\122\ 2016-centered averaged design values represent the average
of the design values for 2016, 2017, and 2018. Similarly, the
maximum 2016-centered design value is the highest measured design
value from these three design value periods.

  Table V.D-1--Average and Maximum 2016-Centered and 2023 Base Case 8-Hour Ozone Design Values and 2020 Design Values (ppb) at Projected Nonattainment
                                                                       Receptors *
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           2016 centered   2016 centered
             Monitor ID                  State             County             average         maximum      2023 average    2023 maximum        2020
--------------------------------------------------------------------------------------------------------------------------------------------------------
060170010..........................  CA            El Dorado............            85.3              88            76.3            78.7              84
060170020..........................  CA            El Dorado............            82.0              84            74.3            76.2              80
060190007..........................  CA            Fresno...............            87.0              89            80.4            82.2              80
060190011..........................  CA            Fresno...............            90.0              91            82.9            83.8              84
060190242..........................  CA            Fresno...............            84.3              86            79.5            81.1              79
060194001..........................  CA            Fresno...............            90.3              92            82.8            84.4              81
060195001..........................  CA            Fresno...............            91.0              94            83.7            86.4              84
060250005..........................  CA            Imperial.............            76.7              77            76.3            76.6              78
060251003..........................  CA            Imperial.............            76.0              76            75.4            75.4              68
060290007..........................  CA            Kern.................            87.7              89            82.8            84.0              93
060290008..........................  CA            Kern.................            83.0              85            79.1            81.0              85
060290011..........................  CA            Kern.................            83.3              85            78.8            80.4              86
060290014..........................  CA            Kern.................            86.0              88            81.3            83.2              85
060290232..........................  CA            Kern.................            79.3              82            74.9            77.5              83
060292012..........................  CA            Kern.................            89.3              90            84.1            84.7              85
060295002..........................  CA            Kern.................            87.3              89            82.4            84.0              89
060296001..........................  CA            Kern.................            80.7              81            77.1            77.4              82
060311004..........................  CA            Kings................            83.3              84            76.9            77.6              80
060370002..........................  CA            Los Angeles..........            94.3              99            88.0            92.4              97
060370016..........................  CA            Los Angeles..........           100.0             103            93.4            96.2             107
060371201..........................  CA            Los Angeles..........            88.3              91            82.7            85.3              92
060371602..........................  CA            Los Angeles..........            75.7              76            73.6            73.9              78
060371701..........................  CA            Los Angeles..........            92.0              95            85.6            88.4              88
060372005..........................  CA            Los Angeles..........            84.7              86            80.7            81.9              93
060376012..........................  CA            Los Angeles..........            98.0             100            91.6            93.4             101
060379033..........................  CA            Los Angeles..........            87.3              89            80.7            82.2              80
060390004..........................  CA            Madera...............            80.3              83            75.7            78.3              76
060392010..........................  CA            Madera...............            82.7              84            77.0            78.2              78
060430003..........................  CA            Mariposa.............            76.0              79            74.2            77.1              79
060470003..........................  CA            Merced...............            80.7              82            74.7            75.9              76
060570005..........................  CA            Nevada...............            86.3              90            78.1            81.5              82

060592022..........................  CA            Orange...............            77.7              78            72.5            72.8              82
060595001..........................  CA            Orange...............            75.3              76            72.3            73.0              77
060610003..........................  CA            Placer...............            85.0              88            77.1            79.8             N/A
060610004..........................  CA            Placer...............            79.3              85            71.9            77.0             N/A
060610006..........................  CA            Placer...............            80.0              81            72.8            73.7              72
060650008..........................  CA            Riverside............            76.5              79            71.0            73.3             N/A
060650012..........................  CA            Riverside............            95.3              98            85.9            88.3              99
060650016..........................  CA            Riverside............            79.0              80            72.0            72.9              78
060651016..........................  CA            Riverside............            99.7             101            89.8            90.9              99
060652002..........................  CA            Riverside............            82.7              85            76.4            78.5              84
060655001..........................  CA            Riverside............            88.7              91            80.5            82.6              88
060656001..........................  CA            Riverside............            92.3              93            83.5            84.1              94
060658001..........................  CA            Riverside............            96.7              98            89.5            90.7              96
060658005..........................  CA            Riverside............            95.0              98            87.9            90.7              98
060659001..........................  CA            Riverside............            88.7              91            80.8            82.9              87
060670002..........................  CA            Sacramento...........            77.7              78            71.4            71.7              72
060670012..........................  CA            Sacramento...........            82.3              83            74.8            75.4             N/A
060710001..........................  CA            San Bernardino.......            79.0              80            74.5            75.4              81
060710005..........................  CA            San Bernardino.......           110.3             112           100.3           101.8             109
060710012..........................  CA            San Bernardino.......            95.0              98            87.3            90.1              90
060710306..........................  CA            San Bernardino.......            84.0              86            76.8            78.6              83
060711004..........................  CA            San Bernardino.......           105.7             109            97.2           100.2             106
060712002..........................  CA            San Bernardino.......            97.7              99            90.1            91.3             102
060714001..........................  CA            San Bernardino.......            90.3              91            82.6            83.3              87
060714003..........................  CA            San Bernardino.......           104.0             107            95.2            98.0             114
060719002..........................  CA            San Bernardino.......            87.3              89            80.1            81.6              86
060719004..........................  CA            San Bernardino.......           108.7             111            99.5           101.6             110
060731006..........................  CA            San Diego............            83.0              84            76.9            77.9              79
060773005..........................  CA            San Joaquin..........            77.3              79            71.3            72.8              70
060990005..........................  CA            Stanislaus...........            81.0              82            75.4            76.3              79
060990006..........................  CA            Stanislaus...........            83.7              84            77.5            77.8              80
061030004..........................  CA            Tehama...............            79.7              81            72.3            73.4              74
061070006..........................  CA            Tulare...............            84.7              86            79.1            80.3              83
061070009..........................  CA            Tulare...............            89.0              89            82.6            82.6              88
061072002..........................  CA            Tulare...............            82.7              85            75.5            77.6              83
061072010..........................  CA            Tulare...............            84.0              86            77.0            78.8              80
061090005..........................  CA            Tuolumne.............            80.7              83            75.6            77.8              77
080350004..........................  CO            Douglas..............            77.3              78            71.7            72.3              81
080590006..........................  CO            Jefferson............            77.3              78            72.6            73.3              79
080590011..........................  CO            Jefferson............            79.3              80            73.8            74.4              80
080690011..........................  CO            Larimer..............            75.7              77            71.3            72.6              75
090010017..........................  CT            Fairfield............            79.3              80            73.0            73.7              82
090013007..........................  CT            Fairfield............            82.0              83            74.2            75.1              80
090019003..........................  CT            Fairfield............            82.7              83            76.1            76.4              79
090099002..........................  CT            New Haven............            79.7              82            71.8            73.9              80
481671034..........................  TX            Galveston............            75.7              77            71.1            72.3              74
482010024..........................  TX            Harris...............            79.3              81            75.2            76.8              79
482010055..........................  TX            Harris...............            76.0              77            71.0            72.0              76
490110004..........................  UT            Davis................            75.7              78            72.9            75.1              77
490353006..........................  UT            Salt Lake............            76.3              78            73.6            75.3              74
490353013..........................  UT            Salt Lake............            76.5              77            74.4            74.9              73
550590019..........................  WI            Kenosha..............            78.0              79            72.8            73.7              74
551010020..........................  WI            Racine...............            76.0              78            71.3            73.2              73
551170006..........................  WI            Sheboygan............            80.0              81            73.6            74.5              75
--------------------------------------------------------------------------------------------------------------------------------------------------------
* ``N/A'' is used to denote that there is no valid 2020 design value.

 Table V.D-2--Average and Maximum 2016-Centered and 2023 Base Case 8-Hour Ozone Design Values and 2020 Design Values (ppb) at Projected Maintenance-Only
                                                                        Receptors
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                           2016 centered   2016 centered
             Monitor ID                  State             County             average         maximum      2023 average    2023 maximum        2020
--------------------------------------------------------------------------------------------------------------------------------------------------------
040278011..........................  AZ            Yuma.................            72.3              74            70.5            72.2              68
060070007..........................  CA            Butte................            76.7              79            68.9            71.0              73
060090001..........................  CA            Calaveras............            77.0              78            70.9            71.9              72
060371103..........................  CA            Los Angeles..........            73.0              74            70.5            71.5              76
060430006..........................  CA            Mariposa.............            75.0              76            70.1            71.0              79

060675003..........................  CA            Sacramento...........            77.3              79            70.2            71.7              70
060711234..........................  CA            San Bernardino.......            72.3              76            70.6            74.2              76
061112002..........................  CA            Ventura..............            77.3              78            70.9            71.6              77
170310001..........................  IL            Cook.................            73.0              77            69.6            73.4              75
170310032..........................  IL            Cook.................            72.3              75            69.8            72.4              74
170310076..........................  IL            Cook.................            72.0              75            69.3            72.1              69
170314201..........................  IL            Cook.................            73.3              77            69.9            73.4              77
170317002..........................  IL            Cook.................            74.0              77            70.1            73.0              75
320030075..........................  NV            Clark................            75.0              76            70.0            71.0              74
350130021..........................  NM            Dona Ana.............            72.7              74            70.9            72.2              78
350130022..........................  NM            Dona Ana.............            71.3              74            69.5            72.1              74
420170012..........................  PA            Bucks................            79.3              81            70.7            72.2              74
480391004..........................  TX            Brazoria.............            74.7              77            70.1            72.3              73
481210034..........................  TX            Denton...............            78.0              80            70.4            72.2              72
481410037..........................  TX            El Paso..............            71.3              73            69.6            71.3              76
482011034..........................  TX            Harris...............            73.7              75            70.3            71.6              73
482011035..........................  TX            Harris...............            71.3              75            68.0            71.6              70
490450004..........................  UT            Tooele...............            73.5              74            70.8            71.3              69
490570002..........................  UT            Weber................            73.0              75            70.6            72.5             N/A
490571003..........................  UT            Weber................            73.0              74            70.5            71.5              71
550590025..........................  WI            Kenosha..............            73.7              77            69.2            72.3              74
--------------------------------------------------------------------------------------------------------------------------------------------------------

    In total, in the 2023 base case there are a total of 111 receptors
nationwide including 85 nonattainment receptors and 26 maintenance-only
receptors.\123\ Of the 85 nonattainment receptors in 2023, 75 remain
nonattainment receptors while 8 are projected to become maintenance-
only receptors and 2 are projected to be in attainment in 2026. Of the
26 maintenance-only receptors in 2023, 13 are projected to remain
maintenance-only receptors and 13 are projected to be in attainment in
2026. The projected average and maximum design values in 2026 for all
receptors are included in the AQM TSD.
---------------------------------------------------------------------------

    \123\ The EPA's modeling also projects that three monitoring
sites in the Uintah Basin (i.e., monitor 490472003 in Uintah County,
Utah and monitors 490130002 and 490137011 in Duchesne County, Utah)
will have average design values above the NAAQS in 2023. However, as
described in the AQM TSD, the Uinta Basin nonattainment area was
designated as nonattainment for the 2015 ozone NAAQS not because of
an ongoing problem with summertime ozone (as is usually the case in
other parts of the country), but instead because it violates the
ozone NAAQS in winter. The main causes of the Uinta Basin's
wintertime ozone are sources located at low elevations within the
Basin, the Basin's unique topography, and the influence of the
wintertime meteorologic inversions that keep ozone and ozone
precursors near the Basin floor and restrict air flow in the Basin.
Because of the localized nature of the ozone problem at these sites
the EPA has not identified these three monitors as receptors in Step
1 of this proposed rule.
---------------------------------------------------------------------------

E. Pollutant Transport From Upwind States

1. Air Quality Modeling To Quantify Upwind State Contributions
    This section documents the procedures the EPA used to quantify the
impact of emissions from specific upwind states on ozone design values
in 2023 and 2026 for the identified downwind nonattainment and
maintenance receptors. The EPA used CAMx photochemical source
apportionment modeling to quantify the impact of emissions in specific
upwind states on downwind nonattainment and maintenance receptors for
8-hour ozone. CAMx employs enhanced source apportionment techniques
that track the formation and transport of ozone from specific emissions
sources and calculates the contribution of sources and precursors to
ozone for individual receptor locations. The benefit of the
photochemical model source apportionment technique is that all modeled
ozone at a given receptor location in the modeling domain is tracked
back to specific sources of emissions and boundary conditions to fully
characterize culpable sources.
    The EPA performed nationwide, state-level ozone source
apportionment modeling using the CAMx Ozone Source Apportionment
Technology/Anthropogenic Precursor Culpability Analysis (OSAT/APCA)
technique \124\ to quantify the contribution of 2023 and 2026 base case
NOX and VOC emissions from all sources in each state to the
corresponding projected ozone design values in 2023 and 2026 at air
quality monitoring sites. The CAMx OSAT/APCA model run was performed
for the period May 1 through September 30 using the projected future
base case emissions and 2016 meteorology for this time period. As
described earlier, in the source apportionment modeling the Agency
tracked (i.e., tagged) the amount of ozone formed from anthropogenic
emissions in each state individually as well as the contributions from
other sources (e.g., natural emissions).
---------------------------------------------------------------------------

    \124\ As part of this technique, ozone formed from reactions
between biogenic VOC and NOX with anthropogenic
NOX and VOC are assigned to the anthropogenic emissions.
---------------------------------------------------------------------------

    In the state-by-state source apportionment model run, the EPA
tracked the ozone formed from each of the following tags:
     States--anthropogenic NOX and VOC emissions
from each state tracked individually (emissions from all anthropogenic
sectors in a given state were combined);
     Biogenics--biogenic NOX and VOC emissions
domain-wide (i.e., not by state);
     Boundary Concentrations--concentrations transported into
the air quality modeling domain;
     Tribes--the emissions from those tribal lands for which
the Agency has point source inventory data in the 2016v1 emissions
modeling platform (EPA did not model the contributions from individual
tribes);

     Canada and Mexico--anthropogenic emissions from sources in
the portions of Canada and Mexico included in the modeling domain (the
EPA did not model the contributions from Canada and Mexico separately);
     Fires--combined emissions from wild and prescribed fires
domain-wide (i.e., not by state); and
     Offshore--combined emissions from offshore marine vessels
and offshore drilling platforms.

The contribution modeling provided contributions to ozone from
anthropogenic NOX and VOC emissions in each state,
individually. The contributions to ozone from chemical reactions
between biogenic NOX and VOC emissions were modeled and
assigned to the ``biogenic'' category. The contributions from wildfire
and prescribed fire NOX and VOC emissions were modeled and
assigned to the ``fires'' category. That is, the contributions from the
``biogenic'' and ``fires'' categories are not assigned to individual
states nor are they included in the state contributions.
    For the Step 2 analysis, the EPA calculated a contribution metric
that considers the average contribution on the 10 highest ozone
concentration days (i.e., top 10 days) in 2023. This average
contribution metric is intended to provide a reasonable representation
of the contribution from individual states to projected future year
design values, based on modeled transport patterns and other
meteorological conditions generally associated with modeled high ozone
concentrations at the receptor. An average contribution metric
constructed in this manner is beneficial since the magnitude of the
contributions is directly related to the magnitude of the design value
at each site.
    The analytic steps for calculating the contribution metric for the
2023 analytic year are as follows:
    (1) Calculate the 8-hour average contribution from each source tag
to each monitoring site for the time period of the 8-hour daily maximum
modeled concentrations in 2023;
    (2) Average the contributions and average the concentrations for
the top 10 modeled ozone concentration days in 2023;
    (3) Divide the average contribution by the corresponding average
concentration to obtain a Relative Contribution Factor (RCF) for each
monitoring site;
    (4) Multiply the 2023 average design values by the 2023 RCF at each
site to produce the average contribution metric values in 2023.\125\
---------------------------------------------------------------------------

    \125\ Note that a contribution metric value was not calculated
for any receptor at which there were fewer than 5 days with model-
predicted MDA8 ozone concentrations greater than or equal to 60 ppb
in 2023. See the AQM TSD for information on those receptors that did
not meet this criterion.
---------------------------------------------------------------------------

    This same approach was applied to calculate contribution metric
values at individual monitoring sites for 2026.\126\
---------------------------------------------------------------------------

    \126\ In order to provide consistency in the contributions for
2023 and 2026, the contribution metric values for 2026 are based on
the 2026 daily contributions for the same days that were used to
calculate the contribution metric values for 2023.
---------------------------------------------------------------------------

    The resulting contributions from each tag to each monitoring site
in the U.S. for 2023 and 2026 can be found in the docket for this
proposed rule. Additional details on the source apportionment modeling
and the procedures for calculating contributions can be found in the
AQM TSD.
    The largest contribution from each state that is the subject of
this rule to 8-hour ozone nonattainment and maintenance receptors in
downwind states in 2023 and 2026 are provided in Table V.E.1-1 and
Table V.E.1-2, respectively.

      Table V.E.1-1--Largest Contribution to Downwind 8-Hour Ozone
          Nonattainment and Maintenance Receptors in 2023 (ppb)
------------------------------------------------------------------------
                                                              Largest
                                              Largest      contribution
                                           contribution     to downwind
              Upwind state                  to downwind    maintenance-
                                           nonattainment       only
                                             receptors       receptors
------------------------------------------------------------------------
Alabama.................................            0.88            0.71
Arizona.................................            0.40            0.21
Arkansas................................            1.00            1.39
California..............................           34.24            7.44
Colorado................................            0.07            0.20
Connecticut.............................            0.01            0.21
Delaware................................            0.53            1.36
District of Columbia....................            0.04            0.07
Florida.................................            0.16            0.15
Georgia.................................            0.16            0.17
Idaho...................................            0.55            0.57
Illinois................................           18.13           18.55
Indiana.................................            6.60            7.10
Iowa....................................            0.64            0.58
Kansas..................................            0.42            0.59
Kentucky................................            0.83            0.88
Louisiana...............................            5.39            7.03
Maine...................................            0.01            0.01
Maryland................................            1.29            2.40
Massachusetts...........................            0.30            0.30
Michigan................................            1.27            1.67
Minnesota...............................            0.50            0.97
Mississippi.............................            1.04            1.14
Missouri................................            1.08            1.66
Montana.................................            0.08            0.11
Nebraska................................            0.26            0.36
Nevada..................................            0.89            0.58
New Hampshire...........................            0.10            0.06
New Jersey..............................            8.85            5.79

New Mexico..............................            0.30            0.13
New York................................           16.81            1.80
North Carolina..........................            0.61            0.33
North Dakota............................            0.12            0.37
Ohio....................................            1.94            1.88
Oklahoma................................            0.57            1.19
Oregon..................................            1.10            1.31
Pennsylvania............................            6.90            0.51
Rhode Island............................            0.04            0.04
South Carolina..........................            0.19            0.07
South Dakota............................            0.05            0.09
Tennessee...............................            0.60            0.94
Texas...................................            1.72            1.81
Utah....................................            1.37            0.10
Vermont.................................            0.02            0.02
Virginia................................            1.77            1.63
Washington..............................            0.34            0.40
West Virginia...........................            1.45            1.44
Wisconsin...............................            0.19            2.61
Wyoming.................................            0.81            0.19
------------------------------------------------------------------------

      Table V.E.1-2--Largest Contribution to Downwind 8-Hour Ozone
          Nonattainment and Maintenance Receptors in 2026 (ppb)
------------------------------------------------------------------------
                                                              Largest
                                              Largest      contribution
                                           contribution     to downwind
              Upwind state                  to downwind    maintenance-
                                           nonattainment       only
                                             receptors       receptors
------------------------------------------------------------------------
Alabama.................................            0.17            0.48
Arizona.................................            0.35            0.23
Arkansas................................            0.62            1.30
California..............................           33.45            4.85
Colorado................................            0.05            0.08
Connecticut.............................            0.01            0.01
Delaware................................            0.42            0.52
District of Columbia....................            0.03            0.04
Florida.................................            0.10            0.09
Georgia.................................            0.14            0.16
Idaho...................................            0.48            0.48
Illinois................................           17.81           18.14
Indiana.................................            6.43            6.99
Iowa....................................            0.57            0.57
Kansas..................................            0.40            0.57
Kentucky................................            0.80            0.80
Louisiana...............................            4.25            6.97
Maine...................................            0.01            0.01
Maryland................................            1.11            1.23
Massachusetts...........................            0.29            0.14
Michigan................................            1.03            1.58
Minnesota...............................            0.36            0.91
Mississippi.............................            0.36            0.90
Missouri................................            0.98            1.53
Montana.................................            0.07            0.08
Nebraska................................            0.11            0.23
Nevada..................................            0.81            0.51
New Hampshire...........................            0.09            0.02
New Jersey..............................            8.54            5.47
New Mexico..............................            0.29            0.23
New York................................           16.58           11.29
North Carolina..........................            0.38            0.54
North Dakota............................            0.11            0.34
Ohio....................................            1.78            1.83
Oklahoma................................            0.54            0.72

Oregon..................................            0.98            0.88
Pennsylvania............................            6.82            4.74
Rhode Island............................            0.04            0.01
South Carolina..........................            0.15            0.17
South Dakota............................            0.03            0.06
Tennessee...............................            0.25            0.34
Texas...................................            1.61            1.70
Utah....................................            0.95            1.18
Vermont.................................            0.02            0.01
Virginia................................            1.14            1.68
Washington..............................            0.31            0.28
West Virginia...........................            1.23            1.35
Wisconsin...............................            0.15            2.44
Wyoming.................................            0.46            0.80
------------------------------------------------------------------------

2. Application of Contribution Screening Threshold
    The EPA evaluated the magnitude of the contributions from each
upwind state to downwind nonattainment and maintenance receptors. In
Step 2 of the interstate transport framework, the EPA uses an air
quality screening threshold to identify upwind states that contribute
to downwind ozone concentrations in amounts sufficient to ``link'' them
to these to downwind nonattainment and maintenance receptors. The
contributions from each state to each downwind nonattainment or
maintenance receptor that were used for the Step 2 evaluation can be
found in the AQM TSD.
    The EPA proposes to apply an air quality screening threshold of 1
percent of the NAAQS, as it has used since the CSAPR rulemaking,
including in the CSAPR Update, the Revised CSAPR Update, and numerous
actions evaluating states' transport SIP submittals. EPA continues to
observe that the majority of nonattainment and maintenance receptors
identified at Step 1 are impacted collectively by contributions of
ozone transport from numerous upwind states. Therefore, application of
a uniform screening threshold allows EPA to identify upwind states that
share a responsibility under the interstate transport provision to
eliminate their significant contribution.
    The EPA recognizes that in 2018 it issued a memorandum indicating
the potential for states to use a higher threshold at Step 2 in the
development of their good neighbor SIP submissions where it could be
technically justified. The August 2018 memorandum stated that ``it may
be reasonable and appropriate'' for states to rely on an alternative 1
ppb threshold at Step 2.\127\ (The memorandum also indicated that any
higher alternative threshold, such as 2 ppb, would likely not be
appropriate.) Here, the EPA proposes to fulfill its role under CAA
section 110(c) in promulgating FIPs to directly implement good neighbor
requirements, and in this role, the EPA notes that it is authorized to
exercise discretion in making policy determinations such as the
appropriateness of a particular contribution threshold that would
otherwise have been exercised by states. Further, as the EPA has
explained in several notices proposing transport SIP disapprovals, see,
e.g., 87 FR 9498 and 87 FR 9510 (Feb. 22, 2022), its experience since
the issuance of the August 2018 memorandum regarding use of alternative
thresholds leads the Agency to now believe it may not be appropriate to
continue to attempt to recognize alternative contribution thresholds at
Step 2, either in the context of SIPs or FIPs.
---------------------------------------------------------------------------

    \127\ August 2018 memo at 4.
---------------------------------------------------------------------------

    EPA's experience since 2018 is that allowing for alternative Step 2
thresholds may be impractical or otherwise inadvisable for a number of
additional policy reasons. For a regional air pollutant such as ozone,
consistency in requirements and expectations across all states is
essential. In the context of a FIP proposal (as much as in the context
of SIP actions), the Agency now believes using different thresholds at
Step 2 with respect to the 2015 ozone NAAQS raises substantial policy
consistency and practical implementation concerns.\128\ The
availability of different thresholds at Step 2 has the potential to
result in inconsistent application of good neighbor obligations. From
the perspective of ensuring effective regional implementation of good
neighbor obligations, the more important analysis is the evaluation of
the emissions reductions needed, if any, to address a state's
significant contribution after consideration of a multifactor analysis
at Step 3, including a detailed evaluation that considers air quality
factors and cost. Where alternative thresholds for purposes of Step 2
may be ``similar'' in terms of capturing the relative amount of upwind
contribution (as described in the August 2018 memorandum), nonetheless,
use of an alternative threshold would allow certain states to avoid
further evaluation of potential emissions controls while other states
must proceed to a Step 3 analysis. This can create significant equity
and consistency problems among states.
---------------------------------------------------------------------------

    \128\ We note that Congress has placed on the EPA a general
obligation to ensure the requirements of the CAA are implemented
consistently across states and regions. See CAA section 301(a)(2).
Where the management and regulation of interstate pollution levels
spanning many states is at stake, consistency in application of CAA
requirements is paramount.
---------------------------------------------------------------------------

    More importantly, in promulgating FIPs to address these obligations
on a nationwide scale, national ozone transport policy is not well-
served by allowing for less stringent thresholds at Step 2. The EPA
recognized in the August 2018 memo that there was some similarity in
the amount of total upwind contribution captured (on a nationwide
basis) between 1 percent and 1 ppb. However, the EPA notes that while
this

may be true in some sense, that is hardly a compelling basis to move to
a 1 ppb threshold. Indeed, the 1 ppb threshold has the disadvantage of
losing a certain amount of total upwind contribution for further
evaluation at Step 3 (e.g., roughly 7 percent of total upwind state
contribution was lost according to the modeling underlying the August
2018 memo; \129\ in EPA's updated modeling, the amount lost is roughly
5 percent). Considering the core statutory objective of ensuring
elimination of all significant contribution to nonattainment or
interference of the NAAQS in other states and the broad, regional
nature of the collective contribution problem with respect to ozone,
there does not appear to be a compelling policy imperative in moving to
a 1 ppb threshold.
---------------------------------------------------------------------------

    \129\ See August 2018 memo, at 4.
---------------------------------------------------------------------------

    Consistency with past interstate transport actions such as CSAPR,
and the CSAPR Update and Revised CSAPR Update rulemakings (which used a
Step 2 threshold of 1 percent of the NAAQS for two less stringent ozone
NAAQS) is also important. Continuing to use a 1 percent of NAAQS
approach ensures that as the NAAQS are revised and made more stringent,
an appropriate increase in stringency at Step 2 occurs, so as to ensure
an appropriately larger amount of total upwind-state contribution is
captured for purposes of fully addressing interstate transport for the
more stringent NAAQS. EPA made this point when it originally
promulgated CSAPR to address the 1997 ozone NAAQS. The Agency continues
to consider this an important consideration for the more stringent 2015
ozone NAAQS. See 76 FR 48237-38.
    Lastly, the Agency does not find it to be a good use of limited
resources to attempt to further justify the use of alternative
thresholds for certain states at Step 2 for purposes of the 2015 ozone
NAAQS. Therefore, while EPA articulated a potential basis for
recognizing the usefulness of alternative Step 2 thresholds
(particularly a 1 ppb threshold) in the August 2018 memorandum, EPA's
experience and further evaluation since the issuance of that memo has
revealed substantial programmatic and policy difficulties in attempting
to implement this approach. Depending on comment and further evaluation
of this issue, the EPA may determine to rescind the 2018 memorandum in
the future.
    In light of the considerations above, EPA proposes using a
contribution threshold of 0.70 ppb as the quantification of 1 percent
of the 2015 ozone NAAQS for purposes of Step 2.
a. States That Contribute Below the Screening Threshold
    Based on EPA's modeling, the contributions from each of the
following states to nonattainment or maintenance-only receptors in the
2023 analytic year are below the 1% of the NAAQS threshold: Arizona,
Colorado, Connecticut, the District of Columbia, Florida, Georgia,
Idaho, Iowa, Kansas, Maine, Massachusetts, Montana, Nebraska, New
Hampshire, New Mexico, North Carolina, North Dakota, Rhode Island,
South Carolina, South Dakota, Vermont, and Washington. The EPA has
already approved many of these states' SIP submittals or is in the
process of taking action to approve them. Because the contributions
from these states to projected downwind air quality problems are below
the screening threshold in the current modeling, these states are not
within the scope of this proposed rule. Additionally, the EPA has made
proposed or final determinations that two states outside the modeling
domain for the air quality modeling analyzed in this proposed
rulemaking--Hawaii \130\ and Alaska \131\--do not significantly
contribute to nonattainment or interfere with maintenance of the NAAQS
in any other state.
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    \130\ The EPA proposed to approve Hawaii's 2015 ozone transport
SIP on September 28, 2021. See 86 FR 53571.
    \131\ The EPA approved Alaska's 2015 ozone transport SIP on
December 18, 2019. See 84 FR 69331.
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a. States That Contribute at or Above the Screening Threshold
    Based on the maximum downwind contributions in Table V.E.1-1, the
Step 2 analysis identifies that the following 22 states contribute at
or above the 0.70 ppb threshold to downwind nonattainment receptors in
2023: Alabama, Arkansas, California, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Michigan, Mississippi, Missouri, Nevada, New
Jersey, New York, Ohio, Oregon, Pennsylvania, Texas, Utah, Virginia,
West Virginia, and Wyoming. Based on the maximum downwind contributions
in Table V.E.1-1, the following 23 states contribute at or above the
0.70 ppb threshold to downwind maintenance-only receptors in 2023:
Alabama, Arkansas, California, Delaware, Illinois, Indiana, Kentucky,
Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New
Jersey, New York, Ohio, Oklahoma, Oregon, Tennessee, Texas, Virginia,
West Virginia, and Wisconsin. The levels of contribution between each
of these linked upwind states and downwind nonattainment receptors and
maintenance-only receptors are provided in the AQM TSD.
    Among the linked states are several western states--California,
Nevada, Oregon, Utah, and Wyoming. While the EPA has not previously
included action on linked western states in its prior CSAPR
rulemakings, the EPA has consistently applied the 4-step framework in
evaluating good neighbor obligations from these states. On a case-by-
case basis, the EPA has found in some instances with respect to the
2008 ozone NAAQS that a unique consideration has warranted approval of
a linked western state's good neighbor SIP submittal without concluding
that additional emissions reductions are required at Step 3 of the
framework.\132\ The EPA has also explained in prior actions that its
air quality modeling is reliable for assessing downwind air quality
problems and ozone transport contributions from upwind states
throughout the nationwide modeling domain.\133\
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    \132\ See interstate transport approval actions under the 2008
ozone NAAQS for Arizona, California, and Wyoming at 81 FR 36179
(June 6, 2016), 83 FR 65093 (December 19, 2018), and 84 FR 14270
(April 10, 2019), respectively.
    \133\ See 81 FR 71991 (October 19, 2016), 82 FR 9155 (February
3, 2017).
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    In EPA's current analysis, the EPA finds that for one linked
state--Oregon--the same considerations that led it to approve another
state's SIP submission, Arizona's, for the 2008 ozone NAAQS apply to
Oregon's circumstances for the 2015 ozone NAAQS. As explained in the
following section, the EPA therefore proposes to affirm its prior
approval of Oregon's good neighbor SIP submission for the 2015 ozone
NAAQS. For the remaining western states included in this proposed rule,
EPA's modeling supports a conclusion that these states are linked above
the contribution threshold to identified ozone transport receptors in
other states, and therefore, consistent with the treatment of all other
states within the modeling domain, the EPA proposes to proceed to
evaluate these states for a determination of ``significant
contribution'' at Step 3.
    In conclusion, as described above, states with contributions that
equal or exceed 1 percent of the NAAQS to either nonattainment or
maintenance receptors are identified as ``linked'' at Step 2 of the
good neighbor framework and warrant further analysis for significant
contribution to nonattainment or interference with

maintenance under Step 3. The EPA proposes that the following 27 States
are linked at Step 2 in 2023: Alabama, Arkansas, California, Delaware,
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota,
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma,
Oregon, Pennsylvania, Tennessee, Texas, Utah, Virginia, West Virginia,
Wisconsin, and Wyoming. In addition, the EPA proposes that the
following 24 States are linked at Step 2 in 2026: Arkansas, California,
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, Minnesota,
Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma,
Oregon, Pennsylvania, Texas, Utah, Virginia, West Virginia, Wisconsin,
and Wyoming. Three states, Alabama, Delaware, and Tennessee, that were
linked in 2023 are not linked in 2026 because the receptor(s) to which
each state was linked in 2023 are projected to attain by 2026.

F. Treatment of Certain Receptors in California and Implications for
Oregon's Good Neighbor Obligations for the 2015 Ozone NAAQS

    The EPA previously approved Oregon's September 25, 2018 transport
SIP submittal for the 2015 ozone NAAQS on May 17, 2019 (84 FR 22376),
because in an earlier round of modeling Oregon was not projected to
contribute above 1 percent of the NAAQS to any downwind receptors. In
EPA's updated modeling, Oregon is linked above the 1 percent of NAAQS
threshold to several monitoring sites in California that would
generally meet EPA's definition of nonattainment or maintenance
``receptors'' at Step 1.\134\ However, EPA's analysis of the nature of
the air quality problem at these monitoring sites leads EPA to propose
a determination that these monitoring sites should not be treated as
receptors for purposes of determining interstate transport obligations
of upwind states under CAA section 110(a)(2)(D)(i)(I). EPA reaches this
conclusion at Step 1 of its four-step framework.
---------------------------------------------------------------------------

    \134\ Monitors are listed in the AQM TSD included in the docket
for this rulemaking. While EPA is providing information about
cumulative upwind contribution to the California monitors, the
Agency does not consider these monitors as ozone transport receptors
in this proposal.
---------------------------------------------------------------------------

    The EPA previously made a similar assessment of the nature of
certain other monitoring sites in California in approving Arizona's
2008 ozone NAAQS transport SIP submittal.\135\ There, the EPA noted
that a ``factor [. . .] relevant to determining the nature of a
projected receptor's interstate transport problem is the magnitude of
ozone attributable to transport from all upwind states collectively
contributing to the air quality problem.'' \136\ The EPA observed that
only one upwind state (Arizona) was linked above 1 percent of the 2008
ozone NAAQS to the two relevant monitoring sites in California, and the
cumulative ozone contribution from all upwind states to those sites was
2.5 percent and 4.4 percent of the total ozone, respectively. The EPA
determined the size of those cumulative upwind contributions was
``negligible, particularly when compared to the relatively large
contributions from upwind states in the East or in certain other areas
of the West.'' \137\ In that action, the EPA concluded the two
California sites to which Arizona was linked should not be treated as
receptors for the purposes of determining Good Neighbor obligations for
the 2008 ozone NAAQS.\138\
---------------------------------------------------------------------------

    \135\ 81 FR 15200 (March 22, 2016) (proposal); 81 FR 31513 (May
19, 2016) (final rule).
    \136\ 81 FR at 15203.
    \137\ Id.
    \138\ Id.
---------------------------------------------------------------------------

    The EPA proposes to make a similar finding for the monitoring sites
in California otherwise projected in its current modeling to be
``receptors'' for the 2015 ozone NAAQS and to which Oregon is linked.
The highest percent of the total cumulative upwind ozone contribution
to any of these sites is 2.8 percent.\139\ This is lower than the
largest transport contribution relative to total ozone at the
California sites identified in EPA's approval of Arizona's 2008 ozone
transport SIP (4.4 percent).\140\ Further, as was the case for the
sites in California analyzed in EPA's Arizona action, the identified
sites in California each have only one upwind state contributing above
1 percent of the NAAQS to them (Oregon). These monitoring sites in
California are overwhelmingly impacted by in-state emissions to a
degree not comparable with any other identified nonattainment or
maintenance-only receptors in the country.
---------------------------------------------------------------------------

    \139\ See Air Quality Modeling TSDin the docket for this action.
    \140\ 81 FR at 15203; 81 FR 31513.
---------------------------------------------------------------------------

    The EPA proposes to find that these monitoring sites should not be
considered receptors for the purpose of assessing 2015 ozone NAAQS
interstate transport obligations. The EPA is not proposing a different
contribution threshold at Step 2 for Western states or receptors, nor
does the EPA reach its conclusion based on any evaluation at Step 3 of
emissions reduction opportunities in Oregon.
    As a consequence of this proposed finding, the EPA continues to
find that ozone-precursor emissions from Oregon do not significantly
contribute to nonattainment or interfere with maintenance of the NAAQS
in any downwind state, because the total collective upwind state ozone
contribution to the California monitoring sites is extremely low
compared to the air quality problems typically addressed under the good
neighbor provision. Therefore, the EPA is not proposing any change in
this action to its prior approval of Oregon's SIP. The EPA is not
proposing any new FIP requirements and is not proposing to require
reductions from new or existing EGU or non-EGU sources in Oregon in
this action. If, however, EPA were not to finalize this proposed
approach, then EPA anticipates that it would apply the same control
strategies in Oregon as applied in all other linked upwind states, as
discussed in Sections VI and VII of this proposed rule. EPA requests
public comment on its approach to characterizing the nature of the
interstate transport problem at the California monitoring sites at
issue and the consequent approach to assessing Oregon's good neighbor
obligations.

VI. Quantifying Upwind-State NOX Emissions Reduction Potential To
Reduce Interstate Ozone Transport for the 2015 Ozone NAAQS

A. The Multi-Factor Test for Determining Significant Contribution

    This section describes EPA's methodology at Step 3 of the 4-step
framework for identifying upwind emissions that constitute
``significant'' contribution for the states subject to this proposed
rule and focuses on the 26 states with FIP requirements identified in
the sections above. Following the existing framework as applied in all
of the prior CSAPR rulemakings, EPA's assessment of linked upwind state
emissions is based primarily on analysis of several alternative levels
of NOX emissions control stringency applied uniformly across
all of the linked states. The analysis includes assessment of non-EGU
stationary sources in addition to EGU sources in the linked upwind
states.
    The EPA applies a multi-factor test--the same multi-factor test
that was used in CSAPR, the CSAPR Update, and the Revised CSAPR Update
\141\--to evaluate increasing levels of uniform NOX control
stringency. The multi-factor test, which is central to EPA's Step 3

quantification of significant contribution, considers cost, available
emissions reductions, downwind air quality impacts, and other factors
to determine the appropriate level of uniform NOX control
stringency that would eliminate significant contribution to downwind
nonattainment or maintenance receptors. The selection of a uniform
level of NOX emissions control stringency across all of the
linked states, reflected as a representative cost per ton of emissions
reduction (or a weighted average cost per ton in the case of EPA's non-
EGU and EGU analysis for 2026 mitigation measures), also serves to
apportion the reduction responsibility among collectively contributing
upwind states. This approach to quantifying upwind state emission-
reduction obligations using uniform cost was reviewed by the Supreme
Court in EME Homer City Generation, which held that using such an
approach to apportion emissions reduction responsibilities among upwind
states that are collectively responsible for downwind air quality
impacts ``is an efficient and equitable solution to the allocation
problem the Good Neighbor Provision requires the Agency to address.''
572 U.S. at 519.
---------------------------------------------------------------------------

    \141\ See CSAPR, Final Rule, 76 FR 48208 (August 8, 2011).
---------------------------------------------------------------------------

    There are four stages in developing the multi-factor test: (1)
Identify levels of uniform NOX control stringency; (2)
evaluate potential NOX emissions reductions associated with
each identified level of uniform control stringency; (3) assess air
quality improvements at downwind receptors for each level of uniform
control stringency; and (4) select a level of control stringency
considering the identified cost, available NOX emissions
reductions, and downwind air quality impacts, while also ensuring that
emissions reductions do not unnecessarily over-control relative to the
contribution threshold or downwind air quality.
    As mentioned in Section IV.A.2 of this proposed rule, commenters on
previous ozone transport rules have suggested that the EPA should
regulate VOCs as an ozone precursor. For this proposed rule, the EPA
examined the results of the contribution modeling performed for this
rule to identify the portion of the ozone contribution attributable to
anthropogenic NOX emissions versus VOC emissions from each
linked upwind state to each downwind receptor. Of the total upwind-
downwind linkages in 2023, the contributions from NOX
emissions comprise 80 percent or more of the total anthropogenic
contribution at the vast majority of linkages (136 out of 140 total).
Across all receptors, the contribution from NOX emissions
ranges from 77 percent to 99 percent of the total anthropogenic
contribution. This review of the portion of the ozone contribution
attributable to anthropogenic NOX emissions versus VOC
emissions from each linked upwind state leads the Agency to conclude
that the vast majority of the downwind air quality areas addressed by
the proposed rule under are primarily NOX-limited, rather
than VOC-limited. Therefore, the EPA is proposing to determine that the
regulation of VOCs as an ozone precursor is not necessary to eliminate
significant contribution of ozone transport to downwind areas in this
proposed rule. The remainder of this section focuses on EPA's strategy
for reducing regional-scale transport of ozone by targeting
NOX emissions from stationary sources to achieve the most
effective reductions of ozone transport over the geography of the
affected downwind areas.
    For both EGUs and non-EGUs, Section VI.B of this proposed rule
describes the available NOX emissions controls that the EPA
evaluated for this proposed rule and their representative cost levels
(in 2016$). Section VI.C of this proposed rule discusses EPA's
application of that information to assess emissions reduction potential
of the identified control stringencies. Finally, Section VI.D of this
proposed rule describes EPA's assessment of associated air quality
impacts and EPA's subsequent identification of appropriate control
stringencies considering the key relevant factors (cost, available
emissions reductions, and downwind air quality impacts).
    This multi-factor approach is consistent with EPA's approach in
prior transport actions, such as CSAPR. In addition, as was evaluated
in the CSAPR Update and Revised CSAPR Update, the EPA evaluated
possible over-control by examining whether an upwind state is linked
solely to downwind air quality problems that could have been resolved
at a lesser threshold of control stringency and whether an upwind state
could reduce its emissions below the 1 percent air quality contribution
threshold at a lesser threshold of control stringency. This analysis is
described in Section VI.D of this proposed rule.
    Finally, while the EPA has evaluated potential emissions reductions
from non-EGU sources in prior rules, this is the first action for which
the EPA is proposing non-EGU emissions reductions within the context of
its 4-step interstate transport framework. The EPA applies its multi-
factor test to non-EGUs and independently evaluates non-EGU industries
in a consistent but parallel track to its Step 3 assessment for EGUs.
This is consistent with the parallel assessment approach taken for EGUs
and non-EGUs in the Revised CSAPR Update. Following the conclusions of
the EGU and non-EGU multi-factor tests, the identified reductions for
EGUs and non-EGUs are combined and collectively analyzed to assess
their effects on downwind air quality and whether the rule achieves a
full remedy to ``significant contribution'' while avoiding over-
control.
    In order to ensure that this rule implements a full remedy for the
elimination of significant contribution from upwind states, the EPA has
reviewed available information on all major industrial source sectors
in the upwind states. This analysis leads the EPA to propose that both
EGUs and certain large sources in several specific industrial
categories should be evaluated for emissions control opportunities. As
discussed in the sections that follow, the EPA proposes that for both
EGUs and the selected non-EGU source categories, there are impactful
emissions reduction opportunities available at reasonable cost-
effectiveness thresholds. As in the Revised CSAPR Update, the EPA
examines EGUs and non-EGUs in this section on consistent but distinct,
parallel tracks due to differences stemming from the unique
characteristics of the power sector compared to other industrial source
categories. Since the NOX SIP Call, EGUs have consistently
been regulated under ozone transport rules. These units operate in a
coordinated manner across a highly interconnected electrical grid.
Their configuration and emissions control strategies are relatively
homogenous, and their emissions levels and emissions control
opportunities are generally very well understood due to longstanding
monitoring and data-reporting requirements. Non-EGU sources, by
contrast, are relatively heterogeneous, even within a single industrial
category, and have far greater variation in existing emissions control
requirements, emissions levels, and technologies to reduce emissions.
In general, despite these differences, the information available for
this proposal indicates that both EGUs and certain non-EGU categories
have available cost-effective NOX emissions reduction
opportunities at relatively commensurate cost per ton levels, and these
emissions reductions will make a meaningful improvement in air quality

at the downwind receptors. Section VI.B.2 of this proposed rule
describes EPA's process for selecting specific Tier I and Tier II non-
EGU source categories included in this proposed rulemaking.
    The EPA notes that its Step 3 analysis does not assess emissions
reduction opportunities from mobile sources. The EPA continues to
believe that title II of the CAA provides the primary authority and
process for reducing ozone-precursor pollutants from mobile sources.
EPA's federal mobile source programs have delivered and are projected
to continue to deliver substantial nationwide reductions in both VOCs
and NOX emissions; these reductions are factored into the
Agency's assessment of air quality and contributions at Steps 1 and 2.
Further, states are generally preempted from regulating new vehicles
and engines with certain exceptions, and therefore a question exists
regarding EPA's authority to address such emissions when regulating in
place of the states under CAA section 110(c). See generally CAA
sections 209, 177. See also 86 FR 23099. As noted earlier, the EPA
accounted for mobile source emissions reductions resulting from other
federally enforceable regulatory programs in the development of
emissions inventories used to support analysis for this proposed
rulemaking, and the EPA does not evaluate any mobile source control
measures in its Step 3 evaluation in this proposal.\142\ For further
discussion of EPA's existing and ongoing mobile source measures, see
Section VI.B.4 of this proposed rule.
---------------------------------------------------------------------------

    \142\ The EPA recognizes that mechanisms exist under title I of
the CAA that allow for the regulation of the use and operation of
mobile sources to reduce ozone-precursor emissions. These include
motor vehicle inspection and maintenance (I/M) programs, gasoline
vapor recovery, clean-fuel vehicle programs, transportation control
programs, and vehicle miles traveled programs. See, e.g., CAA
sections 182(b)(3), 182(b)(4), 182(c)(3), 182(c)(4), 182(c)(5),
182(d)(1), 182(e)(3), and 182(e)(4). The EPA views these programs as
most effective and appropriate in the context of the planning
requirements applicable to designated nonattainment areas.
---------------------------------------------------------------------------

B. Identifying Control Stringency Levels

1. EGU NOX Mitigation Strategies
    In identifying levels of uniform control stringency for EGUs, the
EPA assessed the same NOX emissions controls that the Agency
analyzed in the CSAPR Update and the Revised CSAPR Update, all of which
are considered to be widely available in this sector: (1) Fully
operating existing SCR, including both optimizing NOX
removal by existing operational SCRs and turning on and optimizing
existing idled SCRs; (2) installing state-of-the-art NOX
combustion controls; (3) fully operating existing SNCRs, including both
optimizing NOX removal by existing operational SNCRs and
turning on and optimizing existing idled SNCRs; (4) installing new
SNCRs; (5) installing new SCRs; and (6) generation shifting (i.e.,
emission reductions anticipated to occur from generation shifting from
higher to lower emitting units at each of these stringency levels). For
the reasons explained in the EGU NOX Mitigation Strategies
Proposed Rule TSD included in the docket for this proposed rule, the
EPA determined that for the regional, multi-state scale of this
rulemaking, only EGU NOX emissions controls 1, 3, and 6 are
possible for the 2023 ozone season (fully operating existing SCRs and
SNCRs, and associated generation shifting). The EPA finds that it is
not possible to install state-of-the-art NOX combustion
controls by the 2023 ozone season on a regional scale for Group 3
states not covered under the Revised CSAPR Rule. The EPA also
determined that state-of-the-art NOX combustion controls at
EGUs are available by the beginning of the 2024 ozone season. All cost
values discussed below for EGUs are in 2016 dollars.
a. Optimizing Existing SCRs
    Optimizing (i.e., turning on idled or improving operation of
partially operating) existing SCRs can substantially reduce EGU
NOX emissions quickly, using investments that have already
been made in pollution control technologies. With the promulgation of
the CSAPR Update and the Revised CSAPR Update, most operators in the
covered states improved their SCR performance and have continued to
maintain that level of improved operation. However, this optimized SCR
performance was not universal and not always sustained. Between 2017
and 2020, as the CSAPR Update ozone-season NOX allowance
price declined, NOX emissions rates at some SCR-controlled
EGUs increased. For example, power sector data from 2019 revealed that,
in some cases, operating units had SCR controls that had been idled or
were operating partially, and therefore suggested that there remained
emissions reduction potential through optimization.\143\ The EPA
determined that optimizing all of these remaining SCRs in the 12 linked
states for the Revised CSAPR Update was a readily available approach
for EGUs to reduce NOX emissions. This emissions reduction
measure is currently available at EGUs across the broader geography
affected in this proposed rulemaking (including in states not
previously affected by the Revised CSAPR Update). The EPA thus proposes
that SCR optimization, of both idled and partially operating controls,
is a viable mitigation strategy for the 2023 ozone season.
---------------------------------------------------------------------------

    \143\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason.
---------------------------------------------------------------------------

    The EPA estimates a representative marginal cost of optimizing SCR
controls to be approximately $1,600 per ton, consistent with its
estimation in the Revised CSAPR Update for this technology. EPA's EGU
NOX Mitigation Strategies Proposed Rule TSD for this rule
describes a range of cost estimates for this technology noting that the
costs are frequently lower than--and for the majority of EGUs,
significantly lower than--this representative marginal cost. While the
costs of optimizing existing, operational SCRs include only variable
costs, the cost of optimizing SCR units that are currently idled
considers both variable and fixed costs of returning the control into
service. Variable and fixed costs include labor, maintenance and
repair, parasitic load, and ammonia or urea for use as a NOX
reduction reagent in SCR systems. Depending on a unit's control
operating status, the representative cost at the 90th percentile unit
(among the relevant fleet of coal units with SCR covered in this
rulemaking) ranges between $900 and $1,700 per ton. The EPA performed
an in-depth cost assessment for all coal-fired units with SCRs and
found that for the subset of SCRs that are already partially operating,
the cost of optimizing is often much lower than $1,600 per ton and is
often under $900 per ton. The EPA anticipates the vast majority of
realized cost for compliance with this strategy to be better reflected
by the $900 per ton end of that range (reflecting the 90th percentile
of EGUs optimizing SCRs that are already partially operating) because
this circumstance is considerably more common than EGUs that have
ceased operating their SCR. EPA's analysis of this emissions control is
informed by the latest engineering modeling equations used in EPA's IPM
platform. These cost and performance equations were recently updated in
the summer of 2021. The description and development of the equations
are documented in EGU NOX Mitigation Strategies Proposed
Rule TSD and accompanying documents.\144\ They are also

implemented in an interactive spreadsheet tool called the Retrofit Cost
Analyzer and applied to all units in the fleet. These materials are
available in the docket for this proposal.
---------------------------------------------------------------------------

    \144\ The CSAPR Update estimated $1,400 per ton as a
representative cost of turning on idled SCR controls. EPA used the
same costing methodology while updating for input cost increases
(e.g., urea reagent) to arrive at $1,600 per ton in the final
Revised CSAPR Update (while also updating from 2011 dollars to 2016
dollars).
---------------------------------------------------------------------------

    The EPA is using the same methodology to identify SCR performance
as it did in the Revised CSAPR Update. To estimate EGU NOX
reduction potential from optimizing, the EPA considers the difference
between the non-optimized NOX emissions rates and an
achievable operating and optimized SCR NOX emissions rate.
To determine this rate, EPA evaluated nationwide coal-fired EGU
NOX ozone season emissions data from 2009 through 2019 and
calculated an average NOX ozone season emissions rate across
the fleet of coal-fired EGUs with SCR for each of these eleven years.
The EPA found it prudent to not consider the lowest or second-lowest
ozone season NOX emissions rates, which may reflect SCR
systems that have all new components (e.g., new layers of catalyst).
Data from these systems are potentially not representative of ongoing
achievable NOX emissions rates considering broken-in
components and routine maintenance schedules. To identify the potential
reductions from SCR optimization in this proposed rule, the EPA
followed the same methodology as the Revised CSAPR Update. Considering
the emissions data over the full time period from 2009-2019 data
results in a third-best rate of 0.079 pounds NOX per million
British thermal units (lb/mmBtu).\145\ Therefore, consistent with the
Revised CSAPR Update, where EPA identified 0.08 lb/mmBtu as a
reasonable level of performance for units with optimized SCR, the EPA
proposes a rate of 0.08 lb/mmBtu as the optimized rate for this rule.
The EPA notes that half of the SCR-controlled EGUs achieved a
NOX emissions rate of 0.064 lbs/mmBtu or less over their
third-best entire ozone season. Moreover, for the SCR-controlled coal
units that the EPA identified as having a 2021 emissions rate greater
than 0.08 lb/mmBtu, the EPA verified that in prior years, the majority
(more than 90 percent) of these same units had demonstrated and
achieved a NOX emissions rate of 0.08 lb/mmBtu or less on a
seasonal or monthly basis. This further supports EPA's determination
that 0.08 lb/mmBtu reflects a reasonable emissions rate for
representing SCR optimization at coal steam units in identifying
uniform control stringency. This emissions rate assumption of 0.08 lb/
mmBtu reflects what those units would achieve on average when
optimized, recognizing that individual units may achieve lower or
higher rates based on unit-specific configuration and dispatch
patterns. Units historically performing at, or better, than this rate
of 0.08 lb/mmBtu are assumed to continue to operate at that prior
performance level.
---------------------------------------------------------------------------

    \145\ The EPA notes that updating the inventory of units to
reflect recent retirements and most recent year data (e.g., 2009-
2021) would provide a lower value of 0.071 lb/mmBtu. This value is
lower than the 0.08 pounds per million British thermal units (lb/
mmBtu) assessed in the Revised CSAPR Update as it reflects 2020 data
and also excludes the SCR performance of since retired coal units
with SCRs. However, 2020 was an outlier year (related to pandemic
impacts on the electric grid). Additionally, a unit's retirement
does not obviate the usefulness of its data for assessing technology
performance. Consequently, EPA is proposing the same value of 0.08
lb/mmBtu identified at the time of the final Revised CSAPR Update
Rule.
---------------------------------------------------------------------------

    Given the magnitude and duration of the air quality problems
addressed by this rulemaking, the EPA also applied the same methodology
to identify a reasonable level of performance for optimizing existing
SCRs at oil- and gas-fired steam units and simple cycle units (for
which EPA determined that a 0.03 lb/mmBtu emissions rate reflected SCR
optimization) as well as at combined-cycle units (for which the EPA
determined that a 0.012 lb/mmBtu emissions rate reflected SCR
optimization).
    The EPA evaluated the feasibility of optimizing idled SCRs for the
2023 ozone season. Based on industry past practice, the EPA determined
that idled controls can be restored to operation quickly (i.e., in less
than 2 months). This timeframe is informed by many electric utilities'
previous long-standing practice of utilizing SCRs to reduce EGU
NOX emissions during the ozone season while putting the
systems into protective lay-up during the non-ozone season months. For
example, this was the long-standing practice of many EGUs that used SCR
systems for compliance with the NOX Budget Trading Program.
It was quite typical for SCRs to be turned off following the September
30 end of the ozone season control period. These controls would then be
put into protective lay-up for several months of non-use before being
returned to operation by May 1 of the following ozone season.\146\
Therefore, the EPA believes that optimization of existing SCRs is
possible for the portion of the 2023 ozone season covered under this
proposed rule.
---------------------------------------------------------------------------

    \146\ In the 22-state CSAPR Update region, 2005 EGU
NOX emissions data suggest that 125 EGUs operated SCR
systems in the summer ozone season while idling these controls for
the remaining 7 non-ozone season months of the year. Units with SCR
were identified as those with 2005 ozone season average
NOX rates that were less than 0.12 lbs/mmBtu and 2005
average non-ozone season NOX emissions rates that
exceeded 0.12 lbs/mmBtu and where the average non-ozone season
NOX rate was more than double the ozone season rate.
---------------------------------------------------------------------------

    The vast majority of SCR-controlled units (nationwide and in the 25
linked states for which EPA is issuing a FIP for EGUs) are already
partially operating these controls during the ozone season based on
reported 2021 emissions rates. Existing SCRs operating at partial
capacity still provide functioning, maintained systems that may only
require an increased chemical reagent feed rate (i.e., ammonia or urea)
up to their design potential and catalyst maintenance for mitigating
NOX emissions; such units may require increased frequency or
quantity of deliveries, which can be accomplished within a few weeks.
In many cases, EGUs with SCR have historically achieved more efficient
NOX removal rates than their current performance and can
therefore simply revert to earlier operation and maintenance plans that
achieved demonstrably better SCR performance.
    In the 12 states subject to this control stringency in the Revised
CSAPR Update, the EPA observed significant immediate-term improvements
in SCR performance in the first ozone season following finalization of
that rule, as evidenced in particular by the sharp drop in emissions
rate at Miami Fort unit 7 (see EGU NOX Mitigation Strategies
Proposed Rule TSD). Such empirical data further illustrates the
viability of this mitigation strategy for the 2023 control period in
response to this rule.
b. Installing State-of-the-Art NOX Combustion Controls
    The EPA estimates that the representative cost of installing state-
of-the-art combustion controls is comparable to, if not notably less
than, the estimated cost of optimizing existing SCR (represented by
$1,600 per ton). State-of-the-art combustion controls such as low-
NOX burners (LNB) and over-fire air (OFA) can be installed
or updated quickly and can substantially reduce EGU NOX
emissions. Nationwide, approximately 99 percent of coal-fired EGU
capacity greater than 25 MW is equipped with some form of combustion
control; however, the control configuration or corresponding emissions
rates at a small portion of those units (including units in those
states covered in this action) indicate they do not currently have
state-of-the-

art combustion control technology. As described in the Revised CSAPR
Update, the Agency updated its NOX emissions rates for
upgrading existing combustion controls to state-of-the-art combustion
control. The EPA is maintaining its determination that NOX
emissions rates of 0.146 to 0.199 lbs/mmBtu can be achieved on average
depending on the unit's boiler configuration,\147\ and, once installed,
reduce NOX emissions at all times of EGU operation.
---------------------------------------------------------------------------

    \147\ Details of EPA's assessment of state-of-the-art
NOX combustion controls are provided in the EGU
NOX Mitigation Strategies Proposed Rule TSD.
---------------------------------------------------------------------------

    These assumptions are consistent with the Revised CSAPR Update and
they are further discussed in the EGU NOX Mitigation
Strategies Proposed Rule TSD. In particular, the EPA proposes to apply
the 0.199 lb/mmBtu emissions rate assumption for all unit types,
consistent with its determination in the Revised CSAPR Update. The
average emissions rate assumption derived from EPA's analysis would be
0.199 lb/mmBtu for combustion controls on dry bottom wall fired units
and 0.146 lb/mmBtu for tangentially fired units. However, stakeholders
have provided detailed analysis of how other unit considerations, such
as coal rank, can result in large deviations from what has been
historically demonstrated with this combustion control technology.
Based on this and EPA's review of historical performance data for
tangentially-fired units by coal rank with state-of-the-art combustion
controls, the EPA determined in the final Revised CSAPR Update that it
was appropriate to use the 0.199 lb/mmBtu rate for both tangentially
and wall-fired units when estimating reduction potential for units with
combustion control upgrade potential.
    The EPA proposes to continue that approach in this action. Many of
the likely impacted units burn bituminous coal, and the 0.146 lb/mmBtu
nationwide average for tangentially-fired (inclusive of subbituminous
units) appears to be below the demonstrated emissions rate of state-of-
the-art combustion controls for bituminous coal units of this boiler
type. Therefore, EPA's assumption of 0.199 lb/mmBtu for combustion
controls is robust to current and future coal choice at a unit.
    In promulgating CSAPR, the EPA examined the feasibility of
installing combustion controls, and found that industry had
demonstrated ability to install state-of-the-art LNB controls on a
large unit (800 MW) in under six months when including the pre-
installation phases (design, order placement, fabrication, and
delivery).\148\ In prior rules, the EPA has documented its own
assessment of combustion control timing installation as well as
evaluated comments it received regarding installation of combustion
controls from the Institute of Clean Air Companies.\149\ Those comments
provided information on the equipment and typical installation time
frame for new combustion controls, accounting for all steps. Commenters
noted that it generally takes between 6-8 months on a typical boiler--
covering the time through bid evaluation through start-up of the
technology. The deployment schedule is repeated here as:
---------------------------------------------------------------------------

    \148\ The EPA finds that, generally, the installation phase of
state-of-the-art combustion control upgrades--on a single-unit
basis--can be as little as 4 weeks to install with a scheduled
outage (not including the pre-installation phases such as
permitting, design, order, fabrication, and delivery) and as little
as 6 months considering all implementation phases.
    \149\ EPA-HQ-OAR-2015-0500-0093.

 4-8 weeks--bid evaluation and negotiation
 4-6 weeks--engineering and completion of engineering drawings
 2 weeks--drawing review and approval from user
 10-12 weeks--fabrication of equipment and shipping to end user
site
 2-3 weeks--installation at end user site
 1 week--commissioning and start-up of technology

Given the above timeframe of approximately 6 to 8 months to complete
combustion control installation in the region, the EPA is proposing to
determine that installation of state-of-the-art combustion controls is
a readily available approach for EGUs to reduce NOX
emissions by the start of the 2024 ozone season. More details on these
analyses can be found in the EGU NOX Mitigation Strategies
Proposed Rule TSD.
    The cost of installing state-of-the-art combustion controls per ton
of NOX reduced is dependent on the combustion control type
and unit type. The EPA estimates the cost per ton of state-of-the-art
combustion controls to be $400 per ton to $1,200 per ton of
NOX removed using a representative capacity factor of 85
percent. This cost fits well within EPA's representative cost threshold
observed for SCR optimization and combustion controls (of $1,600 per
ton) which would accommodate combustion control upgrade even under
scenarios where a lower capacity factor is assumed. See the EGU
NOX Mitigation Strategies Proposed Rule TSD for additional
details.
c. Optimizing Already Operating SNCRs or Turning on Idled Existing
SNCRs
    Optimizing already operating SNCRs or turning on idled existing
SNCRs can also reduce EGU NOX emissions quickly, using
investments in pollution control technologies that have already been
made. Compared to no post-combustion controls on a unit, SNCRs can
achieve a 25 percent reduction on average in EGU NOX
emissions (with sufficient reagent). They are less capital intensive
but less efficient at NOX removal than SCRs. These controls
are in use to some degree across the U.S. power sector. In the 25
linked states identified in this proposed rule with identified EGU
reductions in their proposed FIP, approximately 11 percent of coal-
fired EGU capacity is equipped with SNCR.\150\ Recent power sector data
suggest that, in some cases, SNCR controls have been operating less in
2021 relative to performance in prior years.
---------------------------------------------------------------------------

    \150\ https://www.epa.gov/airmarkets/national-electric-energy-data-system-needs-v6.
---------------------------------------------------------------------------

    The EPA determined that optimizing already operating SNCRs or
turning on idled SNCRs is an available approach for EGUs to reduce
NOX emissions, has similar implementation timing to
restarting idled SCR controls (less than 2 months for a given unit),
and therefore could be implemented in time for the 2023 ozone season.
The EPA is proposing implementation of this emissions control
technology beginning in the 2023 ozone season.
    Using an updated data assessment using the Retrofit Cost Analyzer
described in the EGU NOX Mitigation Strategies Proposed TSD,
the EPA estimates a representative cost of optimizing SNCR ranging from
approximately $1,800 per ton (for partially operating SNCRs) to $3,900
per ton (for idled SNCRs). For existing SNCRs that have been idled,
unit operators may need to restart payment of some fixed and variable
operating costs including labor, maintenance and repair, parasitic
load, and ammonia or urea. The EPA determined that the majority of
units with existing SNCR optimization potential were already partially
operating their controls. Therefore, the EPA proposes a representative
cost of $1,800 per ton for SNCR optimization as this value best
reflects the circumstances of the majority of the affected EGUs with
SNCR.

d. Installing New SNCRs
    Like existing SNCRs, new SNCR retrofit is also available to power
plants and can achieve a 25% NOX reduction on average. The
EPA evaluated potential emissions reductions and associated costs from
retrofitting EGUs with new SNCR post-combustion controls at steam units
lacking such controls. New SNCR technology provides owners with a
relatively less capital-intensive option for reducing NOX
emissions compared to new SCR technology, albeit at the expense of
higher operating costs on a per-ton basis and less total emissions
reduction potential. SNCR is more widely observed on relatively smaller
coal units given its low capital/variable cost ratio. The average
capacity of a coal unit with SNCR is half the size of the average
capacity of coal unit with SCR.\151\ Given these observations, the EPA
identifies this technology as an emissions reduction measure for coal
units less than 100 MW lacking post-combustion NOX control
technology. As described in the EGU NOX Mitigation
Strategies Proposed Rule TSD, the EPA estimated that $6,700 per ton
reflects a representative SNCR retrofit cost level for a majority of
these units.
---------------------------------------------------------------------------

    \151\ See EGU NOX Mitigation Strategies Proposed Rule
TSD for additional discussion.
---------------------------------------------------------------------------

    SNCR installations generally have shorter project installation
timeframes relative to other post-combustion controls. The time for
engineering review, contract award, fabrication, delivery, and hookup
is as little as 16 months including pre-contract award steps for an
individual power plant installing controls on more than one boiler.
This timeframe would mean the control would be available for the start
of the 2024 or 2025 ozone season (i.e., calculating 16 months from when
this proposal is finalized). However, SNCR retrofits have less
pollution reduction potential than alternative post-combustion controls
such as SCRs. The EPA is not identifying SNCR technology as a strategy
for larger steam units due to this lower removal efficiency and the
empirical evidence of existing sources preferring the more efficient
SCRs. Even for those smaller units less than 100 MWs identified as
potential candidates for this technology, the EPA does not want to
preclude those units from pursuing more advanced pollution controls.
Therefore, the EPA also considers the point in time when all types of
post-combustion control installation could be achieved--i.e., by the
2026 ozone season. SNCR installation share similar implementation steps
with and also need to account for the same regional factors as SCR
installations.\152\ Therefore, while the EPA is determining that at
least 16 months would be needed to complete all necessary steps of SNCR
development and installation at the EGUs not currently equipped with
SNCRs in the 25 states linked to downwind receptors in this proposed
rule, the EPA notes that the Agency evaluated SNCR as a post-combustion
control technology collectively with SCR and estimated installation
timing considerations of 36 months. EPA believes its proposed
collective timing considerations for post-combustion control retrofit
(SNCR and SCR) are practicable given that the preferable capital-
intensive investment retrofit decision would be highly unit-specific
and subject to a unit's compliance strategy choices with respect to
multiple regulatory requirements.
---------------------------------------------------------------------------

    \152\ A month-by-month evaluation of SNCR installation is
discussed in EPA's NOX Mitigation Strategies Proposed
Rule TSD and in EPA's ``Engineering and Economic Factors Affecting
the Installation of Control Technologies for Multipollutant
Strategies''. The analysis in this exhibit estimates the
installation period from contract award as within a 10-13-month
timeframe. The exhibit also indicates a 16-month timeframe from
start to finish, inclusive of pre-contract award steps of the
engineering assessment of technologies and bid request development.
The timeframe cited for installation of SNCR at an individual source
in this action is consistent with this more complete timeframe
estimated by the analysis in the exhibit.
---------------------------------------------------------------------------

    Nonetheless, the EPA is requesting comment on whether post-
combustion control timing assumptions (SCR and SNCR) should be
decoupled, which would result in the EPA using the 16-month time frame
specific to SNCR installation to estimate the first year in which these
reductions are available. The EPA is only identifying this technology
for units less than 100 MW (a size at which units rarely implement SCR
retrofit technology). In effect, decoupling these timing assumptions
would move the reductions associated with this control stringency from
beginning in the 2026 ozone season to beginning in the 2024 or 2025
ozone season (depending on when this proposal is finalized). This would
impact approximately 1,000 tons of identified reduction potential
related to SNCR retrofit.
e. Installing New SCRs
    Selective Catalytic Reduction (SCR) controls already exist on
approximately 60% of the coal fleet in the linked states that would be
subject to a FIP in this proposed rulemaking. Nearly every pulverized
coal unit larger than 100 MW built in the last 30 years has installed
this control, which is generally required for Best Available Control
Technology (BACT) purposes. Other than circulating fluidized bed coal
units which can achieve a comparably low emissions rate without this
technology, the EPA identifies this emissions reduction measure for
coal steam units greater than or equal to 100 MW. SCR is widely
available for existing coal units of this size and can provide
significant emissions reduction potential, with removal efficiencies of
up to 90 percent. The EPA limited its consideration of SCR technology
to steam units greater than or equal to 100 MW. The costs for
retrofitting a plant smaller than 100 MW with SCR increase rapidly due
to a lack of economy of scale.\153\
---------------------------------------------------------------------------

    \153\ IPM Model-Updates to Cost and Performance for APC
Technologies. SCR Cost Development Methodology for Coal-fired
Boilers. February 2022.
---------------------------------------------------------------------------

    The amount of time needed to retrofit an EGU with new SCR extends
beyond the 2023 ozone season. The EPA proposes that a strategy of
retrofitting new SCR on a fleetwide, regional scale is available by,
but no earlier than, the 2026 ozone season. Similar to the SNCR
retrofits discussed above, the EPA evaluated potential emissions
reductions and associated costs from this control technology, as well
as the impacts and need for this emissions control strategy, at the
earliest point in time when their installation could be achieved. In
the past, the EPA has found the amount of time to retrofit a single EGU
with new SCR, depending on the regulatory program under which such
control may be required, may vary between approximately 2 and 4 years
depending on site-specific engineering considerations and on the number
of installations being considered. This includes steps for engineering
review, construction permit, operating permit, and control technology
installation (including fabrication, pre hookup, control hookup, and
testing). EPA's assessment of installation procedures suggests as
little as 21 months may be needed for a single SCR at an individual
plant and 36 months at a single plant with multiple boilers. EPA's
assessment of units with SCR retrofit potential indicate the majority
fall into this first classification, i.e., a single SCR at a power
plant. Given that some of the assumed SCR retrofit potential occurs at
plants with multiple units identified with retrofit potential, and
given the total volume of SCR retrofit capacity being implemented
across the region, The EPA is proposing 36 months as an appropriate
time frame to accommodate both instances as well as scheduling
necessities attributable to the regional-scale nature of the program.

    Further, the EPA notes that it has previously determined in the
context of ozone transport that regional scale implementation of SCRs
at numerous EGUs is achievable in 36 months. See 63 FR 57356, 57447-50
(October. 27, 1998). The EPA has at times also found up to 39-48 months
to be an appropriate installation timeframe for regionwide actions when
the EPA is evaluating multiple installations at multiple
locations.\154\ However, as discussed in greater detail in Section
VII.A in this proposed rule, the EPA now recognizes that the Wisconsin
decision invalidated the standard under which the EPA had been
evaluating appropriate compliance timeframes for purposes of assessing
interstate transport under the good neighbor provision when the Agency
had concluded a 39-48 month timeframe to install SCR was appropriate.
---------------------------------------------------------------------------

    \154\ See, e.g., CSAPR Close-Out, 83 FR 65878, 65895 (December
21, 2018). See also Final Report: Engineering and Economic Factors
Affecting the Installation of Control Technologies for
Multipollutant Strategies, EPA-600/R-02/073 (Oct. 2002), available
at https://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf.
---------------------------------------------------------------------------

    The Agency examined the cost for retrofitting a coal unit with new
SCR technology, which typically attains controlled NOX rates
of 0.05 lbs/mmBtu or less. These updates are further discussed in the
EGU NOX Mitigation Strategies Proposed Rule TSD.\155\ Based
on the characteristics of coal units of 100 MW or greater capacity that
do not have post-combustion NOX control technology, the EPA
estimated a weighted-average representative SCR cost of $11,000 per
ton.\156\
---------------------------------------------------------------------------

    \155\ As noted in that TSD, approximately half of the recent SCR
retrofits (i.e., installed in the last 10 years) have demonstrated
an emission rate across the ozone season below 0.05 lb/mmBtu, even
absent a requirement or strong incentive to operate at that level in
many cases.
    \156\ This cost estimate is representative of coal units lacking
any post-combustion control. A subset of units within the universe
of coal sources with SCR retrofit potential, but that have an
existing SNCR technology in place would have a weighted average cost
that falls above this level, but still cost effective. See the EGU
NOX Mitigation Strategies Proposed Rule TSD for more
discussion.
---------------------------------------------------------------------------

    The 0.05 lb/mmBtu emission rate performance assumption for new SCR
retrofits is supported by historical data and third party independent
review by pollution control engineering and consulting firms. The EPA
first examined unit-level emission rate data for coal-fired units that
had a relatively recent SCR installation (within the last 10 years).
These SCR retrofits reflect the most recent vintage of the pollution
control technology applied to the power sector and are representative
of new SCR retrofit capability. Although regulatory requirements or
economic incentives were not necessarily in place during this time
period for these SCRs to operate at their full potential, the EPA found
that half of these units had still demonstrated a seasonal emission
rate of 0.05 lb/mmBtu or lower and 78 percent had demonstrated this
rate on a monthly basis. The best performing 10 percent of these SCRs
were demonstrating seasonal emission rates of 0.036 lb/mmBtu during
this time.
    While the EPA identified the 0.05 lb/mmBtu performance assumption
consistent with historical data, these performance levels are also
informed and consistent with the Agency's IPM modeling assumptions used
for more than a decade. These modeling assumptions are based on input
from leading engineering and pollution control consulting entities.
Most recently, these data assumptions were affirmed and updated in the
summer of 2021 and included in the docket for this rulemaking. The EPA
relies on a global firm providing engineering, construction management,
and consulting services for power and energy with expertise in grid
modernization, renewable energy, energy storage, nuclear power, and
fossil fuels. Their familiarity with state-of-the art pollution
controls at power plants derives from experience providing
comprehensive project services--from consulting, design, and
implementation to construction management, commissioning, and
operations/maintenance. This review and update supported the 0.05 lb/
mmBtu performance assumption as a representative emission rate for new
SCR across coal types.
    The EPA performed an assessment for oil/gas steam units in which it
evaluated the nationwide performance of those units with SCR
technology. For these units, the EPA tabulated EGU NOX ozone
season emissions data from 2009 through 2021 and calculated an average
NOX ozone season emissions rate across the fleet of oil- and
gas-fired EGUs with SCR for each of these years. The EPA identified the
third lowest year which yielded an SCR performance rate of 0.03 lb/
mmBtu as representative of performance for this retrofit technology
applied to this type of EGU. Next, the EPA evaluated the emissions and
operational characteristics for the existing oil/gas steam fleet
lacking SCR technology. EPA's analysis indicated that the majority of
reduction potential (approximately 76 percent) from these units
occurred at units greater than or equal to 100 MW and that were
emitting more than 150 tons per ozone season (i.e., approximately 1 ton
per day). Moreover, the cost of reductions for units falling below
these criteria increased significantly. Therefore, the EPA identified
the portion of the oil/gas steam fleet meeting this criteria as
representative of the SCR retrofit reduction potential.\157\ For this
segment of the oil/gas steam units lacking post-combustion
NOX control technology, the EPA estimated a weighted-average
representative SCR cost of $7,700 per ton.
---------------------------------------------------------------------------

    \157\ The EPA used a 3 year average of 2019-2021 reported ozone
season emissions to derive a tons per ozone season value
representative for each covered oil/gas steam unit.
---------------------------------------------------------------------------

f. Generation Shifting
    Finally, EPA evaluates emissions reduction potential from
generation shifting across the representative dollar per ton levels
estimated for the emissions controls considered above. As the cost of
emitting NOX increases, it becomes increasingly cost-
effective for units with lower NOX rates to increase
generation, while units with higher NOX rates reduce
generation. Because the cost of generation is unit-specific, this
generation shifting occurs incrementally on a continuum. Consequently,
there is more generation shifting at higher cost NOX-control
levels.
    It is reasonable for the EPA to quantify and include the emissions
reduction potential from generation shifting at cost levels that are
representative of the emissions control technologies evaluated in the
multi-factor analysis, because all EGUs that would be regulated by this
proposed rule participate in highly coordinated, interconnected systems
where generation shifting will inevitably occur in response to
pollution control requirements. If the EPA did not account for such
emissions reduction potential in its analysis at Step 3, seeking
emissions reductions from pollution control measures at higher-
NOX-emitting EGUs would still incentivize generation
shifting toward lower-NOX-emitting EGUs when sources comply
under the remedy mechanism established in Step 4, and the corresponding
reductions in emissions achieved through such generation shifting would
potentially substitute for some of the emissions reductions intended
through control operation and installation, potentially lessening the
implementation of those mitigation strategies. Generation shifting
treatment and results are discussed in greater detail in the EGU
NOX Mitigation Strategies Proposed TSD and the Ozone
Transport Policy Analysis Proposed Rule TSD.

    The EPA notes that its treatment of generation shifting here is
consistent with the prior CSAPR rulemakings and is grounded on the same
statutory authority. See, e.g., 76 FR 48208, 48280 (August 8, 2011). As
the EPA explained in the CSAPR Update: \158\
---------------------------------------------------------------------------

    \158\ The EPA discussed its legal authority for and the
technical viability of generation shifting as a method of emissions
reduction under the good neighbor provision in the CSAPR Update. See
especially 81 FR 74504, 74545-47; see also CSAPR Update Response to
Comment Document at 546-550 (legal authority); id. 528-533
(technical feasibility). See Final Revised CSAPR Update, 86 FR
23096-97.

    The good neighbor provision requires state and federal plans
implementing its requirements to ``prohibit[ ] . . . any source or
other type of emissions activity within the State from emitting any
air pollutant in amounts which will'' significantly contribute to
nonattainment or interfere with maintenance of the NAAQS in any
other state. CAA section 110(a)(2)(D)(i)(I) (emphasis added). . . .
[T]he statute does not limit the EPA's authority under the good
neighbor provision to basing regulation only to control strategies
for individual sources. The statute authorizes the state or EPA in
promulgating a plan to prohibit emissions from ``any source or other
type of emissions activity within the State'' that contributes (as
determined by EPA) to the interstate transport problem with respect
to a particular NAAQS. This broad statutory language shows that
Congress was directing the states and the EPA to address a wide
range of entities and activities that may be responsible for
downwind emissions. However, this provision is silent as to the type
of emissions reduction measures that the states and the EPA may
consider in establishing emissions reduction requirements, and it
does not limit those measures to individual source controls. . . .
The EPA reasonably interprets this provision to authorize
consideration of a wide range of measures to reduce emissions from
sources, which is consistent with the broad scope of this provision,
---------------------------------------------------------------------------
as noted immediately above.

81 FR 74545.\159\ The EPA continued to apply this same understanding in
the Revised CSAPR Update. See 86 FR 23054, 23095-97 (April 30, 2021);
see also 85 FR 68964, 68992-93 (October 30, 2020).
---------------------------------------------------------------------------

    \159\ The EPA also noted in the CSAPR Update, ``Interpreting the
Good Neighbor Provision to be sufficiently broad to authorize
reliance on generation shifting is also consistent with the
legislative history for the 1970 CAA Amendments. The Senate Report
stated that to achieve the NAAQS, `[g]reater use of natural gas for
electric power generation may be required,' S. Rep. No. 91-1196 at
2.'' 81 FR 74545 n.141.
---------------------------------------------------------------------------

    The EPA requests comment on the suite of mitigation technologies
for EGUs described earlier and assessed in the determination of
significant contribution. The EPA requests comment on the assumed
performance or emissions rate of the technology, the representative
cost, and the timing for installation.\160\ Additionally, the EPA
requests comment on whether other EGU ozone-season NOX
Mitigation technologies should be required to eliminate significant
contribution. For instance, the EGU NOX Mitigation
Strategies Proposed Rule TSD discusses certain mitigation technologies
that have been applied to ``peaking'' units (small, low capacity factor
gas combustion turbines often only operating during periods of peak
demand). To the extent that any of these sources meet the applicability
requirements and are covered in the Group 3 trading program under this
proposed rulemaking, they would have an incentive to reduce emissions
consistent with the ozone season NOX allowance price. The
EPA has not identified determinative evidence that there are additional
meaningful, cost-effective upwind reductions from these emission
controls that are not already being addressed by state rules. EPA's
analysis discussed in the EGU NOX Mitigation Strategies
Proposed Rule TSD highlights that there are 32 units emitting more than
10 tons per year on average for the 2019-2021 ozone seasons and lacking
combustion controls or more advanced controls (totaling approximately
1,000 tons of ozone season NOX emissions in 2021). Some of
the units in the limited inventory are subject to state requirements
delivering additional reductions by 2023. Moreover, the EPA analysis
suggested $25,000-$30,000 per ton estimates for dry low NOX
burners or ultra-low NOX burners at these units, and over
$100,000 per ton for SCR retrofit at some combustion turbines.
Therefore, the EPA is not proposing any additional reductions from new
controls for inclusion in its combustion control or retrofit technology
breakpoints. Although the EPA is not proposing a mitigation technology
for this type of unit, it requests comment on the potential emissions
reductions and cost from such sources in covered states that do not
currently have mitigation requirements for such sources.
---------------------------------------------------------------------------

    \160\ The feasibility of the timetable for emissions reductions
from both EGUs and non-EGUs is further addressed in Section VII.A of
this proposed rule.
---------------------------------------------------------------------------

2. Non-EGU NOX Mitigation Strategies
a. Determining Non-EGU NOX Reduction Potential
    The number of different industries and emissions unit categories
and types, as well as the total number of emissions units that comprise
the universe of non-EGU sources, makes it challenging to define a
single method to identify appropriate control technologies, measures,
or strategies and resulting impactful emissions reductions. Because of
these challenges, the EPA adopted a different approach for assessing
non-EGU NOX emissions reduction potential than the approach
for EGUs described in the preceding section. To assess emissions
reduction potential from non-EGUs, the EPA first performed a screening
assessment to identify those industries that could have the greatest
air quality impact at downwind receptors. This was followed by an
assessment estimating annual NOX emissions reduction
potential at specific cost thresholds for each of the most impactful
industries. Next, the EPA estimated the reductions in ozone
concentrations resulting from the emissions reductions for each
industry in each of the 27 linked upwind states. As described later,
the results indicate that the most impactful industries fall into two
tiers based on the estimated reductions in ozone concentrations
associated with the NOX emissions reductions.
    The Agency incorporated air quality information as a first step in
an analytical framework to help determine potentially impactful
industries to focus on for further assessing potential controls,
emissions reduction potential, air quality improvements, and costs. The
EPA developed the analytical framework using inputs from the air
quality modeling for the Revised CSAPR Update for 2023,\161\ as well as
the projected 2023 annual emissions inventory from the 2016v2 emissions
platform that was used for the air quality modeling for this proposed
rule. Additional information on the analytical framework is presented
in the Non-EGU Screening Assessment memorandum available in the docket.
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    \161\ The EPA used the Revised CSAPR Update air quality modeling
for this screening assessment because the air quality modeling for
this proposed rule was not completed in time to support the
assessment.
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    Using the Revised CSAPR Update modeling for 2023, the EPA
identified upwind states linked to downwind nonattainment or
maintenance receptors using the 1 percent of the NAAQS threshold
criterion, which is 0.7 ppb (1 percent of a 70 ppb NAAQS). In 2023
there were 27 linked states for the 2015 ozone NAAQS: Alabama,
Arkansas, California, Delaware, Illinois, Indiana, Kentucky, Louisiana,
Maryland, Michigan, Minnesota, Mississippi, Missouri, Nevada, New
Jersey, New York, Ohio, Oklahoma, Oregon, Pennsylvania, Tennessee,
Texas, Utah, Virginia, West Virginia, Wisconsin, and Wyoming.

    To analyze non-EGU emissions units, the EPA aggregated the
underlying projected 2023 emissions inventory data into industries
defined by 4-digit NAICS. Then for linked states, the EPA followed the
2-step process below:
    Step 1--The EPA identified industries whose potentially
controllable emissions have the greatest ppb impact on downwind air
quality, and
    Step 2--The EPA determined which of the most impactful industries
and emissions units had the most emissions reductions that would make
meaningful air quality improvements at the downwind receptors at a
marginal cost threshold the EPA determined using underlying control
device efficiency and cost information.
    To estimate the contributions by industry, defined by 4-digit
NAICS, at each downwind receptor the EPA used the 2023 state-receptor
specific Revised CSAPR Update ppb/ton values and the Revised CSAPR
Update calibration factors used in the air quality assessment tool
(AQAT) for control analyses in 2023.\162\ The EPA focused on assessing
emissions units that emit greater than 100 tons per year (tpy) of
NOX.\163\ By limiting the focus to potentially controllable
emissions, well-controlled sources that still emit greater than 100 tpy
are excluded. Instead, the focus is on uncontrolled sources or sources
that could be better controlled at a reasonable cost. As a result,
reductions from any industry identified by this process are more likely
to be achievable and to lead to air quality improvements.
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    \162\ The calibration factors are receptor-specific factors. For
the Revised CSAPR Update, the calibration factors were generated
using 2016 base case and 2023 base case air quality model runs.
These receptor-level ppb/ton factors are discussed in the Ozone
Transport Policy Analysis Final Rule TSD found here: https://www.epa.gov/sites/default/files/2021-03/documents/ozone_transport_policy_analysis_final_rule_tsd_0.pdf.
    \163\ In the non-EGU emissions reduction assessment prepared for
the Revised Cross State Air Pollution Rule Update (https://www.regulations.gov/document/EPA-HQ-OAR-2020-0272-0014), The EPA
reviewed emissions units with >150 tpy of NOX emissions.
In this assessment, EPA broadened the scope to include emissions
units with greater than or equal to 100 tpy of NOX
emissions.
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    From this information, the EPA prepared a summary with the
estimated total, maximum, and average contributions from each industry
and the number of receptors with contributions greater than or equal to
0.01 ppb from each industry.\164\ The EPA used this information to
identify breakpoints in the data to determine which industries to focus
on for the next steps in its analysis, as described in the Non-EGU
Screening Assessment memorandum.
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    \164\ The EPA chose to include in the Non-EGU NOX
reduction potential analysis those industries that contribute at
least 0.01 ppb to a downwind receptor in order to focus the analysis
on the most impactful industries. The 0.01 criterion is based on an
analysis of the distribution and relative magnitude of contributions
from 41 industries, as identified in the Non-EGU Screening
Assessment memorandum. From this analysis the EPA determined that
0.01 ppb provides a meaningful conservative breakpoint for screening
out non-impactful industries from the Non-EGU analysis in this
proposed rule. Details on this analysis that provides the basis for
using 0.01 ppb can be found in the Non-EGU Screening Assessment
memorandum.
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    A review of the maximum contribution data indicated that the EPA
should focus the assessment of NOX reduction potential and
cost primarily on four industries. These industries each (1) have a
maximum contribution to any one receptor of greater than 0.10 ppb and
(2) contribute greater than or equal to 0.01 ppb to at least 10
receptors. The four industries identified below comprise the ``Tier 1''
non-EGU industries.

 Pipeline Transportation of Natural Gas
 Cement and Concrete Product Manufacturing
 Iron and Steel Mills and Ferroalloy Manufacturing
 Glass and Glass Product Manufacturing

    In addition to these industries, the maximum contribution data
suggests including five additional industries as a second tier in the
assessment. These industries each either have (1) a maximum
contribution to any one receptor greater than or equal to 0.10 ppb but
contribute greater than or equal to 0.01 ppb to fewer than 10
receptors, or (2) a maximum contribution less than 0.10 ppb but
contribute greater than or equal to 0.01 ppb to at least 10 receptors.
The five industries identified below comprise the ``Tier 2'' non-EGU
industries.

 Basic Chemical Manufacturing
 Petroleum and Coal Products Manufacturing
 Metal Ore Mining
 Lime and Gypsum Product Manufacturing
 Pulp, Paper, and Paperboard Mills

    For additional discussion of the contribution information, see
Appendix A of the Non-EGU Screening Assessment memorandum included in
the docket for this proposed rulemaking.
    Next, to identify an annual cost threshold for evaluating potential
emissions reductions in the Tier 1 and Tier 2 industries, the EPA used
the Control Strategy Tool (CoST),\165\ the Control Measures Database
(CMDB),\166\ and the projected 2023 emissions inventory to prepare a
listing of potential control measures, and costs, applied to non-EGU
emissions units in the projected 2023 emissions inventory. Using these
data, the EPA plotted curves for Tier 1 industries, Tier 2 industries,
Tier 1 and 2 industries, and all industries at $500 per ton increments.
Figure 1 on page 4 of the Non-EGU Screening Assessment memorandum,
which is available in the docket for this proposed rulemaking,
indicates there is a ``knee in the curve'' at approximately $7,500 per
ton (all non-EGU cost estimates in the assessment and presented in the
rest of this section are in 2016 dollars). The EPA used this marginal
cost threshold to further assess potential control strategies,
estimated emissions reductions, air quality improvements, and costs
from the potentially impactful industries. Note that controls and
related emissions reductions are available at several estimated cost
levels up to the $7,500 per ton threshold. (These costs do not include
monitoring, recordkeeping, reporting, or testing costs.)
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    \165\ Further information on CoST can be found at the following
link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
    \166\ The CMDB is available at the following link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
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    Next, using the marginal cost threshold of $7,500 per ton, to
estimate emissions reductions and costs the EPA processed the CoST run
using the maximum emissions reduction algorithm,\167\ with known
controls.\168\ The EPA identified controls for non-EGU emissions units
in the Tier 1 and Tier 2 industries that cost up to $7,500 per ton. The
EPA then calculated air quality impacts associated with the estimated
reductions for the 27 linked states in 2023 using the following steps.
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    \167\ The maximum emissions reduction algorithm assigns to each
source the single measure (if a measure is available for the source)
that provides the maximum reduction to the target pollutant. For
more information, see the CoST User's Guide available at the
following link: https://www.cmascenter.org/cost/documentation/3.7/CoST%20User's%20Guide/.
    \168\ Known controls are well-demonstrated control devices and
methods that are currently used in practice in many industries.
Known controls do not include cutting edge or emerging pollution
control technologies.
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    1. The EPA binned the estimated reductions by 4-digit NAICS code
into the Tier 1 and Tier 2 industries.
    2. The EPA used the 2023 state-receptor specific Revised CSAPR
Update ppb/ton values and the Revised CSAPR Update calibration factors
used in the AQAT for control analyses in 2023. The EPA multiplied the
estimated

non-EGU reductions by the ppb/ton values and by the receptor-specific
calibration factor to estimate the ppb impacts from these emissions
reductions.
    Next, because boilers represent the majority emissions units in the
Tier 2 industries for which there were controls that cost up to $7,500
per ton, the EPA further targeted emissions reductions and air quality
improvements in Tier 2 industries by identifying potentially impactful
industrial, commercial, and institutional (ICI) boilers. To identify
potentially impactful boilers, using the projected 2023 emissions
inventory in the linked upwind states, the EPA identified a universe of
boilers with greater than 100 tpy NOX emissions that had
contributions at downwind receptors.\169\ \170\ The EPA refined the
universe of boilers to a subset of impactful boilers by sequentially
applying the three criteria below to each boiler. This approach is
similar to the overall analytical framework and was tailored for
application to individual boilers.\171\
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    \169\ The EPA used the 2023fj non-EGU point source inventory
files from the 2016v2 emissions platform.
    \170\ Maryland, Missouri, Nevada, and Wyoming did not have
boilers with >100 tpy NOX emissions.
    \171\ For the impactful boiler assessment, the estimated air
quality contributions and improvements were not based on modeling of
individual emissions units or emissions source sectors. The air
quality estimates were derived by using the 2023 state/receptor
specific Revised CSAPR Update ppb/ton values and the Revised CSAPR
Update calibration factors used in AQAT. The results indicate a
level of precision not supported by the underlying air quality
modeling. The results were intended to provide an indication of the
relative impact across sources.
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     Criterion 1--Estimated maximum air quality contribution at
an individual receptor of greater than or equal to 0.0025 ppb or
estimated total contribution across downwind receptors of greater than
or equal to 0.01 ppb.
     Criterion 2--Controls that cost up to $7,500 per ton.
     Criterion 3--Estimated maximum air quality improvement at
an individual receptor of greater than or equal to 0.001 ppb.
    Lastly, the EPA updated its analytical framework to the 2026
analytic year by which the EPA is proposing non-EGU controls be
installed across the Tier 1 and Tier 2 industries and various emissions
unit types. The EPA concluded, based on the most recent information
available from the CSAPR Update Non-EGU TSD,\172\ that controls on all
of the non-EGU emissions units cannot be installed by the 2023 ozone
season. The EPA prepared the non-EGU screening assessment for the year
2026 by generally applying the analytical framework detailed above,
with some modifications. The updated screening assessment results for
2026 are discussed in Section VI.C.2 \173\ of this proposed rule.
Specifically, the EPA
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    \172\ Final Technical Support Document (TSD) for the Final
Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment
of Non-EGU NOX Emissions Controls, Cost of Controls, and
Time for Compliance Final TSD (``CSAPR Update Non-EGU TSD''), August
2016, available at https://www.epa.gov/csapr/assessment-non-egu-NOX-
emission-controls-cost-controls-and-time-compliance-final-tsd.
    \173\ The non-EGU screening assessment is not intended to be,
nor take the place of, a unit-specific detailed engineering analysis
that evaluates the feasibility of retrofits for the emissions units,
potential controls, and related costs. For more detailed discussion
of these issues, see Section VII.C of this proposed rule and the
Non-EGU Sectors TSD included in the docket.
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     Retained the impactful industries identified in Tier 1 and
Tier 2, the $7,500 cost per ton threshold, and the methodology for
identifying impactful boilers;
     Modified the framework to address challenges associated
with using the projected 2023 emissions inventory by using the 2019
emissions inventory; \174\ and
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    \174\ The EPA determined that the 2019 inventory was appropriate
because it provided a more accurate prediction of potential near-