concentration of holdings of banked Group 3 allowances would generally
be expected to help ensure allowance market liquidity. Third, EPA
considers it equitable to treat the sources in the states transitioning
from the Group 2 trading program to the Group 3 trading program in this
rulemaking roughly similarly to the sources in the states that
transitioned between the same two trading programs in the Revised CSAPR
Update with respect to the benefit they would receive under the Group 3
trading program for any efforts they may have made to make emissions
reductions under the Group 2 trading program beyond the minimum efforts
that were required to comply with the emissions budgets under that
program. Finally, to the extent that the proposed conversion results in
a larger bank of allowances remaining after the 2023 control period
than is considered necessary to sustain a well-functioning trading
program in subsequent control periods, the excess would be removed from
the program in the proposed bank recalibration process that would be
implemented starting with the 2024 control period and therefore would
not weaken sources' incentives to control emissions on a permanent
basis.
    The EPA requests comment on the proposal to create additional
banked Group 3 allowances through the conversion of Group 2 allowances
banked for control periods before 2023.
c. Recall of Group 2 Allowances Allocated for Control Periods After
2022
    To maintain the previously established levels of stringency of the
Group 2 trading program for the states and sources that remain subject
to that program under this proposed rule, the EPA proposes to recall
CSAPR NOX Ozone Season Group 2 allowances equivalent in
amount and usability to all vintage year 2023-2024 CSAPR NOX
Ozone Season Group 2 allowances previously allocated to sources in
Group 3 states and areas of Indian country and recorded in the sources'
compliance accounts. The proposed recall provisions would apply to all
sources in jurisdictions newly added to the Group 3 trading program in
whose compliance accounts CSAPR NOX Ozone Season Group 2
allowances for a control period in 2023 or 2024 were recorded,
including sources where some or all units have permanently retired or
where the previously recorded 2023-2024 allowances have been
transferred out of the compliance account. The proposed recall
provisions provide a flexible compliance schedule intended to
accommodate any sources that have already transferred the previously
recorded 2023-2024 allowances out of their compliance accounts and
allows Group 2 allowances of earlier vintages to be surrendered to
achieve compliance. Like the similar recall provisions finalized in the
Revised CSAPR Update, the proposed recall provisions include
specifications for how the recall provisions apply in instances where a
source and its allowances have been transferred to different parties
and for the procedures that the EPA will follow to implement the
recall.
    Under the Group 2 trading program regulations, each Group 2
allowance is a ``limited authorization to emit one ton of
NOX during the control period in one year,'' where the
relevant limitations include the EPA Administrator's 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.'' 40 CFR
97.806(c)(6)(ii). The Administrator proposes to determine that, in
order to effectively implement the Group 2 trading program as a
compliance mechanism through which states not subject to the Group 3
trading program may continue to meet their obligations under CAA
section 110(a)(2)(D)(i)(I) with regard to the 2008 ozone NAAQS, it is
necessary to limit the use of Group 2 allowances equivalent in quantity
and usability to all Group 2 allowances previously allocated for the
2023-2024 control periods and recorded in the compliance accounts of
sources in the newly added Group 3 jurisdictions. The Group 2
allowances that have already been allocated to sources in the newly
added Group 3 states for the 2023-2024 control periods and recorded in
the sources' compliance accounts represent the substantial majority of
the total remaining quantity of Group 2 allowances that have been
allocated and recorded for the 2023-2024 control periods and that were
not already made subject to recall when other jurisdictions were
transferred from the Group 2 trading program to the Group 3 trading
program in the Revised CSAPR Update. Because allowances can be freely
traded, if the use of the 2023-2024 Group 2 allowances previously
recorded in newly added Group 3 sources' compliance accounts (or
equivalent Group 2 allowances) were not limited, the effect would be
the same as if the EPA had issued to sources in the states that will
remain covered by the Group 2 trading program a quantity of allowances
available for compliance under the 2023-2024 control periods many times
the levels that the EPA determined to be appropriate emissions budgets
for these states in the CSAPR Update. Through the use of banked
allowances, the excess Group 2

allowances would affect compliance under the Group 2 trading program in
control periods after 2024 as well. Continued implementation of the
Group 2 trading program at levels of stringency consistent with the
levels contemplated under the CSAPR Update therefore requires that the
EPA limit the use of the excess allowances, as the EPA is proposing
here.
    In this rulemaking, the EPA proposes to implement limitations on
the use of the excess 2023-2024 Group 2 allowances through requirements
to surrender, for each 2023-2024 Group 2 allowance recorded in a newly
added Group 3 source's compliance account, one Group 2 allowance of
equivalent usability under the Group 2 trading program. The surrender
requirements would apply to the owners and operators of the Group 3
sources in whose compliance account the excess 2023-2024 Group 2
allowances were initially recorded. In general, each source's current
owners and operators would be required to comply with the surrender
requirements for the source by ensuring that sufficient allowances to
complete the deductions are available in the source's compliance
account by one of two possible deadlines discussed below. However, an
exception would be provided if a source's current owners and operators
obtained ownership and operational control of the source in a
transaction that did not include rights to direct the use and transfer
of some or all of the 2023-2024 Group 2 allowances allocated and
recorded (either before or after that transaction) in the source's
compliance account. The proposed rule provides that in such a
circumstance, with respect to the 2023-2024 Group 2 allowances for
which rights were not included in the transaction, the surrender
requirements would apply to the most recent former owners and operators
of the source before any such transactions occurred. Because in this
situation a source's former owners and operators might lack the ability
to access the source's compliance account for purposes of complying
with the surrender requirements, the former owners and operators would
instead be allowed to meet the surrender requirements with Group 2
allowances held in a general account.\300\
---------------------------------------------------------------------------

    \300\ The EPA is currently unaware of any source that would need
to use this flexibility but has included the option in the proposal
to address the theoretical possibility of such a situation.
---------------------------------------------------------------------------

    To provide as much flexibility as possible consistent with the need
to limit the use of the excess Group 2 allowances, for each 2023-2024
Group 2 allowance recorded in a Group 3 source's compliance account,
the EPA proposes to accept the surrender of either the same specific
2023-2024 Group 2 allowance or any other Group 2 allowance with
equivalent (or greater) usability under the Group 2 trading program.
Thus, a surrender requirement with regard to a Group 2 allowance
allocated for the 2023 control period could be met through the
surrender of any Group 2 allowance allocated for the 2023 control
period or the control period in any earlier year--in other words, any
2017-2023 Group 2 allowance.\301\ Similarly, the surrender requirement
with regard to a 2024 Group 2 allowance could be met through the
surrender of any 2017-2024 Group 2 allowance.
---------------------------------------------------------------------------

    \301\ The first control period for the Group 2 trading program
was in 2017.
---------------------------------------------------------------------------

    Owners and operators subject to the surrender requirements could
choose from two possible deadlines for meeting the requirements. The
first deadline would be 15 days after the effective date of a final
rule in this rulemaking.\302\ As soon as practicable or after this
date, the EPA would make a first attempt to complete the deductions of
Group 2 allowances required for each Group 3 source from the source's
compliance account. The EPA would deduct Group 2 allowances first to
address any surrender requirements for the 2023 control period and then
to address any surrender requirements for the 2024 control period. When
deducting Group 2 allowances to address the surrender requirements for
each control period, EPA would first deduct allowances allocated for
that control period and then would deduct allowances allocated for each
successively earlier control period. This order of deductions is
intended to ensure that whatever Group 2 allowances are available in
the account are applied to the surrender requirements in a manner that
both maximizes the extent to which all of the source's surrender
requirements would be met and also ensures that any Group 2 allowances
left in the source's compliance account after completion of all
required deductions would be the earliest allocated, and therefore most
useful, Group 2 allowances possible. Among the Group 2 allowances
allocated for a given control period, The EPA would first deduct
allowances that were initially recorded in that account, in the order
of recordation, and would then deduct allowances that were transferred
into that account after having been initially recorded in some other
account, in the order of recordation.
---------------------------------------------------------------------------

    \302\ As discussed later in this section and in Section
VII.B.9.b, the EPA is proposing to condition recordation of any
allocations of Group 3 allowances in a source's compliance account
on the source's prior compliance with the proposed recall
requirements for Group 2 allowances. The purpose of providing a
first deadline for the recall provisions 15 days after a final
rule's effective would be to ensure that sources have an early
opportunity to comply with the recall provisions in order to be
eligible to have allocations of Group 3 allowances recorded in their
accounts as proposed 30 days after the final rule's effective date.
Because the vast majority of sources subject to the proposed recall
provisions already hold sufficient Group 2 allowances to comply with
the recall provisions, the EPA anticipates that the sources would
easily be able to comply with the proposed first recall deadline.
---------------------------------------------------------------------------

    Following the first attempt to deduct Group 2 allowances to address
Group 3 sources' surrender requirements, the EPA would send a
notification to the designated representative for each such source (as
well as any alternate designated representative) indicating whether all
required deductions were completed and, if not, the additional amounts
of Group 2 allowances usable in the 2023 or 2024 control periods that
must be held in the appropriate account by the second surrender
deadline of September 15, 2023. Each notification would be sent to the
email addresses most recently provided to the EPA for the recipients
and would include information on how to contact the EPA with any
questions. The EPA proposes that no allocations of Group 3 allowances
would be recorded in a source's compliance account until all the
source's surrender requirements with regard to 2023-2024 Group 2
allowances have been met. For this reason, the principal consequence to
a source of failure to fully comply with the surrender requirements by
15 days after the effective date of a final rule would be that any
Group 3 allowances allocated to the units at the source for the 2023
and 2024 control periods that would otherwise have been recorded in the
source's compliance account by 30 days after the effective date of a
final rule would not be recorded as of that recordation date.
    If all surrender requirements of 2023-2024 Group 2 allowances for a
source have not been met in EPA's first attempt, the EPA would make a
second attempt to complete the required deductions from the source's
compliance account (or from a specified general account, in the limited
circumstance noted above) as soon as practicable on or after September
15, 2023. The order in which Group 2 allowances are deducted would be
the same as described above for the first attempt.
    If the second attempt to deduct Group 2 allowances to meet the
surrender requirements through deductions from the source's compliance
account (or

from a specified general account) is unsuccessful for a given source,
the EPA proposes that as soon as practicable on or after November 15,
2023, to the extent necessary to address the unsatisfied surrender
requirements for the source, the EPA would deduct the 2023-2024 Group 2
allowances that were initially recorded in the source's compliance
account from whatever accounts the allowances are held in as of the
date of the deduction, except for any allowances where, as of April 1,
2022, no person with an ownership interest in the allowances was an
owner or operator of the source, was a direct or indirect parent or
subsidiary of an owner or operator of the source, or was directly or
indirectly under common ownership with an owner or operator of the
source.\303\ Before making any deduction under this provision, the EPA
would send a notification to the authorized account representative for
the account in which the allowance is held and would provide an
opportunity for submission of objections concerning the data upon which
the EPA is relying. In EPA's view, this provision would not unduly
interfere with the legitimate expectations of participants in the
allowance markets because the provision would not be invoked in the
case of any allowance that was transferred to an independent party in
an arms-length transaction before EPA's intent to recall 2023-2024
Group 2 allowances became widely known. The provision would apply only
to a Group 2 allowance that, as of April 1, 2022, was still controlled
either by the owners and operators of the source in whose compliance
account it was initially recorded or by an entity affiliated with such
an owner or operator. The EPA believes that by April 1, 2022, all
market participants will have had ample opportunity to become informed
of the proposed rule provisions to recall 2023-2024 Group 2 allowances
recorded in Group 3 sources' compliance accounts, particularly since
the EPA implemented a closely analogous recall of Group 2 allowances in
the Revised CSAPR Update.\304\
---------------------------------------------------------------------------

    \303\ The proposed provision under which the EPA would not
deduct Group 2 allowances transferred to unrelated parties before
April 1, 2022 from the transferees' accounts would not relieve the
source to which the Group 2 allowances were originally allocated
from the obligation to comply with the recall requirements.
Specifically, the source would be required to comply with the recall
requirements by obtaining and surrendering other Group 2 allowances.
    \304\ Even before publication of the proposed rule, the EPA
posted information on its websites to notify market participants
that a pending rulemaking could have consequences for the value and
usability of Group 2 allowances. The posted locations included the
electronic portal that authorized account representatives use to
enter allowance transfers for recordation by the EPA in the
Allowance Management System. Additionally, the EPA emailed a notice
identifying the possibility of such consequences to the
representatives for all Allowance Management System accounts.
---------------------------------------------------------------------------

    The EPA proposes that failure of a source's owners and operators to
comply with the surrender requirements would be subject to possible
enforcement as a violation of the CAA, with each allowance and each day
of the control period constituting a separate violation.
    To eliminate any possible uncertainty regarding the amounts of
Group 2 allowances allocated for the 2023-2024 control periods (or
earlier control periods) that the owners and operators of each Group 3
source would be required to surrender under the recall provisions, the
EPA has prepared a list of the sources in the proposed additional Group
3 states and areas of Indian country in whose compliance accounts
allocations of 2023-2024 Group 2 allowances were recorded, with the
amounts of the allocations recorded in each such compliance account for
the 2023 and 2024 control periods. An additional list shows, for each
newly added Group 3 source, the specific Group 2 allowances (batched by
serial number) allocated for each control period and recorded in the
source's compliance account and indicates whether, as of December 31,
2021, that batch of allowances was held in the source's compliance
account, in an account believed to be partially or fully controlled by
a related party (i.e., an owner or operator of the source or an
affiliate of an owner or operator of the source), or in an account
believed to be fully controlled by independent parties. The lists are
in a spreadsheet titled, ``Recall of Additional CSAPR NOX
Ozone Season Group 2 Allowances'', available in the docket for this
proposed rule. After the first and second surrender deadlines, the EPA
intends to update the lists to indicate for each Group 3 source whether
the surrender requirements for the source under the recall provisions
have been fully satisfied. The EPA would post the updated lists on a
publicly accessible website to ensure that all market participants have
the ability to determine which specific 2023-2024 Group 2 allowances
initially recorded in any given Group 3 source's compliance account do
or do not remain subject to potential deduction to address the source's
surrender requirements under the recall provisions.
    The EPA requests comment on the proposal to recall Group 2
allowances equivalent in quantity and usability to the Group 2
allowances previously issued for the 2023 and 2024 control periods and
recorded in the compliance accounts of sources in jurisdictions being
newly added to the Group 3 trading program in this proposed rule.
12. Conforming Revisions to Other Regulations
    As noted in Section VII.B.1.a of this proposed rule, in addition to
the Group 3 trading program, EPA currently administers five other CSAPR
trading programs, all of which have provisions that in most respects
parallel the provisions of the Group 3 trading program.\305\ The EPA
also administers the Texas SO2 Trading Program, whose
provisions parallel the provisions of the CSAPR trading programs to a
somewhat lesser extent.\306\ In this rulemaking, in addition to the
proposed revisions to the Group 3 trading program, the EPA is proposing
a small number of conforming revisions to the other CSAPR trading
programs and/or the Texas SO2 Trading Program to maintain
consistency across the regulations for the various trading programs to
the extent possible.
---------------------------------------------------------------------------

    \305\ The regulations for the Group 3 Trading Program are at 40
CFR 97, subpart GGGGG. The regulations for the other five CSAPR
trading programs are at 40 CFR part 97, subparts AAAAA, BBBBB,
CCCCC, DDDDD, and EEEEE.
    \306\ The regulations for the Texas SO2 Trading
Program are at 40 CFR part 97, subpart FFFFF.
---------------------------------------------------------------------------

    The first set of proposed conforming revisions concerns the use of
the term ``Indian country'' in the allowance allocation provisions of
the regulations for all the CSAPR trading programs. As discussed in
Section VII.B.9.a of this proposed rule, to reflect the D.C. Circuit's
holding in ODEQ v. EPA that states have initial CAA implementation
planning authority in non-reservation areas of Indian country until
displaced by a demonstration of tribal jurisdiction over such an area,
the EPA is proposing to revise the allowance allocation provisions in
the Group 3 trading program regulations so that, instead of
distinguishing between the sets of units within a given state's borders
that either are not or are in Indian country, the revised regulations
would distinguish between (1) the set of units within the state's
borders that are not in Indian country or are in areas of Indian
country covered by the state's CAA implementation planning authority
and (2) the set of units within the state's borders that are in areas
of Indian country not covered by the state's CAA implementation
planning authority. For the same reasons stated in Section VII.B.9.a of
this proposed rule for the

Group 3 trading program, the EPA proposes to make revisions to the
allowance allocation provisions in the regulations for all the other
CSAPR trading programs establishing the same substantive distinction
among the sets of units within each state's borders. The specific
regulatory provisions that would be affected are identified in Section
X of this proposed rule. The EPA is unaware of any currently operating
units that would be affected by this proposed revision to the
regulations for the other CSAPR trading programs.
    The second set of proposed conforming revisions concerns the
schedule for recording allocations of allowances to existing units. To
maintain consistency with the provisions of the revised Group 3 Trading
Program to the extent possible, the EPA proposes to revise the
regulations for each of the other five CSAPR trading programs and the
Texas SO2 Trading Program to reflect whatever revised
schedule for recording most allowance allocations the EPA may adopt for
the revised Group 3 trading program in a final rule in this rulemaking.
The proposed revisions to the recordation deadlines would affect only
the timing of recordation, not the amounts of allowances allocated to
and recorded for any source for any control period.
    The effect of the proposed revisions would be to establish a new
common recordation schedule for all the CSAPR trading programs and the
Texas SO2 Trading Program. Assuming the common schedule
adopted is the specific schedule proposed for the Group 3 trading
program in Section VII.B.9 of this proposed rule, allocations from the
portion of each state emissions budget under each program not reserved
in a set-aside would be recorded by July 1 of the year immediately
preceding the year of the relevant control period. Under the current
regulations before the proposed revisions, the equivalent recordation
deadline is July 1 of the year three years before the year of the
relevant control period. Relatedly, the EPA also proposes to revise the
deadline for states to submit any state-determined allocations to the
EPA under each trading program to June 1 of the year immediately
preceding the year of the relevant control period, instead of June 1 of
the year three years before the year of the relevant control
period.\307\
---------------------------------------------------------------------------

    \307\ The regulations for the various programs already establish
a common recordation schedule for the portion of each state
emissions budget set aside for possible allocation to new units--
namely, by May 1 of the year after the year of the relevant control
period. The related deadline for states to submit any state-
determined allocations of these allowances to the EPA under each
program is April 1 of the year after the year of the relevant
control period.
---------------------------------------------------------------------------

    This EPA believes that revising the recordation schedules as
proposed to establish a new common recordation schedule for the
affected trading programs would make the programs procedurally more
consistent, generally reducing the time and cost expended by sources to
understand and comply with multiple trading programs. Greater
consistency across the various programs would also support greater
administrative efficiency by the EPA and by states that elect to
determine allowances allocations under the various programs. In
addition, by reducing the number of future control periods for which
allowances are recorded, the proposed revisions would reduce the
likelihood that the EPA might need to recall already-recorded
allowances as part of a transition for some sources to new regulatory
requirements in a future rulemaking. The EPA has implemented such a
recall in the Revised CSAPR Update and has proposed to implement a
similar recall in this rulemaking.
    Finally, the EPA believes that revising the recordation schedules
for the other CSAPR trading programs and the Texas SO2
Trading Program as proposed would not adversely impact allowance market
liquidity. Allowances issued for control periods through 2024 under
each of these programs were recorded by July 1, 2020. As of December
2021, although recorded private transfers of earlier vintage allowances
usable for 2021 compliance have been increasing in advance of the
upcoming June 1, 2022, compliance deadline for the 2021 control
periods, few allowances recorded for the 2023 or 2024 control periods
(or even the 2022 control period) under any of the programs have been
transferred out of the accounts in which they were initially recorded,
except as needed to comply with the recall of certain allowances under
the Revised CSAPR Update. Moreover, most of the recorded transfers of
allowances issued for 2022, 2023, and 2024 have been between accounts
controlled by the same entity, corporate affiliates, or other related
entities (such as unit co-owners) rather than between accounts
controlled by unrelated parties. The EPA therefore believes there would
have been little effect on arms-length allowance market activity in
these programs if the proposed revised recordation schedule had already
been in effect and the allowances for 2023 and 2024 consequently had
not yet been recorded.
    Further details on the specific regulatory provisions that would be
affected by the proposed revisions to allowance allocation recordation
schedules are provided in Section X of the proposed rule.
    The EPA requests comment on the proposed revision to the definition
of ``Indian country'' under the CSAPR NOX Annual,
NOX Ozone Season Group 1, SO2 Group 1,
SO2 Group 2, and NOX Ozone Season Group 2 Trading
Programs and the proposed revisions to the allowance allocation
recordation deadlines under the CSAPR NOX Annual,
NOX Ozone Season Group 1, SO2 Group 1,
SO2 Group 2, and NOX Ozone Season Group 2 Trading
Programs and the Texas SO2 Trading Program.

C. Regulatory Requirements for Non-EGUs

    The EPA is proposing that the FIPs for 23 of the states covered in
this proposed rule will include new emissions limitations on emissions
units in seven non-EGU industries that EPA finds (as discussed in
Section VI of this proposed rule) to be significantly contributing to
nonattainment or interfering with maintenance in other states.
    In order to achieve the necessary non-EGU emissions reductions for
the 23 states, the EPA proposes emissions limitations for the most
impactful units in the relevant industries that are achievable with the
control technologies identified in the Step 3 analysis. The EPA is
proposing a direct control approach with rate-based limits, production-
based limits, and work practice standards set on a uniform basis for
the different segments of non-EGU emissions units using applicability
criteria based on size and type of unit and, in some cases, emissions
thresholds. The EPA believes this approach can achieve the requisite
level of emissions reductions from the covered units through the
assignment of emissions limits that are achievable across the entire
segment. The EPA believes that establishing emissions limits for
emissions units based on size and type of unit and, in some cases,
emissions thresholds, will achieve the necessary reductions without
requiring a unit-by-unit assessment.\308\ By

establishing uniform emissions limits for categories of units rather
than on a unit-by-unit basis, the EPA can also ensure that any new
source of emissions constructed after this proposed rulemaking are also
subject to the emissions limits identified later (see Section IV.B.1.d
of this proposed rule).
---------------------------------------------------------------------------

    \308\ If an emissions unit installs SCR or SNCR to meet an
emissions limit in response to the proposed FIP that would be a
physical change under new source review (NSR) and lead to an
assessment of potential emissions changes. If the installation of
SCR results in an emissions increase that exceeds the thresholds in
the NSR regulations for one or more regulated NSR pollutants,
including the netting analysis, the changes would trigger the
applicability of NSR.
---------------------------------------------------------------------------

    The EPA recognizes that the numerous variables that contribute to
differences in units' emissions rates may complicate development of
limits for groups of units as large as those addressed in this proposed
rule. For each emissions source category, the EPA considered the range
of emissions limits that currently apply to these sources under other
CAA programs, such as RACT, NSPS, NESHAP, and OTC model rules, to
develop an emissions limit that should be achievable by all sources
after installing the controls identified in the Step 3 analysis. For a
detailed discussion of the technical bases for EPA's proposed
requirements for non-EGU emissions units, see the Non-EGU Sectors TSD.
    The EPA is proposing that the emissions limits and compliance
requirements for non-EGUs will apply only during the ozone season
(which runs annually from May-September). This is consistent with EPA's
prior practice in federal actions to eliminate significant contribution
of ozone in the 1998 NOX SIP Call, CAIR, CSAPR, CSAPR
Update, and the Revised CSAPR Update. EPA is seeking comment on whether
non-EGU sources would run controls that would be installed as a result
of this proposed FIP year-round (i.e., will some source categories run
their controls year-round due to the nature of those controls?).
    In addition, the EPA proposes to apply the FIP requirements to all
existing emissions units and any future emissions units constructed
after the promulgation of a final rule. Further, the non-EGU emissions
limits and compliance requirements will apply in all 23 states (and, as
discussed in Section IV.C.2 of this proposed rule, in areas of Indian
country within the borders of those states), even if some of those
states do not currently have emissions units in a particular source
category. This approach will ensure that all new sources constructed in
any of the 23 states will be subject to the same regulatory
requirements as applied for the existing units under this proposed
rule. This will also mitigate any potential incentive to move
production from an existing non-EGU source in one linked state to a new
non-EGU source of the same type but lacking the relevant emissions
control requirements in another linked state.
    At this time, this EPA is not proposing to include non-EGUs in the
trading program described in this proposed rule. If EPA were to include
non-EGUs in the trading program, we would require monitoring and
reporting of hourly mass emissions in accordance with 40 CFR part 75 as
we have required for all trading programs. Monitoring and reporting
under part 75 include CEMS (or an approved alternative method),
rigorous initial certification testing, and periodic quality assurance
testing thereafter, such as relative accuracy test audits and daily
calibrations. This type of consistent and accurate measurement of
emissions is necessary to ensure each allowance actually represents one
ton of emissions and that one ton of reported emissions from one source
would be equivalent to one ton of reported emissions from another
source. See 75 FR 45325 (August 2, 2010). Moreover, these monitoring
requirements generally would need to be in place for at least one full
ozone season to establish baseline data before it would be appropriate
to rely on a trading program as the mechanism to achieve the required
emissions reductions. Therefore, at this time, the EPA believes that
applying unit-level emissions limitations on non-EGU emissions units
rather than constructing an emissions trading regime is more
administratively feasible and more easily implementable at the source
level, and it will effectively eliminate each state's significant
contribution without the need for establishing a new emissions trading
program.
    The EPA is proposing to require electronic reporting for all seven
non-EGU industries. Specifically, owners and operators of affected
units must submit electronic copies of required performance test
reports, performance evaluation reports, quarterly and semi-annual
reports, and excess emissions reports through EPA's Central Data
Exchange (CDX) using the Compliance and Emissions Data Reporting
Interface (CEDRI). The EPA is proposing to require that performance
test results collected using test methods that are supported by EPA's
Electronic Reporting Tool (ERT) as listed on the ERT website \309\ at
the time of the test be submitted in the format generated through the
use of the ERT or an electronic file consistent with the xml schema on
the ERT website, and that other performance test results be submitted
in portable document format (PDF) using the attachment module of the
ERT. Similarly, the EPA is proposing to require that performance
evaluation results of CEMS measuring relative accuracy test audit
(RATA) pollutants that are supported by the ERT at the time of the test
be submitted in the format generated through the use of the ERT or an
electronic file consistent with the xml schema on the ERT website, and
that other performance evaluation results be submitted in PDF using the
attachment module of the ERT. In addition, the EPA is proposing to
require that quarterly and semi-annual reports and excess emissions
reports be submitted in PDF uploaded in CEDRI.
---------------------------------------------------------------------------

    \309\ https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------

    The EPA is proposing to allow for an extension of time to file a
report where an owner or operator demonstrates that it cannot meet the
reporting deadline for reasons outside of its control. Specifically,
the EPA has identified two broad circumstances under which the EPA may
grant a request for an extension of time to file an electronic report.
These circumstances are (1) outages of EPA's CDX or CEDRI which
preclude an owner or operator from accessing the system and submitting
required reports and (2) force majeure events, which are defined as
events that will be or have been caused by circumstances beyond the
control of the affected facility, its contractors, or any entity
controlled by the affected facility that prevent an owner or operator
from complying with the requirement to submit a report electronically.
Examples of force majeure events are acts of nature, acts of war or
terrorism, or equipment failure or safety hazards beyond the control of
the facility. In both circumstances, the decision to grant an extension
of time to report is within the discretion of the Administrator, and
reporting should occur as soon as possible.
    Electronic submittal of required reports will increase the
usefulness of the data contained in those reports, is in keeping with
current trends in data availability and transparency, will further
assist in the protection of public health and the environment, will
improve compliance by facilitating the ability of regulated facilities
to demonstrate compliance with requirements and by facilitating the
ability of the EPA to assess and determine compliance, and will
ultimately reduce burden on regulated facilities and the EPA.
Electronic reporting also eliminates paper-based, manual processes,
thereby saving time and resources, simplifying data entry, eliminating
redundancies, minimizing

data reporting errors, and providing data quickly and accurately to the
affected facilities, air agencies, EPA, and the public. Moreover,
electronic reporting is consistent with EPA's plan \310\ to implement
Executive Order 13563 and is in keeping with EPA's agency-wide policy
\311\ developed in response to the White House's Digital Government
Strategy.\312\
---------------------------------------------------------------------------

    \310\ EPA's Final Plan for Periodic Retrospective Reviews,
August 2011. Available at: https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154.
    \311\ E-Reporting Policy Statement for EPA Regulations,
September 2013. Available at: https://www.epa.gov/sites/production/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf.
    \312\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at: https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html. For more information on the
benefits of electronic reporting, see the memorandum Electronic
Reporting Requirements for New Source Performance Standards (NSPS)
and National Emission Standards for Hazardous Air Pollutants
(NESHAP) Rules, referenced earlier in this section.
---------------------------------------------------------------------------

    The EPA notes that no emissions standard or other requirement
established for non-EGUs in these FIPs may be interpreted, construed,
or applied to diminish or replace the requirements of any emissions
limitation or other applicable requirement established by the
Administrator pursuant to other CAA authority or a standard issued
under State authority.
1. Pipeline Transportation of Natural Gas
Applicability
    The EPA is proposing to establish regulatory requirements for the
Pipeline Transportation of Natural Gas industry that apply to
stationary, natural gas-fired, spark ignited reciprocating internal
combustion engines (``stationary SI engines'') within these facilities
that have a maximum rated capacity of 1,000 horsepower (hp) or greater.
Based on our review of the potential emissions from stationary SI
engines, we find that use of a maximum rated capacity of 1,000 hp
reasonably approximates the selection of 100 tpy used within the non-
EGU screening assessment. Therefore, stationary SI engines subject to
the proposed rule requirements of this section are those found within
any of the 23 covered states with non-EGU emissions reduction
obligations that are within the Pipeline Transportation of Natural Gas
industry and have a maximum rated capacity of 1,000 hp or greater.
Emissions Limitations and Rationale
    In developing the emissions limits for the Pipeline Transportation
of Natural Gas industry, EPA reviewed RACT NOX rules, air
permits, and OTC model rules. While some permits and rules express
engine emissions limits in parts per million by volume (pmmv), the
majority of rules and source-specific requirements express the
emissions limits in grams per horsepower per hour (g/hp-hr). The EPA
has historically set emissions limits for these types of engines using
g/hp-hr and finds that method appropriate for this proposed FIP as
well.
    Based on the available information for this industry, applicable
State and local air agency rules, and active air permits issued to
sources with similar engines, the EPA is proposing the following
emissions limits for stationary SI engines in the covered states:

  Table VII.C-1--Summary of Proposed NOX Emissions Limits for Pipeline
                      Transportation of Natural Gas
------------------------------------------------------------------------
                                   Proposed NOX          Additional
     Engine type and fuel        emissions limit        information
------------------------------------------------------------------------
Natural Gas Fired Four Stroke   1.0 g/hp-hr......  Limits reviewed
 Rich Burn.                                         ranged between 0.2
                                                    and 3.0 g/hp-hr.
Natural Gas Fired Four Stroke   1.5 g/hp-hr......  Limits reviewed
 Lean Burn.                                         ranged between 0.5
                                                    and 3.0 g/hp-hr.
Natural Gas Fired Two Stroke    3.0 g/hp-hr......  Limits reviewed
 Lean Burn.                                         ranged between 0.5
                                                    and 3.0 g/hp-hr.
------------------------------------------------------------------------

    With regard to four stroke rich burn engines, the EPA is proposing
an emissions limit of 1.0 g/hp-hr. This limit is designed to be
achievable by installing Non-Selective Catalytic Reduction (NSCR) on
existing four stroke rich burn engines, as identified in the non-EGU
screening assessment. Sources are free to install another control
technology besides NSCR as long as the unit is still able to meet the
emissions limit. In particular for four stroke rich burn engines, NSCR
can be an effective control technology due to the low oxygen percentage
in the exhaust. Efficient operation of the catalyst in NSCR requires
the engine exhaust gases contain no more than 0.5 percent oxygen, which
makes rich burn engines uniquely suitable to NCSR. Given that NSCR can
achieve NOX reductions of 90 to 99 percent, the EPA believes
an emissions limit of 1.0 g/hp-hr should be readily achievable by all
four stroke rich burn engines subject to this proposed rulemaking. The
EPA is taking comment on whether a lower emissions limit is more
appropriate since even an assumed reduction of 95 percent would result
in most engines being able to achieve an emissions rate of 0.5 g/hp-hr.
However, at this time, the EPA does not have the information necessary
to determine if a lower emissions limit is achievable for the four
stroke rich burn engines subject to the proposed rulemaking, and
therefore, the EPA is proposing an emissions limit of 1.0 g/hp-hr.
    With regard to four stroke lean burn engines, the EPA is proposing
an emissions limit of 1.5 g/hp-hr. This limit is designed to be
achievable by installing SCR on existing four stroke lean burn engines.
Sources are free to install another control technology with or without
SCR as long as the unit is still able to meet the emissions limit. For
example, it might be more cost effective on an ongoing basis for some
four stroke lean burn engines to install layered combustion controls
alone or along with SCR to achieve the necessary emissions reductions.
Information available to the EPA suggests that some four stroke lean
burn engines can achieve 90% reductions from layered combustion
controls alone, such as turbochargers and inter-cooling, pre-chamber
ignition or high energy ignition, improved fuel injection control, air/
fuel ratio control.\313\ Independent of unit specific considerations,
the EPA believes that four stroke lean burn engines subject to this
proposed FIP can achieve an emissions limit of 1.5 g/hp-hr with the
installation and operation of SCR or other control technologies at the
marginal cost threshold of $7,500 per

ton identified in the non-EGU screening assessment. While a lower
emissions limit may be achievable with SCR for some four stroke lean
burn engines, the achievability of those lower limits may depend on
engine age and come with increased costs not accounted for in this
proposed rule. The EPA is seeking comment on whether a lower and higher
emissions limit is appropriate for these units.
---------------------------------------------------------------------------

    \313\ Ozone Transport Commission, Technical Information Oil and
Gas Sector Significant Stationary Sources of NOX Emissions, 35-39,
October 17, 2012.
---------------------------------------------------------------------------

    For two stroke lean burn engines, the EPA is currently proposing an
emissions limit of 3.0 g/hp-hr. This limit is designed to be achievable
by retrofitting existing two stroke lean burn engines with layered
combustion to achieve this emissions limit. Sources are free to install
another control technology besides layered combustion as long as the
unit is still able to meet the emissions limit. As identified in the
non-EGU screening assessment, the EPA believes that layered combustion
controls, such as improved airflow, improved fuel to air mixing,
improved ignition, and modern engine electronic controls can be
achieved on two stroke engines at the marginal cost threshold of $7,500
per ton. With these types of controls, the information currently
available to the EPA indicates that the amount of achievable emissions
reductions is unit specific and can range from a 60 to 90 percent
reduction in NOX emissions. The EPA estimates that existing
uncontrolled two stroke lean burn engines would need to reduce
emissions by about 80 percent to comply with a 3.0 g/hp-hr emissions
limit. While some RACT and model rules reviewed contained more
stringent emissions limits for two stroke lean burn engines, the EPA
does not have information adequate to conclude that the two stroke lean
burn engines across all 23 states can meet a lower limit. Further, some
information available supports a finding that an emissions limit below
3.0 g/hp-hr might not be achievable with layered combustion controls
alone for some units, and those units would require additional controls
beyond our cost threshold.\314\ Therefore, the EPA is proposing an
emissions limit of 3.0 g/bhp-hr for two stroke engines. The EPA is
seeking comment on whether a lower emissions limit would be achievable
with layered combustion alone for the sources covered by this FIP.
Further, the EPA is seeking comment on whether additional control
technology could be installed on these sources at or below the marginal
cost threshold to achieve a lower emissions rate.
---------------------------------------------------------------------------

    \314\ Ozone Transport Commission, Technical Information Oil and
Gas Sector Significant Stationary Sources of NOX Emissions at 24-25.
---------------------------------------------------------------------------

Compliance Assurance Requirement
    The EPA is proposing to require stationary SI engines subject to
this proposed FIP to conduct semi-annual performance testing in
accordance with 40 CFR 60.8 to ensure that the engine is meeting the
NOX emissions limit. The EPA is proposing that affected
engines then monitor and record hours of operation and fuel consumption
to calculate ongoing compliance with the applicable emissions limit. In
addition, the EPA is proposing that affected engines would use
continuous parametric monitoring systems (CPMS) to ensure that the
NOX emissions limit is being met at all times. For example,
engines utilizing layered combustion controls would need to monitor and
record temperature, air to fuel ratio, and other parameters as
appropriate to ensure that combustion conditions are optimized to
reduce NOX emissions and assure compliance with the
emissions limit. For engines using SCR or NSCR, the EPA is proposing
that source monitor and record parameters such as inlet temperature to
the catalyst and pressure drop across the catalyst.
    The EPA is seeking comment on whether it is feasible or appropriate
to require affected engines to be equipped with continuous emissions
monitoring systems (CEMS) to measure and monitor the NOx
emissions instead of conducting performance tests on a semiannual
basis.
2. Cement and Concrete Product Manufacturing
Applicability
    The EPA is proposing to establish regulatory requirements for the
Cement and Concrete Product Manufacturing source category that apply to
emissions units (kilns) that directly emit or have the potential to
emit 100 tpy or more of NOX. Further, the EPA is proposing
emissions limits based on type of unit to ensure that the necessary
NOX emissions reductions occur. The EPA is seeking comment
on whether it should set an applicability threshold based on a unit's
design production capacity rather than an emissions threshold.
Emissions Limitations and Rationale
    In developing the emissions limits for the Cement and Concrete
Manufacturing industry, the EPA reviewed RACT NOX rules, air
permits, and consent decrees. These rules and source-specific
requirements most commonly express the emissions limits for this
industry in terms of mass of pollutant emitted (pounds) per kiln's
clinker output (tons), i.e., pounds of NOX emitted per ton
of clinker produced. A regulated entity routinely monitors and keeps
track of its clinker output as it pertains to a kiln design capacity
and the plant's production. Therefore, the EPA believes that this form
of NOX emissions limit is effective, practicable and
convenient to record and report to an air agency.
    In determining the averaging time for the limit, the EPA considered
the NSPS for Portland Cement Plants at 40 CFR part 60, subpart F.
Section 60.62(a)(3) of this subpart establishes a 30-operating day
rolling average period for the NOX emitted per ton of
clinker produced and further states that an operating day includes all
valid data obtained in any daily 24-hour period during which the kiln
operates and excludes any measurements made during the daily 24-hour
period when the kiln was not operating. In addition, 40 CFR 60.44b(i)
requires that compliance with the applicable NOX emissions
limit be determined on a 30-day rolling average basis. The EPA is
proposing to require a 30-operating day rolling average period as the
averaging time frame for this particular industry. The proposed
averaging timeframe is consistent with the longstanding national
technology-based NSPS for this industry at 40 CFR part 60, subpart F.
Furthermore, an air agency may choose to require an averaging period
shorter than a 30-operating day rolling average in air permit(s) issued
to these plants. The EPA finds that a 30-operating day rolling average
period provides a reasonable balance between short term (hourly or
daily) and long term (annual) averaging periods, while being flexible
and responsive to fluctuations in operations and production.
    Based on the available information for this industry, applicable
State and local air agency rules, and active air permits or enforceable
orders issued to affected cement plants, the EPA is proposing the
following emissions limits for cement kilns:

      Table VII.C-2--Summary of Proposed NOX Emissions Limits for Kiln Types in Cement and Concrete Product
                                                  Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                        Proposed NOX
                    Kiln type                       emissions limit (lb/          Additional information
                                                      ton of clinker)
----------------------------------------------------------------------------------------------------------------
Long Wet.........................................                    4.0  Limits reviewed ranged between 3.88-
                                                                           5.2; one State rule allows as high as
                                                                           6.0; with addition of a post
                                                                           combustion NOX control the upper
                                                                           range could be reduced significantly.
Long Dry.........................................                    3.0  Limits reviewed showed 5.1; with
                                                                           addition of post combustion NOX
                                                                           control the limit could be reduced
                                                                           significantly; limit of 3.0 would
                                                                           achieve a 41% reduction in NOX
                                                                           emissions.
Preheater........................................                    3.8  Limits reviewed ranged between 1.5-
                                                                           3.44; limit of 3.8 is consistent with
                                                                           30 TAC 117.3110(a)(3) and 35 IAC
                                                                           217.224(a).
Precalciner......................................                    2.3  Requires post combustion NOX control;
                                                                           consistent with permit A0017 for
                                                                           Lehigh Southwest Cement Company
                                                                           issued on May 5, 2020 by the Bay Area
                                                                           Air Quality Management District.
Preheater/Precalciner............................                    2.8  Limits reviewed ranged between 1.8-
                                                                           3.4; limit of 2.8 is consistent with
                                                                           30 TAC 117.3110(a)(4); Mitsubishi
                                                                           Cement Corporation Lucerne Valley
                                                                           Federal Operating Permit 11800001
                                                                           issued by the Mojave Desert Air
                                                                           Quality Management District (MDAQMD)
                                                                           June 18, 2020; MDAQMD Rule 1161
                                                                           (C)(2); and Illinois 35 IAC
                                                                           217.224(a).
----------------------------------------------------------------------------------------------------------------

Although the EPA is proposing NOX emissions limits based on
the specific kiln types listed in Table VII.C-2, to provide operational
flexibility the EPA is also proposing a source cap limit expressed in
tons per day (tpd) of NOX for each individual cement plant
according to the following equation.
[GRAPHIC] [TIFF OMITTED] TP06AP22.002

Where:

CAP2015 Ozone Transport = total allowable NOX emissions
from all cement kilns located at one cement plant, in tons per day,
on a 30-operating day rolling average basis;
KD = 1.7 pounds NOX per ton of clinker for dry preheater-
precalciner or precalciner kilns;
KW = 3.4 pounds NOX per ton of clinker for long wet
kilns;
ND = the average annual production in tons of clinker plus one
standard deviation for the three most recent calendar years from all
dry preheater-precalciner or precalciner kilns located at one cement
plant; and
NW = the average annual production in tons of clinker plus one
standard deviation for the three most recent calendar years from all
long wet kilns located at one cement plant.

    An affected cement plant will need to comply with both the source
cap limit and the specific NOX emissions limits assigned to
its individual kiln type(s). The EPA notes that the above source cap
would be calculated and assigned to operating kilns in a particular
plant. That is, the total allowable NOX emissions in tpd
from one plant cannot be traded with another plant, regardless of these
plants' control of ownership or operator's status, or regardless of
these plants' proximity to each other or their location.
    The EPA is soliciting comment on whether it is feasible or
appropriate to phase out and retire existing long wet kilns in the
affected states and to replace them with more energy efficient and less
emitting units like preheater/precalciner installations. The EPA is
also requesting comment on the time needed to complete such a task. It
has been shown that such kilns replacements (preheater/precalciner
kilns), when equipped with post-combustion NOX control
devices such as SNCR, are capable of meeting NOX emissions
limit of 1.5 lb/ton of clinker on a 30-operating day basis. For this
reason, the EPA proposes to find that conversion from long wet kilns to
preheater/precalciner installations is generally feasible. Given that
long wet kilns are less energy efficient and generally emit more
NOX than other kiln types, conversion to preheater/
precalciner installations would be the most effective method of
NOX reduction (per ton of clinker produced).
    Additionally, EPA is soliciting comments on whether it is feasible
or appropriate to require sources with existing preheater/precalciner
kilns in the affected states that currently utilize low NOX
burners, combustion controls, staged combustion, or mid-kiln firing to
add and operate a post combustion control device like SNCR or SCR to
further improve their NOX removal efficiency and lower
NOX emissions to 1.95 lb/ton of clinker or less. The EPA is
also requesting comments on the time needed to complete such an
addition. We note that the EPA previously stated that it expects that
the controls for cement kilns would take at least 2 years to install on
a sector-wide basis across the 12-state region affected by the Revised
CSAPR Update.\315\
---------------------------------------------------------------------------

    \315\ 85 FR 68999 (October 30, 2020).
---------------------------------------------------------------------------

Compliance Assurance Requirements
    The EPA is proposing that performance tests be conducted on a
semiannual basis. Such tests shall be conducted in conformance with the
requirements of 40 CFR 60.8. Stack tests will need to conform with the
Test Methods and Procedures in 40 CFR 60 appendix A, or other EPA-
approved (federally enforceable) test methods and procedures.
    The EPA is soliciting comments on whether it is feasible or
appropriate to require affected units (kilns) to be equipped with CEMS
to measure and monitor the NOX concentration (emissions
level) instead of conducting performance tests on semiannual basis.
    We are also soliciting comment on whether it is appropriate for the
affected units (kilns) to use CPMS instead of CEMS to monitor the
NOX concentration (emissions level). We note that CPMS, also
called parametric monitoring, measures a parameter (or multiple
parameters) as a key indicator of system performance. The parameter is
generally an operational parameter of the process

or the air pollution control device (APCD) that is known to affect the
emissions levels from the process or the control efficiency of the
APCD. Examples of parametric monitoring include kiln feed rate, clinker
production rate, fuel type, fuel flow rate, specific heat consumption,
secondary air temperature, kiln feed-end temperature, preheater exhaust
gas temperature, induced draught fan pressure drop, kiln feed-end
percentage oxygen, percentage downcomer oxygen, primary air flow rate,
ammonia feed rate and slippage.
3. Iron and Steel Mills and Ferroalloy Manufacturing
Applicability
    The EPA is proposing to establish regulatory requirements for the
Iron and Steel Mills and Ferroalloy Manufacturing source category that
apply to emissions units that directly emit or have the potential to
emit 100 tpy or more of NOX and to facilities containing two
or more such units that collectively emit or have the potential to emit
100 tpy or more of NOX. The EPA is setting emissions limits
based on type of unit to ensure that the necessary emissions reductions
occur across all units of the same type. The EPA is seeking comment on
whether it should set an applicability threshold based on a unit's
production capacity rather than an emissions threshold.
Emissions Limitations and Rationale
    In developing the emissions limits for the Iron and Steel and
Ferroalloy Manufacturing industry, the EPA reviewed RACT NOX
rules, NESHAP rules, air permits and related emissions tests, technical
support documents, and consent decrees. These rules and source-specific
requirements most commonly express the emissions limits for this
industry in terms of mass of pollutant emitted (pounds) per operating
hour (hours) (i.e., pounds of NOX emitted per production
hour), pounds per energy unit (i.e., million British thermal unit
(mmBtu)), or pounds of NOX per ton of steel produced. A
regulated entity routinely monitors and keeps track of its production
in terms of tons of steel produced per hour (heat rate) as it pertains
to the facility's rate of iron and steel production. Depending on the
type of unit and industry practice, the EPA is proposing rate-based
emissions limits in the form of lb/mmBtu, production-based limits in
the form of lb/ton, and work practice standards.
    In determining the averaging times for the limits, EPA initially
reviewed the NESHAP for Iron and Steel Foundries codified at 40 CFR
part 63 subpart EEEEE, the NESHAP for Integrated Iron and Steel
manufacturing facilities codified at 40 CFR part 63 subpart FFFFF, the
NESHAP for Ferroalloys Production: Ferromanganese and Silicomanganese
codified at 40 CFR part 63 subpart XXX, and the NESHAP for Ferroalloys
Production Facilities codified at 40 CFR part 63 subpart YYYYYY. EPA
also reviewed various RACT NOX rules from states located
within the OTR, several of which have chosen to implement OTC model
rules and recommendations. Based on this information, the EPA is
proposing to require a 30-operating day rolling average period as the
averaging time frame for this particular industry. The EPA finds that a
30-operating day rolling average period provides a reasonable balance
between short term (hourly or daily) and long term (annual) averaging
periods, while being flexible and responsive to fluctuations in
operations and production.
    Based on the available information for this industry, applicable
federal and state rules, and active air permits or enforceable orders
issued to affected facilities in the iron and steel and ferroalloy
manufacturing industry, the EPA proposes the following emissions
limits:

    Table VII.C-3--Summary of Proposed NOX Emissions Limits for Iron and Steel and Ferroalloy Emissions Units
----------------------------------------------------------------------------------------------------------------
                                                Proposed NOX emissions standard or
              Emissions unit                    requirement (lbs/hour or lb/mmBtu)       Additional information
----------------------------------------------------------------------------------------------------------------
Blast Furnace.............................  0.03 lb/mmBtu.............................  OH NOX RACT rules limit
                                                                                NOX emissions from
                                                                                blast furnaces to 0.06
                                                                                lb/mmBtu without
                                                                                requiring specific
                                                                                control technology.
                                                                                Control NOX at stoves
                                                                                (typically 3 or 4 per
                                                                                blast furnace),
                                                                                assuming 40-50%
                                                                                reduction) by burner
                                                                                replacement plus SCR.
Basic Oxygen Furnace......................  0.07 lb/ton...............................  Potential 25-50%
                                                                                reduction by SCR/SNCR
                                                                                from 0.14 lb/ton based
                                                                                on emissions testing.
Electric Arc Furnace......................  0.15 lb/ton steel.........................  Example permit limits at
                                                                                around 0.2 lb/ton.
                                                                                Assumes 25% reduction
                                                                                by SCR to achieve 0.15
                                                                                lb/ton steel.
Ladle/tundish Preheaters..................  0.06 lb/mmBtu.............................  Nucor Kankakee BACT
                                                                                permit limit issued
                                                                                January 2021 is 0.1 lb/
                                                                                mmBtu, 2021. Assume 40%
                                                                                reduction by SCR.
Reheat furnace............................  0.05 lb/mmBtu.............................  Sterling Steel permit,
                                                                                issued 2019: Low-NOX
                                                                                natural gas fired
                                                                                burners designed to
                                                                                emit no more than 0.073
                                                                                lb NOX/mmBtu, Ohio RACT
                                                                                limit is 0.09 lb/mmBtu.
                                                                                Assume 40% reduction by
                                                                                SCR.
Annealing Furnace.........................  0.06 lb/mmBtu.............................  Big River Steel (AR)
                                                                                2018 limit and Benteler
                                                                                Steel (LA) 2019 limit
                                                                                (0.11 lb/mmBtu), 85
                                                                                mmBtu/hr and 13 mmBtu/
                                                                                hr, respectively.
                                                                                Lowest was 0.0915 lb/
                                                                                mmBtu, Nucor AR. Assume
                                                                                40% reduction by SCR.
Vacuum Degasser...........................  0.03 lb/mmBtu.............................  0.05 lb/mmBtu Nucor
                                                                                Darlington (SC) and
                                                                                Nucor Tuscaloosa (AL).
                                                                                Assume 40% reduction by
                                                                                SCR.
Ladle Metallurgy Furnace..................  0.1 lb/ton................................  Assume 40% reduction by
                                                                                SCR.
Taconite Production Kilns.................  Work practice standard to install and       Consistent with
                                             operate low NOX burners.                    requirements in
                                                                                Minnesota Taconite FIP
                                                                                See 81 FR 21671.
Coke Ovens (charging).....................  0.15 lb/ton of coal charged...............  Assume 50% reduction
                                                                                staged combustion and/
                                                                                or limited use SCR/SNCR
                                                                                during charging
                                                                                operations from AP-42
                                                                                0.3 lb/ton emission
                                                                                factor.
Coke Ovens (pushing)......................  0.015 lb/ton of coal pushed...............  SunCoke Middletown limit
                                                                                is 0.02 lb/ton of coal.
                                                                                Assume 25% reduction by
                                                                                SCR.
Boilers--Coal.............................  0.20 lb/mmBtu.............................  See explanation in
                                                                                Section VII.C.5.
Boilers--Residual oil.....................  0.20 lb/mmBtu.............................  See explanation in
                                                                                Section VII.C.5.
Boilers--Distillate oil...................  0.12 lb/mmBtu.............................  See explanation in
                                                                                Section VII.C.5.

Boilers--Natural gas......................  0.08 lb/mmBtu.............................  See explanation in
                                                                                Section VII.C.5.
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    Due to the many types of units within Iron and Steel Mills and
Ferroalloy Manufacturing facilities that are not currently subject to
NOX limitations of the stringency necessary to eliminate
significant contribution, most of the emissions limits in this proposed
rule are based on examples of permitted emissions and estimated
reduction potential from the identified control technology. Based on
the selection of SCR, SNCR, and burner replacement in the non-EGU
screening assessment, the EPA assumed reductions of 20 to 50 percent
from current permitted limits and emissions tests depending on the type
of unit and controls being implemented.
    In addition, for Taconite Production Kilns, the EPA does not
currently have the data to determine appropriate emissions limits that
these units could achieve by installing low NOX burners.
Therefore, the EPA is proposing to require the installation of low
NOX burners for Taconite Production Kilns and work practice
standards for operating these control technologies to achieve emissions
reductions. The EPA is also proposing to require these sources to
perform performance tests and establish a unit-specific emissions limit
at that time. These work practice standards are consistent with EPA's
Taconite FIP for Minnesota. See 81 FR 21671 (April 12, 2016). Due to
the ongoing nature of this FIP, the EPA is proposing to require
installation of specific control technologies and a period of
evaluation before setting a numerical emissions limit.
Compliance Assurance Requirements
    The EPA is proposing to require each owner or operator of an
affected facility that is subject to the NOX emissions limit
for Iron and Steel Mills and Ferroalloy Manufacturing emissions units
contained in this section to install, calibrate, maintain, and operate
a CEMS for the measurement of NOX emissions discharged into
the atmosphere from the affected facility. The EPA is proposing that
each emissions unit will be required to conduct an initial performance
test and to operate CEMS to assure compliance. In conducting the
performance tests to demonstrate compliance, sources must use test
methods and procedures in 40 CFR 60 appendix A, Method 7E, or other
EPA-approved (federally enforceable) test methods and procedures. The
EPA is also soliciting comments on alternative monitoring systems or
methods that are equivalent to CEMS to demonstrate compliance with the
emissions limits.
4. Glass and Glass Product Manufacturing
Applicability
    The EPA is proposing to establish regulatory requirements for the
Glass and Glass Product Manufacturing source category that apply to
emissions units that directly emit or have the potential to emit 100
tpy or more of NOX. The EPA is setting emissions limits
based on type of unit to ensure that the necessary emissions reductions
occur. The EPA is seeking comment on whether it should set an
applicability threshold based on a unit's production capacity rather
than an emissions threshold.
Emissions Limitations and Rationale
    In developing the emissions limits for the Glass and Glass Product
Manufacturing industry, the EPA reviewed RACT NOX rules, air
permits, Alternative Control Techniques (ACT), and consent decrees.
These rules and source-specific requirements most commonly express the
emissions limits for this industry in terms of mass of pollutant
emitted (pounds) per weight of glass removed from the furnace (tons),
i.e., pounds of NOX emitted per ton of glass produced. A
regulated entity routinely monitors and keeps track of its glass
outputs as it pertains to a furnace's design capacity and the plant's
production. Therefore, the EPA believes that this form of
NOX emissions limit is effective, practicable, and
convenient to record and report to an air agency.
    In determining the averaging time for the limits, the EPA initially
reviewed the NSPS for glass manufacturing plants codified at 40 CFR
part 60 subpart CC. This NSPS applied to any glass melting furnace in
an affected facility that commenced construction or modification after
June 15, 1979, and produced more than 5 tons of glass per day. It was
noted that the NSPS only provides standards for particulate matter and
does not provide standards or averaging times for NOX. In
order to determine the averaging time for the NOX emissions
limits, the EPA reviewed various RACT NOX rules from states
located within the OTR, several of which have chosen to implement OTC
model rules and recommendations.
    Most of the states within the OTR implement RACT regulations for
the glass manufacturing industry that do not specify presumptive
NOX limits.\316\ With respect to those RACT rules in the OTR
states that contain presumptive RACT NOX limits for glass
manufacturing furnaces, EPA found variations in averaging times,
ranging from a 30-day rolling average to a more stringent daily
average.\317\ The EPA also reviewed RACT NOX regulations for
the glass manufacturing industry outside the OTR and observed that 30-
day rolling averages and daily averages varied throughout the
states.\318\ The EPA is proposing to require owners or operators of
glass manufacturing furnaces to comply with the applicable presumptive
NOX emissions limits on a 30-day rolling average time frame.
This averaging time frame is consistent with other statewide RACT
NOX regulations for this particular industry. Furthermore, a
state's air agency may choose to require an averaging period shorter
than a 30-operating day rolling

average in air permits or RACT regulations for these plants. The EPA
finds that a 30-operating day rolling average period provides a
reasonable balance between short term (hourly or daily) and long term
(annual) averaging periods, while being flexible and responsive to
fluctuations in operation and production.
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    \316\ RACT NOX rules of the following OTR states CT,
DC, DE, MD, ME, NH, NY, RI, VA, and VT do not provide presumptive
NOX limits for glass manufacturing sources. These RACT
regulations require owners or operators to submit RACT case-by-case
analysis.
    \317\ Pennsylvania's presumptive RACT NOX emissions
limits are based on 30-day rolling average. New Jersey's and
Massachusetts' rules contain more stringent daily averages.