2019 and, in this regard, we are calculating both the ozone design
values and the contributions based on a top-10 day approach (https://www3.epa.gov/ttn/scram/guidance/guide/O3-PM-RH-Modeling_Guidance-2018.pdf).
---------------------------------------------------------------------------

    Step 3--For states that are linked in Step 2 to downwind air
quality problems, the CSAPR and the CSAPR Update evaluated
NOX reductions that were available in upwind states by
applying a uniform control technology (represented by a marginal cost
of NOX emissions) to entities in these states. EPA evaluated
NOX reduction potential, cost, and downwind air quality
improvements available at several cost thresholds in the multi-factor
test. In both the CSAPR and the CSAPR Update, EPA selected the cost-
threshold that maximized cost-effectiveness (of the cost thresholds
examined), that is, the level of stringency in emission budgets at
which incremental NOX reduction potential and corresponding
downwind ozone air quality improvements are maximized with respect to
marginal cost relative to the other emission budget levels evaluated.
See, e.g., 81 FR 74550. This evaluation quantified the magnitude of
emissions that significantly contribute to nonattainment or interfere
with maintenance of a NAAQS downwind and apportioned upwind
responsibility among linked states, an approach upheld by the U.S.
Supreme Court in EPA v. EME Homer City.\69\ In general, EPA proposes in
this action to apply this approach to identify NOX emission
reductions necessary to address significant contribution for the 2008
ozone NAAQS.
---------------------------------------------------------------------------

    \69\ EPA v. EME Homer City Generation, L.P., 572 U.S. 489
(2014).
---------------------------------------------------------------------------

    In EME Homer City, the Supreme Court held that ``EPA cannot require
a State to reduce its output of pollution by more than is necessary to
achieve attainment in every downwind State or at odds with the one-
percent threshold the Agency has set.'' 572 U.S. at 521. The Court
acknowledged that ``instances of `over-control' in particular downwind
locations may be incidental to reductions necessary to ensure
attainment elsewhere.'' Id. at 492.

``Because individual upwind States often `contribute significantly'
to nonattainment in multiple downwind locations, the emissions
reductions required to bring one linked downwind State into
attainment may well be large enough to push other linked downwind
States over the attainment line. As the Good Neighbor Provision
seeks attainment in every downwind State, however, exceeding
attainment in one State cannot rank as `over-control' unless
unnecessary to achieving attainment in any downwind State. Only
reductions unnecessary to downwind attainment anywhere fall outside
the Agency's statutory authority.''

Id. at 522 (footnotes excluded).
    The Court further explained that ``while EPA has a statutory duty
to avoid over-control, the Agency also has a statutory obligation to
avoid `under-control,' i.e., to maximize achievement of attainment
downwind.'' Id. at 523. Therefore, in the CSAPR Update, EPA evaluated
possible over-control by considering whether an upwind state is linked
solely to downwind air quality problems that can be resolved at a lower
cost threshold, or if upwind states would reduce their emissions at a
lower cost threshold to the extent that they would no longer meet or
exceed the 1 percent air quality contribution threshold. See 81 FR at
74551-52. This evaluation of cost, NOX reductions, and air
quality improvements, including consideration of potential over-
control, results in EPA's determination of upwind emissions that
significantly contribute to nonattainment or interfere with maintenance
of the NAAQS downwind and should therefore be eliminated. This allows
EPA to then determine an enforceable emissions limit (often embodied in
the form of an emissions budget) for the covered sources. Emissions
budgets are the remaining allowable emissions after the elimination of
emissions identified as significantly contributing to nonattainment or
interfering with maintenance of the standard downwind.
    In both the CSAPR and the CSAPR Update, EPA focused its Step 3
analysis on EGUs. In the CSAPR Update, EPA did not quantify non-EGU
stationary source emissions reductions to address interstate ozone
transport for the 2008 ozone NAAQS for two reasons. First, EPA
explained that there was greater uncertainty in EPA's assessment of
non-EGU NOX mitigation potential, and that more time would
be required for states and EPA to improve non-EGU point source data and
pollution control assumptions before it could develop emission
reduction obligations based on that data. See 81 FR 74542. Second, EPA
explained that it did not believe that significant, certain, and
meaningful non-EGU NOX reduction was in fact feasible for
the 2017 ozone season. Id. In Wisconsin, the D.C. Circuit found that
the practical obstacles EPA identified with respect to its evaluation
of non-EGUs did not rise to the level of an ``impossibility,'' 938 F.3d
at 318-20. The court also found that EPA must make a higher showing of
uncertainty regarding non-EGU point-source NOX mitigation
potential before declining to regulate such sources on such a basis,
id. Therefore, as discussed in more detail in Section VII, in this
proposed action on remand from Wisconsin, EPA has included all major
stationary source sectors in the linked upwind states in its
``significant contribution'' analysis at Step 3 of the 4-step
framework.
    Step 4--CSAPR and the CSAPR Update established interstate trading
programs to implement the necessary emission reductions. Each state
subject to the program is assigned an emissions budget for the covered
sources. Emissions allowances are allocated to units covered by the
trading program, and the covered units then surrender allowances after
the close of each control period in an amount equal to their ozone
season EGU NOX emissions.
    EPA's trading programs under the good neighbor provision allow for
interstate trading. However, in order to ensure that each state
achieves reductions proportional to the level of their significant
contribution, beginning with the CSAPR, EPA established ``assurance
levels'' set as percentage of each state's budget (e.g., 121 percent)
above which emissions from sources in that state become subject to a
higher ``penalty'' surrender ratio. These assurance levels are designed
to allow for a certain level of year-to-year

variability within power sector emissions to account for fluctuations
in demand and EGU operations. The levels are therefore set by
determining a ``variability limit,'' calculated based on an analysis of
the historical level of variability in EGU operations.
    Thus, both the CSAPR and the CSAPR Update set assurance levels
equal to the sum of each state's emissions budget plus its variability
limit. The CSAPR and the CSAPR Update included assurance provisions to
limit state emissions to levels below 121 percent of the state's budget
by requiring additional allowance surrenders in the instance that
emissions in the state exceed this level. This limit on the degree to
which a state's emissions can exceed its budget is responsive to
previous court decisions (see discussion in section VIII.C.2 of this
preamble) and was not part of the CSAPR Update aspects remanded to EPA
in Wisconsin. EPA proposes to apply the same variability limits and
assurance provisions in this rulemaking.\70\ Implementation using a
CSAPR trading program is further described in section VIII of this
notice.
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    \70\ Historical heat input and NOX emissions in
states covered by the CSAPR programs may be found in the
``Historical CSAPR Update Emissions and Heat Input 2000 to
2019.xlsx'' file.
---------------------------------------------------------------------------

VI. Analyzing Downwind Air Quality and Upwind-State Contributions

    In this section, EPA describes the air quality modeling and
analyses performed to identify nonattainment and/or maintenance
receptors and evaluate interstate contributions to these receptors from
individual upwind states for the 2021 analytic year. Although the air
quality modeling was performed using an air quality modeling platform
that covers the contiguous 48 states, the analysis to identify
receptors and evaluate contributions focuses on the 21 upwind states
that are the subject of this rule.
    The year 2021 was selected as the appropriate future analytic year
for this rule because it coincides with the July 20, 2021, Serious area
attainment date under the 2008 ozone NAAQS. In the CSAPR Update, EPA
had aligned its analysis and implementation of emission reductions with
the 2017 ozone season (ozone seasons run each year from May 1-September
30) in order to assist downwind states with timely attainment of the
2008 ozone NAAQS by the Moderate area attainment date of July 20, 2018.
See 81 FR 74516. In order to demonstrate attainment by this deadline,
states were required to rely on design values calculated using ozone
season data from 2015 through 2017, since the July 20, 2018, deadline
did not afford enough time for measured data of the full 2018 ozone
season. Similarly, for the Serious area attainment date in 2021, states
will rely on design values calculated using ozone season data from 2018
through 2020. However, it is not possible to impose emission reductions
on upwind states in the 2020 ozone season, which has already passed.
Reductions in the 2021 ozone season will nonetheless occur in time for
the 2021 attainment date and therefore assist downwind states in
achieving attainment by the July 20, 2021 attainment date, in
compliance with the Wisconsin holding. See Wisconsin, 938 F.3d at 309
(the CSAPR Update is unlawful to the extent it allowed upwind states to
``continue their significant contributions to downwind air quality
problems beyond the statutory deadlines by which downwind States must
demonstrate their attainment of air quality standards'') (emphasis
added). Further, EPA continues to interpret the good neighbor provision
as forward-looking, based on Congress's use of the future-tense
``will'' in section 110(a)(2)(D)(i), an interpretation upheld in
Wisconsin, 938 F.3d at 322. It would be ``anomalous,'' id., for EPA to
impose good neighbor obligations in 2021 and future years based solely
on finding that ``significant contribution'' had existed at some time
in the past.
    EPA has also conducted additional analysis of remaining air quality
receptors and contribution in years beyond 2021, in order to ensure a
complete Step 3 analysis. EPA has analyzed these later years to
determine whether any additional emission reductions that are
impossible to obtain by the 2021 attainment date may yet be necessary
in order to fully address significant contribution. This comports with
the D.C. Circuit's direction in Wisconsin that implementing good
neighbor obligations beyond the dates established for attainment may be
justified on a proper showing of impossibility and/or necessity. See
938 F.3d at 320. However, for purposes of EPA's initial analysis of air
quality at Step 1 of the 4-step framework, in accordance with
Wisconsin, EPA has selected the 2021 ozone season, corresponding with
the 2021 Serious area attainment date.
    The remainder of this section includes information on (1) the air
quality modeling platform used in support of the proposed rule with a
focus on the base year and future year base case emission inventories,
(2) the method for projecting design values in 2021, and (3) the
approach for calculating ozone contributions from upwind states.\71\
The Agency also provides the design values for nonattainment and
maintenance receptors and the predicted interstate contributions that
are at or above the one percent of the NAAQS screening threshold. The
2016 base period and 2021, 2023, and 2028 future design values and
contributions for all ozone monitoring sites are provided in the docket
for this proposed rule. The Air Quality Modeling Technical Support
Document (AQM TSD) in the docket for this proposed rule contains more
detailed information on the air quality modeling aspects of this rule.
---------------------------------------------------------------------------

    \71\ For the 2023 and 2028 modeling used in the Step 3 analysis,
EPA followed the same method for projecting design values and
approach for calculating contributions as described for the 2021
analytic year.
---------------------------------------------------------------------------

A. Overview of Air Quality Modeling Platform

    EPA used the 2016-based modeling platform for the air quality
modeling for this proposed rule. This modeling platform includes 2016
base year emissions from anthropogenic and natural sources and 2016
meteorology. The platform also includes anthropogenic emission
projections for 2023 and 2028. The emissions data contained in this
platform were developed by EPA, Multi-Jurisdictional Organizations
(MJOs), and state and local air agencies as part of the Emissions
Inventory Collaborative Process. This process resulted in a common-use
set of emissions data for a 2016 base year and 2023 and 2028 that can
be leveraged by EPA and states for regulatory air quality modeling.\72\
The air quality modeling was performed for a modeling region (i.e.,
modeling domain) that covers the contiguous 48 states using a
horizontal resolution of 12 x 12 km. EPA used the CAMx version 7beta6
for air quality modeling since this was the most recent version of CAMx
available at the time the air quality modeling was performed.\73\
Additional information on the 2016-based air quality modeling platform
can be found in the AQM TSD.
---------------------------------------------------------------------------

    \72\ http://views.cira.colostate.edu/wiki/wiki/9169.
    \73\ Ramboll Environment and Health, May 2020, www.camx.com.
Note that CAMx v7beta6 is a pre-lease of version 7 that EPA used
because the official release of version 7 did not occur until May
2020, which was too late for use in the air quality modeling for
this proposal.
---------------------------------------------------------------------------

B. Emissions Inventories

    EPA developed emission inventories for this proposal, including
emission estimates for EGUs, non-EGU point sources, stationary nonpoint
sources,

onroad mobile sources, nonroad mobile sources, wildfires, prescribed
fires, and biogenic emissions that are not the result of human
activities. EPA's air quality modeling relies on this comprehensive set
of emission inventories because emissions from multiple source
categories are needed to model ambient air quality and to facilitate
comparison of model outputs with ambient measurements.
    To prepare the emission inventories for air quality modeling, EPA
processed the emission inventories using the Sparse Matrix Operator
Kernel Emissions (SMOKE) Modeling System version 4.7 to produce the
gridded, hourly, speciated, model-ready emissions for input to the air
quality model. Additional information on the development of the
emission inventories and on data sets used during the emissions
modeling process are provided in the Technical Support Document (TSD)
``Preparation of Emissions Inventories for the 2016v1 North American
Emissions Modeling Platform,'' hereafter known as the ``Emissions
Modeling TSD.'' This TSD is available in the docket for this rule and
at https://www.epa.gov/air-emissions-modeling/2016v1-platform.
1. Foundation Emission Inventory Data Sets
    Emissions data were developed that represented the year 2016 to
support air quality modeling of a base year from which future air
quality could be forecasted. As noted above, EPA used the Inventory
Collaborative 2016 version 1 (2016v1) Emissions Modeling Platform,
released in October 2019, as the primary basis for the inventories
supporting the air quality modeling. This platform was developed
through a national collaborative effort between EPA and state and local
agencies along with MJOs. The original starting point for the U.S.
portions of the 2016 inventory was the 2014 National Emissions
Inventory (NEI), version 2 (2014NEIv2), although all of the inventory
sectors were updated to better represent the year 2016 through the
incorporation of 2016-specific state and local data along with
nationally applied adjustment methods. The future base case inventories
developed for 2023 and 2028 represent projected changes in activity
data and predicted emission reductions from on-the-books actions,
planned emission control installations, and promulgated federal
measures that affect anthropogenic emissions.\74\
---------------------------------------------------------------------------

    \74\ Biogenic emissions and emissions from wildfires and
prescribed fires were held constant between 2016 and the future
years because (1) these emissions are tied to the 2016
meteorological conditions and (2) the focus of this rule is on the
contribution from anthropogenic emissions to projected ozone
nonattainment and maintenance.
---------------------------------------------------------------------------

2. Development of Emission Inventories for EGUs
    Annual NOX and SO2 emissions for EGUs in the
2016 base year inventory are based primarily on data from continuous
emission monitoring systems (CEMS) and other monitoring systems allowed
for use by qualifying units under 40 CFR part 75, with other EGU
pollutants estimated using emission factors and annual heat input data
reported to EPA. For EGUs not reporting under part 75, EPA used the
most recent data submitted to the NEI by the states. Emissions data for
sources that did not have data provided for the year 2016 were pulled
forward from data submitted for 2014. The Air Emissions Reporting Rule,
(80 FR 8787; February 19, 2015), requires that Type A point sources
large enough to meet or exceed specific thresholds for emissions be
reported to EPA every year, while the smaller Type B point sources must
only be reported to EPA every three years. For more information on how
the 2016 EGU emissions data were developed and prepared for air quality
modeling, see the Emissions Modeling TSD.
    EPA projected future 2023 and 2028 baseline EGU emissions using the
version 6--January 2020 reference case of the Integrated Planning Model
(IPM).75 76 IPM, developed by ICF Consulting, is a state-of-
the-art, peer-reviewed, multi-regional, dynamic, deterministic linear
programming model of the contiguous U.S. electric power sector. It
provides forecasts of least cost capacity expansion, electricity
dispatch, and emission control strategies while meeting energy demand
and environmental, transmission, dispatch, and reliability constraints.
EPA has used IPM for over two decades to better understand power sector
behavior under future business-as-usual conditions and to evaluate the
economic and emission impacts of prospective environmental policies.
The model is designed to reflect electricity markets as accurately as
possible. EPA uses the best available information from utilities,
industry experts, gas and coal market experts, financial institutions,
and government statistics as the basis for the detailed power sector
modeling in IPM. The model documentation provides additional
information on the assumptions discussed here as well as all other
model assumptions and inputs.\77\
---------------------------------------------------------------------------

    \75\ https://www.epa.gov/powersectormodeling.
    \76\ The 2016v1 platform released in October 2019 used the May
2019 reference case. The January 2020 IPM reference case is a later
version than what was released with 2016v1.
    \77\ Detailed information and documentation of EPA's Base Case,
including all the underlying assumptions, data sources, and
architecture parameters can be found on EPA's website at:
www.epa.gov/airmarkets/powersectormodeling.
---------------------------------------------------------------------------

    The IPM version 6--January 2020 reference base case accounts for
updated federal and state environmental regulations, committed EGU
retirements and new builds, and technology cost and performance
assumptions as of late 2019. This projected base case accounts for the
effects of the finalized Mercury and Air Toxics Standards rule, the
CSAPR and the CSAPR Update, New Source Review settlements, and other
on-the-books federal and state rules through 2019 \78\ impacting
SO2, NOX, directly emitted particulate matter,
and CO2, and final actions EPA has taken to implement the
Regional Haze Rule.
---------------------------------------------------------------------------

    \78\ For any specific version of IPM there is a cutoff date
after which it is no longer possible to incorporate updates into the
input databases. For version 6--January reference case, that cutoff
date was November 2019.
---------------------------------------------------------------------------

    Additional 2021 EGU emissions baseline levels were developed
through engineering analytics as an alternative approach that did not
involve IPM. EPA developed this inventory for use in Step 3 of this
proposed rulemaking, where it determines emission reduction potential
and corresponding emission budgets. IPM includes optimization and
perfect foresight in solving for least cost dispatch. Given that the
final rule will likely become effective either immediately prior to or
slightly after the start of the 2021 ozone season, EPA adopted a
similar approach to the CSAPR Update where it relied on IPM in a
relative way in Step 3 to avoid overstating optimization and dispatch
decisions that were not possible in the short time frame. EPA does this
by using the difference in emission rate observed between IPM runs with
and without the cost threshold applied, rather than using absolute
values. In both the CSAPR Update and in this rule at Step 3, EPA
complemented that projected IPM EGU outlook with historical (e.g.,
engineering analytics) perspective based on historical data that only
factors in known changes to the fleet. This 2021 engineering analytics
data set is described in more detail in the Ozone Transport Policy
Analysis TSD.
3. Development of Emission Inventories for non-EGU Point Sources
    The non-EGU point source emissions in the 2016 base case inventory
match those in the 2016v1 platform. Some non-EGU point source emissions
were based on data submitted for 2016, others were projected from 2014
to 2016, and

the emissions for remaining small sources were kept at 2014 levels.
Prior to air quality modeling, the emission inventories were processed
into a format that is appropriate for the air quality model to use.
Projection factors and percent reductions in this proposal reflect
comments received as a result of the Inventory Collaborative
development process, along with emission reductions due to national and
local rules, control programs, plant closures, consent decrees, and
settlements. Reductions from several Maximum Achievable Control
Technology and National Emission Standards for Hazardous Air Pollutants
(NESHAP) standards are included. Projection approaches for corn ethanol
and biodiesel plants, refineries and upstream impacts represent
requirements pursuant to the Energy Independence and Security Act of
2007 (EISA). Details on the development and processing of the non-EGU
emissions inventories for 2016, 2023, and 2028 are available in the
Emissions Modeling TSD.
    For aircraft emissions at airports, the emissions used were based
on adjustments to emissions in the 2017 NEI (see https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data
for data and a TSD). EPA developed and applied factors to adjust the
2017 emissions to 2016, 2023, and 2028 based on activity growth
projected by the Federal Aviation Administration Terminal Area Forecast
system, published in 2018.
    Emissions at rail yards were represented as non-EGU point sources.
The 2016 rail yard emissions are largely consistent with the 2017 NEI
rail yard emissions. The 2016, 2023, and 2028 rail yard emissions were
developed through the Inventory Collaborative process. The rail yard
emissions were interpolated from the 2016 and 2023 emissions. Class I
rail yard emissions were projected using the Energy Information
Administration's 2019 AEO freight rail energy use growth rate
projections for 2016, 2023, and 2028 with the fleet mix assumed to be
constant throughout the period.
    Point source oil and gas emissions for 2016 were based on the
2016v1 point inventory, while nonpoint oil and gas emissions were
primarily based on a run of EPA Oil and Gas Tool for the year 2016. The
2016 oil and gas inventories were projected to 2023 and 2028 using
regional projection factors by product type based on Annual Energy
Outlook (AEO) 2018 projections. NOX and VOC reductions that
are co-benefits to the NESHAP and New Source Performance Standards
(NSPS) for Stationary Reciprocating Internal Combustion Engines (RICE)
are reflected for select source categories. In addition, Natural Gas
Turbines and Process Heaters NSPS NOX controls and NSPS Oil
and Gas VOC controls are reflected for select source categories.
Additional information on the development and modeling of the oil and
gas emission inventories can be found in the Emissions Modeling TSD.
4. Development of Emission Inventories for Onroad Mobile Sources
    Onroad mobile sources include exhaust, evaporative, and brake and
tire wear emissions from vehicles that drive on roads, parked vehicles,
and vehicle refueling. Emissions from vehicles using regular gasoline,
high ethanol gasoline, diesel fuel, and electric vehicles were
represented, along with buses that used compressed natural gas. EPA
developed the onroad mobile source emissions for states other than
California using EPA's Motor Vehicle Emissions Simulator (MOVES) 2014b.
MOVES2014b was used with inputs provided by state and local agencies,
where available, in combination with nationally available data sets.
Onroad emissions for the platform were developed based on emissions
factors output from MOVES2014b run for the year 2016, coupled with
activity data (e.g., vehicle miles traveled and vehicle populations)
representing the year 2016. The 2016 activity data were provided by
some state and local agencies, and the remaining activity data were
derived from the 2014NEIv2. The onroad emissions were computed within
SMOKE by multiplying emission factors developed using MOVES with the
appropriate activity data. Onroad mobile source emissions for
California were consistent with the emissions provided by the state.
    The future-year emissions for onroad mobile sources represent all
national control programs known at the time of modeling except for the
Greenhouse Gas Emissions and Fuel Efficiency Standards for Medium- and
Heavy-Duty Engines and Vehicles--Phase 2 \79\ and the Safer Affordable
Fuel-Efficient (SAFE) Vehicles Rule.\80\ Finalized rules incorporated
into the onroad mobile source emissions include: Tier 3 Standards
(March 2014), the Light-Duty Greenhouse Gas Rule (March 2013), Heavy
(and Medium)-Duty Greenhouse Gas Rule (August 2011), the Renewable Fuel
Standard (February 2010), the Light Duty Greenhouse Gas Rule (April
2010), the Corporate-Average Fuel Economy standards for 2008-2011
(April 2010), the 2007 Onroad Heavy-Duty Rule (February 2009), and the
Final Mobile Source Air Toxics Rule (MSAT2) (February 2007). Estimates
of the impacts of rules that were in effect in 2016 are included in the
2016 base year emissions at a level that corresponds to the extent to
which each rule had penetrated into the fleet and fuel supply by the
year 2016. Local control programs such as the California LEV III
program are included in the onroad mobile source emissions. The future
year onroad emissions reflect projected changes to fuel properties and
usage. MOVES was run for the years 2023 and 2028 to generate the
emissions factors relevant to those years. Future year activity data
for onroad mobile sources were provided by some state and local
agencies, and otherwise were projected to 2023 and 2028 using AEO 2019-
based factors. The future year emissions were computed within SMOKE by
multiplying the future year emission factors developed using MOVES with
the year-specific activity data. Additional information on the approach
for generating the onroad mobile source emissions is available in the
Emissions Modeling TSD.
---------------------------------------------------------------------------

    \79\ The effect of the HDGHG Phase 2 rule on criteria pollutants
is estimated in Table 5-48 of the Regulatory Impact Analysis,
available from https://nepis.epa.gov/Exe/ZyPDF.cgi/P100P7NS.PDF?Dockey=P100P7NS.PDF.
    \80\ Information on the SAFE vehicles rule is available from
https://www.epa.gov/regulations-emissions-vehicles-and-engines/safer-affordable-fuel-efficient-safe-vehicles-final-rule.
Preliminary analysis by the Office of Transportation and Air Quality
of the impact of this rule on criteria pollutants show impacts of
less than 1 percent for VOC and no impact for NOX.
---------------------------------------------------------------------------

5. Development of Emission Inventories for Commercial Marine Vessels
    The commercial marine vessel (CMV) emissions in the 2016 base case
emission inventory for this rule were based on those in the 2017 NEI.
Factors were then applied to adjust the 2017 NEI emissions backward to
represent emissions for the year 2016. The CMV emissions reflect
reductions associated with the Emissions Control Area proposal to the
International Maritime Organization control strategy (EPA-420-F-10-041,
August 2010); reductions of NOX, VOC, and CO emissions for
new C3 engines that went into effect in 2011; and fuel sulfur limits
that went into effect prior to 2016. The cumulative impacts of these
rules through 2023 and 2028 were incorporated into the projected
emissions for CMV sources. The CMV emissions were split into emissions
inventories from the larger category 3 (C3) engines, and those from the
smaller category 1 and 2 (C1C2) engines. Some minor adjustments to the
CMV

emissions were implemented following the October 2019 2016v1 release.
These updated CMV inventories were released publicly by February,
2020.\81\
---------------------------------------------------------------------------

    \81\ See 2016 emissions, 2023 emissions, and 2028 emissions
under ftp://newftp.epa.gov/air/emismod/2016/v1/.
---------------------------------------------------------------------------

6. Development of Emission Inventories for Other Nonroad Mobile Sources
    Nonroad mobile source emission inventories (other than CMV,
locomotive, and aircraft emissions) were developed from monthly,
county, and process level emissions output from MOVES2014b. MOVES2014b
included important updates to nonroad engine population growth rates.
Types of nonroad equipment include recreational vehicles, pleasure
craft, and construction, agricultural, mining, and lawn and garden
equipment. State-submitted emissions data for nonroad sources were used
for California.
    EPA also ran MOVES2014b for 2023 and 2028 to prepare nonroad mobile
emissions inventories for future years. The nonroad mobile emission
control programs include reductions to locomotives, diesel engines, and
recreational marine engines, along with standards for fuel sulfur
content and evaporative emissions. A comprehensive list of control
programs included for mobile sources is available in the Emissions
Modeling TSD.
    Line haul locomotives are also considered a type of nonroad mobile
source but the emissions inventories for locomotives were not developed
using MOVES2014b. Year 2016 locomotive emissions were developed through
the Inventory Collaborative and are mostly consistent with those in the
2017 NEI. The projected locomotive emissions for 2023 and 2028 were
developed by applying factors to the base year emissions using activity
data based on 2018 AEO freight rail energy use growth rate projections
and emission rates adjusted to account for recent historic trends.
7. Development of Emission Inventories for Nonpoint Sources
    The emissions for stationary nonpoint sources in our 2016 base case
emission inventory are largely consistent with those in the 2014NEIv2,
although some were adjusted to more closely reflect year 2016 using
factors based on changes to human population from 2014 to 2016.
Stationary nonpoint sources include evaporative sources, consumer
products, fuel combustion that is not captured by point sources,
agricultural livestock, agricultural fertilizer, residential wood
combustion, fugitive dust, and oil and gas sources. For more
information on the nonpoint sources in the 2016 base case inventory,
see the Emissions Modeling TSD and the 2014NEIv2 TSD.
    Where states provided the Inventory Collaborative information about
projected control measures or changes in nonpoint source emissions,
those inputs were incorporated into the projected inventories for 2023
and 2028. Adjustments for state fuel sulfur content rules for fuel oil
in the Northeast were included. Projected emissions for portable fuel
containers reflect the impact of projection factors required by the
final MSAT2 rule and the EISA, including updates to cellulosic ethanol
plants, ethanol transport working losses, and ethanol distribution
vapor losses.
    For 2016, nonpoint oil and gas emissions inventories were developed
based on a run of EPA Oil and Gas Tool for 2016. To develop the future
year inventories, regional projection factors for nonpoint oil and gas
sources were developed by product type based on AEO 2018 projections to
2023 and 2028. Estimates of criteria air pollutant (CAP) co-benefit
reductions resulting from the NESHAP for RICE and NSPS rules and Oil
and Gas NSPS VOC controls for select source categories were included.
Additional details on the application of these rules and projections
for nonpoint sources are available in the Emissions Modeling TSD.

C. Air Quality Modeling and Analyses To Identify Nonattainment and
Maintenance Receptors

    In this section the Agency describes the air quality modeling and
analyses performed in Step 1 to identify locations where the Agency
expects there to be nonattainment or maintenance receptors for the 2008
8-hour ozone NAAQS in the 2021 analytic future year. Where EPA's
analysis shows that an area or site does not fall under the definition
of a nonattainment or maintenance receptor in 2021, that site is
excluded from further analysis under EPA's good neighbor framework.
    In this proposed rule, EPA is not reopening the approach used in
the CSAPR Update to identify nonattainment and maintenance receptors.
However, as an aid to understanding EPA's approach to identifying
receptors, a summary of this approach follows.
    EPA's approach gives independent effect to both the ``contribute
significantly to nonattainment'' and the ``interfere with maintenance''
prongs of section 110(a)(2)(D)(i)(I), consistent with the D.C.
Circuit's direction in North Carolina.\82\ Further, in its decision on
the remand of the CSAPR from the Supreme Court in the EME Homer City
case, the D.C. Circuit confirmed that EPA's approach to identifying
maintenance receptors in the CSAPR comported with the court's prior
instruction to give independent meaning to the ``interfere with
maintenance'' prong in the good neighbor provision. EME Homer City II,
795 F.3d at 136.
---------------------------------------------------------------------------

    \82\ 531 F.3d at 910-911 (holding that EPA must give
``independent significance'' to each prong of CAA section
110(a)(2)(D)(i)(I)).
---------------------------------------------------------------------------

    In the CSAPR Update, EPA identified nonattainment receptors as
those monitoring sites that are projected to have average design values
that exceed the NAAQS and that are also measuring nonattainment based
on the most recent monitored design values. This approach is consistent
with prior transport rulemakings, such as the NOX SIP Call
and CAIR, where EPA defined nonattainment receptors as those areas that
both currently monitor nonattainment and that EPA projects will be in
nonattainment in the future compliance year.\83\
---------------------------------------------------------------------------

    \83\ See 63 FR 57375, 57377 (October 27, 1998); 70 FR 25241
(January 14, 2005). See also North Carolina, 531 F.3d at 913-914
(affirming as reasonable EPA's approach to defining nonattainment in
CAIR).
---------------------------------------------------------------------------

    The Agency explained in the NOX SIP Call and CAIR and
then reaffirmed in the CSAPR Update that EPA has the most confidence in
our projections of nonattainment for those counties that also measure
nonattainment for the most recent period of available ambient data. EPA
separately identified maintenance receptors as those receptors that
would have difficulty maintaining the relevant NAAQS in a scenario that
takes into account historical variability in air quality at that
receptor. The variability in air quality was determined by evaluating
the ``maximum'' future design value at each receptor based on a
projection of the maximum measured design value over the relevant
period. EPA interprets the projected maximum future design value to be
a potential future air quality outcome consistent with the meteorology
that yielded maximum measured concentrations in the ambient data set
analyzed for that receptor (i.e., ozone conducive meteorology). EPA
also recognizes that previously experienced meteorological conditions
(e.g., dominant wind direction, temperatures, air mass patterns)
promoting ozone formation that led to maximum concentrations in the
measured data may reoccur in the future. The maximum design value

gives a reasonable projection of future air quality at the receptor
under a scenario in which such conditions do, in fact, reoccur. The
projected maximum design value is used to identify upwind emissions
that, under those circumstances, could interfere with the downwind
area's ability to maintain the NAAQS.
    Therefore, applying this methodology in this proposed rule, EPA
assessed the magnitude of the maximum projected design value for 2021
at each receptor in relation to the 2008 ozone NAAQS and, where such a
value exceeds the NAAQS, EPA determined that receptor to be a
``maintenance'' receptor for purposes of defining interference with
maintenance, consistent with the method used in the CSAPR and upheld by
the D.C. Circuit in EME Homer City II.\84\ That is, monitoring sites
with a maximum design value that exceeds the NAAQS are projected to
have a maintenance problem in 2021.
---------------------------------------------------------------------------

    \84\ See 795 F.3d at 136.
---------------------------------------------------------------------------

    Recognizing that nonattainment receptors are also, by definition,
maintenance receptors, EPA often uses the term ``maintenance-only'' to
refer to receptors that are not also nonattainment receptors.
Consistent with the methodology described above, monitoring sites with
a projected maximum design value that exceeds the NAAQS, but with a
projected average design value that is below the NAAQS, are identified
as maintenance-only receptors. In addition, those sites that are
currently measuring ozone concentrations below the level of the
applicable NAAQS, but are projected to be nonattainment based on the
average design value and that, by definition, are projected to have a
maximum design value above the standard are also identified as
maintenance-only receptors.
    As described above in section VI.B., EPA is using the 2016 and 2023
base case emissions developed under the EPA/MJO/state collaborative
project as the primary source for base year and 2023 future year
emissions data for this proposed rule. Because this platform does not
include emissions for 2021, EPA developed an interpolation technique
based on modeling for 2023 and measured ozone data to determine ozone
concentrations for 2021. To estimate average and maximum design values
for 2021, EPA first performed air quality modeling for 2016 and 2023 to
obtain design values in 2023. The 2023 design values were then coupled
with the corresponding 2016 measured design values to estimate design
values in 2021 using the interpolation technique described below.
    Consistent with EPA's modeling guidance,\85\ the 2016 and 2023 air
quality modeling results were used in a ``relative'' sense to project
design values for 2023. That is, the ratios of future year model
predictions to base year model predictions are used to adjust ambient
ozone design values \86\ up or down depending on the relative (percent)
change in model predictions for each location. The modeling guidance
recommends using measured ozone concentrations for the 5-year period
centered on the base year as the air quality data starting point for
future year projections. This average design value is used to dampen
the effects of inter-annual variability in meteorology on ozone
concentrations and to provide a reasonable projection of future air
quality at the receptor under ``average'' conditions. In addition, the
Agency calculated maximum design values from within the 5-year base
period to represent conditions when meteorology is more favorable than
average for ozone formation. Because the base year for the air quality
modeling used in this proposed rule is 2016, the base period 2014-2018
ambient ozone design value data was used in order to project average
and maximum design values in 2023.
---------------------------------------------------------------------------

    \85\ U.S. Environmental Protection Agency, 2018. Modeling
Guidance for Demonstrating Attainment of Air Quality Goals for
Ozone, PM2.5, and Regional Haze, Research Triangle Park,
NC. https://www.epa.gov/scram/state-implementation-plan-sip-attainment-demonstration-guidance.
    \86\ The ozone design value at a particular monitoring site is
the 3-year average of the annual 4th highest daily maximum 8-hour
ozone concentration at that site.
---------------------------------------------------------------------------

    The ozone predictions from the 2016 and 2023 air quality model
simulations were used to project 2014-2018 average and maximum ozone
design values to 2023 using an approach similar to the approach in
EPA's guidance for attainment demonstration modeling. This guidance
recommends using model predictions from the ``3 x 3'' array of grid
cells \87\ surrounding the location of the monitoring site to calculate
a Relative Response Factor (RRF) for that site.\88\ The 2014-2018
average and maximum design values were multiplied by the RRF to project
each of these design values to 2023. In this manner, the projected
design values are grounded in monitored data, and not the absolute
model-predicted 2023 concentrations. In light of comments on the Notice
of Data Availability (82 FR 1733; January 6, 2017) and other analyses,
EPA also projected 2023 design values based on a modified version of
the ``3 x 3'' approach for those monitoring sites located in coastal
areas. In this alternative approach, EPA eliminated from the RRF
calculations the modeling data in those grid cells that are dominated
by water (i.e., more than 50 percent of the area in the grid cell is
water) and that do not contain a monitoring site (i.e., if a grid cell
is more than 50 percent water but contains an air quality monitor, that
cell would remain in the calculation). The choice of more than 50
percent of the grid cell area as water as the criteria for identifying
overwater grid cells is based on the treatment of land use in the
Weather Research and Forecasting model (WRF).\89\ Specifically, in the
WRF meteorological model those grid cells that are greater than 50
percent overwater are treated as being 100 percent overwater. In such
cases the meteorological conditions in the entire grid cell reflect the
vertical mixing and winds over water, even if part of the grid cell
also happens to be over land with land-based emissions, as can often be
the case for coastal areas. Overlaying land-based emissions with
overwater meteorology may be representative of conditions at coastal
monitors during times of on-shore flow associated with synoptic
conditions and/or sea-breeze or lake-breeze wind flows. But there may
be other times, particularly with off-shore wind flow when vertical
mixing of land-based emissions may be too limited due to the presence
of overwater meteorology. Thus, for our modeling EPA calculated 2023
projected average and maximum design values at individual monitoring
sites based on both the ``3 x 3'' approach as well as the alternative
approach that eliminates overwater cells in the RRF calculation for
near-coastal areas (i.e., ``no water'' approach).
---------------------------------------------------------------------------

    \87\ As noted above, each model grid cell is 12 x 12 km.
    \88\ The relative response factor represents the change in ozone
based on emission changes at a given site. In order to calculate the
RRF, EPA's modeling guidance recommends selecting the 10 highest
ozone days in an ozone season at any given monitor in the base year,
noting which of the grid cells in the 3x3 array experienced the
highest ozone concentrations in the base year, and averaging those
ten highest concentrations. The model is then run using the
projected year emissions, in this case 2023, with all other model
variables held constant. Ozone concentrations from the same ten
days, in the same ten grid cells, are then averaged. The fractional
change between the base year (2011 model run) averaged ozone
concentrations and the future year (2023 model run) averaged ozone
concentrations represents the relative response factor.
    \89\ https://www.mmm.ucar.edu/weather-research-and-forecasting-model.
---------------------------------------------------------------------------

    The 2023 average and maximum design values for both the ``3 x 3''
and ``no water'' approaches were then paired

with the corresponding base period measured design values at each ozone
monitoring site. Design values for 2021 for both approaches were
calculated by linearly interpolating between the 2016 base period and
2023 projected values.\90\ The steps in the interpolation process for
estimating 2021 average and maximum design values are as follows:
---------------------------------------------------------------------------

    \90\ EPA examined the 2019 design values as a way to support the
set of monitoring sites that were identified as receptors based on
the 2021 interpolated design values. The outcome of this analysis
was that each of the five receptors in 2021 had 2019 measured design
values that exceeded the 2008 NAAQS. In addition, there are four
other monitoring sites in the eastern U.S. that are not projected to
be receptors in 2021, but that have 2019 design values that exceeded
the NAAQS. Because the measured design values at these sites are
only 1 or 2 ppb above the NAAQS, it is reasonable to assume that
these four sites will be clean by 2021--which is consistent with the
projections for these monitoring sites. Thus, the analysis of 2019
measured data and 2021 projections provides confidence in the
approach for identifying nonattainment/maintenance receptors in
2021.
---------------------------------------------------------------------------

    (1) Calculate the ppb change in design values between the 2016 base
period and 2023;
    (2) Divide the ppb change by 7 to calculate the ppb change per year
over the 7-year period between 2016 and 2023;
    (3) Multiply the ppb per year value by 5 to calculate the ppb
change in design values over the 5-year period between 2016 and 2021;
    (4) Subtract the ppb change between 2016 to 2021 from the 2016
design values to produce the design values for 2021.
    The projected 2021 and 2023 design values using both the ``3 x 3''
and ``no-water'' approaches are provided in the AQM TSD.\91\ EPA is
soliciting public comment on the use of the ``3 x 3'' and ``no water''
approaches for this rulemaking (Comment C-2). For this proposed rule,
EPA is relying upon design values based on the ``no water'' approach
for identifying nonattainment and maintenance receptors.
---------------------------------------------------------------------------

    \91\ Based on the 2021 design values, there are 129 monitoring
sites that have different design values based on the ``3 x 3''
approach vs the ``no-water'' approach. For these 129 monitoring
sites, the average difference is 0.41 ppb and the median difference
is 0.28 ppb. The average and median percent differences between the
``3 x 3'' and ``no-water'' design values at these 129 monitoring
sites are 0.65 percent and 0.52 percent, respectively. Thus, there
is not much difference in the design values between these two
approaches.
---------------------------------------------------------------------------

    Consistent with the truncation and rounding procedures for the 8-
hour ozone NAAQS, the projected design values are truncated to integers
in units of ppb.\92\ Therefore, projected design values that are
greater than or equal to 76 ppb are considered to be violating the 2008
ozone NAAQS. For those sites that are projected to be violating the
NAAQS based on the average design values in 2021, the Agency examined
the preliminary measured design values for 2019, which are the most
recent available measured design values at the time of this proposal.
As noted above, the Agency is proposing to identify nonattainment
receptors in this rulemaking as those sites that are violating the
NAAQS based on current measured air quality and also have projected
average design values of 76 ppb or greater. Maintenance-only receptors
include both (1) those sites with projected average design values above
the NAAQS that are currently measuring clean data and (2) those sites
with projected average design values below the level of the NAAQS, but
with projected maximum design values of 76 ppb or greater. In addition
to the maintenance-only receptors, the 2021 ozone nonattainment
receptors are also maintenance receptors because the maximum design
values for each of these sites is always greater than or equal to the
average design value. The monitoring sites that the Agency projects to
be nonattainment and maintenance receptors for the ozone NAAQS in the
2021 base case are used for assessing the contribution of emissions in
upwind states to downwind nonattainment and maintenance of ozone NAAQS
as part of this proposal.
---------------------------------------------------------------------------

    \92\ 40 CFR part 50, Appendix P to part 50--Interpretation of
the Primary and Secondary National Ambient Air Quality Standards for
Ozone.
---------------------------------------------------------------------------

    Table VI.C-1 contains the 2014-2018 base period average and maximum
8-hour ozone design values, the 2021 base case average and maximum
design values,\93\ and the 2019 preliminary design values for the two
sites that are projected to be nonattainment receptors in 2021 and the
two sites that are projected to be maintenance-only receptors in
2021.\94\ The design values for all monitoring sites in the U.S. are
provided in the docket for this rule. Additional details on the
approach for projecting average and maximum design values are provided
in the AQM TSD.
---------------------------------------------------------------------------

    \93\ The design values for 2021 in this table are based on the
``no water'' approach.
    \94\ Using design values from the ``3 x 3'' approach does not
change the total number of receptors in 2021. However, with the ``3
x 3'' approach the maintenance-only receptor in New Haven County, CT
has a projected maximum design value of 75.5 ppb and would,
therefore, not be a receptor using this approach. In contrast,
monitoring site 090010017 in Fairfield County, CT has projected
average and maximum design value of 75.7 and 76.3 ppb, respectively,
with the ``3 x 3'' approach and would, therefore, be a maintenance-
only receptor with this approach.

     Table VI.C-1--Average and Maximum 2014-2018 and 2021 Base Case 8-Hour Ozone Design Values and 2019 Preliminary Design Values (ppb) at Projected
                                                        Nonattainment and Maintenance-Only Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          Average design  Maximum design
            Monitor ID                    State              Site           value 2014-     value 2014-   Average design  Maximum design    2019 Design
                                                                               2018            2018         value 2021      value 2021         value
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                 Nonattainment Receptors
--------------------------------------------------------------------------------------------------------------------------------------------------------
090013007.........................  CT                Stratford.........            83.0              83            76.5            77.4              82
090019003.........................  CT                Westport..........            82.7              83            78.5            78.9              82
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Maintenance-Only Receptors
--------------------------------------------------------------------------------------------------------------------------------------------------------
090099002.........................  CT                Madison...........            79.7              82            74.0            76.1              82
482010024.........................  TX                Houston...........            79.3              81            75.5            77.1              81
--------------------------------------------------------------------------------------------------------------------------------------------------------

D. Pollutant Transport From Upwind States

1. Air Quality Modeling To Quantify Upwind State Contributions
    This section documents the procedures EPA used to quantify the
impact of emissions from specific upwind states on 2021 8-hour design
values for the identified downwind nonattainment and maintenance
receptors. 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 strength 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.
    EPA performed nationwide, state-level ozone source apportionment
modeling using the CAMx Ozone Source Apportionment Technology/
Anthropogenic Precursor Culpability Analysis (OSAT/APCA) technique \95\
to quantify the contribution of 2023 base case NOX and VOC
emissions from all sources in each state to projected 2023 ozone design
values at air quality monitoring sites. The CAMx OSAT/APCA model run
was performed for the period May 1 through September 30 using the
projected 2023 base case emissions and 2016 meteorology for this time
period. As described below, 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).
---------------------------------------------------------------------------

    \95\ As part of this technique, ozone formed from reactions
between biogenic VOC and anthropogenic NOX or biogenic
NOX and anthropogenic VOC are assigned to the
anthropogenic emissions. This approach is designed to fully capture
as part of the anthropogenic contribution the total amount of ozone
formed from photochemical reactions that involve emissions from all
anthropogenic sources. In this manner, ozone is assigned to the
controllable (i.e., anthropogenic) precursors that react with non-
controllable (i.e., biogenic) precursors.
---------------------------------------------------------------------------

    To determine upwind contributions in 2021 the Agency applied the
contributions from the 2023 modeling in a relative manner to the 2021
ozone design values. The analytic steps in the process 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 concentrations for each of the
top 10 modeled ozone concentration days in 2023 \96\ and then divide
the average contribution by the corresponding concentration to obtain a
Relative Contribution Factor (RCF) for each monitoring site; and
---------------------------------------------------------------------------

    \96\ The number of days used in calculating the average
contribution metric has historically been determined in a manner
that is generally consistent with EPA's recommendations for
projecting future year ozone design values. Our ozone attainment
demonstration modeling guidance at the time of CSAPR recommended
using all model-predicted days above the NAAQS to calculate future
year design values (https://www3.epa.gov/ttn/scram/guidance/guide/final-03-pm-rh-guidance.pdf). In 2014 EPA issued draft revised
guidance that changed the recommended number of days to the top-10
model predicted days (https://www3.epa.gov/ttn/scram/guidance/guide/Draft-O3-PM-RH-Modeling_Guidance-2014.pdf). For CSAPR Update we
transitioned to calculating design values based on this draft
revised approach. The revised modeling guidance was finalized in
2019 and, in this regard, we are calculating both the ozone design
values and the contributions based on a top-10 day approach (https://www3.epa.gov/ttn/scram/guidance/guide/O3-PM-RH-Modeling_Guidance-2018.pdf).
---------------------------------------------------------------------------

    (3) Multiply the 2021 design values by the 2023 RCF at each site to
produce the average contribution metric values in 2021.\97\ The
resulting 2021 contributions from each tag to each monitoring site in
the U.S. along with additional details on the source apportionment
modeling and the procedures for calculating contributions can be found
in the AQM TSD.
---------------------------------------------------------------------------

    \97\ The method for calculating the average contribution metric
values in 2021 was also applied to 2023 and 2028 based on the
projected design values and contribution modeling for each of those
years, respectively.
---------------------------------------------------------------------------

    In the source apportionment model run, 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 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 (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.
    The average contribution metric is intended to provide a reasonable
representation of the contribution from individual states to the
projected 2021 design value, 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 largest contribution from each state that is the subject of
this rule to 8-hour ozone nonattainment and maintenance receptors in
downwind states in 2021 is provided in Table VI.D-1.

  Table VI.D-1.--Largest Contribution to Downwind 8-Hour Ozone Nonattainment and Maintenance Receptors in 2021.
----------------------------------------------------------------------------------------------------------------
                                                                            Largest downwind   Largest downwind
                                                                            contribution to     contribution to
                               Upwind state                                  nonattainment     maintenance-only
                                                                             receptors for       receptors for
                                                                              ozone (ppb)         ozone (ppb)
----------------------------------------------------------------------------------------------------------------
Alabama..................................................................               0.11                0.27
Arkansas.................................................................               0.18                0.15
Illinois.................................................................               0.81                0.80
Indiana..................................................................               1.26                1.08
Iowa.....................................................................               0.17                0.22
Kansas...................................................................               0.13                0.11
Kentucky.................................................................               0.87                0.79
Louisiana................................................................               0.27                4.68
Maryland.................................................................               1.21                1.56
Michigan.................................................................               1.71                1.62
Mississippi..............................................................               0.10                0.37
Missouri.................................................................               0.36                0.33
New Jersey...............................................................               8.62                5.71
New York.................................................................              14.44               12.54
Ohio.....................................................................               2.55                2.35
Oklahoma.................................................................               0.20                0.14
Pennsylvania.............................................................               6.86                5.64
Texas....................................................................               0.59                0.36
Virginia.................................................................               1.30                1.69
West Virginia............................................................               1.49                1.55
Wisconsin................................................................               0.23                0.23
----------------------------------------------------------------------------------------------------------------

2. Application of Screening Threshold
    EPA evaluated the magnitude of the contributions from each upwind
state to downwind nonattainment and maintenance receptors. In Step 2 of
the good neighbor framework, 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 of the CSAPR Update states to each downwind nonattainment
and/or maintenance receptor that were used for the Step 2 evaluation
can be found in the AQM TSD.
    As discussed above in section V, EPA is not reopening the air
quality screening threshold of 1 percent of the NAAQS used in the CSAPR
Update. Therefore, as in the CSAPR Update, EPA uses an 8-hour ozone
value for this air quality threshold of 0.75 ppb as the quantification
of 1 percent of the 2008 ozone NAAQS.
a. States That Contribute Below the Screening Threshold
    Of the 21 states that are the subject of this proposed rule, EPA
has determined that the contributions from each of the following states
to nonattainment and/or maintenance-only receptors in the 2021 analytic
year are below the threshold: Alabama, Arkansas, Iowa, Kansas,
Mississippi, Missouri, Oklahoma, Texas, and Wisconsin. Because these
states are considered not to contribute to projected downwind air
quality problems, EPA proposes to determine that the CSAPR Update FIPs
for these states (or, in the case of Alabama and Missouri, the SIP
revisions later approved to replace the states' CSAPR Update FIPs) are
a complete remedy to address their significant contribution under the
good neighbor provision for the 2008 ozone NAAQS. These states remain
subject to the ozone season NOX emission budgets established
in the CSAPR Update, and EPA is not reopening the determinations in the
CSAPR Update regarding these states.\98\
---------------------------------------------------------------------------

    \98\ EPA notes that the updated modeling establishing that these
states no longer contribute as of 2021 assumes in its baseline the
continued implementation of the CSAPR Update budgets in these
states.
---------------------------------------------------------------------------

    However, for each of these states, EPA notes that updates to the
air quality and contributions analysis for the final rule could change
the analysis as to which states have contributions to downwind
receptors that meet or exceed the contribution screening threshold. In
the event that such analysis conducted for the final rule demonstrates
that any of those states that contribute amounts below the threshold in
the proposal are projected to contribute amounts greater than or equal
to the threshold in the final rule analysis, EPA proposes to apply the
same Step 3 analysis applied to the linked states in this proposal and
may finalize revised emissions budgets or other requirements (as
presented for comment in this proposal) for such states. In order to
ensure adequate notice of the potential for this change in our analysis
between proposal and final and any resulting emission reduction
obligations, EPA has calculated emissions budgets for EGUs in each of
these nine states applying the same methodology and determinations used
for the linked states in the Step 3 analysis described below. In
addition, EPA would anticipate extending its proposed assessment of
non-EGU sources (and associated requests for comment) for linked states
to these states. Any adjustments in the implementation of the emissions
budgets at Step 4 for linked states would also apply in these states.
EPA is proposing to extend and apply any such analysis and/or
emissions-reduction budgets to these states if, and only if, the final
rule air quality modeling and other air quality and contribution
analysis identifies a linkage as just described. The updated ozone
season NOX emission budgets that may be applied in these
states are available in the Ozone Transport Policy Analysis TSD.

b. States That Contribute at or Above the Screening Threshold

    In this proposed rule, states with remanded emission budgets under
the CSAPR Update that contribute to a specific receptor in an amount at
or above the screening threshold in 2021 are considered linked to that
receptor. The ozone contributions and emissions (and available emission
reductions) for these states are analyzed further at Step 3, as
described in section VII, to determine whether and to what extent
emissions reductions might be required from each state.
    Based on the maximum downwind contributions in Table VI.D-1, the
Step 2 analysis identifies that the following 11 states contribute at
or above the 0.75 ppb threshold to downwind nonattainment receptors:
Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, New York,
Ohio, Pennsylvania, Virginia, and West Virginia. Based on the maximum
downwind contributions in Table VI.D-1, the following 12 states
contribute at or above the 0.75 ppb threshold to downwind maintenance-
only receptors: Illinois, Indiana, Kentucky, Louisiana, Maryland,
Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West
Virginia. The levels of contribution between each of these linked
upwind state and downwind nonattainment receptors and maintenance-only
receptors are provided in Table VI.D-2 and Table VI.D-3, respectively.

    Table VI.D-2--Contribution (ppb) From Each Linked Upwind State to
                Downwind Nonattainment Receptors in 2021
------------------------------------------------------------------------
                                              Nonattainment receptors
              Upwind state               -------------------------------
                                           Stratford, CT   Westport, CT
------------------------------------------------------------------------
Illinois................................            0.69            0.81
Indiana.................................            0.99            1.26
Kentucky................................            0.78            0.87
Louisiana...............................            0.27            0.27
Maryland................................            1.21            1.20
Michigan................................            1.16            1.71
New Jersey..............................            7.70            8.62
New York................................           14.42           14.44
Ohio....................................            2.34            2.55
Pennsylvania............................            6.72            6.86
Virginia................................            1.29            1.30
West Virginia...........................            1.45            1.49
------------------------------------------------------------------------

    Table VI.D-3--Contribution (ppb) From Each Linked Upwind State to
               Downwind Maintenance-Only Receptors in 2021
------------------------------------------------------------------------
                                            Maintenance-only receptors
              Upwind state               -------------------------------
                                            Madison, CT     Houston, TX
------------------------------------------------------------------------
Illinois................................            0.80            0.02
Indiana.................................            1.08            0.02
Kentucky................................            0.79            0.02
Louisiana...............................            0.15            4.68
Maryland................................            1.56            0.00
Michigan................................            1.62            0.00
New Jersey..............................            5.71            0.00
New York................................           12.54            0.00
Ohio....................................            2.35            0.00
Pennsylvania............................            5.64            0.00
Virginia................................            1.69            0.00
West Virginia...........................            1.55            0.00
------------------------------------------------------------------------

    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. EPA proposes that the following 12 States are linked at Step 2:
Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey,
New York, Ohio, Pennsylvania, Virginia, and West Virginia.

VII. Quantifying Upwind-State NOX Reduction Potential To
Reduce Interstate Ozone Transport for the 2008 Ozone NAAQS

A. The Multi-Factor Test

    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. This analysis focuses on the 12 states linked at steps 1 and 2 of
the framework, as identified in the sections above. Following the
existing framework as applied in the CSAPR Update, EPA's assessment of
linked upwind state emissions reflects analysis of uniform
NOX emission control stringency. The analysis has been
extended to include assessment of non-EGU sources in addition to EGU
sources in the linked upwind states.
    Each level of uniform NOX control stringency is
represented by an estimated cost per ton of NOX reduced and
is characterized by a set of pollution control measures. EPA applies a
multi-factor test--the same multi-factor test that was used in the
CSAPR and the CSAPR Update \99\--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 emission reductions, and downwind air quality
impacts to determine the appropriate level of uniform NOX
control stringency that addresses the impacts of interstate transport
on downwind nonattainment or maintenance receptors. The uniform
NOX emission control stringency, represented by marginal
cost (or a weighted average cost in the case of EPA's non-EGU
analysis), 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 EPA v. EME Homer City Generation,
which held that using such an approach to apportion emission 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. There are four stages in
developing the multi-factor test: (1) Identify levels of uniform
NOX control stringency, represented by an estimated cost-
per-ton of control that is applied across linked upwind states; (2)
evaluate potential NOX emission 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 emission
reductions, and downwind air quality impacts, while also ensuring that
emission reductions do not unnecessarily over-control relative to the
contribution threshold or downwind air quality.
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    \99\ See CSAPR, Final Rule, 76 FR 48208 (Aug. 8, 2011).
---------------------------------------------------------------------------

    For both EGUs and non-EGUs, section VII.B describes the available
mitigation technologies considered and their associated cost levels.
Section VII.C discusses EPA's application of that information to assess
emission reduction potential of the identified control strategies.
Finally, section VII.D describes EPA's assessment of associated air
quality impacts and EPA's subsequent identification of appropriate
control stringencies considering the relevant factors (cost, available
emission reductions, and downwind air quality impacts). As discussed in
greater detail in section VII.D, EPA's multi-factor test informed EPA's
determination of

appropriate EGU NOX ozone season emission budgets necessary
to reduce emissions that significantly contribute to nonattainment or
interfere with maintenance of the 2008 ozone NAAQS for the 2021 ozone
season and subsequent control periods. Application of the multi-factor
test to non-EGU sources has led EPA to propose to conclude that
emissions reductions from non-EGU sources are not necessary to address
significant contribution under the 2008 ozone NAAQS. In light of
uncertainty in its current information on emissions, existing controls
on emissions sources, and emission-reduction potential for non-EGU
sources, however, EPA requests comment on its analysis, and whether,
based on updated or more complete information, there may be grounds to
find non-EGU emissions reductions are necessary to address significant
contribution for the 2008 ozone NAAQS (Comment C-3).
    This multi-factor approach is consistent with EPA's approach in the
prior CSAPR and CSAPR Update actions. In addition, as was done in the
CSAPR Update, EPA evaluated possible over-control by determining if an
upwind state is linked solely to downwind air quality problems that
could have been resolved at a lower cost threshold, or if upwind states
could reduce their emissions below the 1 percent air quality
contribution threshold at a lower cost threshold. This analysis is
described in section VII.D below.

B. Identifying Levels of Control Stringency

1. EGU NOX Mitigation Strategies
    In identifying levels of uniform control stringency for EGUs, EPA
reassessed the same NOX control strategies that it had
analyzed in the 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) turning on existing
idled Selective Non-Catalytic Reduction (SNCRs); (4) installing new
SNCRs; and (5) installing new SCRs. For the reasons explained in the
EGU NOX Mitigation Strategies TSD included in the docket for
this proposed action, EPA determined that for the regional, multi-state
scale of this rulemaking, only EGU NOX control strategies 1
and 3 are possible for the 2021 ozone season (fully operating existing
SCRs, including both optimizing NOX removal by existing
operational SCRs and turning on and optimizing existing idled SCRs; and
turning on existing idled SNCRs). As discussed in section VII.B.1.b,
EPA notes that it is not possible to install state-of-the-art
NOX combustion controls by the beginning of the 2021 ozone
season on a regional scale. EPA considers state-of-the-art
NOX combustion controls at EGUs to be available by the
beginning of the 2022 ozone season.
    The following subsections describe EPA's identification of uniform
levels of NOX emission control stringencies, each
represented by an estimated marginal cost per ton of NOX
reduced (in 2016$) and characterized by a set of EGU mitigation
technologies.
a. $1,600 per Ton, Representing 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, most operators improved their SCR performance and
have continued to maintain that level of improved operation. However,
this SCR performance is not universal and some drop has been observed
as the CSAPR Update ozone-season allowance price has declined steadily
since 2017. For example, recent power sector data from 2019 reveal
that, in some cases, operating units have SCR controls that have been
idled or are operating partially, and therefore suggest that there
remains reduction potential through optimization.\100\ EPA finds that
optimizing all of these remaining SCRs in the 12 linked states is a
readily available approach for EGUs to reduce NOX emissions.
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    \100\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason.
---------------------------------------------------------------------------

    EPA identifies $1,600 per ton as a level of uniform control
stringency that represents optimizing SCR controls. EPA's analysis of
this level of uniform control stringency is informed by comment on the
CSAPR Update proposal and updated information on operation and
industrial-input costs that have become available since the CSAPR
Update.\101\ While the costs of optimizing existing, operational SCRs
include only variable costs, the cost of optimizing SCR units that are
currently idled back into service considers both variable and fixed
costs. 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. EPA performed an in-depth cost
assessment for all coal-fired units with SCRs. More information about
this analysis is available in the EGU NOX Mitigation
Strategies Proposed Rule TSD, which is found in the docket for this
proposed rule. The TSD notes that, for the subset of SCRs that are
already partially operating, the cost of optimizing is often much lower
than the $1,600 per ton marginal cost and often under $800 per ton.
---------------------------------------------------------------------------

    \101\ The CSAPR Update found $1,400 per ton was a level of
uniform control stringency that represented turning on idled SCR
controls. EPA uses the same costing methodology, but updating for
input cost increases (e.g., urea reagent) to arrive at $1,600 per
ton in this proposal (while also updated from 2011 dollars to 2016
dollars).
---------------------------------------------------------------------------

    EPA is using the same methodology to identify SCR performance as it
did in the CSAPR Update rule. To estimate EGU NOX reduction
potential from optimizing, EPA considers the difference between the
non-optimized NOX emission rates and an achievable operating
and optimized SCR NOX emission rate. To determine this rate
in the CSAPR Update, EPA evaluated nationwide coal-fired EGU
NOX ozone season emissions data from 2009 through 2015 and
calculated an average NOX ozone season emission rate across
the fleet of coal-fired EGUs with SCR for each of these seven years.
EPA found it prudent to not consider the lowest or second-lowest ozone
season NOX emission rates, which may reflect new SCR systems
that have all new components (e.g., new layers of catalyst). Data from
these new systems are not representative of ongoing achievable
NOX emission rates considering broken-in components and
routine maintenance schedules. To identify the potential reductions
from SCR optimization in this proposed action, EPA followed the same
methodology and incorporated the latest reported coal-fired EGU
NOX ozone season emissions data. EPA updated the timeframe
to include the most recent and best available operational data (i.e.,
2009 up through 2019). Considering the emissions data over the full
time period of available data results in a third-best rate of 0.08
Pounds per Million British Thermal Units (lb/mmBtu). EPA notes that
over half of the SCR-controlled EGUs achieved a NOX emission
rate of 0.068 lbs/mmBtu or less over their third-best entire ozone
season. Moreover, for the SCR-controlled coal units that EPA identified
as having a 2019 emission rate greater than 0.08 lb/mmBtu, EPA verified
that in prior years, the majority (over 90 percent) of these

same units had demonstrated and achieved a NOX emission rate
of 0.08 lb/mmBtu or less on a seasonal and/or monthly basis. This
further supports EPA's determination that 0.08 lb/mmBtu reflects a
reasonable emission rate for representing SCR optimization in
quantifying state emission budgets as discussed in section VIII.B. This
fleet-level emission rate assumption of 0.08 lb/mmBtu for non-optimized
units reflects, on average, what those units would achieve when
optimized. Some of these units may achieve rates that are lower than
0.08 lb/mmBtu, and some units may operate above that rate based on
unit-specific configuration and dispatch patterns. EPA evaluated the
feasibility of optimizing idled SCRs for the 2021 ozone season. Based
on past practice, EPA finds that idled controls can be restored to
operation quickly (less than two months). This timeframe is informed by
many electric utilities' previous long-standing practice of utilizing
SCRs to reduce EGU NOX emission 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.\102\ Therefore, EPA believes that SCR
optimization mitigation strategies are available for the 2021 ozone
season.
---------------------------------------------------------------------------

    \102\ 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 emission 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 12
linked states) are already partially operating these controls during
the ozone season based on historical 2019 emissions rates. EPA believes
that this widely demonstrated seasonal behavior of turning on idled
SCRs also supports the Agency's finding that optimizing existing SCR
systems currently being operated to some degree within the ozone
season, which would necessitate fewer changes to SCR operation relative
to restarting idled systems, is also feasible for the 2021 ozone
season. Full operation of existing SCRs that are already operating to
some extent involves increasing reagent (i.e., ammonia or urea) flow
rate, and maintaining and replacing catalyst to sustain higher
NOX removal rate operations. Increasing NOX
removal by SCR controls that are already operating can be implemented
by procuring more reagent and catalyst. EGUs with SCR routinely procure
reagent and catalyst as part of ongoing operation and maintenance of
the SCR system. In many cases, where EPA has identified EGUs that are
operating their SCR at non-optimized NOX removal
efficiencies, EGU data indicate that these units historically have
achieved more efficient NOX removal rates. Therefore, EPA
finds that optimizing existing SCRs currently being operated could
generally be done by reverting back to previous operation and
maintenance plans. Regarding full operation activities, existing SCRs
that are only operating at partial capacity still provide functioning,
maintained systems that may only require increased chemical reagent
feed rate up to their design potential and catalyst maintenance for
mitigating NOX emissions. Units must have adequate inventory
of chemical reagent and catalyst deliveries to sustain operations.
Considering that units have procurement programs in place for operating
SCRs, this may only require updating the frequency of deliveries. This
may be accomplished within a few weeks.
b. $1,600 per Ton, Representing Installing State-of-the-Art
NOX Combustion Controls
    EPA also includes installing state-of-the-art combustion controls
in the level of uniform control stringency 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 and/or updated
quickly and can substantially reduce EGU NOX emissions. In
the 12 states linked to downwind receptors under this proposed rule,
approximately 99 percent of coal-fired EGU capacity is equipped with
some form of combustion control; however, the control configuration
and/or corresponding emission rates at some units indicate they may not
currently have state-of-the-art combustion control technology.
Upgrading existing combustion controls to state-of-the-art combustion
control alone can achieve NOX emission rates of 0.139 to
0.155 lbs/mmBtu,\103\ and, once installed, reduce NOX
emissions at all times of EGU operation. EPA proposes that the
installation of state-of-the-art combustion controls is a readily
available approach for EGUs to reduce NOX emissions by the
start of the 2022 ozone season.
---------------------------------------------------------------------------

    \103\ Details of EPA's assessment of state-of-the-art
NOX combustion controls are provided in the EGU
NOX Mitigation Strategies Proposed Rule TSD.
---------------------------------------------------------------------------

    EPA also finds that, generally, state-of-the-art combustion control
upgrades require a short installation time--as little as four weeks to
install with a scheduled outage (with permitting, design, order
placement, fabrication, and delivery occurring beforehand). Feasibility
of installing combustion controls was examined by EPA in CSAPR where
industry demonstrated the ability to install state-of-the-art LNB
controls on a large unit (800 MW) in under six months. EPA received
comments in the CSAPR Update on installation of combustion controls
from the Institute of Clean Air Companies.\104\ Commenters provided
information on the equipment and typical installation time frame for
new combustion controls, accounting for all steps, and noted 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 was described as:
---------------------------------------------------------------------------

    \104\ EPA-HQ-OAR-2015-0500-0093
---------------------------------------------------------------------------

     4-8 weeks--bid evaluation
     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 previous comments and EPA observations on past installations,
EPA does not believe that it is possible to obtain installation of
these controls between rule finalization and the start of the 2021
ozone season. However, EPA does believe the technology could be
installed by the start of the 2022 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. 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 70 percent. See the NOX Mitigation Strategies
Proposed Rule TSD for additional details. In specifying a
representative marginal cost at which state-of-the-art combustion
controls are widely available, EPA considered all of these estimated
costs and finds that the cost is typically comparable to the EGU
NOX control stringency of $1,600 per ton, and hence EPA
includes installing state-of-the-art NOX combustion controls
in the uniform control stringency level represented by $1,600 per ton
of NOX removed.
c. $3,900 per ton, Representing Turning on Idled Existing SNCRs
    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). These controls are
in use to some degree across the U.S. power sector. In the 12 states
identified in this proposed rule, approximately 14 percent of coal-
fired EGU capacity is equipped with SNCR. Recent power sector data
suggest that, in some cases, SNCR controls have been idled or operating
less in 2019 relative to performance in prior years.\105\ EPA finds
that turning on idled SNCRs is an available approach for EGUs to reduce
NOX emissions, and similar to restarting idled SCR controls,
could be done in time for the 2021 ozone season.
---------------------------------------------------------------------------

    \105\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason
---------------------------------------------------------------------------

    EPA identifies $3,900 per ton as a level of uniform control
stringency that represents turning on and fully operating idled SNCRs.
For existing SNCRs that have been idled, unit operators may need to
restart payment of some fixed and variable costs associated with these
controls. Fixed and variable costs include labor, maintenance and
repair, parasitic load, and ammonia or urea. The majority of the total
fixed and variable operating costs for SNCR is related to the cost of
the reagent used (e.g., ammonia or urea) and the resulting cost per ton
of NOX reduction is sensitive to the NOX rate of
the unit prior to SNCR operation. For more details on this assessment,
refer to the EGU NOX Mitigation Strategies Proposed Rule TSD
in the docket for this proposed rule.
d. $5,800 per ton, Representing Installing New SNCRs.
    The amount of time needed to retrofit an EGU with new SNCR extends
beyond the 2021 Serious area attainment date. However, similar to SCR
retrofits discussed in section VII.B.1.e, and consistent with the
Wisconsin decision, EPA evaluated potential emission reductions and
associated costs from this control technology, and assessed the impacts
and need for this emissions control strategy at the earliest point in
time when post combustion control installation could be achieved. SNCR
installations, while generally having shorter project timeframes (i.e.,
as little as 16 months for an individual power plant installing
controls on more than one boiler), share similar implementation steps
with and also need to account for the same regional factors as SCR
installations.\106\ For example, SNCR installation at the Jeffrey power
plant (Kansas) was in the planning phase in 2013 but not in service
until 2015.\107\ Therefore, EPA finds that more than 16 months would be
needed to complete all necessary steps of SNCR development at EGUs on a
regional scale. EPA discusses the timing of SNCR and SCR post-
combustion retrofits together and in more detail in section VII.C.1.
---------------------------------------------------------------------------

    \106\ A month-by-month evaluation of SNCR installation is
discussed in EPA's ``Engineering and Economic Factors Affecting the
Installation of Control Technologies for Multipollutant Strategies''
at Exhibit A-6 and in EPA's NOX Mitigation Strategies
TSD. As noted at proposal, 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 final action is consistent with this more complete timeframe
estimated by the analysis in the exhibit.
    \107\ 2013 EIA Form 860, Schedule 6, Environmental Control
Equipment.
---------------------------------------------------------------------------

    SNCR technology provides owners a relatively less capital-intensive
option for reducing NOX emissions compared to SCR
technology, albeit at the expense of higher operating costs on a per-
ton basis and less total emission reduction potential. EPA examined the
remaining nationwide coal-fired fleet that lack SNCR or other
NOX post-combustion control to estimate a representative
cost of SNCR installation (on a $ per ton basis). Costs were estimated
using the operating and unit characteristics specific to this fleet. As
described in the NOX Mitigation Strategies Proposed Rule
TSD, EPA proposes that $5,800 per ton is the representative cost of
these controls reflecting a cost level at which they are available for
a majority of the uncontrolled fleet.
e. $9,600 per ton, Representing Installing New SCRs.
    The amount of time needed to retrofit an EGU with new SCR extends
beyond the 2021 Serious area attainment date. However, similar to SNCR
retrofits discussed above, and consistent with the Wisconsin decision,
EPA evaluated potential emission reductions and associated costs from
this control technology, as well as assessed the impacts and need for
this emissions control strategy at the earliest point in time when
their installation could be achieved. The amount of time to retrofit
EGUs with new SCR varies between approximately 2 and 4 years depending
on site-specific engineering considerations and on the number of
installations being considered. In prior actions, EPA has noted 39-48
months as appropriate for regionwide actions when EPA is evaluating
multiple installations at multiple locations.\108\
---------------------------------------------------------------------------

    \108\ 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 unit with new SCR
technology, which typically attains controlled NOX rates of
0.07 lbs/mmBtu or less. Based on the characteristics of the remaining
nationwide coal fleet that does not have a post-combustion control
retrofit, EPA determined that for unit and performance characteristics
representative of that subgroup, $9,600 per ton was the cost level that
represents the point at which the SCR retrofit technology was typically
available for the majority of these sources. For more details on this
assessment, refer to the EGU NOX Mitigation Strategies
Proposed Rule TSD in the docket for this proposed rule.
    Generation shifting - Finally, for each of the technologies
considered above, EPA evaluates emission reduction potential from
generation shifting at that representative dollar per ton level.
Shifting generation to lower NOX-emitting or zero-emitting
EGUs occurs in response to economic factors. 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. Because the
Agency

has identified discrete cost thresholds resulting from the full
implementation of particular types of emission controls, it is
reasonable to simultaneously quantify and include the reduction
potential from generation shifting at each cost level up to levels that
are consistent with control operation. Including these reductions is
important, ensuring that other cost-effective reductions (e.g., fully
operating controls) at each cost level can be expected to occur.
Generation shifting treatment and results are discussed in greater
detail in the NOX Mitigation Strategies Proposed Rule TSD.
    In general, when EPA estimates emission reduction potential from
generation shifting, EPA finds small amounts of generation shifting to
existing lower NOX- emitting or zero-emitting units could
occur consistent with the near-term implementation timing for this
proposed rule. As a proxy for limiting the amount of generation
shifting that is feasible for the near-term ozone seasons, EPA limits
its assessment to shifting generation to other EGUs within the same
state. EPA believes that limiting its evaluation of shifting generation
(which EPA sometimes refers to as re-dispatch) to the amount that could
occur within the state represents a conservatively small amount of
generation-shifting because it does not capture further potential
emission reductions that would occur if generation was shifted more
broadly among units in different states within the interconnected
electricity grid. EPA seeks comment on the extent to which generation
shifting towards lower-emitting resources should be incorporated into
the overall EGU emission reductions reflected in the state emission
budgets (Comment C-4).
    Finally, EPA seeks comment on whether other ozone-season
NOX mitigation technologies should be considered (Comment C-
5). EPA invites comments on the cost and performance of the above
listed technologies and any other potential mitigation technologies.
For example, in January of 2020 the New York Department of
Environmental Conservation adopted a rule to limit emissions from
combustion turbines that operate as peaking units. EPA has not
historically considered NOX mitigation technologies for
these sources in its rulemakings, such as the CSAPR and the CSAPR
Update, but invites comment on their appropriateness for this
rulemaking. Separately, location and high emission rates of grid-
connected municipal solid waste combustors, generally not covered under
EPA's transport rules given their small size and differing purpose,
have also led some stakeholders to suggest mitigation measures be
considered for those sources. EPA similarly invites comment on
mitigation opportunities for all of these mitigation technologies
discussed in this section and, in particular, requests comment on its
discussion of these additional strategies in the NOX
Mitigation Strategies Proposed Rule TSD.
2. Non-EGU NOX Mitigation Strategies
    EPA has not regulated emissions from non-EGU sources as part of its
regional transport rulemakings since the 1998 NOX SIP Call.
In Wisconsin, the D.C. Circuit held that EPA must on remand implement a
full remedy by the next attainment date (2021 for this proposed rule),
or as soon as possible thereafter on a showing of impossibility, to
achieve necessary reductions by that date. 938 F.3d at 320. The court
also directed the Agency to address non-EGU sources, unless ``the
scientific uncertainty is so profound that it precludes EPA from making
a reasoned judgment.'' Id. at 318-20 (quoting Massachusetts v. EPA, 549
U.S. 497, 534 (2007)). The D.C. Circuit found that the practical
obstacles EPA identified with respect to its evaluation of non-EGUs in
the CSAPR Update did not rise to the level of an ``impossibility,'' id.
The court also found that EPA must make a higher showing of uncertainty
regarding non-EGU point-source NOX mitigation potential
before declining to regulate such sources on the basis of
``uncertainty.'' Id. In this proposed rule, EPA has extended its
analysis to include all major stationary source sectors in the linked
upwind states, including non-EGU emissions sources in various industry
sectors. As discussed in section VI, of the 22 states originally
included in the CSAPR Update, EPA proposes in this action that 12
states warrant analysis at step 3 for significant contribution to
downwind nonattainment and/or maintenance receptors for the 2008 ozone
NAAQS. Therefore, the Agency focused its Step 3 assessment on non-EGU
sources in these 12 states. For these sources, EPA retained its focus
on NOX as the most effective precursor pollutant for
addressing interstate ozone transport at a regional scale. See 82 FR
51238, 51248 (Nov. 3, 2017) (citing 76 FR 48222) and 63 FR 57381.
    For non-EGU sources, there are many types of emissions sources or
units that emit NOX and many control technologies or
combinations of control technologies for these sources or units. As
such, there are many approaches to assessing emission reduction
potential from non-EGU emissions sources or units. In this assessment,
EPA attempted to apply the multi-factor test used for EGUs to determine
an appropriate stringency level for non-EGU sources in linked upwind
states. EPA identified available control technologies and estimated
their costs and potential emissions reductions. The information the
Agency currently has regarding implementation timeframes to determine
potential air quality impacts in relevant future years was also
considered.
    To identify levels of control for non-EGU sources, EPA used the
Control Strategy Tool (CoST),\109\ the Control Measures Database
(CMDb), and the projected 2023 inventory from the 2016v1 modeling
platform. EPA assessed potential emissions reductions associated with
applying controls to emissions units with 150 tons per year (tpy) or
more of pre-control NOX emissions in 2023, which is an
emissions threshold comparable to 25 MW for EGUs used in prior
interstate transport rulemakings. To derive this emissions threshold,
EPA used emissions expected from an average 25 MW EGU unit operating at
a median heat rate, emission rate, and capacity factor for a coal-fired
unit.\110\ In CoST, the Agency used the maximum emission reduction
strategy \111\ to estimate the largest quantity of potential emissions
reductions from each emissions source or unit located in the 12 upwind
states linked to downwind receptors in this proposed rule. 11 of the 12
upwind states had sources with 150 tpy or more of pre-control
NOX emissions in 2023; the projected 2023 emissions
inventory did not include non-EGU point sources in New Jersey with pre-
control NOx emissions greater than 150 tpy for which CoST had
applicable control measures.
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    \109\ 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.
    \110\ For additional details on calculating the 150 tpy
emissions threshold, please see the section titled Background for
Determining Source Size/Threshold for Non-EGU Emissions Sources in
the memorandum titled Assessing Non-EGU Emission Reduction
Potential, available in the docket for this proposed rule.
    \111\ The maximum emission 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,
regardless of cost. For more information, see the CoST User's Guide
available at the following link: https://www.cmascenter.org/cost/
documentation/3.5/CoST%20User's%20Guide/.
---------------------------------------------------------------------------

    For the 12 linked states, EPA categorized the CoST results for
control technologies that comprise approximately 92 percent of the
total estimated potential emissions

reductions from the non-EGU sources with 150 tpy or more of
NOX emissions in these states; \112\ those technologies and
related emissions sources are summarized in Table VII.B.2-1 below. In
tranche one before further refinement and verification, the number of
emissions units CoST applied SCR to was 51 and the number of emissions
units CoST applied SNCR to was 23. The estimated emissions reductions
from those control applications were 12,724 ozone season tons. In
tranche two before further refinement and verification, the number of
emissions units CoST applied layered combustion to was 49, the number
of emissions units CoST applied NSCR or layered combustion to was 65,
and the number of emissions units CoST applied ultra-low NOX
burner and SCR to was 56. The estimated emissions reductions from those
control applications were 17,283 ozone season tons. EPA then calculated
a weighted average cost per ton (in 2016$) for estimated potential
reductions associated with each control technology and plotted the
weighted average cost per ton values. From the resulting curve, EPA
identified a clear break point that defined two tranches of potential
emissions reductions, as shown in Table VII.B.2-1. For additional
details on the curve and the potential emissions reductions in tranches
one and two, please see the memorandum titled Assessing Non-EGU
Emission Reduction Potential, available in the docket for this proposed
rule.
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    \112\ CoST applied a few additional controls that are not
commonly used and did not result in significant additional emissions
reductions. Ten different control technology applications make up
the remaining 8 percent of the control technology applications.
Compared to the five technologies EPA assessed further, these ten
control technology applications do not, individually or
collectively, have the potential to result in significant additional
emissions reductions. For additional details, see the technical
memorandum titled Assessing Non-EGU Emission Reduction Potential and
the Excel workbook titled Control Summary--Max Emission Reduction
$10k 150 tpy cutoff 12 States Updated Modeling--No Replace--05-18-
2020.xlsx in the docket for this proposed rule.
    \113\ For the emissions unit estimated to generate emissions
reductions at $64 per ton, the emissions and cost estimates were
incorrect. The 2023 projected emissions for the unit were
significantly overestimated as a result of a growth factor EPA
received for these emissions from a multi-jurisdictional partner
organization. Further, the equation used to estimate the cost was
mis-specified in CoST, and the true cost is likely on the order of
$800 per ton. Changes to these underlying factors will likely guide
an updated assessment for a final rulemaking.

               Table VII.B.2-1--Details on Tranches One and Two of Potential Emissions Reductions
----------------------------------------------------------------------------------------------------------------
                                                                              Weighted average
                 Tranche                    Technologies/industry sectors or   cost (2016$ per     Cost range
                                                     source groups                  ton)         (2016$ per ton)
----------------------------------------------------------------------------------------------------------------
Tranche One..............................  SCR/Glass Manufacturing, IC                   2,000    64 \113\-5,700
                                            Engines.
                                           SNCR/Cement Manufacturing........
Tranche Two..............................  Layered Combustion/Lean Burn IC         5,000-6,600       1,400-9,700
                                            Engines.
                                           NSCR or Layered Combustion/
                                            Industrial Rich Burn Natural Gas
                                            IC Engines *.
                                           Ultra-low NOX Burner and SCR/
                                            Industrial Boilers.
----------------------------------------------------------------------------------------------------------------
Note: * NSCR is non-selective catalytic reduction, a control technology applicable to rich-burn natural gas-
  fired IC engines.

    Given the large number of emissions units in a given industry
sector that could require control installation, EPA does not have
detailed information on the time needed to install all of the control
technologies identified in Table VII.B.2-1. Any installation timing
estimates would need to reflect the time needed to install controls
across a potentially large number of sources, the time needed to have
NOX monitoring installed, and other steps in the permitting
and construction processes. EPA previously examined the time necessary
to install some of the controls indicated in Table VII.B.2-1 for
different industries in the 2016 Final Technical Support Document (TSD)
for the Final Cross-State Air Pollution Rule for the 2008 Ozone NAAQS,
Assessment of Non-EGU NOX Emission Controls, Cost of
Controls, and Time for Compliance Final TSD (``CSAPR Update Non-EGU
TSD''), which is discussed in Section VII.C.2. EPA expects that the
controls for glass furnaces and cement kilns would take at least 2
years to install on a sector-wide basis across the 12-state region
affected by this proposed rule. Therefore, based on the information
available to us at this time, EPA proposes that the 2023 ozone season
is the earliest ozone season by which these non-EGU controls could
likely be installed. EPA thus concludes that no NOX controls
for non-EGUs included in this cost analysis can be installed by the
2021 ozone season. Additional information on installation times for
non-EGU NOX controls can be found in Section VII.C.
3. Mobile Source NOX Mitigation Strategies
    Under a variety of CAA programs, EPA has established federal
emissions and fuel quality standards that reduce emissions from cars,
trucks, buses, nonroad engines and equipment, locomotives, marine
vessels, and aircraft (i.e., ``mobile sources''). Because states are
generally preempted from regulating new vehicles and engines with
certain exceptions (see generally CAA sections 209, 177), mobile source
emissions are primarily controlled through EPA's federal programs. EPA
has been regulating mobile source emissions since it was established as
a federal agency in 1970, and all mobile source sectors are currently
subject to NOX emissions standards. EPA factors these
standards and associated emission reductions into its baseline air
quality assessment in good neighbor rulemaking, including in this
action. Such reductions are an important reason for the historical and
long-running trend of improving air quality in the United States. These
trends help explain why the overall number of receptors and severity of
ozone nonattainment problems under the 2008 ozone NAAQS continues to
decline. Such data are factored into EPA's analysis at steps 1 and 2 of
the 4-step framework. As a result of this long history, NOX
emissions from onroad and nonroad mobile sources have substantially
decreased (73 percent and 57 percent since 2002, for onroad and
nonroad, respectively) \114\ and are predicted to continue to decrease
into the future as newer vehicles and engines that are subject to the
most recent, stringent standards replace older vehicles and
engines.\115\
---------------------------------------------------------------------------

    \114\ US EPA. Our Nation's Air: Status and Trends Through 2019.
https://gispub.epa.gov/air/trendsreport/2020/#home.
    \115\ National Emissions Inventory Collaborative (2019). 2016v1
Emissions Modeling Platform. Retrieved from http://views.cira.colostate.edu/wiki/wiki/10202.
---------------------------------------------------------------------------

    For example, in 2014 EPA promulgated new, more stringent emissions
and fuel standards for light-

duty passenger cars and trucks.\116\ The fuel standards took effect in
2017, and the vehicle standards are phasing in between 2017 and 2025.
Other EPA actions that are continuing to reduce NOX
emissions include the Heavy-Duty Engine and Vehicle Standards and
Highway Diesel Fuel Sulfur Control Requirements (66 FR 5002; January
18, 2001); the Clean Air Nonroad Diesel Rule (69 FR 38957; June 29,
2004); the Locomotive and Marine Rule (73 FR 25098; May 6, 2008); the
Marine Spark-Ignition and Small Spark-Ignition Engine Rule (73 FR
59034; October 8, 2008); the New Marine Compression-Ignition Engines at
or Above 30 Liters per Cylinder Rule (75 FR 22895; April 30, 2010); and
the Aircraft and Aircraft Engine Emissions Standards (77 FR 36342; June
18, 2012).
---------------------------------------------------------------------------

    \116\ Control of Air Pollution from Motor Vehicles: Tier 3 Motor
Vehicle Emission and Fuel Standards, 79 FR 23414 (April 28, 2014).
---------------------------------------------------------------------------

    EPA is currently developing a new regulatory effort to reduce
NOX and other pollution from heavy-duty trucks (known as the
Cleaner Trucks Initiative), as described in the January 21, 2020,
Advance Notice of Proposed Rulemaking (85 FR 3306). Heavy-duty vehicles
are the largest contributor to mobile source emissions of
NOX and will be one of the largest mobile source
contributors to ozone in 2025.\117\ Reducing heavy-duty vehicle
emissions nationally would improve air quality where the trucks are
operating as well as downwind. As required by CAA section 202(a)(3)(A)
of the Act, EPA will be proposing NOX emission standards
that ``reflect the greatest degree of emission reduction achievable
through the application of technology which the Administrator
determines will be available for the model year to which such standards
apply, giving appropriate consideration to cost, energy, and safety
factors associated with the application of such technology.'' Section
202(a)(3)(C) requires that standards apply for no less than 3 model
years and apply no earlier than 4 years after promulgation.
---------------------------------------------------------------------------

    \117\ Zawacki et al, 2018. Mobile source contributions to
ambient ozone and particulate matter in 2025. Atmospheric
Environment. Vol 188, pg 129-141. Available online: https://doi.org/10.1016/j.atmosenv.2018.04.057.
---------------------------------------------------------------------------

    Given these requirements, EPA is considering implementation of new
heavy-duty NOX emission standards beginning in model year
2027. In addition, any new rulemaking process for other mobile source
sectors would not achieve actual NOX emissions reductions
before 2025, given the lead time necessary for EPA and for
manufacturers.
    However, EPA's existing regulatory program will continue to reduce
NOX emissions into the future, and EPA is currently taking
active steps to ensure that these NOX reductions occur. The
CAA prohibits tampering with emissions controls, as well as
manufacturing, selling, and installing aftermarket devices intended to
defeat those controls. EPA currently has a National Compliance
Initiative called ``Stopping Aftermarket Defeat Devices for Vehicles
and Engines,'' which focuses on stopping the manufacture, sale, and
installation of hardware and software specifically designed to defeat
required emissions controls on onroad and nonroad vehicles and engines.

C. Control Stringencies Represented by Cost Threshold ($ per ton) and
Corresponding Emission Reduction Potential

1. EGU Emissions Reduction Potential by Cost Threshold
    For EGUs, as discussed in section VII.A, the multi-factor test
considers increasing levels of uniform control stringency, where each
level is represented by cost per ton of emissions reduced, in
combination with consideration of total NOX reduction
potential and corresponding air quality improvements. To determine
which cost thresholds to use to assess upwind state NOX
mitigation potential, EPA evaluated EGU NOX control costs
that represent the thresholds at which various control technologies are
widely available (described previously in section VII.B.1), the use of
certain cost thresholds in previous rules to address ozone transport,
and cost thresholds incorporated into state requirements to address
ozone nonattainment.
    EPA began by determining the appropriate range of costs to
evaluate. In the CSAPR Update, $1,400 per ton in 2011$ was the EGU
NOX cost threshold relied upon to partially address
obligations in time for the 2017 ozone season. This figure represented
the lowest marginal cost where EPA expects SCR optimization at all
existing SCR controls (including fully idled controls \118\) to be
cost-effective. Based on our assessment of EGU NOX
mitigation strategies, this same technology would now have a cost of
$1,600 per ton in 2016$.\119\ Specifically, the cost of this approach
to NOX reduction is the marginal cost of optimizing existing
SCRs at higher levels of NOX removal than they are currently
achieving if their current rate is greater than 0.08 lb/mmBtu. Given
that EPA has already determined this technology is cost-effective and
reasonable to consider for significant contribution determination in
the CSAPR Update (and those determination were not remanded), EPA has
not included a representation of mitigation technologies with any lower
cost levels in this proposal's analyses in Step 3. (Further, as
explained below, such analysis is not necessary for purposes of
checking for overcontrol at the selected cost threshold.)
---------------------------------------------------------------------------

    \118\ EPA had estimated an $800 threshold representing
optimizing SCRs for existing SCRs currently in some level of
operation. See 81 FR 7540-41. In this action, EPA has combined this
level of control into the $1600 control strategy for EGUs.
    \119\ Note, a portion of the cost increase from $1400 to $1600
is simply adjusting from 2011$ to 2016$, but some is also due to
change in material costs.
---------------------------------------------------------------------------

    EPA then evaluated EGU NOX cost thresholds to determine
an appropriate upper bound for our assessment. EPA identified $9,600
per ton as an upper bound as it represented the most stringent
mitigation technology (SCR retrofit) that EPA identified in its
assessment. EPA seeks comment on whether $1,600 per ton is an
appropriate minimum and $9,600 per ton is an appropriate maximum
uniform cost threshold to evaluate for the purpose of quantifying EGU
NOX reductions to reduce interstate ozone transport for the
2008 ozone NAAQS (Comment C-6).
    EPA then determined appropriate EGU NOX cost thresholds
to evaluate within the range of $1,600 per ton to $9,600 per ton and
identified two additional thresholds. Table VII.C.1-1 lists the EGU
NOX cost thresholds evaluated and the NOX
reduction strategy or policy used to identify each cost threshold. As
described above in Section VII.B, these cost thresholds are informed by
our assessment of the costs at which EGU NOX control
strategies are widely available. Evaluating additional cost thresholds
in between the four thresholds EPA identifies here would not yield
meaningful insights as to NOX reduction potential. EPA-
selected cost thresholds represent the points at which specific control
technologies become widely available and thereby where the most
significant incremental emission reduction potential is expected.
Analyzing costs between these cost thresholds is not expected to reveal
significant incremental emission reduction potential that isn't already
anticipated at the analyzed cost thresholds.

  Table VII.C.1-1--EGU NOX Cost Thresholds and NOX Reduction Strategies
------------------------------------------------------------------------
  EGU NOX cost threshold (2016$)
               \120\                             Technology
------------------------------------------------------------------------
$1,600 per ton....................  Fully operating all existing post-
                                     combustion SCR controls and