Maryland's RACT rule, section <IP_ADDRESS>.I, requires owner or
operators to optimize combustion by performing daily oxygen tests
and maintain excess oxygen at 4.5% or less. See http://www.dsd.state.md.us/comar/comarhtml/26/<IP_ADDRESS>.htm.
    \318\ For example, presumptive RACT NOX emissions
limits in California are based on both 30-day rolling and daily
averages (see https://www.valleyair.org/rules/currntrules/R4354%20051911.pdf). Wisconsin's NOX emissions limits are
based on a 30-day rolling average (see https://casetext.com/regulation/wisconsin-administrative-code/agency-department-of-natural-resources/environmental-protection-air-pollution-control/chapter-nr-428-control-of-nitrogen-compound-emissions/subchapter-iv-NOX-reasonably-available-control-technology-requirements/section-nr-
42822-emission-limitation-requirements).
---------------------------------------------------------------------------

    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 glass manufacturing plants, EPA is proposing
the following emissions limits for glass manufacturing furnaces:

    Table VII.C-4--Summary of Proposed NOX Emissions Limits for Furnace Unit Types in Glass and Glass Product
                                                  Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                  Proposed NOX
                                                emissions limit
                 Furnace type                   (lb/ton of glass              Additional information
                                                   produced)
----------------------------------------------------------------------------------------------------------------
Container Glass Manufacturing Furnace........                4.0  Limits reviewed ranged between 1-4; one state
                                                                   rule allowed as high as 5; with addition of
                                                                   post combustion NOX controls, the upper range
                                                                   could be reduced significantly; consistent
                                                                   with 25 Pennsylvania Code 129.304(a)(1) and
                                                                   New Jersey Administrative Code 7:27
                                                                   Subchapter 19.1.
Pressed/Blown Glass Manufacturing Furnace or                 4.0  Limits reviewed ranged between 1.36-4; one
 Fiberglass Manufacturing Furnace.                                 state rule allowed as high as 7; with
                                                                   addition of post combustion control the limit
                                                                   could be reduced significantly; limit of 4.0
                                                                   is consistent with RACT regulations for
                                                                   states located within OTR.
Flat Glass Manufacturing Furnace.............                9.2  Limits reviewed ranged between 5-9.2; with the
                                                                   addition of post combustion controls the
                                                                   limit could be reduced significantly;
                                                                   consistent with San Joaquin Valley Air
                                                                   Pollution Control District Rule 4354 5.1.1
                                                                   and New Jersey Administrative Code 7:27
                                                                   Subchapter 19.1.
----------------------------------------------------------------------------------------------------------------

    The EPA is soliciting comment on whether it is feasible or
appropriate to phase out and retire existing glass manufacturing
furnaces in the affected states and replace them with more energy
efficient and less emitting units like all-electric melter
installations. The EPA is also requesting comment on the time needed to
complete such a task. All-electric melters are glass melting furnaces
in which all the heat required for melting is provided by electric
current from electrodes submerged in the molten glass.\319\ All-
electric melter furnaces could provide an energy efficient and
NOX emission-free alternative to current methods of melting
and producing glass.
---------------------------------------------------------------------------

    \319\ See definitions in 40 CFR part 60 subpart CC.
---------------------------------------------------------------------------

    According to the EPA's ``Alternative Control Techniques Document--
NOX Emissions from Glass Manufacturing,'' \320\ glass
manufacturing furnaces may utilize combustion modifications equivalent
to low-NOX burners and oxy-firing. The EPA is soliciting
comment on whether it is feasible or appropriate to require sources
with existing glass manufacturing furnaces in affected states that
currently utilize these combustion modifications to add and operate a
post-combustion control device like SNCR and SCR to further improve
their NOX removal efficiency. The EPA is also requesting
comments on the time needed to install such controls.
---------------------------------------------------------------------------

    \320\ ``Alternative Control Techniques Document--NOX
Emissions from Glass Manufacturing,'' EPA-453/R-94-037, June 1994.
---------------------------------------------------------------------------

Compliance Assurance Requirements
    The EPA is proposing to require each owner or operator of an
affected facility that is subject to the NOX emissions
standards for glass manufacturing furnaces 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 also soliciting comments on alternative
monitoring systems or methods that are equivalent to CEMS to
demonstrate compliance with the emissions limits. In conducting the
performance tests to demonstrate compliance, sources must use test
methods and procedures in 40 CFR part 60 appendix A, method 7E, or
other EPA-approved (federally enforceable) methods and procedures.
Owners or operators must calculate and record the 30-operating day
rolling emissions rate of NOX as the total of all hourly
emissions data for a glass manufacturing furnace in the preceding 30
days, divided by the total tons of glass produced in that furnace
during the same 30-operating day period. Owners or operators of glass
manufacturing furnaces installed with continuous emissions monitoring
may demonstrate compliance with the emissions limit as follows: (1)
Determine the average pounds of NOX emitted per day, (2)
determine the tons of glass removed per day during the same day, (3)
divide the average pounds of NOX emitted per day by the tons
of glass removed per day as determined in step (2), and (4) compare the
quotient to the emissions limits prescribed in the Section VII of this
proposed rule. If the pollutant mass emissions rate is in lb/hr, the
following equation \321\ shall be used to convert the emissions rate to
lb pollutant/ton of glass pulled:
---------------------------------------------------------------------------

    \321\ This equation is provided in the San Joaquin Valley
Unified Air Pollution Control District's Rule 4354, section 8.1.
[GRAPHIC] [TIFF OMITTED] TP06AP22.003

5. Boilers From Basic Chemical Manufacturing, Petroleum and Coal
Products Manufacturing, and Pulp, Paper, and Paperboard Mills
Applicability
    The EPA is proposing to establish regulatory requirements for the
Basic Chemical Manufacturing, Petroleum and Coal Products
Manufacturing, and Pulp, Paper, and Paperboard Mills industries that
apply to boilers within these facilities that have a design capacity of
100 mmBtu/hr or greater. These requirements are consistent with EPA's
findings at Step 3 with respect to Tier 2 non-EGU industries. As noted
below, we do not believe boilers meeting this size classification exist
within the other Tier 2, or Tier 1 industries, but if they do, the EPA
proposes that they would also be subject to the requirements of this
part. Based on our review of the potential emissions from industrial
boilers of various fuel types, we find that use of a boiler design
capacity of 100 mmBtu/hr reasonably approximates the selection of 100
tpy used within the Non-EGU Screening Assessment memorandum. Therefore,
boilers subject to the requirements of this section of the proposed
rule are those found within any of the 23 covered states with non-EGU
emissions reduction obligations that are within a Tier 1 or Tier 2
industry and have a design capacity of 100 mmBTU/hr or greater. The EPA
is seeking comment on whether EPA should alternatively set an
applicability threshold based on potential to emit.
Emissions Limitations and Rationale
    This section of the proposed rule applies to certain boilers
located at any facility identified as a Tier 2 industry within the non-
EGU screening assessment. As described within the Non-EGU Screening
Assessment memorandum, the EPA reviewed the projected 2026 emissions
data to identify large boilers within the Tier 2 industries, defined as
boilers projected to emit more than 100 tons per year in 2026. Boilers
meeting this threshold were found in three of the five Tier 2
industries, as identified in Table VII.C.5-1.

  Table VII.C.5-1--Tier 2 Industries With Large Boilers and Associated
                               NAICS Codes
------------------------------------------------------------------------
                                                                  NAICS
                            Industry                               code
------------------------------------------------------------------------
Basic Chemical Manufacturing...................................   3251xx
Petroleum and Coal Products Manufacturing......................   3241xx
Pulp, Paper, and Paperboard Mills..............................   3221xx
------------------------------------------------------------------------

    The EPA did not find large boilers within the Lime and Gypsum
Product Manufacturing (NAICS code 3274xx) or the Metal Ore Mining
industries (NAICS code 2122xx). As such the EPA is not expressly
proposing to include boilers in those industries. However, if as a
result of receiving additional information during the comment period
the EPA identifies large boilers within these two industries that meet
the applicability criteria described below, those boilers could be
subject to the requirements of the final rule.
    As described within the Non-EGU Sectors TSD, the RACT rules we
reviewed containing NOX limits for industrial boilers relied
primarily on design capacity in mmBtu/hr as the metric for selecting
design criteria. The EPA is proposing to use that same metric to
establish control requirements for boilers with a design capacity of
100 mmBtu/hr or greater. As noted within the Non-EGU Sectors TSD,
boilers rated at 100 mmBtu/hr or greater can emit large amounts of
NOX, particularly if they do not operate NOX
control equipment.
    The EPA reviewed NOX emissions limits for industrial
boilers with design capacities of 100 mmBtu/hr or greater that have
been adopted by states and incorporated into their SIPs. The Non-EGU
Sectors TSD contains a detailed discussion of that evaluation. Based on
our review, we propose to establish the following NOX
emissions limits for coal, oil, and gas fired industrial boilers
located at a Tier 2 industry:

               Table VII.C.5-2--Proposed NOX Emissions Limits for Industrial Boilers >100 mmBtu/hr
----------------------------------------------------------------------------------------------------------------
                                           Emissions limit
               Unit type                   (lbs NOX/mmBtu)                  Additional information

----------------------------------------------------------------------------------------------------------------
Coal...................................               0.20   Limits reviewed ranged from 0.08 to 1.0. Proposed
                                                              limit will likely require a combination of
                                                              combustion controls or post-combustion controls.
Residual oil...........................               0.20   Limits reviewed ranged from 0.15 to 0.50. Proposed
                                                              limit will likely require combustion controls.
Distillate oil.........................               0.12   Limits reviewed ranged from 0.10 to 0.43. Proposed
                                                              limit will likely require combustion controls.
Natural gas............................               0.08   Limits reviewed ranged from 0.06 to 0.25.
                                                             Proposed limit will likely require a combination of
                                                              combustion controls or post-combustion controls.
----------------------------------------------------------------------------------------------------------------

Additional information on the EPA's derivation of these proposed
emissions rates for boilers is provided below and in the Non-EGU
Sectors TSD.
    The EPA notes that some coal, oil, and gas-fired industrial boilers
may have already installed combustion or post-combustion control
equipment, such as SCR or SNCR, sufficient to meet the emission limits
established in this FIP. Some of the boilers covered by this FIP might
have install controls to meet the emission limits contained within
EPA's NSPS located at 40 CFR 60 Subpart Db, which requires that some
fossil fuel-fired units that commenced construction, modification, or
reconstruction after June 19, 1984, meet various NOx
emission limits based on factors such as unit type or heat rate.
Additionally, industrial boilers located in ozone nonattainment areas
or within the ozone transport region may have installed controls to
meet emission limits adopted by states to meet NOx RACT
requirements.
a. Coal-Fired Industrial Boilers
    Coal-fired industrial boilers subject to the proposed requirements
of this section would have to meet a NOX emissions limit of
0.2 lbs/mmBtu on a 30-day rolling average basis.
    Various forms of combustion and post-combustion NOX
control technology exist that should enable most facilities to be
retrofit with equipment that will enable them to meet these emissions
limits. Additionally, as noted in the Non-EGU Sectors TSD, many states
containing ozone nonattainment areas or located within the OTR have
already adopted emissions limits similar to or more stringent than the
limits the EPA proposes here. Furthermore, some coal-fired industrial
boilers may have installed combustion or post-combustion control
equipment to meet the emissions limits contained within EPA's NSPS
located at 40 CFR part 60 subpart Db, which requires that coal-fired
industrial boilers meet a NOX emissions limit of between 0.5
and 0.8

lbs/mmBtu depending on unit type.\322\ Enhancements to or retrofit of
additional NOX control technology should enable most sources
to meet the proposed NOX limit.
---------------------------------------------------------------------------

    \322\ 40 CFR 60.44b.
---------------------------------------------------------------------------

    There are two main types of NOX control technology that
we believe can be retrofit to most existing industrial boilers, or
incorporated into the design of new boilers, to meet our proposed
emissions limits. These two control types are combustion controls and
post-combustion controls, and in some instances both types are used
together. As noted in the EPA's ``Alternative Control Techniques
Document--NOX Emissions from Industrial/Commercial/
Institutional (ICI) Boilers'' (hereafter ``ICI Boiler ACT''),\323\ the
type of NOX control available for use on a particular unit
depends primarily on the type of boiler, fuel type, and fuel-firing
configuration. For example, Table 2-3 of the ICI Boiler ACT indicates
which types of combustion and post-combustion NOX controls
are suitable to various types of coal-fired ICI boilers. We note that
one type of combustion control, staged combustion air, and one type of
post-combustion control, SNCR, are indicated as being compatible with
all coal-fired unit types. Additional resources are available that
document the availability of NOX control equipment for
industrial boilers.\324\
---------------------------------------------------------------------------

    \323\ ``Alternative Control Techniques Document--NOX
Emissions from Industrial/Commercial/Institutional (ICI) Boilers,''
EPA-453/R-94-022, March 1994.
    \324\ For example, see ``Applicability and Feasibility of
NOX, SO2, and PM Emissions Control
Technologies for Industrial, Commercial, and Institutional
Boilers,'' Northeast States for Coordinated Air Use Management,
November 2008 (revised January 2009) and ``Nitrogen Oxides
(NOx), Why and How They Are Controlled,'' EPA, Clean Air
Technical Center, 456/F-99-006R, November 1999.
---------------------------------------------------------------------------

b. Oil-Fired Industrial Boilers
    Most oil-fired boilers are fueled by either residual (heavy) oil or
distillate (light) oil. The proposed NOX emissions limit for
residual oil-fired boilers subject to the requirements of this section
is 0.2 lbs/mmBtu, and the proposed emissions limit for distillate oil-
fired boilers is 0.12 lbs/mmBtu. The proposed averaging time for these
emissions limits is a 30-day rolling average. As with coal-fired
industrial boilers, a number of combustion and post-combustion
NOX control technologies exist that should enable most
facilities to meet these emissions limits, and the Non-EGU Sectors TSD
identifies numerous states that have already adopted emissions limits
similar to the limits EPA proposes here. Table 2-3 of the ICI Boiler
ACT indicates that two types of NOX combustion control, low-
NOX burners and flue gas recirculation, are commonly found
on oil-fueled industrial boilers, and that SNCR, a post-combustion
control technology, is suitable to most oil-fueled industrial boilers
other than those of the packaged firetube design. Some oil-fired
industrial boilers may have already installed combustion or post-
combustion control equipment to meet the emissions limits contained
within EPA's NSPS at 40 CFR part 60 subpart Db, which requires that
distillate oil-fired units meet a NOX emissions limit of
between 0.1 to 0.2 lbs/mmBtu depending on heat release rate, and that
residual oil-fired units meet a NOX emissions limit of
between 0.3 to 0.4 lbs/mmBtu also depending on heat release rate.\325\
The additional resources noted in the paragraph above discussing coal-
fired industrial boilers also contain useful information regarding
effective NOX control equipment for residual and distillate
fueled industrial boilers.
---------------------------------------------------------------------------

    \325\ 40 CFR 60.44b.
---------------------------------------------------------------------------

c. Gas-Fired Industrial Boilers
    The proposed NOX emissions limit for gas-fired boilers
subject to the requirements of this section is 0.08 lbs/mmBtu. The
proposed averaging time for these emissions limits is a 30-day rolling
average.
    As with fossil-fuel-fired boilers, numerous combustion and post-
combustion NOX control technologies exist that should enable
most facilities to meet these emissions limits, and many states have
already adopted emissions limits similar to the limits the EPA proposes
here. Table 2-3 of the ICI Boiler ACT indicates the same control
technologies that are suitable for application to oil-fired boilers are
also likely to be effective at controlling NOX emissions
from gas-fired industrial boilers. Some gas-fired industrial boilers
may have already installed combustion or post-combustion control
equipment to meet the emissions limits contained within EPA's NSPS at
40 CFR 60 Subpart Db, which requires that gas-fired units meet a
NOX emissions limit of between 0.1 to 0.2 lbs/MMBtu
depending on heat release rate. The additional resources noted in the
discussion of coal-fired industrial boilers also contain useful
information regarding effective NOX control equipment for
gas-fired industrial boilers.
    The EPA anticipates that the majority of boilers covered by this
section of the FIP will combust one of the fuels for which we have
proposed emissions limits. However, we request comment on whether
emissions limits for other types of fuels should be included in a final
FIP, and if so, the types of fuels and the emissions limits that
boilers powered by these fuels should be required to meet.
Additionally, the EPA seeks comment on whether the EPA should establish
less stringent emissions rates for boilers with low utilization rates,
and if so, the appropriate emissions rate(s) and corresponding boiler
utilization rate(s). The EPA also seeks comment on whether a different
averaging time other than the 30-day averaging time proposed for
boilers would be more appropriate and requests information supporting
any suggested alternative.
Compliance Assurance Requirements
    Given the similarities in the types of units covered, the EPA
proposes that boilers subject to the requirements of this section
demonstrate compliance in a manner similar to the emissions monitoring
requirements found in section 60.45 of the NSPS for industrial,
commercial, and institutional (ICI) boilers at 40 CFR part 60 subpart
D. Those requirements include, among other provisions, the performance
of an initial compliance test, installation of a CEMS unless the
initial performance test indicates the unit's emissions rate is 70
percent or less of the required emissions rate, and an annual stack
test for units not required to install a CEMS.

D. Submitting a SIP

    A state may submit a SIP at any time to address CAA requirements
that are covered by a FIP, and if the EPA approves the SIP it would
replace the FIP, in whole or in part, as appropriate.\326\ The EPA has
established certain specialized provisions for replacing FIPs with SIPs
within all the CSAPR trading programs, including the use of so-called
``abbreviated SIPs'' and ``full SIPs,'' see 40 CFR 52.38(a)(4) and (5)
and (b)(4), (5), (8), (9), (11), and (12); 40 CFR 52.39(e), (f), (h),
and (i). For a state to remove all FIP provisions through an approved
SIP revision, a state would need to address all of the required
reductions addressed by the FIP for that state, i.e., reductions
achieved through both EGU control and non-EGU control, as applicable to
that state. Additionally, tribes in Indian country within the
geographic scope of this proposed rule may elect to work with EPA under
the Tribal Authority Rule to replace the FIP for areas of Indian
country, in whole or in part, with a tribal implementation plan or

reasonably severable portions of a tribal implementation plan.
---------------------------------------------------------------------------

    \326\ CAA sections 110(c)(1)(B), 110(k)(3).
---------------------------------------------------------------------------

    Under the proposed new FIPs for the 25 states whose EGUs would be
required to participate in the CSAPR NOX Ozone Season Group
3 Trading Program with its proposed modifications, ``abbreviated'' and
``full'' SIP options continue to be available. An ``abbreviated SIP''
allows a state to submit a SIP revision that would establish state-
determined allowance allocation provisions replacing the default FIP
allocation provisions but leaves the remaining FIP provisions in place.
A ``full SIP'' allows a state to adopt a trading program meeting
certain requirements that would allow sources in the state to continue
to use the EPA-administered trading program through an approved SIP
revision, rather than a FIP. In addition, as under past CSAPR
rulemakings, the EPA proposes to provide states with an opportunity to
adopt state-determined allowance allocations for existing units for the
second control period under this rule--in this case, the 2024 control
period--through streamlined SIP revisions. See 76 FR 48326-48332 for
additional discussion of full and abbreviated SIP options; see also 40
CFR 52.38(b).
1. SIP Option To Modify Allocations for 2024 Under EGU Trading Program
    As with the start of past CSAPR rulemakings, the EPA proposes to
allow a state to use a similar process to submit a SIP revision
establishing allowance allocations for existing EGU units in the state
for the second control period of the new requirements, i.e., in 2024,
to replace the EPA-determined default allocations. This proposed
process would use updated deadlines, i.e., a state must submit a letter
to EPA within 60 days of publication of the final rule indicating its
intent to submit a complete SIP revision by September 1, 2023. The SIP
would provide in an EPA-prescribed format a list of existing units
within the state and their allocations for the 2024 control period. If
a state does not submit a letter of intent to submit a SIP revision,
the EPA-determined default allocations will be recorded by 90 days of
publication of the final rule. If a state submits a timely letter of
intent but fails to submit a SIP revision, the EPA-determined default
allocations will be recorded by September 15, 2023. If a state submits
a timely letter of intent followed by a timely SIP revision that is
approved, the approved SIP allocations will be recorded by March 1,
2024.
    The EPA requests comment on the proposed option to modify allowance
allocations under the Group 3 trading program for EGUs for the 2024
control period through a SIP revision.
2. SIP Option To Modify Allocations for 2025 and Beyond Under EGU
Trading Program
    For the 2025 control period and later, the EPA proposes that states
in the CSAPR NOX Ozone Season Group 3 Trading Program can
modify the EPA-determined default allocations with an approved SIP
revision. For the 2025 control period and later, SIPs can be full or
abbreviated SIPs. States will also have the option to expand
applicability to include EGUs between 15 MWe and 25 MWe or, in the case
of states subject to the NOX SIP Call, as discussed in
Section VII.F.1 of this proposed rule, large non-EGU boilers and
combustion turbines. Inclusion of the large non-EGUs would serve as a
mechanism to address the state's outstanding regulatory obligations
under the NOX SIP Call with respect to those sources, and
the state would be allowed to allocate a defined quantity of additional
Group 3 allowances because of the expanded set of sources. See above
and 76 FR 48326-48332 for additional discussion of full and abbreviated
SIP options; see also 40 CFR 52.38(b).
    For states that want to modify the EPA-determined default
allocations or expand applicability of the EGU trading program, the EPA
proposes that a state could submit a SIP revision that makes changes
only to one or both of those type of provisions while relying on the
FIP for the remaining provisions of the EGU trading program. This
abbreviated SIP option allows states to tailor the FIP to their
individual choices while maintaining the FIP-based structure of the
trading program. In order to ensure the availability of allowance
allocations for units in any Indian country within a state not covered
by the state's CAA implementation planning authority, if the state
chose to replace EPA's default allocations with state-determined
allocations, the EPA would continue to administer any portion of each
state emissions budget reserved as a new unit set-aside or an Indian
country existing unit set-aside.
    The proposed SIP submittal deadline for this type of revision is
December 1, 2023, if the state intends for the SIP revision to be
effective beginning with the 2025 control period. For states that
submit this type of SIP revision, the EPA proposes that the deadline to
submit state-determined allocations beginning with the 2025 control
period under an approved SIP would be June 1, 2024, and the deadline
for the EPA to record those allocations would be July 1, 2024.
Similarly, under the proposed new deadlines a state could submit a SIP
revision beginning with the 2026 control period and beyond by December
1, 2024, with state allocations for the 2026 control period due June 1,
2025, and the EPA recordation of the allocations by July 1, 2025.
    The EPA requests comment on the proposed option to replace certain
allowance allocation or applicability provisions under the Group 3
trading program for EGUs for control periods in 2025 and later years
through a SIP revision.
3. SIP Option To Replace the Federal EGU Trading Program With an
Integrated State EGU Trading Program
    For the 2025 control period and later, the EPA proposes that states
in the CSAPR NOX Ozone Season Group 3 Trading Program can
choose to replace the Federal EGU trading program with an integrated
State EGU trading program through an approved SIP revision. Under this
option, a state would submit a SIP revision that makes changes only to
modify the EPA-determined default allocations or expand applicability
of the EGU trading program and adopt identical provisions for the
remaining portions of the EGU trading program. This SIP option allows
states to replace these FIP provisions with state-based SIP provisions
while continuing participation in the larger regional trading program.
As with the abbreviated SIP option discussed above, in order to ensure
the availability of allowance allocations for units in any Indian
country within a state not covered by the state's CAA implementation
planning authority, if the state chose to replace EPA's default
allocations with state-determined allocations, EPA would continue to
administer any portion of each state emissions budget reserved as a new
unit set-aside or an Indian country existing unit set-aside.
    Proposed deadlines for this type of SIP revision are the same as
the deadlines for abbreviated SIP revisions. For the SIP-based program
to start with the 2025 control period, the SIP deadline would be
December 1, 2023, the deadline to submit state-determined allocations
for the 2025 control period under an approved SIP would be June 1,
2024, and the deadline for the EPA to record those allocations would be
July 1, 2024, and so on.
    The EPA requests comment on the proposed option to replace the
federal trading program for EGUs with an integrated state trading
program for EGUs for control periods in 2025 and later years through a
SIP revision.

4. SIP Revisions That Do Not Use the New Trading Program
    States can submit SIP revisions to replace the FIP that achieve the
necessary EGU emissions reductions but do not use the CSAPR
NOX Ozone Season Group 3 Trading Program. For a transport
SIP revision that does not use the CSAPR NOX Ozone Season
Group 3 Trading Program, the EPA would evaluate the transport SIP based
on the particular control strategies selected and whether the
strategies as a whole provide adequate and enforceable provisions
ensuring that the necessary emissions reductions (i.e., reductions
equal to or greater than what the Group 3 trading program will achieve)
will be achieved. In order to address the applicable CAA requirements,
the SIP revision should include the following general elements: (1) A
comprehensive baseline 2023 statewide NOX emissions
inventory (which includes existing control requirements), which should
be consistent with the 2023 emissions inventory that the EPA used to
calculate the required state budget in this final proposed rule (unless
the state can explain the discrepancy); (2) a list and description of
control measures to satisfy the state emissions reduction obligation
and a demonstration showing when each measure would be implemented to
meet the 2023 and successive control periods; (3) fully-adopted state
rules providing for such NOX controls during the ozone
season; (4) for EGUs greater than 25 MWe, monitoring and reporting
under 40 CFR part 75, and for other units, monitoring and reporting
procedures sufficient to demonstrate that sources are complying with
the SIP (see 40 CFR part 51 subpart K (``source surveillance''
requirements)); and (5) a projected inventory demonstrating that state
measures along with federal measures will achieve the necessary
emissions reductions in time to meet the 2023 and successive compliance
deadlines (e.g., enforceable reductions commensurate with installation
of SCR on coal-fired EGUs by the 2026 ozone season). The SIPs must meet
procedural requirements under the Act, such as the requirements for
public hearing, be adopted by the appropriate state board or authority,
and establish by a practically enforceable regulation or permit(s) a
schedule and date for each affected source or source category to
achieve compliance. Once the state has made a SIP submission, the EPA
will evaluate the submission(s) for completeness before acting on the
SIP. EPA's criteria for determining completeness of a SIP submission
are codified at 40 CFR part 51 appendix V.
    For further information on replacing a FIP with a SIP, see the
discussion in the final CSAPR rulemaking (76 FR 48326).
5. SIP Revision Requirements for Non-EGU Emissions Limits
    EPA's promulgation of a non-EGU transport FIP would in no way
affect the ability of states to submit, for review and approval, a SIP
that replaces the requirements of the FIP with state requirements. In
order to replace the non-EGU portion of the FIP in a state, the state's
SIP must provide adequate provisions to prohibit an equivalent or
greater amount of NOX emissions that contribute
significantly to nonattainment or interfere with maintenance of the
2015 ozone NAAQS in any other state. The non-EGU requirements of the
FIP would remain in place in each covered state until a state's SIP has
been approved by the EPA to replace the FIP.
    After promulgation of the final FIP, the EPA anticipates that the
most straightforward method for a state to submit a SIP revision to
replace the non-EGU portion of the FIP for the state would be to
provide a SIP that includes emissions limits at an equivalent or
greater level of stringency than is specified for non-EGU sources
meeting the applicability criteria and associated compliance assurance
provisions for each of the unit types identified in Section VII.C of
this proposed rule.
    The EPA seeks comment on other potential methods by which states
could develop a SIP to obtain emissions reductions from non-EGU sources
that would replace the state's non-EGU portion of the FIP. The EPA
recognizes that states may select emissions reductions strategies that
differ from the emissions limitations included in the proposed non-EGU
FIP. But the state must still demonstrate that the replacement SIP
provides an equivalent or greater amount of emissions reductions as the
proposed FIP. The EPA anticipates that such emissions reductions
strategies would have to achieve reductions beyond those emissions
reductions already projected to occur in EPA's emissions projections
and air quality modeling conducted at Steps 1 and 2. Such reductions
must also be achieved on the same timeframe as the reductions that
would be required in a final FIP. A demonstration of equivalency using
other control strategies is complicated by the fact that the proposed
emissions limits for non-EGU sources are generally rate-based and
expressed in a variety of forms; this will make comparative analysis to
determine equivalency challenging.
    In all cases, a SIP submitted by a state to replace the non-EGU
FIPs would need to rely on permanent and practically enforceable
controls measures that are included in the SIP and, once approved by
the EPA, rendered federally enforceable. So-called ``demonstration-
only'' or ``non-regulatory'' SIPs would be insufficient. Further, the
EPA anticipates that states would bear the burden of establishing that
the state's alternative approach achieves at least an equivalent level
of emissions reduction as the FIP, and (unless merely adopting directly
the control requirements of the FIP) the state would need to provide a
Step 3 multifactor analysis that the state's SIP eliminates significant
contribution.

E. Title V Permitting

    This proposed rule, like CSAPR, the CSAPR Update, and the Revised
CSAPR Update does not establish any permitting requirements independent
of those under Title V of the CAA and the regulations implementing
Title V, 40 CFR parts 70 and 71.\327\ All major stationary sources of
air pollution and certain other sources are required to apply for title
V operating permits that include emissions limitations and other
conditions as necessary to ensure compliance with the applicable
requirements of the CAA, including the requirements of the applicable
SIP. CAA sections 502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a).
The ``applicable requirements'' that must be addressed in title V
permits are defined in the title V regulations (40 CFR 70.2 and 71.2
(definition of ``applicable requirement'')).
---------------------------------------------------------------------------

    \327\ Part 70 addresses requirements for state title V programs,
and Part 71 governs the federal title V program.
---------------------------------------------------------------------------

    The EPA anticipates that, given the nature of the units subject to
this proposed rule, most if not all of the sources at which the units
are located are already subject to title V permitting requirements. For
sources subject to title V, the interstate transport requirements for
the 2015 ozone NAAQS that are applicable to them under the new or
amended FIPs would be ``applicable requirements'' under title V and
therefore must be addressed in the title V permits. For example,
requirements concerning designated representatives, monitoring,
reporting, and recordkeeping, the requirement to hold allowances
covering emissions, the compliance assurance provisions, and liability
are ``applicable requirements'' that must be addressed in the permits.
    Title V of the CAA establishes the basic requirements for state
title V

permitting programs, including, among other things, provisions
governing permit applications, permit content, and permit revisions
that address applicable requirements under final FIPs in a manner that
provides the flexibility necessary to implement market-based programs
such as the trading programs established in CSAPR, the CSAPR Update,
the Revised CSAPR Update and this proposed rule. 42 U.S.C. 7661a(b); 40
CFR 70.6(a)(8) & (10); 40 CFR 71.6(a)(8) & (10).
    In CSAPR, the CSAPR Update and the Revised CSAPR Update, the EPA
established standard requirements governing how sources covered by that
rule would comply with title V and its regulations.\328\ 40 CFR
97.506(d), 97.806(d) and 97.1006(d). For any new or existing sources
subject to this proposed rule, identical title V compliance provisions
would apply, just as they would have in the CSAPR NOX Ozone
Season Group 3 Trading Program. For example, the title V regulations
provide that a permit issued under title V must include ``[a] provision
stating that no permit revision shall be required under any approved .
. . emissions trading and other similar programs or processes for
changes that are provided for in the permit.'' 40 CFR 70.6(a)(8) and
71.6(a)(8). Consistent with these provisions in the title V
regulations, in CSAPR, the CSAPR Update and the Revised CSAPR Update,
the EPA included a provision stating that no permit revision is
necessary for the allocation, holding, deduction, or transfer of
allowances. 40 CFR 97.506(d)(1), 97.806(d)(1) and 97.1006(d)(1). This
provision is also included in each title V permit for an affected
source. This proposed rule maintains the approach taken under CSAPR,
the CSAPR Update and the Revised CSAPR Update that allows allowances to
be traded (or allocated, held, or deducted) without a revision to the
title V permit of any of the sources involved.
---------------------------------------------------------------------------

    \328\ The EPA has also issued a guidance document and template
that includes instructions for how to incorporate the applicable
requirements into a source's Title V permit. See Memorandum dated
May 13, 2015, from Anna Marie Wood, Director, Air Quality Policy
Division, and Reid P. Harvey, Director, Clean Air Market Division,
EPA, to Regional Air Division Directors, Subject: ``Title V Permit
Guidance and Template for the Cross-State Air Pollution Rule''
(``2015 Title V Guidance''), available at https://www.epa.gov/sites/default/files/2016-10/documents/csapr_title_v_permit_guidance.pdf.
---------------------------------------------------------------------------

    Similarly, this proposed rule would also continue to support the
means by which a source in the proposed trading program can use the
title V minor modification procedure to change its approach for
monitoring and reporting emissions, in certain circumstances.
Specifically, sources may use the minor modification procedure so long
as the new monitoring and reporting approach is one of the prior-
approved approaches under CSAPR, the CSAPR Update and the Revised CSAPR
Update (i.e., approaches using a continuous emissions monitoring system
under subparts B and H of part 75, an excepted monitoring system under
appendices D and E to part 75, a low mass emissions excepted monitoring
methodology under 40 CFR 75.19, or an alternative monitoring system
under subpart E of part 75), and the permit already includes a
description of the new monitoring and reporting approach to be used.
See 40 CFR 97.506(d)(2), 97.806(d)(2) and 97.1006(d)(2); 40 CFR
70.7(e)(2)(i)(B) and 40 CFR 71.7(e)(1)(i)(B). As described in EPA's
2015 Title V Guidance, sources may comply with this requirement by
including a table of all of the approved monitoring and reporting
approaches under CSAPR, the CSAPR Update and the Revised CSAPR Update
trading programs in which the source is required to participate, and
the applicable requirements governing each of those approaches.\329\
Inclusion of such a table in a source's title V permit therefore allows
a covered unit that seeks to change or add to its chosen monitoring and
recordkeeping approach to easily comply with the regulations governing
the use of the title V minor modification procedure.
---------------------------------------------------------------------------

    \329\ Id.
---------------------------------------------------------------------------

    Under CSAPR, the CSAPR Update and the Revised CSAPR Update, in
order to employ a monitoring or reporting approach different from the
prior-approved approaches discussed previously, unit owners and
operators must submit monitoring system certification applications to
the EPA establishing the monitoring and reporting approach actually to
be used by the unit, or, if the owners and operators choose to employ
an alternative monitoring system, to submit petitions for that
alternative to the EPA. These applications and petitions are subject to
the EPA review and approval to ensure consistency in monitoring and
reporting among all trading program participants. EPA's responses to
any petitions for alternative monitoring systems or for alternatives to
specific monitoring or reporting requirements are posted on EPA's
website.\330\ The EPA maintains the same approach in this proposed
rule.
---------------------------------------------------------------------------

    \330\ https://www.epa.gov/airmarkets/part-75-petition-responses.
---------------------------------------------------------------------------

    Consistent with EPA's approach under CSAPR, the CSAPR Update and
the Revised CSAPR Update, the applicable requirements resulting from
the new and amended FIPs generally will have to be incorporated into
affected sources' existing title V permits either pursuant to the
provisions for reopening for cause (40 CFR 70.7(f) and 71.7(f)) or the
standard permit renewal provisions (40 CFR 70.7(c) and 71.7(c)).\331\
For sources newly subject to title V that are affected sources under
the FIPs, the initial title V permit issued pursuant to 40 CFR 70.7(a)
should address the final FIP requirements.
---------------------------------------------------------------------------

    \331\ A permit is reopened for cause if any new applicable
requirements (such as those under a FIP) become applicable to an
affected source with a remaining permit term of 3 or more years. If
the remaining permit term is less than 3 years, such new applicable
requirements will be added to the permit during permit renewal. See
40 CFR 70.7(f)(1)(I) and 71.7(f)(1)(I).
---------------------------------------------------------------------------

    As was the case in the CSAPR, the CSAPR Update and the Revised
CSAPR Update, the new and amended FIPs impose no independent permitting
requirements and the title V permitting process will impose no
additional burden on sources already required to be permitted under
title V.

F. Relationship to Other Emissions Trading and Ozone Transport Programs

1. NOX SIP Call
    States affected by both the NOX SIP Call for the 1979
ozone NAAQS and any final ozone season requirements established upon
finalization of this proposed rule for the 2015 ozone NAAQS will be
required to comply with the requirements of both rules. EPA is
proposing to require NOX ozone season emissions reductions
from EGUs larger than 25 MWe in many of the NOX SIP Call
states, and at greater stringency than required by the NOX
SIP Call, by requiring the EGUs to participate in the CSAPR
NOX Ozone Season Group 3 Trading Program. Therefore, this
proposed rule, if finalized, would satisfy the requirements of the
NOX SIP Call for these large EGUs.
    In the Revised CSAPR Update, the EPA finalized the option for any
NOX SIP Call state that was also subject to the Revised
CSAPR Update to voluntarily submit a SIP revision to expand the
applicability of the Group 3 trading program to include all
NOX Budget Trading Program units, which in addition to large
EGUs also include large non-EGU boilers and combustion turbines with a
maximum design heat input greater than 250 mmBtu/hr. As part of such a
SIP revision, the state

would be allowed to issue additional emissions allowances capped at a
level intended to preserve the stringency of the Group 3 trading
program. In today's proposed rule, the EPA is not proposing any changes
to this provision of the Group 3 trading program.\332\
---------------------------------------------------------------------------

    \332\ In the CSAPR Update, the EPA finalized an identical option
allowing NOX SIP Call states to expand applicability of
the Group 2 trading program to cover certain non-EGUs. If the
geographic expansion of the Group 3 trading program proposed in this
rulemaking is finalized as proposed, no NOX SIP Call
states would continue to be covered by the Group 2 trading program.
Because the provision allowing NOX SIP Call states to
expand applicability of the Group 2 trading program to include such
non-EGUs would therefore be obsolete, the EPA is proposing to remove
the provision.
---------------------------------------------------------------------------

2. Acid Rain Program
    This proposed rule, if finalized, would not affect any Acid Rain
Program requirements. Any Title IV sources that are subject to
provisions of this proposed rule would still need to continue to comply
with all Acid Rain provisions. Acid Rain Program SO2 and
NOX requirements are established independently in Title IV
of the CAA and will continue to apply independently of this proposed
rule's provisions. Acid Rain sources will still be required to comply
with Title IV requirements, including the requirement to hold Title IV
allowances to cover SO2 emissions after the end of a
compliance year.
3. Other Current Emissions Trading Programs
    This proposed rule, if finalized, would not substantively affect
any provisions of the CSAPR NOX Annual, CSAPR SO2
Group 1, CSAPR SO2 Group 2, CSAPR NOX Ozone
Season Group 1, or CSAPR NOX Ozone Season Group 2 trading
programs for sources that continue to participate in those programs
except with regard to the schedule for EPA to record certain allowance
allocations, as discussed in Section VII.B.12 of this proposed rule. In
addition, certain revisions are proposed to the CSAPR NOX
Ozone Season Group 2 Trading Program regulations to address the
proposed transition of sources in eight states from that program to the
CSAPR NOX Ozone Season Group 3 Trading Program, as discussed
in Section VII.B.11 of this proposed rule. Sources that are subject to
any of the CSAPR trading programs will still be required to comply with
all requirements, including the requirement to hold allowances to cover
emissions after the end of a control period.

VIII. Environmental Justice Analytical Considerations and Stakeholder
Outreach and Engagement

    Consistent with EPA's commitment to integrating environmental
justice in the agency's actions, and following the directives set forth
in multiple Executive Orders, the Agency has analyzed the impacts of
this proposed rule on communities with environmental justice concerns
and engaged with stakeholders representing these communities to seek
input and feedback. Executive Order 12898 is discussed in Section XI.J
of this proposed rule and analytical results are available in Chapter 7
of the RIA.

A. Introduction

    Executive Order 12898 directs EPA staff to identify the populations
of concern who are most likely to experience unequal burdens from
environmental harms; specifically, minority populations, low-income
populations, and indigenous peoples.\333\ Additionally, Executive Order
13985 is intended to advance racial equity and support underserved
communities through federal government actions.\334\ The EPA defines
environmental justice as the fair treatment and meaningful involvement
of all people regardless of race, color, national origin, or income,
with respect to the development, implementation, and enforcement of
environmental laws, regulations, and policies. EPA further defines the
term fair treatment to mean that ``no group of people should bear a
disproportionate burden of environmental harms and risks, including
those resulting from the negative environmental consequences of
industrial, governmental, and commercial operations or programs and
policies.'' \335\ In recognizing that minority and low-income
populations often bear an unequal burden of environmental harms and
risks, EPA continues to consider ways of protecting them from adverse
public health and environmental effects of air pollution.
---------------------------------------------------------------------------

    \333\ 59 FR 7629, February 16, 1994.
    \334\ 86 FR 7009, January 20, 2021.
    \335\ https://www.epa.gov/environmentaljustice.
---------------------------------------------------------------------------

B. Analytical Considerations

    EPA's environmental justice technical guidance \336\ states that
``[t]he analysis of potential EJ concerns for regulatory actions should
address three questions:
---------------------------------------------------------------------------

    \336\ U.S. Environmental Protection Agency (EPA), 2015. Guidance
on Considering Environmental Justice During the Development of
Regulatory Actions.

    1. Are there potential environmental justice concerns associated
with environmental stressors affected by the regulatory action for
population groups of concern in the baseline?
    2. Are there potential environmental justice concerns associated
with environmental stressors affected by the regulatory action for
population groups of concern for the regulatory option(s) under
consideration?
    3. For the regulatory option(s) under consideration, are
potential environmental justice concerns created or mitigated
compared to the baseline?''

    To address these questions in EPA's first quantitative EJ analysis
in the context of a transport rule, the EPA developed a unique
analytical approach that considers the purpose and specifics of the
proposed rulemaking, as well as the nature of known and potential
exposures and impacts. However, due to data limitations, it is possible
that our analysis failed to identify disparities that may exist, such
as potential environmental justice characteristics (e.g., unemployed),
environmental impacts (e.g., other ozone metrics), and more granular
spatial resolutions (e.g., neighborhood scale) that were not evaluated.
    For the proposed rule, we employ two types of analytics to respond
to the above three questions: Proximity analyses and exposure analyses.
Both types of analyses can inform whether there are potential EJ
concerns for population groups of concern in the baseline (question
1).\337\ In contrast, only the exposure analyses, which are based on
future air quality modeling, can inform whether there will be potential
EJ concerns after implementation of the regulatory options under
consideration (question 2) and whether potential EJ concerns will be
created or mitigated compared to the baseline (question 3). While the
exposure analysis can respond to all three questions, it should be
noted that exposure is limited to a single ozone metric, the maximum
daily 8-hour average, averaged across the April through September warm
season (AS-MO3). This ozone metric likely smooths potential daily ozone
gradients and is not directly relatable to the National Ambient Air
Quality Standard (NAAQS). Additionally, the ozone exposure analytic
results are provided in two formats: Aggregated and distributional. The
aggregated results provide an overview of potential ozone exposure
differences across populations at the national- and state-levels, while
the distributional results show detailed

information about ozone concentrations experienced by everyone within
each population.
---------------------------------------------------------------------------

    \337\ The baseline for proximity analyses is current population
information (e.g., 2021), whereas the baseline for ozone exposure
analyses are the future years in which the regulatory options will
be implemented (e.g., 2023 and 2026).
---------------------------------------------------------------------------

    In Chapter 7 of the RIA we utilize the two types of analytics to
address the three EJ questions by quantitatively evaluating (1) the
proximity of affected facilities to potentially disadvantaged
populations (Section 7.3.1), (2) the potential for disproportionate
total ozone concentrations in the baseline across different demographic
groups (Sections <IP_ADDRESS> and <IP_ADDRESS>), and (3) how regulatory
alternatives differentially impact the ozone concentration changes
experienced by different demographic populations (Sections <IP_ADDRESS> and
<IP_ADDRESS>). Each of these analyses depends on mutually exclusive
assumptions, was performed to answer separate questions, and is
associated with unique limitations and uncertainties.
    Baseline demographic proximity analyses can be relevant for
identifying populations that may be exposed to local pollutants, such
as NO2 emitted from affected sources in this proposed rule.
However, such analyses are less useful here as they do not account for
the potential impacts of this proposed rule on long-range ozone
concentration changes. The baseline demographic proximity analysis
presented in the RIA finds larger percentages of Hispanic individuals,
Black individuals, people below the poverty level, people with less
educational attainment, and people linguistically isolated living
within 5 km and 10 km of an affected EGU, compared to national
averages. It also finds larger percentages of people below the poverty
level and with less educational attainment living within 5 km and 10 km
of an affected non-EGU. Separately, the tribal proximity analysis finds
multiple tribes and unique tribal lands located within 50 miles of an
affected facility. These results do not in themselves demonstrate
disproportionate impacts of affected facilities in the baseline but
could suggest that emission reductions from this proposed rule may be
responsive to potential local air quality concerns of nearby
communities.
    Whereas the proximity analyses are limited to evaluating local
pollutants under baseline scenarios (question 1), the ozone exposure
analyses can provide insight into all three EJ questions with regard to
AS-MO3 concentrations. Even though both the proximity and ozone
exposure analyses can improve understanding of baseline EJ concerns
(question 1), the two should not be directly compared. This is because
the demographic proximity analysis does not include air quality
information and is based on current, not future, population
information.
    Importantly, the baseline analysis of AS-MO3 ozone concentrations
responds to question 1 from EPA's environmental justice technical
guidance document more directly than the proximity analyses, as it
evaluates a form of the environmental stressor targeted by the
regulatory action. Baseline AS-MO3 analyses show that certain
populations, such as American Indians, Hispanics, and Asians, may
experience somewhat higher AS-MO3 concentrations compared to the
national average. The less educated and children may also experience
higher concentrations compared to the national average, but to a lesser
extent. Conversely, Black populations may experience lower AS-MO3
concentrations than the national average. Therefore, also in response
to question 1, there likely are potential environmental justice
concerns associated with ozone exposures affected by the regulatory
action for population groups of concern in the baseline. However, these
baseline exposure results have not been fully explored and additional
analyses are likely needed to understand potential implications.
    The ozone exposure analysis evaluates the impacts of the proposed
rule on future ozone concentrations after rule implementation. When
comparing across the policy, more-, and less-stringent regulatory
alternatives, AS-MO3 concentrations are reduced across all populations
evaluated in both future years and across both EGUs and non-EGUs. In
other words, we expect that populations experiencing disproportionate
AS-MO3 exposures in the baseline will experience similar
disproportionate AS-MO3 exposures under the proposed rulemaking,
although to a lesser absolute extent as the action described in this
proposed rule is expected to lower ozone in many areas, including
residual ozone nonattainment areas, and thus alleviate some pre-
existing health risks of ozone across all populations evaluated.
Therefore, in response to question 2, we expect that there will be
potential EJ concerns with regard to AS-MO3 concentrations after
implementation of the regulatory options under consideration.
    Question 3 asks whether potential EJ concerns will be created or
mitigated as compared to the baseline. As the RIA estimates
disproportionate AS-MO3 exposures in the baseline and similar
reductions in all population evaluated, we do not predict that
potential EJ concerns related to AS-MO3 concentrations will be created
or mitigated as compared to the baseline (question 3).
    The ozone exposure results should not be extrapolated to ozone
metrics other than AS-MO3. Detailed environmental justice analytical
results can be found in Chapter 7 of the RIA.

C. Outreach and Engagement

    Prior to this proposed rule, EPA initiated a public outreach effort
to gather input from stakeholder groups likely to be interested in this
proposed rule. Specifically, the EPA hosted an environmental justice
webinar on October 26, 2021, to share information about the proposed
rule and solicit feedback about potential environmental justice
considerations. The webinar was attended by over 180 individuals
representing state governments, federally recognized tribes,
environmental NGOs, higher education institutions, industry, and the
EPA.\338\ Participants were invited to comment during the webinar or
provide written comments to a pre-regulatory docket. The webinar was
recorded and distributed to attendees after the event. Some of the key
issues raised by stakeholders during the webinar and in the pre-
proposal comments are described below.
---------------------------------------------------------------------------

    \338\ This does not constitute EPA's tribal consultation under
E.O. 13175, which is described in Section XI.F of this proposed
rule.
---------------------------------------------------------------------------

    Daily emissions rate limits. Several commenters asserted that cap
and trade programs with seasonal limits on overall NOX
emissions do not prevent facilities from running their controls
inefficiently on high ozone days. These commenters recommended that
facilities linked to downwind ozone problems comply with daily rate
limits to ensure that emissions reductions occur on days when ozone is
highest. The commenters noted that daily limits could particularly
benefit environmental justice communities located near facilities and
would also benefit those located downwind.
    Regulation of other sources. Several commenters asserted that the
EPA should consider regulation of sources other than EGUs and sources
of NOX in rulemakings pertaining to issues of ozone
transport. For example, some commenters asserted that the EPA should
regulate emissions from non-EGUs, mobile sources, and sources of VOCs.
    Environmental justice analysis and methodology in rulemakings.
Several commenters offered recommendations to improve environmental
justice analysis and methodology in rulemakings that address air
pollution.

One commenter recommended that the EPA should broadly: (1) Identify
communities of interest, based on the number of and proximity to
polluting facilities; (2) integrate demographic factors to discern
social, economic, and racial disparities in these areas; (3) consider
the community's particular vulnerabilities and sensitivities to health
harms and risks, and exposure to cumulative health harms and risks; and
(4) reach out to the community members near such facilities themselves
to gain tangible, lived experiences across their lifetimes. The
commenter also suggested that the EPA should build off factors
identified in existing environmental justice screening tools, including
EPA EJSCREEN and California's CalEnviroScreen. One commenter noted that
in developing environmental justice analyses, the EPA should consider
and address the need for regulatory certainty, including the need for
clear regulatory definitions of environmental justice areas and clear
requirements for those areas.
    Environmental justice stakeholder outreach in rulemakings. Some
commenters asserted that the EPA could improve stakeholder outreach in
the rulemaking process. For example, one commenter noted that during
the development of a rule proposal, the EPA could more directly reach
out to all potentially impacted environmental justice communities, be
more prepared to answer questions about the rule proposal, and be more
aware of holidays when establishing comment periods.
    Additionally, some comments touched on issues that are also
relevant to other EPA policies and programs. For example, some
commenters asserted that the EPA should base air pollutant transport
policy more on monitored data rather than modeling data to promptly
address air pollution in areas where current monitoring data indicates
an exceedance of the NAAQS. Other commenters recommended that the EPA
consider strengthening cost thresholds for Reasonably Available Control
Technology (RACT), a program that is applicable to certain existing
sources in non-attainment areas.
    In addition to the engagement conducted prior to this proposed
rule, EPA is providing the public, including those communities
disproportionately impacted by the burdens of pollution, opportunities
to engage in the EPA's public comment period for this proposed rule,
including by hosting a public hearing. This public hearing will occur
according to the schedule identified in the Public Participation
section of this proposed rule.

IX. Costs, Benefits, and Other Impacts of the Proposed Rule

    In the Regulatory Impact Analysis for the proposed Federal
Implementation Plan Addressing Regional Ozone Transport for the 2015
Ozone National Ambient Air Quality Standards (RIA), EPA estimated the
benefits, compliance costs, and emissions changes that may result from
the proposed rule for the analysis period 2023 to 2042. The estimated
benefits and compliance costs are presented in detail in the RIA
accompanying this proposed rule. EPA notes that for EGUs the estimated
benefits and compliance costs are directly associated with generation
shifting to minimize costs; fully operating existing SCRs during ozone
season; fully operating existing SNCRs during ozone season; installing
state-of-the-art combustion controls; imposing backstop emission rate
limits on certain units that lack SCR controls; and unit-level
decisions to retrofit or retire. EPA also notes that for non-EGUs the
estimated benefits and compliance costs are directly associated with
installing controls to meet the NOX emissions limits
presented in Section I.B above.
    For EGUs, EPA analyzed this proposed rule's emission budgets using
uniform control stringency represented by $1,800 per ton of
NOX (2016$) in 2023 and $11,000 per ton of NOX
(2016$) in 2026. EPA also analyzed a more and a less stringent
alternative. The more and less stringent alternatives differ from the
proposed rule in that they set different NOX ozone season
emission budgets for the affected EGUs and different dates for
compliance with backstop emission rate limits.
    For non-EGUs, EPA analyzed this proposed rule using a marginal cost
threshold of up to $7,500 per ton (2016$) for 2026 for the following
emissions units and industries: Reciprocating internal combustion
engines in Pipeline Transportation of Natural Gas; kilns in Cement and
Cement Product Manufacturing; boilers and furnaces in Iron and Steel
Mills and Ferroalloy Manufacturing; furnaces in Glass and Glass Product
Manufacturing; and high-emitting boilers in Basic Chemical
Manufacturing, Petroleum and Coal Products Manufacturing, and Pulp,
Paper, and Paperboard Mills. The less stringent alternative assumes
there are emissions limits for all emission units from the proposal
except for high-emitting boilers in Basic Chemical Manufacturing,
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and
Paperboard Mills. The more stringent alternative assumes emissions
limits for all emission units from the proposed rule and all boilers,
not just high-emitting boilers, in Basic Chemical Manufacturing,
Petroleum and Coal Products Manufacturing, and Pulp, Paper, and
Paperboard Mills.
    Table IX-1 provides the projected 2023 through 2027, 2030, 2035,
and 2042 EGU emission reductions for the evaluated regulatory control
alternatives. For additional information on emissions changes, see
Table 4.6 and Table 4-7 in Chapter 4 of the RIA.

 Table IX-1--EGU Ozone Season NOX Emissions Changes and Annual Emissions Reductions (Tons) for NOX, SO2, PM2.5,
                         and CO2 for the Regulatory Control Alternatives From 2023-2042
----------------------------------------------------------------------------------------------------------------
                                                                                Less stringent   More stringent
                                                                Proposed rule     alternative      alternative
----------------------------------------------------------------------------------------------------------------
2023:
    NOX (ozone season).......................................            6,000            6,000            7,000
    NOX (annual).............................................           10,000           10,000           10,000
    SO2 (annual) *...........................................  ...............            1,000            2,000
    CO2 (annual, thousand metric)............................  ...............  ...............  ...............
    PM2.5 (annual)...........................................  ...............  ...............  ...............
2024:
    NOX (ozone season).......................................           26,000           14,000           29,000
    NOX (annual).............................................           42,000           22,000           45,000
    SO2 (annual).............................................           42,000           20,000           43,000
    CO2 (annual, thousand metric)............................           18,000           10,000           19,000
    PM2.5 (annual)...........................................            4,000            1,000            4,000
2025:

    NOX (ozone season).......................................           46,000           22,000           51,000
    NOX (annual).............................................           73,000           33,000           80,000
    SO2 (annual).............................................           83,000           39,000           84,000
    CO2 (annual, thousand metric)............................           37,000           19,000           38,000
    PM2.5 (annual)...........................................            9,000            2,000            9,000
2026:
    NOX (ozone season).......................................           47,000           32,000           53,000
    NOX (annual).............................................           81,000           55,000           87,000
    SO2 (annual).............................................          106,000           76,000          108,000
    CO2 (annual, thousand metric)............................           40,000           26,000           42,000
    PM2.5 (annual)...........................................            9,000            5,000            9,000
2027:
    NOX (ozone season).......................................           49,000           42,000           54,000
    NOX (annual).............................................           88,000           76,000           95,000
    SO2 (annual).............................................          129,000          113,000          131,000
    CO2 (annual, thousand metric)............................           43,000           34,000           46,000
    PM2.5 (annual)...........................................           10,000            7,000           10,000
2030:
    NOX (ozone season).......................................           52,000           52,000           57,000
    NOX (annual).............................................           96,000           98,000          100,000
    SO2 (annual).............................................          104,000          100,000          103,000
    CO2 (annual, thousand metric)............................           50,000           45,000           50,000
    PM2.5 (annual)...........................................            9,000            9,000            9,000
2035:
    NOX (ozone season).......................................           49,000           50,000           52,000
    NOX (annual).............................................           90,000           93,000           93,000
    SO2 (annual).............................................           96,000           93,000           98,000
    CO2 (annual, thousand metric)............................           38,000           36,000           38,000
    PM2.5 (annual)...........................................           11,000           12,000           10,000
2042:
    NOX (ozone season).......................................           47,000           47,000           48,000
    NOX (annual).............................................           70,000           75,000           71,000
    SO2 (annual).............................................           54,000           50,000           54,000
    CO2 (annual, thousand metric)............................           25,000           23,000           24,000
    PM2.5 (annual)...........................................            8,000            9,000            8,000
----------------------------------------------------------------------------------------------------------------
*SO2 emissions reductions under the proposed rule are 350 tons and rounded to zero. SO2 emissions reductions
  under the less stringent alternative are 507 tons and rounded to 1,000 tons. SO2 emissions reductions are
  1,699 tons under the more stringent alternative and rounded to 2,000 tons. Given the rounding, the difference
  between the reductions under the proposed rule and the less stringent alternative is approximately 160 tons.

    Table IX-2 below provides a summary of the ozone season emissions
for non-EGUs for the 23 states subject to the proposed non-EGU
emissions limits starting in 2026, along with the estimated ozone
season reductions for 2026 for the proposed rule and the less and more
stringent alternatives. The analysis in the RIA assumes that the
estimated reductions in 2026 will be the same in later years.

 Table IX-2--Ozone Season (OS) NOX Emissions and Emissions Reductions (Tons) for Non-EGUs for the Proposed Rule
                                 and the Less and More Stringent Alternatives *
----------------------------------------------------------------------------------------------------------------
                                                                               Less stringent    More stringent
                                             2019 OS NOX     Proposed rule--   alternative--OS   alternative--OS
                  State                     emissions \a\        OS NOX        NOX reductions    NOX reductions
                                                               reductions
----------------------------------------------------------------------------------------------------------------
AR......................................             8,265             1,654               922             1,654
CA......................................            14,579             1,666             1,598             1,777
IL......................................            16,870             2,452             2,452             2,553
IN......................................            19,604             3,175             2,787             3,175
KY......................................            11,934             2,291             2,291             2,291
LA......................................            35,831             6,769             4,121             6,955
MD......................................             2,365                45                45                45
MI......................................            18,996             2,731             2,731             3,093
MN......................................            17,591               673               673               789
MO......................................             9,109             3,103             3,103             3,103
MS......................................            12,284             1,761             1,577             1,761
NJ......................................             2,025                 0                 0                29
NV......................................             2,418                 0                 0                 0
NY......................................             6,003               500               389               613
OH......................................            19,729             2,790             2,611             2,814
OK......................................            22,146             3,575             3,575             3,871

PA......................................            15,861             3,284             3,132             3,340
TX......................................            47,135             4,440             4,440             6,596
UT......................................             6,276               757               757               757
VA......................................             7,041             1,563             1,465             1,660
WI......................................             6,571             2,150               677             2,234
WV......................................             9,825               982               982               982
WY......................................            10,335               826               826               826
                                         -----------------------------------------------------------------------
    Totals..............................           322,793            47,186            41,153            50,918
----------------------------------------------------------------------------------------------------------------
* In the non-EGU screening assessment for 2026, EPA estimated emissions reduction potential from the non-EGU
  industries and emissions units. In the screening assessment, EPA used CoST to identify emissions units,
  emissions reductions, and associated compliance costs to evaluate the effects of potential non-EGU emissions
  control measures and technologies. CoST is designed to be used for illustrative control strategy analyses
  (e.g., NAAQS regulatory impact analyses) and not for unit-specific, detailed engineering analyses. The
  estimates from CoST identify proxies for (1) non-EGU emissions units that have emissions reduction potential,
  (2) potential controls for and emissions reductions from these emissions units, and (3) control costs from the
  potential controls on these emissions units. The control cost estimates do not include monitoring,
  recordkeeping, reporting, or testing costs. This screening assessment is not intended to be, nor take the
  place of, a unit-specific detailed engineering analysis that fully evaluates the feasibility of retrofits for
  the emissions units, potential controls, and related costs.
\a\ EPA determined that the 2019 inventory was appropriate because it provided a more accurate prediction of
  potential near-term emissions reductions. The analysis in the RIA assumes that the 2019 ozone season emissions
  will be the same in 2026 and later years.

    For EGUs, the EPA analyzed ozone season NOX emission
reductions and the associated costs to the power sector using the
Integrated Planning Model (IPM) and its underlying data and inputs. For
non-EGUs, the EPA analyzed ozone season NOX emission
reductions and the associated costs for 2026 in the Non-EGU Screening
Assessment memorandum. Table IX-3 reflects the estimates of the changes
in the cost of supplying electricity for the regulatory control
alternatives for EGUs and estimates of complying with the emissions
limits for non-EGUs. For EGUs, compliance costs are negative in 2023.
While seemingly counterintuitive, estimating negative compliance costs
in a single year is possible given IPM's objective function is to
minimize the discounted net present value (NPV) of a stream of annual
total cost of generation over a multi-decadal time period. As such the
model may undertake a compliance pathway that pushes higher costs later
into the forecast period, since future costs are discounted more
heavily than near term costs. This can result in a policy scenario
showing single year costs that are lower than the Baseline, but over
the entire forecast horizon, the policy scenario shows higher costs.
For a detailed description of these cost trends, please see Chapter 4,
Section 4.5.2 of the RIA. For a detailed description of the methods and
results from Non-EGU Screening Assessment memorandum, see Chapter 4,
Sections 4.4 and 4.5.2 of the RIA.

                     Table IX-3--Total Estimated Compliance Costs (Million 2016$), 2023-2042
----------------------------------------------------------------------------------------------------------------
                                                                               Less-stringent    More-stringent
                                                              Proposed rule      alternative       alternative
----------------------------------------------------------------------------------------------------------------
2023:
    EGUs...................................................             -209              -173              -178
    Non-EGUs...............................................  ...............  ................  ................
    Total..................................................             -209              -173              -178
2026:
    EGUs...................................................              707              -406             1,180
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,117               -49             1,625
2027:
    EGUs...................................................            1,544             1,540             1,983
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,955             1,896             2,428
2030:
    EGUs...................................................            1,235             1,200             1,740
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,646             1,557             2,185
2035:
    EGUs...................................................            1,729             1,596             2,335
    Non-EGUs...............................................              411               357               445
    Total..................................................            2,139             1,953             2,780
2042:
    EGUs...................................................              910             1,757             1,001
    Non-EGUs...............................................              411               357               445
    Total..................................................            1,321             2,114             1,446
----------------------------------------------------------------------------------------------------------------

    Tables IX-4 and IX-5 report the estimated economic value of avoided
premature deaths and illness in each year relative to the baseline
along with the 95% confidence interval. In each of these tables, for
each discount rate and regulatory control alternative, multiple
benefits estimates are presented reflecting alternative ozone and
PM2.5 mortality risk estimates. For additional information
on these benefits, see Chapter 5 of the RIA.

 Table IX-4--Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Attributable Premature Mortality and
                                Illness for the Proposed Policy Scenarios in 2023
                              [95% Confidence interval; millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                       More stringent          Less stringent
      Disc. rate            Pollutant             Proposal               alternative            alternative
----------------------------------------------------------------------------------------------------------------
3%....................  Ozone Benefits...  $57 ($15 to $120) \c\   $65 ($17 to $140) \c\   $57 ($15 to $120) \c\
                                            and $460 ($51 to        and $530 ($59 to        and $460 ($51 to
                                            $1,200) \d\.            $1,400) \d\.            $1,200).\d\
                        PM Benefit Per     $44 and $45...........  $190 and $190.........  $59 and $60.
                         Ton (BPT)s.
                        Ozone Benefits     $100 ($59 to $160) \c\  $250 ($200 to $330)     $120 ($74 to $180)
                         plus PM BPTs.      and $500 ($96 to        \c\ and $720 ($250 to   \c\ and $520 ($110
                                            $1,200) \d\.            $1,600) \d\.            to $1,300).\d\
7%....................  Ozone Benefits...  $51 ($9.6 to 110) \c\   $58 ($11 to $130) \c\   $51 ($9.6 to $110)
                                            and $410 ($42 to        and $480 ($49 to        \c\ and $410 ($42 to
                                            $1,100) \d\.            $1,300) \d\.            $1,100).\d\
                        PM BPTs..........  $40 and $41...........  $170 and $170.........  $53 and $54.
                        Ozone Benefits     $90 ($49 to $150) \c\   $230 ($180 to $300)     $100 ($63 to $170)
                         plus PM BPTs.      and $450 ($83 to        \c\ and $650 ($220 to   \c\ and $470 ($97 to
                                            $1,100) \d\.            $1,400) \d\.            $1,100).\d\
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. The two benefits estimates are separated by the word ``and'' to
  signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates
  and should not be summed.
\b\ We estimated ozone benefits for changes in NOX for the ozone season and changes in PM2.5 and PM2.5
  precursors for EGUs in 2023. This table does not include benefits from reductions for non-EGUs because
  reductions from these sources are not expected prior to 2026 when the proposed standards would become
  effective.
\c\ Using the pooled short-term ozone exposure mortality risk estimate.
\d\ Using the long-term ozone exposure mortality risk estimate.

 Table IX-5--Estimated Discounted Economic Value of Avoided Ozone and PM2.5-Attributable Premature Mortality and
                                Illness for the Proposed Policy Scenario in 2026
                              [95% Confidence interval; millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                       More stringent          Less stringent
      Disc. rate            Pollutant             Proposal               alternative            alternative
----------------------------------------------------------------------------------------------------------------
3%....................  Ozone Benefits...  $1,200 ($310 to         $1,300 (340 to $2,900)  $830 ($210 to $1,800)
                                            $2,600) \c\ and         \c\ and $11,000         \c\ and $6,900 ($760
                                            $10,000 ($1,100 to      ($1,200 to $29,000)     to $18,000).\d\
                                            $26,000) \d\.           \d\.
                        PM BPTs..........  $8,100 and $8,300.....  $7,800 and $7,900.....  $3,400 and $3,500.
                        Ozone Benefits     $9,300 ($8,400 to       $9,100 ($8,100 to       $4,300 ($3,700 to
                         plus PM BPTs.      $11,000) \c\ and        $11,000) \c\ and        $5,200) \c\ and
                                            $18,000 ($9,400 to      $19,000 ($9,200 to      $10,000 ($4,300 to
                                            $35,000) \d\.           $37,000) \d\.           $22,000).\d\
7%....................  Ozone Benefits...  $1,100 ($200 to         $1,200 ($220 to         $740 ($140 to $1,700)
                                            $2,400) \c\ and         $2,700) \c\ and         \c\ and $6,200 ($630
                                            $9,000 ($920 to         $10,000 ($1,000 to      to $16,000).\d\
                                            $24,000) \d\.           $26,000) \d\.
                        PM BPTs..........  $7,300 and $7,400.....  $7,000 and $7,100.....  $3,100 and $3,200.
                        Ozone Benefits     $8,400 ($7,500 to       $8,200 ($7,200 to       $3,800 ($3,200 to
                         plus PM BPTs.      $9,700) \c\ and         $9,700) \c\ and         $4,800) \c\ and
                                            $16,000 ($8,300 to      $17,000 ($8,200 to      $9,300 ($3,800 to
                                            $31,000) \d\.           $34,000) \d\.           $19,000).\d\
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. The two benefits estimates are separated by the word ``and'' to
  signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates
  and should not be summed.
\b\ We estimated changes in NOX for the ozone season and changes in PM2.5 and PM2.5 precursors in 2026. This
  table represents changes in EGU and non-EGU ozone season and annual controls.
\c\ Sum of ozone mortality estimated using the pooled short-term ozone exposure risk estimate and the Di et al.
  (2017) long-term PM2.5 exposure mortality risk estimate.
\d\ Sum of the Turner et al. (2016) long-term ozone exposure risk estimate and the Di et al. (2017) long-term
  PM2.5 exposure mortality risk estimate.

    In Tables IX-6, IX-7, and IX-8, EPA presents a summary of the
monetized benefits, costs, and net benefits of the proposal and the
more and less stringent alternatives for 2023, 2026, and 2030,
respectively. The monetized benefits estimates do not include important
climate benefits that were not monetized in the RIA. In addition, there
are important water quality benefits and health benefits associated
with reductions in concentrations of air pollutants other than
PM2.5 and ozone that are not quantified. We request comment
on how to address the climate benefits and other categories of non-
monetized benefits of the proposed rule. Discussion of the non-
monetized health, climate, welfare, and water quality benefits is found
in Chapter 5 of the RIA.

Table IX-6--Monetized Benefits, Costs, and Net Benefits of the Proposed and Less and More Stringent Alternatives
                                              for 2023 for the U.S.
                                           [Millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                            Proposed rule             alternative              alternative
----------------------------------------------------------------------------------------------------------------
Benefits \c\ (3%)....................  $100 and $500..........  $120 and $520..........  $250 and $720.
Costs \d\............................  -$210..................  -$170..................  -$180.
Net Benefits.........................  $310 and $710..........  $290 and $690..........  $430 and $900.
Benefits \c\ (7%)....................  $90 and $450...........  $100 and $470..........  $230 and $650.
Costs \d\............................  -$210..................  -$170..................  -$180
Net Benefits.........................  $300 and $660..........  $280 and $640..........  $400 and $820.
----------------------------------------------------------------------------------------------------------------
\a\ We focus results to provide a snapshot of costs and benefits in 2023, using the best available information
  to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
\b\ Rows may not appear to add correctly due to rounding.

\c\ Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone
  concentrations. The health benefits are associated with several point estimates and are presented at a real
  discount rate of 3 percent. Several categories of benefits remain unmonetized and are thus not reflected in
  the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The
  U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization
  of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No.
  21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the benefit-cost
  analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA for
  more discussion. In addition, there are important unquantified water quality benefits and benefits associated
  with reductions in other air pollutants.
\d\ The costs presented in this table are 2023 annual estimates for each alternative analyzed. An NPV of costs
  was calculated using a 3.76% real discount rate consistent with the rate used in IPM's objective function for
  cost-minimization.

Table IX-7--Monetized Benefits, Costs, and Net Benefits of the Proposed and Less and More Stringent Alternatives
                                              for 2026 for the U.S.
                                           [Millions of 2016$] \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                            Proposed rule             alternative              alternative
----------------------------------------------------------------------------------------------------------------
Benefits \c\ (3%)....................  $9,300 and $18,000.....  $4,300 and $10,000.....  $9,100 and $19,000.
Costs \d\............................  $1,100.................  -$49...................  $1,600.
Net Benefits.........................  $8,200 and $17,000.....  $4,300 and $10,000.....  $7,500 and $17,000.
Benefits \c\ (7%)....................  $8,400 and $16,000.....  $3,800 and $9,300......  $8,200 and $17,000.
Costs \d\............................  $1,100.................  -$49...................  $1,600
Net Benefits.........................  $7,300 and $15,000.....  $9,300 and $3,900......  $6,600 and $15,000.
----------------------------------------------------------------------------------------------------------------
\a\ We focus results to provide a snapshot of costs and benefits in 2026, using the best available information
  to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
\b\ Rows may not appear to add correctly due to rounding.
\c\ Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone
  concentrations. The health benefits are associated with several point estimates and are presented at a real
  discount rate of 3 percent. Several categories of benefits remain unmonetized and are thus not reflected in
  the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The
  U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization
  of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No.
  21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the benefit-cost
  analysis of this proposal conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA for
  more discussion. In addition, there are important unquantified water quality benefits and benefits associated
  with reductions in other air pollutants.
\d\ The costs presented in this table are 2026 annual estimates for each alternative analyzed. An NPV of costs
  was calculated using a 3.76% real discount rate consistent with the rate used in IPM's objective function for
  cost-minimization.

Table IX-8--Monetized Benefits, Costs, and Net Benefits of the Proposed and Less and More Stringent Alternatives
                                              for 2030 for the U.S.
                                           (Millions of 2016$) \a\ \b\
----------------------------------------------------------------------------------------------------------------
                                                                     Less stringent           More stringent
                                            Proposed rule             alternative              alternative
----------------------------------------------------------------------------------------------------------------
Benefits \c\ (3%)....................  $9,400 and $20,000.....  $4,300 and $11,000.....  $9,200 and $21,000.
Costs \d\............................  $1,600.................  $1,600.................  $2,200.
Net Benefits.........................  $7,700 and $18,000.....  $2,800 and $9,700......  $7,000 and $19,000.
Benefits \c\ (7%)....................  $8,400 and $18,000.....  $3,900 and $10,000.....  $8,300 and $19,000.
Costs \d\............................  $1,600.................  $1,600.................  $2,200.
Net Benefits.........................  $6,800 and $16,000.....  $2,300 and $8,400......  $6,100 and $16,000.
----------------------------------------------------------------------------------------------------------------
\a\ We focus results to provide a snapshot of costs and benefits in 2030, using the best available information
  to approximate social costs and social benefits recognizing uncertainties and limitations in those estimates.
\b\ Rows may not appear to add correctly due to rounding.
\c\ Monetized benefits include those related to public health associated with reductions in PM2.5 and ozone
  concentrations. The health benefits are associated with several point estimates and are presented at a real
  discount rate of 3 percent. Several categories of benefits remain unmonetized and are thus not reflected in
  the table. Non-monetized benefits include important climate benefits from reductions in CO2 emissions. The
  U.S. District Court for the Western District of Louisiana has issued an injunction concerning the monetization
  of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana v. Biden, No.
  21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the benefit-cost
  analysis of this proposed rule conducted pursuant to E.O. 12866. Please see Chapter 5, Section 5.2 of the RIA
  for more discussion. In addition, there are important unquantified water quality benefits and benefits
  associated with reductions in other air pollutants.
\d\ The costs presented in this table are 2030 annual estimates for each alternative analyzed. An NPV of costs
  was calculated using a 3.76% real discount rate consistent with the rate used in IPM's objective function for
  cost-minimization.

    In addition, Table IX-9 presents estimates of the present value
(PV) of the monetized benefits and costs and the equivalent annualized
value (EAV), an estimate of the annualized value of the net benefits
consistent with the present value, over the twenty-year period of 2023
to 2042. The estimates of the PV and EAV are calculated using discount
rates of 3 and 7 percent as directed by OMB's Circular A-4 and are
presented in 2016 dollars discounted to 2022.

 Table IX-9--Monetized Estimated Benefits, Compliance Costs, and Net Benefits of the Proposed Rule and Less and
                                 More Stringent Alternatives, 2023 Through 2042
                                    (Millions 2016$, discounted to 2022) \a\
----------------------------------------------------------------------------------------------------------------
                                                      3 Percent discount rate         7 Percent discount rate
                                                 ---------------------------------------------------------------
                                                        PV              EAV             PV              EAV
----------------------------------------------------------------------------------------------------------------
                                                    Benefits
----------------------------------------------------------------------------------------------------------------
Proposed Rule...................................        $250,000         $17,000        $150,000         $14,000
Less Stringent Alternative......................         150,000           9,500          88,000           7,800
More Stringent Alternative......................         270,000          17,000         160,000          14,000
----------------------------------------------------------------------------------------------------------------
                                                Compliance Costs
----------------------------------------------------------------------------------------------------------------
Proposed Rule...................................          22,000           1,500          14,000           1,300
Less Stringent Alternative......................          20,000           1,300          12,000           1,100
More Stringent Alternative......................          28,000           1,900          18,000           1,700
----------------------------------------------------------------------------------------------------------------
                                                  Net Benefits
----------------------------------------------------------------------------------------------------------------
Proposed Rule...................................         220,000          15,000         130,000          12,000
Less Stringent Alternative......................         120,000           8,100          70,000           6,600
More Stringent Alternative......................         230,000          15,000         130,000          12,000
----------------------------------------------------------------------------------------------------------------
\a\ The U.S. District Court for the Western District of Louisiana has issued an injunction concerning the
  monetization of the benefits of greenhouse gas emission reductions by EPA and other defendants. See Louisiana
  v. Biden, No. 21-cv-01074-JDC-KK (W.D. La. Feb. 11, 2022). Therefore, such values are not presented in the
  benefit-cost analysis of this proposed rule conducted pursuant to E.O. 12866.

    As shown in Table IX-9, the PV of the benefits of this proposed
rule, discounted at a 3-percent discount rate, is estimated to be about
$250,000 million, with an EAV of about $17,000 million. At a 7-percent
discount rate, the PV of the benefits is estimated to be $150,000
million, with an EAV of about $14,000 million. The PV of the compliance
costs, discounted at a 3-percent rate, is estimated to be about $22,000
million, with an EAV of about $1,500 million. At a 7-percent discount
rate, the PV of the compliance costs is estimated to be about $14,000
million, with an EAV of about $1,300 million.
    In addition to the analysis of costs and benefits, EPA also
estimated the impacts on projected 2023 and 2026 ozone design values
that are expected from the EGU and non-EGU control alternatives in this
proposed rule. As described above, the alternative scenarios include
the proposed rule along with scenarios that reflect less stringent and
more stringent alternatives for EGUs and non-EGUs. The projected ozone
design values and ozone impacts estimated in 2023 and 2026 for the
proposed, less stringent, and more stringent alternatives are provided
in Appendix 3B of the RIA. In summary, the differences in the amount of
ozone reduction across the three alternatives at individual receptors
in 2023 are consistent with the relative changes in NOX
emissions in this year under the different scenarios. Overall, in 2023
the estimated ozone reductions from all three of the alternatives are
projected to be less than 0.1 ppb at most receptors. The exceptions are
at certain receptors in Connecticut, Illinois, Texas, and Utah where
impacts are between 0.1 and 0.2 ppb. In 2026, the largest impacts in
the proposed rule are estimated at the two receptors in Texas (i.e.,
Brazoria County and Harris County), where the average reduction is 1.3
ppb. Elsewhere in 2026, the average reductions for the proposed rule
are on the order of 0.5 ppb at receptors in Connecticut, Illinois, and
Wisconsin. The average reduction for the four receptors in Utah is
approximately 0.3 ppb, while the average reduction at receptors in
Colorado and California are approximately 0.2 ppb. Overall, the less
stringent alternative provides approximately 0.1 to 0.3 ppb less ppb
reduction (i.e., 30 to 40 percent less reduction), on average, compared
to the proposed rule at receptors in the East and in Colorado and Utah.
The more stringent alternative does not appear to provide any notable
additional ozone reductions compared to the proposed rule in all
receptor areas, except at receptors in Connecticut and Texas where the
average reduction increases by 0.1 ppb and 0.2 ppb with the more
stringent alternative, respectively.
    Examining the projected average and maximum design values in 2023
at individual receptors for the proposed, less stringent, and more
stringent alternatives indicates that three of the receptors included
in this impact analysis are projected to change attainment status in
2023 as a result of this proposed rule. Specifically, receptors in
Clark County, Nevada, Butte County, California, and Riverside County
Californian (Monitor ID: 060650008) are projected to switch from
maintenance-only in the 2023 baseline to attainment and the receptor in
Harris County, Texas is projected to switch from nonattainment to
maintenance-only under any of the alternatives in 2023. In 2026, six of
the receptors in this analysis are projected to change attainment
status as a result of the emissions reductions in this proposed rule.
Specifically, Calaveras County, California, Brazoria County, Texas, and
in Kenosha County, Wisconsin (Monitor ID: 550590025) are projected to
switch from maintenance-only to attainment in 2026 and a receptor in
Riverside County, California (Monitor ID: 060650016) is projected to
switch from nonattainment to maintenance under any of the alternatives.
The receptor in Douglas County, Colorado and one of the receptors in
Cook County, Illinois (Monitor ID: 170310076) are projected to switch
from maintenance-only to attainment under the proposed and more
stringent alternatives, but these receptors are projected to remain as
maintenance-only in the less stringent alternative. The projected
design values and additional information on the ozone impact analysis
can be found in Appendix 3B of the proposed rule RIA.

X. Summary of Proposed Changes to the Regulatory Text for the Federal
Implementation Plans and Trading Programs for EGUs

    This section describes the proposed amendments to the regulatory
text that

would implement the proposed findings and remedy discussed elsewhere in
this proposed rule with respect to EGUs. The primary CFR amendments
would be revisions to the FIP provisions addressing states' good
neighbor obligations related to ozone in 40 CFR part 52 as well as the
revisions to the regulations for the CSAPR NOX Ozone Season
Group 3 Trading Program in 40 CFR part 97, subpart GGGGG. In
conjunction with the amendments to the Group 3 trading program, the
monitoring, recordkeeping, and reporting regulations in 40 CFR part 75
would be amended to reflect the addition of certain new reporting
requirements associated with the amended trading program and the
administrative appeal provisions in 40 CFR part 78 would be amended to
identify certain additional types of appealable decisions of the EPA
Administrator under the amended trading program. The proposed
provisions to address the transition of the EGUs in certain states from
the Group 2 trading program to the Group 3 trading program would be
implemented in part through revisions to regulations noted above and in
part through revisions to the regulations for the Group 2 trading
program in 40 CFR part 97, subpart EEEEE.
    In addition to these primary amendments, certain revisions are
proposed to the regulations for the other CSAPR trading programs in 40
CFR part 97, subparts AAAAA through EEEEE, and the Texas SO2
Trading Program in 40 CFR part 97, subpart FFFFF, for conformity with
the proposed amended provisions of the Group 3 trading program, as
discussed in Section VII.B.12 of this proposed rule. Documents have
been included in the docket for this proposed rule showing all of the
proposed revisions in redline-strikeout format.

A. Amendments to FIP Provisions in 40 CFR Part 52

    The CSAPR, CSAPR Update, and Revised CSAPR Update FIP requirements
related to ozone season NOX emissions are set forth in 40
CFR 52.38(b) as well as other sections of part 52 specific to each
covered state. The existing text of Sec.  52.38(b)(1) identifies the
trading program regulations in 40 CFR part 97, subparts BBBBB, EEEEE,
and GGGGG as constituting the relevant FIP provisions relating to
seasonal NOX emissions and transported ozone pollution.
Because the EPA is proposing in this rulemaking to establish new or
amended FIP requirements not only for the types of EGUs covered by the
trading programs but also for other types of sources, a proposed
amendment to Sec.  52.38(b)(1) would clarify that the trading programs
constitute the FIP provisions only for the sources meeting the
applicability requirements of the trading programs. A parallel
clarification would be added to Sec. Sec.  52.38(a)(1) and 52.39(a)
with respect to the CSAPR FIP requirements relating to annual
NOX emissions, SO2 emissions, and transported
fine particulate pollution.
    The states whose EGU sources are required to participate in the
CSAPR NOX Ozone Season Group 1, Group 2, and Group 3 trading
programs under the FIPs established in CSAPR, the CSAPR Update, and the
Revised CSAPR Update, as well as the control periods for which those
requirements apply, are identified in Sec.  52.38(b)(2). Proposed
amendments to this paragraph would expand the applicability of the
Group 3 trading program to sources in the thirteen additional states
that the EPA is proposing to add to the Group 3 trading program
starting with the 2023 control period and would end the applicability
of the Group 2 trading program (with the exception of certain
provisions) for sources in eight of the thirteen states after the 2022
control period, as discussed in Section VII.B.2 of this proposed
rule.\339\ The current subparagraphs within Sec.  52.38(b)(2) would
also be renumbered to clarify the organization of the provisions and to
facilitate cross-references from other regulatory provisions. Regarding
the two states currently participating in the Group 2 trading program
through approved SIP revisions that replaced the previous FIPs issued
under the CSAPR Update (Alabama and Missouri), a provision indicating
that EPA would no longer administer the state trading programs adopted
under those SIP revisions after the 2022 control period would be added
at Sec.  52.38(b)(16)(ii)(B).
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    \339\ Both the current text of Sec.  52.38(b)(2) and the
proposed amended text expressly encompass sources in Indian country
within the respective states' borders.
---------------------------------------------------------------------------

    In the Revised CSAPR Update, the EPA established several options
for states to revise their SIPs to modify or replace the FIPs
applicable to their sources while continuing to use the Group 3 trading
program as the mechanism for meeting the states' good neighbor
obligations. Existing Sec.  52.38(b)(10), (11), and (12) establish
options to replace allowance allocations for the 2022 control period,
to adopt an abbreviated SIP revision for control periods in 2023 or
later years, and to adopt a full SIP revision for control periods in
2023 or later years, respectively. As discussed in Section VII.D of
this proposed rule, the EPA is proposing to retain these SIP revision
options and to make them available for all states that would be covered
by the Group 3 trading program after the proposed geographic expansion.
The option under Sec.  52.38(b)(10) to replace allowance allocations
for a single control period would be amended to be available for the
2024 control period, with attendant revisions to the years and dates
shown in Sec.  52.38(b)(10) (multiple paragraphs) and (b)(17)(i) as
well as the Group 3 trading program regulations, as discussed in
Section X.B of this proposed rule. The options under Sec.  52.38(b)(11)
and (12) to adopt abbreviated or full SIP revisions would be amended to
be available starting with the 2025 control period, with attendant
revisions to Sec.  52.38(b)(11)(iii), (b)(12)(iii), and
(b)(17)(ii).\340\
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    \340\ No state currently in the Group 3 trading program has
submitted a SIP revision to make use of these options in control
periods before the control periods in which the options could be
used under the proposed amendments.
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    The proposed changes with respect to set-asides, the treatment of
units in Indian country, and recordation schedules discussed in Section
VII.B.9 of this proposed rule, although implemented largely through
proposed amendments to the Group 3 trading program regulations, would
also be implemented in part through proposed amendments to Sec.
52.38(b)(11) and (12). First, the text in Sec.  52.38(b)(11)(iii)(A)
and (b)(12)(iii)(A) identifying the portion of each state trading
budget for which a state could establish state-determined allowance
allocations would be revised to exclude any allowances in a new unit
set-aside, Indian country new unit set-aside, or Indian country
existing unit set-aside. Second, the text in Sec.  52.38(b)(12)(vi)
identifying provisions that states could not adopt into their SIPs
(because the provisions concern regulation of sources in Indian country
not subject to a state's CAA implementation planning authority) would
be revised to include the provisions of the amended Group 3 trading
program addressing allocation and recordation of allowances from all
types of set-asides. Third, the text in Sec.  52.38(b)(12)(vii)
authorizing the EPA to modify the previous approval of a SIP revision
with regard to the assurance provisions ``if and when a covered unit is
located in Indian country'' would be revised to account for the fact
that at least one covered unit would already be located in Indian
country not subject to a state's jurisdiction if the geographic
expansion proposed in this rulemaking

is finalized. Finally, the text in Sec.  52.38(b)(11)(iii)(B) and
(b)(12)(iii)(B) would be revised to amend the deadline for states to
submit state-determined allowance allocations to the EPA from June 1 in
the third year before the relevant control period to June 1 in the year
before the relevant control period.
    The proposed transitional provisions discussed in Section VII.B.11
of this proposed rule to convert certain 2017-2022 Group 2 allowances
to Group 3 allowances and to recall certain 2023-2024 Group 2
allowances, although promulgated as amendments to the Group 2 trading
program regulations, would necessarily be implemented after the end of
the 2022 control period. Proposed amendments clarifying that these
provisions continue to apply to the relevant sources and holders of
allowances notwithstanding the transition of certain states out of the
Group 2 trading program after the 2022 control period would be added at
Sec.  52.38(b)(14)(iii)(F) and (G). Cross-references clarifying that
EPA's allocations of the converted Group 3 allowances would not be
subject to modification through SIP revisions would also be added to
the existing provisions at Sec.  52.38(b)(11)(iii)(D) and
(b)(12)(iii)(D).
    The general FIP provisions applicable to all states covered by this
proposed rule as set forth in Sec.  52.38(b)(2) would be replicated in
the state-specific subparts of 40 CFR part 52 for each of the thirteen
states that the EPA is proposing to add to the Group 3 trading
program.\341\ In each such state-specific CFR subpart, provisions would
be added indicating that sources in the state are required to
participate in the CSAPR NOX Ozone Season Group 3 Trading
Program with respect to emissions starting in 2023. Provisions would
also be added repeating the substance of Sec.  52.38(b)(13)(i), which
generally provides that the Administrator's full and unconditional
approval of a full SIP revision correcting the same SIP deficiency that
is the basis for a FIP promulgated in this rulemaking would cause the
FIP to no longer apply to sources subject to the state's CAA
implementation planning authority, and Sec.  52.38(b)(14)(ii), which
generally provides the EPA with authority to complete recordation of
EPA-determined allowance allocations for any control period for which
EPA has already started such recordation notwithstanding the approval
of a state's SIP revision establishing state-determined allowance
allocations.
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    \341\ See proposed Sec. Sec.  52.54(b) (Alabama), 52.184(a)
(Arkansas), 52.440(d) (Delaware), 52.1240(d) (Minnesota), 52.1824(a)
(Mississippi), 52.1326(b) (Missouri), 52.1492 (Nevada), 52.1930(a)
(Oklahoma), 52.2240(e) (Tennessee), 52.2283(d) (Texas), 52.2356
(Utah), 52.2587(e) (Wisconsin), and 52.2638(a) (Wyoming).
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    For each of the eight states that the EPA is proposing to remove
from the Group 2 trading program, the current provisions of the state-
specific CFR subparts indicating that sources in the state are required
to participate in that trading program would be revised to end that
requirement with respect to emissions after 2022, and a further
provision would be added repeating the substance of Sec.
52.38(b)(14)(iii), which identifies certain provisions that continue to
apply to sources and allowances notwithstanding discontinuation of a
trading program with respect to a particular state.\342\ In addition,
for the six states that during their time in the Group 2 trading
program have not exercised the option to adopt full SIP revisions to
replace the FIPs issued under the CSAPR Update (all but Alabama and
Missouri), obsolete provisions concerning the unexercised SIP revision
option would be removed.
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    \342\ See proposed Sec. Sec.  52.54(b) (Alabama), 52.184(a)
(Arkansas), 52.1824(a) (Mississippi), 52.1326(b) (Missouri),
52.1930(a) (Oklahoma), 52.2240(e) (Tennessee), 52.2283(d) (Texas),
and 52.2587(e) (Wisconsin).
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    No amendments with respect to FIP requirements for EGUs would be
made to the state-specific CFR subparts for the twelve states whose
sources currently participate in the Group 3 trading program \343\
except as needed to update cross-references or to implement the
proposed changes related to the treatment of Indian country, as
discussed in Section X.D of this proposed rule.
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    \343\ See proposed Sec. Sec.  52.731(b) (Illinois), 52.789(b)
(Indiana), 52.940(b) (Kentucky), 52.984(d) (Louisiana), 52.1084(b)
(Maryland), 52.1186(e) (Michigan), 52.1584(e) (New Jersey),
52.1684(b) (New York), 52.1882(b) (Ohio), 52.2040(b) (Pennsylvania),
52.2440(b) (Virginia), and 52.2540(b) (West Virginia).
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B. Amendments to Group 3 Trading Program and Related Regulations

    To implement the geographic expansion of the Group 3 trading
program and the revised trading budgets that would be established under
the new and amended FIPs proposed in this rulemaking, several sections
of the Group 3 trading program regulations would be amended. Revisions
identifying the applicable control periods, deadlines for certification
of monitoring systems, and deadlines for commencement of quarterly
reporting for sources not previously covered by the Group 3 trading
program would be made at Sec. Sec.  97.1006(c)(3)(i), 97.1030(b)(1),
and 97.1034(d)(2)(i), respectively. Revisions identifying the proposed
new or revised budgets and new unit set-asides for the 2023 and 2024
control periods for all covered states would be made at Sec.
97.1010(a)(1) and (b)(1), respectively.
    Each of the proposed enhancements to the Group 3 trading program
discussed in Section VII.B of this proposed rule would also be
implemented primarily through revisions to the trading program
regulations. The dynamic budget-setting process discussed in Section
VII.B.4 of this proposed rule would be implemented at Sec.
97.1010(a)(2) and (3), and the associated revised process for
determining variability limits and assurance levels discussed in
Section VII.B.5 of this proposed rule would be implemented at Sec.
97.1010(e). The Group 3 allowance bank recalibration process discussed
in Section VII.B.6 of this proposed rule would be implemented at Sec.
97.1026(d). The backstop daily NOX emissions rate component
of the primary emissions limitation discussed in Section VII.B.7 would
be implemented at Sec. Sec.  97.1006(c)(1)(i) and 97.1024(b)(1) and
(3), accompanied by the addition of a definition of ``backstop daily
NOX emissions rate'' and modification of the definition of
``CSAPR NOX Ozone Season Group 3 allowance'' in Sec.
97.1002. The secondary emissions limitation for sources found
responsible for exceedances of the assurance levels discussed in
Section VII.B.8 of this proposed rule would be implemented at
Sec. Sec.  97.1006(c)(1)(iii) and (iv) and (c)(3)(ii) and 97.1025(c),
accompanied by the addition of a definition of ``CSAPR NOX
Ozone Season Group 3 secondary emissions limitation'' in Sec.  97.1002.
    The proposed changes relating to set-asides, the treatment of
Indian country, unit-level allowance allocations, and recordation
schedules discussed in Section VII.B.9 of this proposed rule would be
implemented through revisions to multiple sections of Sec. Sec.
97.1010, 97.1011, 97.1012, and 97.1021, as well as limited revisions to
97.1002 (definition of ``allocate or allocation'') and 97.1006(b)(2).
In Sec.  97.1010, paragraphs (b), (c), and (d) would address the
amounts for each control period of the new unit set-asides, Indian
country new unit set-asides, and Indian country existing unit set-
asides, respectively. Paragraphs (c) and (d) would reflect the
discontinuation of Indian country new unit set-asides after the 2022
control period and the establishment of Indian

country existing unit set-asides starting with the 2023 control
period.\344\
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    \344\ The current Sec.  97.1011(c), which addresses the
relationships of set-asides and variability limits to state trading
budgets, would be relocated to Sec.  97.1011(f).
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    The proposed revisions to Sec.  97.1011 would refocus the section
exclusively on allocation to ``existing'' units from the portion of
each state emissions budget not reserved in a new unit set-aside or
Indian country new unit set-aside. In Sec.  97.1011(a), the provision
currently in Sec.  97.1011(a)(1) requiring allocations to existing
units to be made in the amounts provided in notices of data
availability (NODAs) issued by the EPA would be split into two separate
provisions, with paragraph (a)(1) applying to existing units in the
state and areas of Indian country covered by the state's CAA
implementation planning authority and paragraph (a)(2) applying to
existing units in areas of Indian country not covered by the state's
CAA implementation planning authority.\345\ This split would facilitate
the submission and approval of SIP revisions by states interested in
submitting state-determined allowance allocations for the units over
which they exercise CAA implementation authority, while leaving
allocations to any units outside their authority to be addressed either
by the EPA or by the relevant tribe under an approved tribal
implementation plan. The proposed dynamic process for determining
default allocations to existing units of allowances from state trading
budgets starting with the 2025 control period would be set forth in
revised Sec.  97.1011(b), while the current provisions of Sec.
97.1011(b), which concern timing and notice procedures for allocations
to new units, would be relocated to Sec.  97.1012. The provisions
addressing incorrectly allocated allowances at Sec.  97.1011(c) would
be streamlined by relocating the portions applicable to new units to
Sec.  97.1012(c). In addition, as discussed in Section VII.B.9.d of
this proposed rule, Sec.  97.1011(c)(5) would be revised to provide