this proposed rule and at http://www.epa.gov/ttn/chief/net/2011inventory.html#inventorydoc. The future base case scenario modeled
for

2017 includes a representation of changes in activity data and of
predicted emission reductions from on-the-books actions, including
planned emission control installations and promulgated federal measures
that affect anthropogenic emissions.\73\
---------------------------------------------------------------------------

    \73\ Biogenic emissions and emissions from wild fires and
prescribed fires were held constant between 2011 and 2017 since (1)
these emissions are tied to the 2011 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
2011NEIv2 are based primarily on data from continuous emission
monitoring systems (CEMS), with other EGU pollutants estimated using
emission factors and annual heat input data reported to the EPA. For
EGUs without CEMS, the EPA used data submitted to the NEI by the
states. For more information on the details of how the 2011 EGU
emissions were developed and prepared for air quality modeling, see the
Emissions Modeling TSD.
    The EPA projected future 2017 baseline EGU emissions using version
5.14 of the Integrated Planning Model (IPM) (http://www.epa.gov/powersectormodeling). 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. The 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.\74\
---------------------------------------------------------------------------

    \74\ 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 Web site at:
www.epa.gov/airmarkets/powersectormodeling.
---------------------------------------------------------------------------

    The IPM version 5.14 base case accounts for comments received as a
result of the NODAs released in 2013 and 2014 (including control
configuration) as well as updated environmental regulations. This
projected base case accounts for the effects of the finalized MATS \75\
and CSAPR rules, New Source Review settlements, and on-the-books state
rules through 2014 \76\ impacting SO2, NOX,
directly emitted particulate matter, and CO2, and final
actions the EPA has taken to implement the Regional Haze Rule. The
EPA's IPM base case also includes two federal non-air rules affecting
EGUs: The Cooling Water Intake Structure (Clean Water Act section
316(b)) rule and the Coal Combustion Residuals (CCR) rule.
Documentation of IPM version 5.14 is in the docket and available online
at www.epa.gov/powersectormodeling.
---------------------------------------------------------------------------

    \75\ In Michigan v. EPA, the Supreme Court reversed on narrow
grounds a portion of the D.C. Circuit decision upholding the MATS
rule, finding that EPA erred by not considering cost when
determining that regulation of EGUs was ``appropriate'' pursuant to
CAA section 112(n)(1). 135 S.Ct. 192 (2015). The case was remanded
to the D.C. Circuit for further proceedings, and the MATS rule
currently remains in place.
    \76\ 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 5.14, that cutoff date was November
2014.
---------------------------------------------------------------------------

    After the receptor and contribution analyses for this proposal were
underway, the EPA released an updated IPM base case, version 5.15, and
the final Clean Power Plan (CPP).\77\ In order to reflect all on-the-
books policies as well as the most current power sector modeling data,
the EPA performed an assessment, described in section V-D below, to
reflect inclusion of IPM 5.15 with the CPP in the base case for this
proposal. The EPA plans to use this base case, including the final CPP,
for its modeling analysis for the final rule. However, EPA's analysis
for the final rule may include updated or different assumptions about
the inclusion of the CPP and the CSAPR phase 2 NOX ozone-
season or SO2 annual emissions budgets for those states with
budgets that were declared invalid and remanded to the EPA by the D.C.
Circuit's decision in EME Homer City II.
---------------------------------------------------------------------------

    \77\ Carbon Pollution Emission Guidelines for Existing
Stationary Sources: Electric Utility Generating Units, 80 FR 64662
(Oct. 23, 2015).
---------------------------------------------------------------------------

    In projecting future 2017 baseline EGU emissions, the EPA adjusted
the 2018 IPM version 5.14 base case results to account for three
categories of differences between 2017 and 2018. The categories are:
(1) Adjusting NOX emissions for units with SCRs in 2018 but
that are assumed not to operate or be installed in 2017; (2) adding
NOX emissions for units that are retiring in 2018 but are
projected to operate in 2017; and (3) adjusting NOX
emissions for coal-fired units that are projected to convert to natural
gas (i.e., ``coal-to-gas'') in 2018, but are still projected to burn
coal in 2017. These adjustments were only made to the air quality flat
file outputs of IPM and are discussed in greater detail in the IPM
documentation found in the docket for this proposed rule.
3. Development of Emission Inventories for Non-EGU Point Sources
    The 2011 non-EGU point sources in the 2011 base case inventory
match those in the 2011NEIv2. Details on the development of the 2011
emission inventories can be found in the 2011NEIv2 TSD. Prior to air
quality modeling, the emission inventories must be processed into a
format that is appropriate for the air quality model to use. Details on
the processing of the emissions for 2011 and on the development of the
2017 non-EGU emission inventories are available in the Emissions
Modeling TSD. Projection factors and percent reductions in this
proposal reflect comments received as a result of the NODAs in 2013 and
2014, 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 (MACT)
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).
    For aircraft emissions at airports, the EPA developed projection
factors based on activity growth projected by the Federal Aviation
Administration Terminal Area Forecast (TAF) system, published in March
2013.
    Point source and nonpoint oil and gas emissions are projected to
2018 using regional projection factors by product type using Annual
Energy Outlook (AEO) 2014 projections to year 2017. 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.

4. Development of Emission Inventories for Onroad Mobile Sources
    The EPA developed the onroad mobile source emissions for states
other than California using the EPA's Motor Vehicle Emissions Simulator
(MOVES) 2014. We computed the emissions within SMOKE by multiplying
emission factors developed using MOVES with the appropriate activity
data. We also used MOVES emission factors to estimate emissions from
refueling. The 2011 onroad mobile source emissions used in the
inventory for this rule are similar but not identical to the 2011NEIv2
emissions due to a more detailed treatment of E-85 emissions in the
2011 emission modeling platform used for this rule. Additional
information on the approach for generating the onroad mobile source
emissions is available in the Emissions Modeling TSD. Onroad mobile
source emissions for California are consistent with the emissions
submitted by the state as reflected in the 2011NEIv2.
    In the future-year modeling for mobile sources, we included all
national measures known at the time of modeling. The future scenarios
for mobile sources reflect projected changes to fuel usage and onroad
mobile control programs finalized as of the date of the model run.
Finalized rules that are incorporated into the 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). Impacts of rules that were in effect in 2011 are
reflected in the 2011 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 2011. Local control programs such as the California
LEV III program are included in the onroad mobile source emissions.
Activity data for onroad mobile sources was projected using AEO 2014.
Because EPA changed the model year from 2018 to 2017 between its pre-
proposal modeling and the modeling conducted for this proposal (see
footnote 64), and due to the substantial amount of lead time required
to generate emission factors with MOVES, the EPA was unable to directly
generate emission factors for 2017 prior to the modeling used to
support this proposed rule. Therefore, for this proposal, future year
onroad mobile source emissions were computed for 2018 and adjusted to
2017 levels using adjustment factors derived from national MOVES runs
for 2017 and 2018. Emission factors will be generated directly for 2017
prior to air quality modeling for the final rule.
5. Development of Emission Inventories for Commercial Marine Category 3
(Vessel)
    The commercial marine category 3 vessel (``C3 marine'') emissions
in the 2011 base case emission inventory for this proposed rule are
consistent with those in the 2011NEIv2. These 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 as early as 2010. The cumulative impacts of these
rules through 2017 are incorporated in the 2017 projected emissions for
C3 marine sources.
6. Development of Emission Inventories for Other Nonroad Mobile Sources
    To develop the nonroad mobile source emission inventories other
than C3 marine for the modeling platform, the EPA used monthly, county,
and process level emissions output from the National Mobile Inventory
Model (NMIM) (see http://www.epa.gov/otaq/nmim.htm). State-submitted
emissions data for nonroad sources were used for Texas and California.
These emissions are consistent with those in the 2011NEIv2.
    The EPA also used NMIM to project nonroad mobile emissions for
future years. Development of the future year nonroad emissions require
a substantial amount of lead time and the emissions were prepared for
the year 2018 before the model year was changed to 2017 when the
attainment date was revised in the 2008 Ozone NAAQS SIP Requirements
Rule. To develop a 2017 nonroad emissions inventory for this proposal
that accounted for the difference between 2017 and 2018 emissions
levels, we calculated the nonroad emissions for 2018, and then adjusted
those emissions to 2017 levels using national adjustment factors
derived from national NMIM runs for 2017 and 2018. Emissions specific
to 2017 will be developed for the modeling that will support the final
rule. The nonroad mobile emission control programs include reductions
to locomotives, diesel engines and 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.
7. Development of Emission Inventories for Nonpoint Sources
    The emissions for stationary nonpoint sources in our 2011 base case
emission inventory are largely consistent with those in the 2011NEIv2.
For more information on the nonpoint sources in the 2011 base case
inventory, see the Emissions Modeling TSD and the 2011NEIv2 TSD.
    Where states provided EPA with information about projected control
measures or changes in nonpoint source emissions, the EPA incorporated
those inputs in its projections. We included adjustments for state fuel
sulfur content rules for fuel oil in the Northeast. Projected emissions
for portable fuel containers reflect the impact of projection factors
required by the final Mobile Source Air Toxics (MSAT2) rule and the
EISA, including updates to cellulosic ethanol plants, ethanol transport
working losses, and ethanol distribution vapor losses.
    The EPA developed regional projection factors for nonpoint oil and
gas sources by product type based on Annual Energy Outlook (AEO) 2014
projections to year 2018. We reflected criteria air pollutant (CAP) co-
benefit reductions resulting from the National Emission Standards for
Hazardous Air Pollutants (NESHAP) for Reciprocating Internal Combustion
Engines (RICE) and NSPS rules and Oil and Gas NSPS VOC controls for
select source categories. Additional details on the projections are
available in the Emissions Modeling TSD.

C. Air Quality Modeling To Identify Nonattainment and Maintenance
Receptors

    In this section, we describe the air quality modeling performed to
identify locations where we expect there to be nonattainment or
maintenance problems for the 2008 8-hour ozone NAAQS in the 2017
analytic future year chosen for this proposal. We then describe how we
factored current monitored data into the identification of sites as
having either nonattainment or maintenance concerns for the purposes of
this rulemaking. These sites are used as the ``receptors'' for
quantifying the contributions of emissions in upwind states to
nonattainment and maintenance concerns in downwind locations.

    In this proposed rule, the EPA is relying on CSAPR's approach to
identify separate nonattainment and maintenance receptors in order to
give 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.\78\ In its decision on remand from the
Supreme Court, the D.C. Circuit confirmed that EPA's approach to
identifying maintenance receptors in 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.
---------------------------------------------------------------------------

    \78\ 531 F.3d at 910-911 (holding that the EPA must give
``independent significance'' to each prong of CAA section
110(a)(2)(D)(i)(I)).
---------------------------------------------------------------------------

    In CSAPR, the EPA identified nonattainment receptors as those
monitoring sites that are projected to have average design values that
exceed the NAAQS. The 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 CSAPR approach for identifying
nonattainment and maintenance receptors relied only upon air quality
model projections of measured design values. In CSAPR, if the average
design value in the analysis year was projected to exceed the NAAQS,
then the monitoring site is identified as a nonattainment receptor
without consideration of whether the monitoring site is currently
measuring ``clean data'' (i.e., design values below the NAAQS based on
the most recent three years of measured data). In prior transport
rulemakings, such as the NOX SIP Call and CAIR, the EPA
defined nonattainment receptors as those areas that both currently
monitor nonattainment and that the EPA projects will be in
nonattainment in the future compliance year.\79\ We explained that we
had the most confidence in our projections of nonattainment for those
counties that also measure nonattainment for the most recent period of
available ambient data. In CSAPR, we were compelled to deviate from
this practice of incorporating monitored data into EPA's evaluation of
projected nonattainment receptors because the most recent monitoring
data then available reflected large emission reductions from CAIR,
which CSAPR was designed to replace. As recently affirmed by the D.C.
Circuit, it was therefore reasonable for the EPA to decide not to
compare monitored data reflecting CAIR emissions reductions to its
modeling projections that instead excluded CAIR from its baseline.\80\
---------------------------------------------------------------------------

    \79\ 63 FR at 57375, 57377 (Oct. 27, 1998); 70 FR at 25241 (May
12, 2005). See also North Carolina, 531 F.3d at 913-914 (affirming
as reasonable EPA's approach to defining nonattainment in CAIR).
    \80\ EME Homer City II, 795 F.3d at 135-36; see also 76 FR 48208
at 48230-31 (August 8, 2011).
---------------------------------------------------------------------------

    As the EPA is not replacing an existing transport program in this
rulemaking proposal, we are proposing to consider current monitored
data as part of the process for identifying projected nonattainment
receptors for this rulemaking. Accordingly, in this rulemaking, the EPA
is proposing to return to our prior practice of comparing our modeled
nonattainment projections to current monitored air quality. For the
purposes of this rulemaking, the EPA proposes to identify as
nonattainment receptors those monitors that both currently measure
nonattainment and that the EPA projects will be in nonattainment in
2017.
    As noted above, in CSAPR the EPA 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.
    The 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. The 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, the EPA assesses the magnitude of the maximum projected
design value for 2017 at each receptor in relation to the 2008 ozone
NAAQS and, where such a value exceeds the NAAQS, EPA determines that
receptor to be a ``maintenance'' receptor for purposes of defining
interference with maintenance in this proposal, consistent with the
method used in CSAPR and upheld by the D.C. Circuit in EME Homer City
II.\81\ That is, monitoring sites with a maximum design value that
exceeds the NAAQS are projected to have a maintenance problem in 2017.
---------------------------------------------------------------------------

    \81\ See 795 F.3d at 136.
---------------------------------------------------------------------------

    Consistent with the CSAPR methodology, 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 clean data, 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. We are not proposing that
monitored data have any effect on the EPA's determination of
maintenance receptors using the CSAPR method since even those receptor
sites that are not currently monitoring violations are still subject to
conditions that may allow violations to reoccur and therefore have
future maintenance concerns.
    The following is a brief summary of the procedures for projecting
future-year 8-hour ozone average and maximum design values to 2017.
Consistent with the EPA's modeling guidance we use the air quality
modeling results in a ``relative'' sense to project future
concentrations. That is, the ratios of future year model predictions to
base year model predictions are used to adjust ambient ozone design
values \82\ 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. Because the base year for this proposal
is 2011, we are using the base period 2009-2013 ambient ozone design
value data in order to project

2017 average design values in a manner consistent with the modeling
guidance.
---------------------------------------------------------------------------

    \82\ 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 approach for projecting future ozone design values involved the
projection of an average of up to 3 design value periods, which include
the years 2009-2013 (design values for 2009-2011, 2010-2012, and 2011-
2013). The 2009-2011, 2010-2012, and 2011-2013 design values are
accessible at www.epa.gov/airtrends/values.html. The average of the 3
design values creates a ``5-year weighted average'' value. The 5-year
weighted average values were then projected to 2017. To project 8-hour
ozone design values we used the 2011 base year and 2017 future base-
case model-predicted ozone concentrations to calculate relative
reduction factors (RRFs) for the location of each monitoring site. The
RRFs were applied to the 2009-2013 average ozone design values and the
individual design values for 2009-2011, 2010-2012, and 2011-2013
through the following steps:
    Step 1: For each monitoring site, we calculate the average
concentration across the 10 days with the 10 highest 8-hour daily
maximum ozone predictions in the 2017 baseline \83\ using the
predictions in the nine grid cells that include or surround the
location of the monitoring site. The RRF for a site is the ratio of the
mean prediction in the future year to the mean prediction in the 2011
base year. The RRFs were calculated on a site-by-site basis.\84\
---------------------------------------------------------------------------

    \83\ As specified in the attainment demonstration modeling
guidance, if there are fewer than 10 modeled days greater than or
equal to (>=) 70 ppb, then the threshold is lowered in 1 ppb
increments (to as low as 60 ppb) until there are 10 days. If there
are fewer than 5 days >= 60 ppb, then an RRF calculation is not
completed for that site.
    \84\ Sites with insufficient valid design values were not
included in the calculation. In addition, sites with fewer than 5
days with predicted 8-hour ozone >= 60 ppb in 2018 were dropped from
the analysis.
---------------------------------------------------------------------------

    Step 2: The RRF for each site is then multiplied by the 2009-2013
5-year weighted average ambient design value for that site, yielding an
estimate of the future average design value at that particular
monitoring location.
    Step 3: We calculate the maximum future design value by multiplying
the RRF for each site by the three base periods (2009-2011, 2010-2012,
and 2011-2013) separately. The highest of the three future values is
the projected maximum design value. 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.\85\
---------------------------------------------------------------------------

    \85\ 40 CFR part 50, Appendix P to Part 50--Interpretation of
the Primary and Secondary National Ambient Air Quality Standards for
Ozone.
---------------------------------------------------------------------------

    Projected design values that are greater than or equal to 76 ppb
are considered to be violating the NAAQS in 2017. For those sites that
are projected to be violating the NAAQS based on the average design
values in 2017, we examined measured design values for the period 2012-
2014, which is the most recent available measured design values at the
time of this proposal. As noted above, we are 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 therefore 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 2017
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 we
project to be nonattainment and maintenance receptors for the ozone
NAAQS in the 2017 baseline are used for assessing the contribution of
emissions in upwind states to downwind nonattainment and maintenance of
ozone NAAQS as part of this proposal.
    Table V.C-1 contains the 2009-2013 base period average and maximum
8-hour ozone design values, the 2017 baseline average and maximum
design values, and the 2012-2014 design values for the 8 sites in the
eastern U.S. projected to be 2017 nonattainment receptors. Table V.C-2
contains this same information for the 6 maintenance-only sites in the
eastern U.S. that are projected nonattainment but currently measuring
clean data. Table V.C-3 contains this same information for the 23
maintenance-only sites in the eastern U.S. that are projected to have
average design values below the NAAQS, but maximum design values above
the NAAQS. The design values for all monitoring sites in the U.S. are
provided in docket item EPA-HQ-OAR-2015-0500-0006. Additional details
on the approach for projecting average and maximum design values are
provided in the modeling guidance, Model Attainment Test Software \86\
documentation, and the AQM TSD. The EPA is seeking comment on the
proposed methods for determining projected nonattainment and
maintenance receptors.
---------------------------------------------------------------------------

    \86\ Abt Associates, 2014. User's Guide: Modeled Attainment Test
Software. http://www.epa.gov/scram001/modelingapps_mats.htm.

  Table V.C-1--Average and Maximum 2009-2013 and 2017 Baseline 8-Hour Ozone Design Values and 2012-2014 Design Values (ppb) at Projected Nonattainment
                                                                Sites in the Eastern U.S.
                                                                [Nonattainment receptors]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                          Average design  Maximum design
           Monitor ID                    State              County          value 2009-     value 2009-   Average design  Maximum design     2012-2014
                                                                               2013            2013         value 2017      value 2017     design value
--------------------------------------------------------------------------------------------------------------------------------------------------------
90013007........................  Connecticut.......  Fairfield.........            84.3            89.0            77.1            81.4            84.0
90019003........................  Connecticut.......  Fairfield.........            83.7            87.0            78.0            81.1            85.0
90099002........................  Connecticut.......  New Haven.........            85.7            89.0            77.2            80.2            81.0
480391004.......................  Texas.............  Brazoria..........            88.0            89.0            81.4            82.3            80.0
481210034.......................  Texas.............  Denton............            84.3            87.0            76.9            79.4            81.0
484392003.......................  Texas.............  Tarrant...........            87.3            90.0            79.6            82.1            77.0
484393009.......................  Texas.............  Tarrant...........            86.0            86.0            78.6            78.6            80.0
551170006.......................  Wisconsin.........  Sheboygan.........            84.3            87.0            77.0            79.4            81.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

 Table V.C-2--Average and Maximum 2009-2013 and 2017 Baseline 8-Hour Ozone Design Values and 2012-2014 Design Values (ppb) at Sites in the Eastern U.S.
                                           That Are Projected Nonattainment But Currently Measuring Clean Data
                                                              [Maintenance-only receptors]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Average design  Maximum design
           Monitor ID                   State              County         value 2009-     value 2009-   Average design  Maximum design  2012-2014 design
                                                                             2013            2013         value 2017      value 2017          value
--------------------------------------------------------------------------------------------------------------------------------------------------------
240251001......................  Maryland..........  Harford..........            90.0            93.0            81.3            84.0              75.0
360850067......................  New York..........  Richmond.........            81.3            83.0            76.3            77.8              73.0
361030002......................  New York..........  Suffolk..........            83.3            85.0            79.2            80.8              73.0
390610006......................  Ohio..............  Hamilton.........            82.0            85.0            76.3            79.1              75.0
482011034......................  Texas.............  Harris...........            81.0            82.0            76.8            77.8              72.0
482011039......................  Texas.............  Harris...........            82.0            84.0            78.2            80.2              72.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

Table V.C-3--Average and Maximum 2009-2013 and 2017 Baseline 8-Hour Ozone Design Values and 2012-2014 Design Values (ppb) at Projected Maintenance Sites
                                                   in the Eastern U.S. Based on the CSAPR Methodology
                                                              [Maintenance-only receptors]
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                        Average design  Maximum design
           Monitor ID                   State              County         value 2009-     value 2009-   Average design  Maximum design  2012-2014 design
                                                                             2013            2013         value 2017      value 2017          value
--------------------------------------------------------------------------------------------------------------------------------------------------------
90010017.......................  Connecticut.......  Fairfield........            80.3            83.0            75.8            78.4              82.0
211110067......................  Kentucky..........  Jefferson........            82.0            85.0            75.8            78.6   Incomplete Data
211850004......................  Kentucky..........  Oldham...........            82.0            86.0            73.7            77.3              74.0
240053001......................  Maryland..........  Baltimore........            80.7            84.0            73.2            76.2              72.0
260050003......................  Michigan..........  Allegan..........            82.7            86.0            75.5            78.5              83.0
261630019......................  Michigan..........  Wayne............            78.7            81.0            74.0            76.2              74.0
340071001......................  New Jersey........  Camden...........            82.7            87.0            74.2            78.1              76.0
340150002......................  New Jersey........  Gloucester.......            84.3            87.0            75.1            77.5              76.0
340230011......................  New Jersey........  Middlesex........            81.3            85.0            73.0            76.3              74.0
340290006......................  New Jersey........  Ocean............            82.0            85.0            73.9            76.6              75.0
360810124......................  New York..........  Queens...........            78.0            80.0            75.7            77.6              72.0
420031005......................  Pennsylvania......  Allegheny........            80.7            82.0            75.3            76.5              77.0
421010024......................  Pennsylvania......  Philadelphia.....            83.3            87.0            75.1            78.4              75.0
480850005......................  Texas.............  Collin...........            82.7            84.0            74.9            76.0              78.0
481130069......................  Texas.............  Dallas...........            79.7            84.0            74.0            78.0              78.0
481130075......................  Texas.............  Dallas...........            82.0            83.0            75.8            76.7              77.0
481211032......................  Texas.............  Denton...........            82.7            84.0            75.1            76.3              79.0
482010024......................  Texas.............  Harris...........            80.3            83.0            75.9            78.5              72.0
482010026......................  Texas.............  Harris...........            77.3            80.0            73.5            76.1              67.0
482010055......................  Texas.............  Harris...........            81.3            83.0            75.4            77.0              75.0
482011050......................  Texas.............  Harris...........            78.3            80.0            74.6            76.2              72.0
484390075......................  Texas.............  Tarrant..........            82.0            83.0            75.5            76.4              79.0
484393011......................  Texas.............  Tarrant..........            80.7            83.0            74.5            76.6              75.0
--------------------------------------------------------------------------------------------------------------------------------------------------------

D. Pollutant Transport From Upwind States

1. Air Quality Modeling To Quantify Upwind State Contributions
    This section documents the procedures the EPA used to quantify the
impact of emissions from specific upwind states on 2017 8-hour design
values for identified downwind nonattainment and maintenance receptors.
The EPA used CAMx photochemical source apportionment modeling to
quantify the impact of emissions in specific upwind states on downwind
nonattainment and maintenance receptors for 8-hour ozone. CAMx employs
enhanced source apportionment techniques that track the formation and
transport of ozone from specific emissions sources and calculates the
contribution of sources and precursors to ozone for individual receptor
locations. The 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.
    The EPA performed nationwide, state-level ozone source
apportionment modeling using the CAMx Ozone Source Apportionment
Technology/Anthropogenic Precursor Culpability Analysis (OSAT/APCA)
technique \87\ to quantify the contribution of 2017 baseline
NOX and VOC emissions from all sources in each state to
projected 2017 ozone concentrations at air quality monitoring sites. In
the source apportionment model run, we tracked the ozone formed from
each of the following contribution categories (i.e., ``tags''):
---------------------------------------------------------------------------

    \87\ As part of this technique, ozone formed from reactions
between biogenic VOC and NOX with anthropogenic
NOX and VOC are assigned to the anthropogenic emissions.
---------------------------------------------------------------------------

     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 we
have point source inventory data in the 2011 NEI (we 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 (we
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 wild fire
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 CAMx OSAT/APCA model run was performed for the period May 1
through September 30 using the projected 2017 baseline emissions and
2011 meteorology for this time period. The hourly contributions \88\
from each tag were processed to obtain the 8-hour average contributions
corresponding to the time period of the 8-hour daily maximum
concentration on each day in the 2017 model simulation. This step was
performed for those model grid cells containing monitoring sites in
order to obtain 8-hour average contributions for each day at the
location of each site. The model-predicted contributions were then
applied in a relative sense to quantify the contributions to the 2017
average design value at each site. The resulting 2017 contributions
from each tag to each monitoring site in the eastern and western U.S.
along with additional details on the source apportionment modeling and
the procedures for calculating contributions can be found in the AQM
TSD. The EPA is seeking comment on the methodologies for calculating
ozone contributions.
---------------------------------------------------------------------------

    \88\ Contributions from anthropogenic emissions under
``NOX-limited'' and ``VOC-limited'' chemical regimes were
combined to obtain the net contribution from NOX and VOC
anthropogenic emissions in each state.
---------------------------------------------------------------------------

    The average contribution metric is intended to provide a reasonable
representation of the contribution from individual states to the
projected 2017 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 in the East to 8-hour
ozone nonattainment receptors in downwind states is provided in Table
V.D-1. The largest contribution from each state in the East to 8-hour
ozone maintenance-only receptors in downwind states is also provided in
Table V.D-1.

Table V.D-1--Largest Contribution to Downwind 8-Hour Ozone Nonattainment
      and Maintenance Receptors for Each State in the Eastern U.S.
------------------------------------------------------------------------
                                     Largest downwind   Largest downwind
                                     contribution to    contribution to
           Upwind state               nonattainment       maintenance
                                      receptors  for     receptors for
                                       ozone  (ppb)       ozone  (ppb)
------------------------------------------------------------------------
AL................................               0.79               1.28
AR................................               0.98               2.15
CT................................               0.00               0.46
DE................................               0.37               2.23
DC................................               0.06               0.73
FL................................               0.54               0.72
GA................................               0.47               0.58
IL................................              17.48              23.17
IN................................               6.24              14.95
IA................................               0.61               0.85
KS................................               0.80               1.03
KY................................               0.75              11.17
LA................................               3.09               4.23
ME................................               0.00               0.08
MD................................               2.07               7.11
MA................................               0.10               0.37
MI................................               2.69               1.79
MN................................               0.40               0.47
MS................................               0.78               1.48
MO................................               1.63               3.69
NE................................               0.24               0.36
NH................................               0.02               0.07
NJ................................               8.84              12.38
NY................................              16.96              17.21
NC................................               0.55               0.93
ND................................               0.11               0.28
OH................................               2.18               7.92
OK................................               1.70               2.46
PA................................               9.39              15.93
RI................................               0.02               0.08
SC................................               0.16               0.21

SD................................               0.08               0.12
TN................................               0.51               1.67
TX................................               2.44               2.95
VT................................               0.01               0.05
VA................................               1.87               5.29
WV................................               0.95               3.11
WI................................               0.34               2.59
------------------------------------------------------------------------

2. Application of Screening Threshold
    The EPA then evaluated the magnitude of the contributions from each
upwind state to downwind nonattainment and maintenance receptors. In
this proposal, the EPA uses an air quality screening threshold to
identify upwind states that contribute to downwind ozone concentrations
in amounts sufficient to ``link'' them to these to downwind
nonattainment and maintenance receptors.
    As discussed above in section III, the EPA is proposing to
establish the air quality screening threshold calculated as one percent
of the NAAQS. Specifically for this rule, we propose calculating an 8-
hour ozone value for this air quality threshold of 0.75 ppb as the
quantification of one percent of the 2008 ozone NAAQS.
    States in the East \89\ whose contributions to a specific receptor
meet or exceed the screening threshold are considered linked to that
receptor; those states' ozone contributions and emissions (and
available emission reductions) are analyzed further, as described in
section VI, to determine whether and what emissions reductions might be
required from each state.
---------------------------------------------------------------------------

    \89\ As discussed in section III this assessment shows that
there are problem receptors in the West where western states
contribute amounts greater than or equal to the screening threshold
used to evaluate eastern states (i.e., 1 percent of the NAAQS).
However, there may be additional criteria to evaluate regarding
transported air pollution in the West and upwind state obligations.
The EPA proposes to focus this rulemaking on eastern states, but
seeks comment on whether to include western states in this rule.
---------------------------------------------------------------------------

    States in the East whose contributions are below the threshold are
not included in the proposed rule and are considered to make
insignificant contributions to projected downwind air quality problems.
However, for eastern states for which the EPA is not proposing FIPs in
this action, the EPA notes that updates to the modeling for the final
rule could change the analysis as to which states have contributions
that meet or exceed the screening threshold. In the event that air
quality modeling conducted for the final rule demonstrates that 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 modeling, the EPA instead proposes to finalize
revised budgets (presented with this rulemaking for comment) for
whichever of those states may be identified as linked to such air
quality problems. The EPA has calculated emissions budgets for all
eastern states that we are proposing to apply to those states if, and
only if, the final rule air quality modeling identifies a linkage as
just described. These budgets are available in the Ozone Transport
Policy Analysis TSD.
    Based on the maximum downwind contributions in Table V.D-1, the
following states contribute at or above the 0.75 ppb threshold to
downwind nonattainment receptors: Alabama, Arkansas, Illinois, Indiana,
Kansas, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri,
New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia,
and West Virginia. Based on the maximum downwind contributions in Table
V.D-1, the following states contribute at or above the 0.75 ppb
threshold to downwind maintenance-only receptors: Alabama, Arkansas,
Delaware, Illinois, Indiana, Iowa, Kansas, Kentucky, Louisiana,
Maryland, Michigan, Mississippi, Missouri, New Jersey, New York, North
Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Virginia,
West Virginia, and Wisconsin. The linkages between each upwind state
and downwind nonattainment receptors and maintenance-only receptors in
the eastern U.S. are provided in Table V.D-2 and Table V.D-3,
respectively.

      Table V.D-2--Linkages Between Each Upwind State and Downwind
               Nonattainment Receptors in the Eastern U.S.
------------------------------------------------------------------------
         Upwind state               Downwind nonattainment receptors
------------------------------------------------------------------------
AL............................  Tarrant Co., TX (484392003).
AR............................  Brazoria Co., TX (480391004); Tarrant
                                 Co., TX (484392003); Tarrant Co., TX
                                 (484393009).
IL............................  Brazoria Co., TX (480391004); Sheboygan
                                 Co., WI (551170006).
IN............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); Sheboygan Co., WI
                                 (551170006).
KS............................  Sheboygan Co., WI (551170006).
KY............................  Sheboygan Co., WI (551170006).
LA............................  Brazoria Co., TX (480391004); Denton
                                 Co., TX (481210034); Tarrant Co., TX
                                 (484392003); Tarrant Co., TX
                                 (484393009); Sheboygan Co., WI
                                 (551170006).
MD............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002).
MI............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002); Sheboygan Co., WI
                                 (551170006).
MS............................  Brazoria Co., TX (480391004).

MO............................  Brazoria Co., TX (480391004); Sheboygan
                                 Co., WI (551170006).
NJ............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002).
NY............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002).
OH............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002); Sheboygan Co., WI
                                 (551170006).
OK............................  Denton Co., TX (481210034); Tarrant Co.,
                                 TX (484392003); Tarrant Co., TX
                                 (484393009); Sheboygan Co., WI
                                 (551170006).
PA............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002).
TX............................  Sheboygan Co., WI (551170006).
VA............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003); New Haven Co., CT
                                 (90099002).
WV............................  Fairfield Co., CT (90013007); Fairfield
                                 Co., CT (90019003).
------------------------------------------------------------------------

      Table V.D-3--Linkages Between Each Upwind States and Downwind
             Maintenance-Only Receptors in the Eastern U.S.
------------------------------------------------------------------------
           Upwind state                Downwind maintenance receptors
------------------------------------------------------------------------
AL................................  Hamilton Co., OH (390610006); Harris
                                     Co., TX (482010055).
AR................................  Oldham Co., KY (211850004); Allegan
                                     Co., MI (260050003); Dallas Co., TX
                                     (481130069); Dallas Co., TX
                                     (481130075); Harris Co., TX
                                     (482010026); Harris Co., TX
                                     (482010055); Harris Co., TX
                                     (482011039); Harris Co., TX
                                     (482011050); Tarrant Co., TX
                                     (484390075); Tarrant Co., TX
                                     (484393011).
DE................................  Camden Co., NJ (340071001);
                                     Gloucester Co., NJ (340150002);
                                     Ocean Co., NJ (340290006);
                                     Philadelphia Co., PA (421010024).
IL................................  Jefferson Co., KY (211110067);
                                     Oldham Co., KY (211850004); Allegan
                                     Co., MI (260050003); Wayne Co., MI
                                     (261630019); Camden Co., NJ
                                     (340071001); Gloucester Co., NJ
                                     (340150002); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Suffolk Co., NY
                                     (361030002); Hamilton Co., OH
                                     (390610006); Allegheny Co., PA
                                     (420031005); Harris Co., TX
                                     (482010026); Harris Co., TX
                                     (482011039).
IN................................  Jefferson Co., KY (211110067);
                                     Oldham Co., KY (211850004);
                                     Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001);
                                     Allegan Co., MI (260050003); Wayne
                                     Co., MI (261630019); Camden Co., NJ
                                     (340071001); Gloucester Co., NJ
                                     (340150002); Middlesex Co., NJ
                                     (340230011); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Richmond Co., NY
                                     (360850067); Suffolk Co., NY
                                     (361030002); Hamilton Co., OH
                                     (390610006); Allegheny Co., PA
                                     (420031005); Philadelphia Co., PA
                                     (421010024).
IA................................  Allegan Co., MI (260050003).
KS................................  Allegan Co., MI (260050003); Tarrant
                                     Co., TX (484390075); Tarrant Co.,
                                     TX (484393011).
KY................................  Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001); Camden
                                     Co., NJ (340071001); Gloucester
                                     Co., NJ (340150002); Middlesex Co.,
                                     NJ (340230011); Ocean Co., NJ
                                     (340290006); Richmond Co., NY
                                     (360850067); Hamilton Co., OH
                                     (390610006); Allegheny Co., PA
                                     (420031005); Philadelphia Co., PA
                                     (421010024).
LA................................  Collin Co., TX (480850005); Dallas
                                     Co., TX (481130069); Dallas Co., TX
                                     (481130075); Denton Co., TX
                                     (481211032); Harris Co., TX
                                     (482010024); Harris Co., TX
                                     (482010026); Harris Co., TX
                                     (482010055); Harris Co., TX
                                     (482011034); Harris Co., TX
                                     (482011039); Harris Co., TX
                                     (482011050); Tarrant Co., TX
                                     (484390075); Tarrant Co., TX
                                     (484393011).
MD................................  Fairfield Co., CT (90010017);
                                     Gloucester Co., NJ (340150002);
                                     Middlesex Co., NJ (340230011);
                                     Ocean Co., NJ (340290006); Queens
                                     Co., NY (360810124); Richmond Co.,
                                     NY (360850067); Suffolk Co., NY
                                     (361030002); Philadelphia Co., PA
                                     (421010024).
MI................................  Fairfield Co., CT (90010017);
                                     Jefferson Co., KY (211110067);
                                     Oldham Co., KY (211850004); Harford
                                     Co., MD (240251001); Camden Co., NJ
                                     (340071001); Gloucester Co., NJ
                                     (340150002); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Richmond Co., NY
                                     (360850067); Suffolk Co., NY
                                     (361030002); Hamilton Co., OH
                                     (390610006); Allegheny Co., PA
                                     (420031005).
MS................................  Harris Co., TX (482010055); Harris
                                     Co., TX (482011039).
MO................................  Oldham Co., KY (211850004); Allegan
                                     Co., MI (260050003); Camden Co., NJ
                                     (340071001); Hamilton Co., OH
                                     (390610006); Harris Co., TX
                                     (482010026); Harris Co., TX
                                     (482010055); Harris Co., TX
                                     (482011039); Harris Co., TX
                                     (482011050).
NJ................................  Fairfield Co., CT (90010017); Queens
                                     Co., NY (360810124); Richmond Co.,
                                     NY (360850067); Suffolk Co., NY
                                     (361030002); Philadelphia Co., PA
                                     (421010024).
NY................................  Fairfield Co., CT (90010017); Camden
                                     Co., NJ (340071001); Gloucester
                                     Co., NJ (340150002); Middlesex Co.,
                                     NJ (340230011); Ocean Co., NJ
                                     (340290006).
NC................................  Baltimore Co., MD (240053001).
OH................................  Fairfield Co., CT (90010017);
                                     Jefferson Co., KY (211110067);
                                     Oldham Co., KY (211850004);
                                     Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001); Wayne
                                     Co., MI (261630019); Camden Co., NJ
                                     (340071001); Gloucester Co., NJ
                                     (340150002); Middlesex Co., NJ
                                     (340230011); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Richmond Co., NY
                                     (360850067); Suffolk Co., NY
                                     (361030002); Allegheny Co., PA
                                     (420031005); Philadelphia Co., PA
                                     (421010024).
OK................................  Allegan Co., MI (260050003);
                                     Hamilton Co., OH (390610006);
                                     Dallas Co., TX (481130069); Dallas
                                     Co., TX (481130075); Denton Co., TX
                                     (481211032); Harris Co., TX
                                     (482010026); Harris Co., TX
                                     (482011034); Harris Co., TX
                                     (482011039); Tarrant Co., TX
                                     (484390075); Tarrant Co., TX
                                     (484393011).
PA................................  Fairfield Co., CT (90010017);
                                     Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001); Camden
                                     Co., NJ (340071001); Gloucester
                                     Co., NJ (340150002); Middlesex Co.,
                                     NJ (340230011); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Richmond Co., NY
                                     (360850067); Suffolk Co., NY
                                     (361030002).
TN................................  Hamilton Co., OH (390610006);
                                     Philadelphia Co., PA (421010024).

TX................................  Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001);
                                     Allegan Co., MI (260050003); Camden
                                     Co., NJ (340071001); Gloucester
                                     Co., NJ (340150002); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Richmond Co., NY
                                     (360850067); Suffolk Co., NY
                                     (361030002); Hamilton Co., OH
                                     (390610006); Allegheny Co., PA
                                     (420031005); Philadelphia Co., PA
                                     (421010024).
VA................................  Fairfield Co., CT (90010017);
                                     Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001);
                                     Gloucester Co., NJ (340150002);
                                     Middlesex Co., NJ (340230011);
                                     Ocean Co., NJ (340290006); Queens
                                     Co., NY (360810124); Richmond Co.,
                                     NY (360850067); Suffolk Co., NY
                                     (361030002); Philadelphia Co., PA
                                     (421010024).
WV................................  Baltimore Co., MD (240053001);
                                     Harford Co., MD (240251001); Camden
                                     Co., NJ (340071001); Gloucester
                                     Co., NJ (340150002); Middlesex Co.,
                                     NJ (340230011); Ocean Co., NJ
                                     (340290006); Queens Co., NY
                                     (360810124); Richmond Co., NY
                                     (360850067); Suffolk Co., NY
                                     (361030002); Hamilton Co., OH
                                     (390610006); Allegheny Co., PA
                                     (420031005); Philadelphia Co., PA
                                     (421010024).
WI................................  Allegan Co., MI (260050003); Wayne
                                     Co., MI (261630019).
------------------------------------------------------------------------

    As discussed previously, after the receptor and contribution
analyses for this proposal were underway, the EPA released an updated
IPM base case, version 5.15, and the final CPP. In order to reflect all
on-the-books policies as well as the most current power sector modeling
data, the EPA performed an assessment to reflect inclusion of IPM 5.15
with the CPP in an ``adjusted'' base case for this proposal. All
references below to the ``adjusted base case'' refer to the 2017 air
quality modeling base case which has been adjusted to account for the
revised IPM 5.15 with CPP emissions. This assessment method relied on
the EPA's air quality modeling contribution data as well as projected
ozone concentrations from an illustrative EGU NOX mitigation
scenario. For more information about these methods, refer to the Ozone
Transport Policy Analysis Technical Support Document.
    This assessment shows that two receptors--Hamilton County Ohio
(390610006) and Richmond County New York (360850067)--that were
projected to have average design values exceeding the NAAQS in the
modeled 2017 baseline, are expected to have average design values below
the NAAQS with the adjusted base case. However, these receptors are
still expected to have maximum design values exceeding the NAAQS with
the adjusted base case. Because both of these receptors are also
considered maintenance receptors for the purposes of this proposal,
their status as identified air quality concerns and the status of
states linked to these receptors is unchanged by the adjusted base
case.
    This assessment also shows that four receptors--Allegheny County
Pennsylvania (420031005), Collin County Texas (480850005), Wayne County
Michigan (261630019), and Middlesex County New Jersey (340230011)--that
were projected to have maximum design values exceeding the NAAQS in the
modeled base case, are expected to have maximum design values below the
NAAQS with the adjusted base case. With the adjusted base case, these
sites would not be considered nonattainment or maintenance receptors
for the purposes of this proposal. However, because no state is linked
solely to any one of these sites, changing the status of these
receptors does not impact the scope of states linked to downwind
nonattainment or maintenance receptors for this proposal.
    In addition to evaluating the status of downwind receptors
identified for this proposal, the EPA evaluated whether the adjusted
base case would reduce ozone contributions from upwind states to the
extent that a previously linked state would have a maximum contribution
less than the 1% threshold. This assessment shows that in the adjusted
base case, all states are expected to remain linked (i.e., contribute
greater than or equal to 1% of the NAAQS) to at least one downwind
nonattainment or maintenance receptor. Therefore, using the adjusted
base case for this proposal does not impact the scope of states linked
to downwind nonattainment or maintenance receptors relative to the
modeled base case.
    The analyses that EPA uses in section VI to quantify EGU
NOX ozone-season emissions budgets for this proposal also
rely on the adjusted base case.
    The EPA seeks comment on its assessment of the impacts of relying
on the adjusted base case for these purposes, and on EPA's intention to
rely on full air quality and IPM modeling of the adjusted base case to
identify nonattainment and maintenance receptors and to inform the
analysis of interstate ozone transport for the 2008 ozone NAAQS.

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

A. Introduction

    This section describes the EPA's proposed quantification of near-
term EGU NOX reductions that are necessary to fulfill (at
least in part) the Clean Air Act requirement to address interstate
ozone transport for the 2008 NAAQS. This section also describes the
EPA's proposal to translate these reductions into EGU NOX
ozone-season emissions budgets. Section VII describes the EPA's
proposal to implement these proposed emissions budgets via updates to
the existing CSAPR NOX ozone-season trading program.
    As described in section V, the EPA separately identified
nonattainment receptors and maintenance receptors. The EPA proposes to
apply a single approach for quantifying an upwind state's ozone
transport obligation to both nonattainment and maintenance receptors.
It is reasonable to apply the same approach to quantify upwind-state
reduction requirements with respect to both nonattainment and
maintenance because the structure of the problems is the same--
emissions from sources in upwind states contributing to downwind ozone
concentrations that put the downwind receptor at risk of nonattainment
with respect to the EPA's clean air standards. Moreover, as all
nonattainment receptors are also maintenance receptors because the
maximum design value will always be equal to or exceed the average
design value, it is reasonable to control all sites consistent with the
level of control necessary to reduce maintenance concerns.
    As described in section III of this preamble, due to the impending
July 2018 moderate area attainment date, the EPA is proposing, as a
first step, to

quantify near-term EGU NOX ozone-season emission reductions
to reduce interstate ozone transport for the 2008 ozone NAAQS. For this
section, this means that the EPA is proposing to quantify ozone season
EGU NOX reductions achievable for the 2017 ozone season
(i.e., the last full ozone season prior to the July 2018 attainment
date).
    The EPA's assessment of upwind state obligations in this proposal
reflects application of a multi-factor test that considers cost,
available emission reductions, and air quality. This is the same multi-
factor test used in the original CSAPR. This multi-factor test
considers increasing levels of uniform control stringency, where each
level is represented by cost, to determine the appropriate magnitude of
pollution reduction that would reduce the impacts of interstate
transport on downwind states and to apportion that reduction
responsibility among collectively-contributing upwind states. This
approach to quantifying upwind state emission reduction obligations was
reviewed by the Supreme Court in EPA v. EME Homer City Generation,
which held that using such an approach to apportion 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.'' 134 S.Ct. at 1607.
    There are three steps in developing and applying the multi-factor
test to quantify upwind state emission reductions as to the 2008 ozone
NAAQS: (1) Identify NOX mitigation strategies, focusing on
those that can be in place for the 2017 ozone season; (2) develop
uniform EGU NOX cost thresholds based on these NOx
mitigation strategies; (3) assess EGU NOX mitigation
potential that is achievable for 2017 and assess corresponding air
quality improvements resulting from the application of each uniform
cost threshold, including to check for over-control. This multi-factor
evaluation informs the EPA's determination of appropriate ozone season
EGU NOX reductions necessary to reduce significant
contribution to nonattainment and interference with maintenance of the
2008 ozone NAAQS for the proposed 2017 compliance year. These steps are
discussed in further detail in the following sections.
    This proposal evaluates a range of uniform EGU NOX costs
from $500 per ton to $10,000 per ton. This range, and the intermediate
uniform NOX cost thresholds evaluated within that range,
were selected based on the cost thresholds at which various EGU
NOX control technologies are widely available, the use of
certain EGU NOX cost thresholds in previous rules to address
ozone transport, and EGU NOX cost thresholds incorporated
into state requirements to address ozone nonattainment.
    In this proposal, the EPA evaluated the emission reduction
potential in each upwind state at each uniform NOX cost
threshold using the adjusted IPM base case 5.15. In this case, the EPA
limited IPM's evaluation of NOX mitigation strategies to
those that can be implemented for the 2017 ozone season, which is the
proposed compliance timing for this rulemaking, as described in section
VI.B below.

B. NOX Mitigation Strategies

    The following sub-sections describe the EPA's assessment of EGU and
non-EGU point source NOX mitigation strategies. For more
details on these assessments, refer to the EGU NOX
Mitigation Strategies TSD and the Update to Non-EGU Emission Reductions
Cost and Potential for States with Potentially Significant
Contributions under the 2008 Ozone Standard TSD in the docket for this
proposed rule.
1. EGU NOX Mitigation Strategies
    In developing this proposed rule, the EPA considered all widely
used EGU NOX control strategies: Fully operating existing
Selective Catalytic Reduction (SCR) and Selective Non-Catalytic
Reduction (SNCR)--including optimizing NOX removal by
existing, operational SCRs and SNCRs and turning on and optimizing
existing idled SCRs and SNCRs; installation of (or upgrading to) state-
of-the-art NOX combustion controls; shifting generation to
units with lower NOX emission rates within the same state;
and installing new SCRs and SNCRs. Although this proposal does not
require or impose any specific technology standards to demonstrate
compliance, EPA determined that certain technologies would be available
by the 2017 timeframe when assessing potential reductions in the
region.
    For the reasons explained below, the EPA determined that the power
sector could implement all of these NOX mitigation
strategies, except installation of new SCRs or SNCRs, between
finalization of this proposal in summer of 2016 and the 2017 ozone
season. As to the installation of new SCRs or SNCRs, the amount of time
from contract award through commissioning for retrofit with new SCR or
SNCR exceeds 18 and 12 months, respectively. For both technologies,
conceptual design, permitting, financing, and bid review require
additional time. It would therefore not be feasible to retrofit new SCR
or SNCR to achieve EGU NOX reductions in the 2017 ozone
season. See EGU NOX Mitigation Strategies TSD for discussion
of feasibility of EGU NOX controls for the 2017 ozone
season. Therefore, the EPA analyzed the remaining strategies for
purposes of quantifying upwind state obligations in this rule.
Exclusion of new SCR and SNCR installation from this analysis reflects
a determination only that these strategies are infeasible by 2017, not
a determination that they are infeasible or inappropriate for
consideration of cost-effective NOX reduction potential over
a longer timeframe. The EPA requests comment on what EGU NOX
mitigation strategies are feasible for the 2017 ozone season.
a. Fully Operating Existing SCRs and SNCRs
    Fully operating existing SCR and SNCRs can significantly reduce EGU
NOX emissions quickly, using investments that have already
been made. SCRs can achieve up to 90 percent reduction in EGU
NOX (with sufficient installed catalyst), while SNCRs can
achieve 20-30 percent reduction in EGU NOX, beyond the
reductions from combustion controls. These controls are in widespread
use across the U.S. power sector. In the east, approximately 64 percent
of coal-fired EGU capacity and 75 percent of natural gas combined cycle
(NGCC) EGU capacity is equipped with SCR or SNCR. Recent power sector
data reveal that some SCR and SNCR controls are being underused.\90\ In
some cases, controls are not fully operating (i.e., the controls could
be operated at a higher NOX removal rate). In other cases,
controls have been idled for years. Fully operating existing SCR and
SNCR would be a cost-effective and readily available approach for EGUs
to reduce NOX emissions and the EPA evaluated this
NOX mitigation strategy in quantifying EGU NOX
obligations for this proposal.
---------------------------------------------------------------------------

    \90\ This assessment is available in the EGU NOX
Mitigation Strategies TSD.
---------------------------------------------------------------------------

    For existing SCRs and SNCRs that are operating to some extent, but
not at their full pollution control capability, the EPA's analysis
determined that $500 per ton represents the costs reflective of fully
operating these systems. Because the SCR or SNCR is already installed
and is at least to some extent operating, the EPA assumes that
additional reagent (i.e., ammonia or urea) is the only

significant cost required for full operation. We observe that urea can
cost on the order of $300 per metric ton. The cost for anhydrous
ammonia is around $750 per ton.\91\ In our assessment, we assume that a
50 percent solution is used in removing an equivalent amount of
NOX. Thus, we estimate that sufficient reagent could be
purchased at a cost of $500 per ton of NOX removed to
achieve full operation for most SCRs and SNCRs. For more details on
this assessment, refer to the EGU NOX Mitigation Strategies
TSD in the docket for this proposed rule. The proposal seeks comment on
this assessment.
---------------------------------------------------------------------------

    \91\ Schnitkey, G. ``Nitrogen Fertilizer Prices and 2015
Planting Decisions.'' farmdoc daily (4):195, Department of
Agricultural and Consumer Economics, University of Illinois at
Urbana-Champaign, October 9, 2014.
    Permalink URL http://farmdocvdaily.illinois.edu/2014/10/nitrogen-fertilizer-prices-and-2015-planting-decisions.html.
---------------------------------------------------------------------------

    The operational difference between not fully operating and fully
operating existing SCRs and SNCRs is increasing reagent (i.e., ammonia
or urea) flow rate and ensuring sufficient reagent exists to sustain
higher flow operations. Therefore, increasing NOX removal
from these controls can be implemented by procuring more reagent.
Stocking-up additional reagent for sustaining increased NOX
removal could be done in a one or two weeks.\92\
---------------------------------------------------------------------------

    \92\ This assessment is available in the EGU NOX
Mitigation Strategies TSD.
---------------------------------------------------------------------------

    For existing SCRs and SNCRs that have been idled for years, unit
operators may need to restart payment of some fixed and variable costs
associated with that control. Fixed and variable costs include labor,
maintenance and repair, reagent, parasitic load, and ammonia or urea.
As further detailed in the EGU NOX Mitigation Strategies
TSD, which is found in the docket for this proposed rule, the EPA
performed an in-depth cost assessment for all coal-fired units with
SCRs, finding that 90 percent of the units had total SCR operation
costs of $1,300 per ton of NOX removed, or less.
    Based on this assessment, the EPA proposes that turning on and
fully operating idled SCRs is widely available at a uniform cost of
$1,300 per ton of NOX removed. For more details on this
assessment, refer to the EGU NOX Mitigation Strategies TSD
in the docket for this proposed rule. The proposal seeks comment on
this assessment.
    The EPA performed a similar assessment for fully operating existing
idled SNCR systems, finding that the majority of the total fixed and
variable operating cost for SNCR is related to the cost of the reagent
used (e.g., ammonia or urea) and that the resulting cost per ton of
NOX reduction is sensitive to the NOX rate of the
unit prior to SNCR operation. Based on the results of this analysis,
and in order to represent a broad range of unit-level NOX
rates before SNCR operation, the EPA proposes that turning on and fully
operating idled SNCRs is widely available at a uniform cost of $3,400
per ton of NOX removed. For more details on this assessment,
refer to the EGU NOX Mitigation Strategies TSD in the docket
for this proposed rule. The proposal seeks comment on this assessment
and on higher cost thresholds that would require some installation of
new SCRs/SNCRs and the appropriate timetable or phase-in needed to
accommodate those technologies.
    The EPA also evaluated the feasibility of turning on idled SCR and
SNCR for the 2017 ozone season. Based on past practice and the possible
effort to restart the controls (e.g., stockpiling reagent, bringing the
system out of protective lay-up, performing inspections, etc.),
returning these idled controls to operation should be available in
equal to or less than 3 months.\93\ The proposal seeks comment on this
assessment.
---------------------------------------------------------------------------

    \93\ This assessment is available in the EGU NOX
Mitigation Strategies TSD.
---------------------------------------------------------------------------

b. State-of-the-Art NOX Combustion Controls
    State-of-the-art combustion controls such as low-NOX
burners (LNB) and/or over-fire air (OFA) are cost-effective, can be
installed quickly, and can significantly reduce EGU NOX
emissions. Ninety-nine percent of coal-fired EGU capacity in the East
is equipped with some form of combustion control. Combustion controls
alone can achieve NOX emission rates of 0.15 to 0.50 lb/
mmBtu. Once installed, combustion controls reduce NOX
emissions at all times of EGU operation. State-of-the-art combustion
controls would be a cost-effective, timely, and readily available
approach for EGUs to reduce NOX emissions and the EPA
included this NOX mitigation strategy in quantifying EGU
NOX reductions for this proposal.
    The cost of state-of-the-art combustion controls per ton of
NOX reduced is dependent on the combustion control type and
unit type. We estimate the cost per ton of state-of-the-art combustion
controls to be $500 per ton to $1,200 per ton of NOX
removed. To be conservative, the EPA proposes that installation of (or
upgrading to) state-of-the-art NOX combustion controls is
widely available at $1,300 per ton of NOX removed.
    As described in CSAPR the EPA has observed that upgrade,
replacement, or installation of combustion controls has been
demonstrated to be achievable within the timeframe provided for by this
rulemaking and its compliance dates.\94\ The EPA revisited this
analysis with data specific to this proposal and proposes that a 2017
compliance timeframe is feasible for this EGU NOX mitigation
strategy. These controls are fully proven, widely used, and with a
reasonable effort can be procured, designed, installed, tested and be
in operation on any coal-steam EGU consistent with the compliance
timeframe provided for this rulemaking. The EPA proposes that this will
be feasible for the 2017 ozone season. The proposal seeks comment on
additional EGU NOx mitigation strategies that may be feasible for the
2017 ozone season.
---------------------------------------------------------------------------

    \94\ ``Installation Timing for Low NOX Burners
(LNB)'', Docket ID No. EPA-HQ-OAR-2009-0491-0051.
---------------------------------------------------------------------------

    For more details on this assessment, refer to the EGU
NOX Mitigation Strategies TSD in the docket for this
proposed rule. The proposal seeks comment on this assessment.
c. Shifting Generation to Lower NOX-Emitting EGUs
    Shifting generation to lower NOX-emitting EGUs, similar
to operating existing post-combustion controls, uses investments that
have already been made, can be done quickly, and can significantly
reduce EGU NOX emissions.
    Since CSAPR was promulgated, electricity generation has trended
toward lower NOX-emitting generation due to market
conditions (e.g., low natural gas prices) and state and federal
environmental policies. For example, new NGCC facilities, which
represented 45% of new 2014 capacity, can achieve NOX
emission rates of 0.0095 lb/mmBtu, compared to existing coal steam
facilities, which emitted at an average rate across the 23 states
included in this proposal of 0.18 lbs/mmBtu of NOX in 2014.
This substantial difference in NOX emission performance
between existing coal steam and new NGCC generation is due both to
higher nitrogen content in coal compared to natural gas, as well as to
the substantially lower generating efficiency of steam combustion
technology compared to combined cycle combustion technology. Shifting
generation to lower NOX-emitting EGUs would be a cost-
effective, timely, and readily available approach for EGUs to reduce
NOX emissions and the EPA

included this NOX mitigation strategy in quantifying EGU
NOX obligations for this proposal.
    Shifting generation to lower NOX-emitting EGUs occurs on
a continuum in response to economic factors such as fuel costs and
uniform NOX cost thresholds, including those evaluated for
this proposal (i.e., relatively lower uniform NOX cost
thresholds incentivize relatively fewer EGU NOX reductions
resulting from shifting generation, while relatively higher uniform
NOX cost thresholds encourage more EGU NOX
reductions driven by shifting generation). As a result, the EPA
quantified reduction potential from this EGU NOX mitigation
strategy at each cost level identified that represents the availability
of other pollution control measures evaluated in our assessment of
uniform NOX cost thresholds described in section VI.C.
    In this analysis, the EPA assumed shifting generation to units with
lower NOX emission rates could occur within the same state
by the near-term 2017 implementation timing for this proposed rule when
assessing state emission reduction potential for emissions budget
purposes. This conservative approach does not capture emission
reductions that would occur if generation was shifted more broadly
among units in different states, which the EPA believes is feasible
over time but which may be subject to out-of-merit order dispatch
constraints in the near term. Limiting such generation shifting
potential to units within each state is not a reflection of how
generation shifting works in practice (given that the grid crosses
state boundaries); instead, it is an analytic proxy designed to respect
the feasibility of near-term generation shifting in light of these
potential near-term out-of-merit order dispatch constraints. The EPA
seeks comment on this assessment and on this limitation in quantifying
EGU NOX reduction potential for the 2017 ozone season.
2. Non-EGU NOX Mitigation Strategies
    The EPA is not proposing to address non-EGU emission reductions in
its efforts to reduce interstate ozone transport for the 2008 ozone
NAAQS at this time. Compared to EGUs, there are relatively more non-EGU
point sources and these sources on average are smaller than EGUs. The
implication of these fleet characteristics is that there are more
individual sources to control and there are relatively fewer emission
reductions available from each source. Given the proposed 2017
implementation timing for this rulemaking, we are uncertain that
significant aggregate NOX mitigation is achievable from non-
EGU point sources for 2017. Moreover, there is greater uncertainty in
the EPA's assessment of non-EGU point-source NOX mitigation
potential (see below). The EPA requests comment on these issues,
including how non-EGU reductions should be addressed and considered in
fulfilling upwind states' good neighbor obligations under the 2008
ozone standard in the future, as the control of non-EGUs may be a
necessary part of addressing states' full transport obligation. States
can always choose to reduce non-EGU emissions via good neighbor SIPs.
    The EPA has evaluated the potential for ozone season NOX
reductions from non-EGU sources. A detailed discussion of this
assessment is provided in the Non-EGU NOX Mitigation
Potential TSD, located in the docket for this proposed rule. This TSD
discusses non-EGU source category emissions, EPA tools for estimating
emission reductions from non-EGU categories, and efforts, to date, to
review and refine our estimates for certain states. In addition, the
TSD contains brief discussions of available controls, costs, and
potential emission reductions for a few specific source categories. The
EPA views this non-EGU assessment as an initial step in future efforts
to evaluate non-EGU categories that may be necessary to fully quantify
upwind states' significant contribution to nonattainment and
interference with maintenance. The EPA seeks comment on its assessment
that non-EGU controls are not feasible by the 2017 ozone-season. It
also seeks comment on its broader non-EGU NOX mitigation
assessment and the availability of non-EGU NOX emission
reductions to mitigate interstate ozone transport in years following
2017.
    Although EPA did not find non-EGU reductions feasible by 2017 in
this proposal, it is taking comment on that assessment. Future EPA
rulemakings or guidance could revisit the potential for reductions from
non-EGU sources. Under such a scenario, EPA could use a similar
approach of identifying appropriate cost thresholds for non-EGUs and
EGUs alike, and then identify potential emission reductions and
corresponding emission budgets. Under this scenario, an emission budget
could be established for all covered sources (e.g., EGUs and non-EGUs
alike) with fungible allowances. EPA is taking comment on the potential
to combine EGUs and non-EGUs into a single trading program to resolve
the remaining non-attainment and maintenance issues at a later date.

C. Uniform EGU Cost Thresholds for Assessment

    As discussed above, the multi-factor test used here considers
increasing levels of uniform control stringency, where each level is
represented by cost, in combination with consideration of
NOX reduction potential and corresponding air quality
improvements. To determine which cost thresholds to use to assess
upwind state NOX mitigation potential, the EPA evaluated EGU
NOX control costs that represent the thresholds at which
various control technologies are widely available (described previously
in section VI.B), the use of certain cost thresholds in previous rules
to address ozone transport, and cost thresholds incorporated into state
requirements to address ozone nonattainment.
    The EPA began by determining the appropriate range of costs to
evaluate. The lower end of the range is informed by a confluence of
considerations. In CSAPR, $500 per ton was the EGU NOX cost
threshold relied upon to partially address ozone transport for the less
stringent 1997 standard. It is also the lowest marginal cost where EPA
expects NOX reduction to be cost effective, based on our
assessment of EGU NOX mitigation strategies (see section B).
Specifically, the cost of this approach to NOX reduction is
the marginal cost of running currently operating SCR and SNCR systems
at higher levels of NOX removal than they are currently
achieving. The EPA has not identified a discrete NOX
pollution control measure that would achieve sufficient emission
reductions to address relevant air quality impacts at an estimated cost
of less than $500 per ton; as a result, the EPA has not included a
representation of such a cost level in this proposal's analyses.\95\
---------------------------------------------------------------------------

    \95\ Additionally, the EPA notes that, as discussed in more
detail below, no identified air quality problems were resolved at
the $500 per ton cost threshold. Accordingly, it would not be
practical for the EPA to evaluate emission reductions achieved at
cost thresholds below $500 per ton.
---------------------------------------------------------------------------

    The EPA then evaluated EGU NOX cost thresholds to
determine an appropriate upper bound for our assessment. The EPA
identified $10,000 per ton as an upper bound, exceeding the costs of
operating existing or installing new EGU NOX controls.
    The EPA seeks comment on whether $500 per ton is an appropriate
minimum and $10,000 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.

    The EPA then determined appropriate EGU NOX cost
thresholds to evaluate within the range of $500 per ton to $10,000 per
ton. As described above, these cost thresholds are informed by our
assessment of the costs at which EGU NOX control strategies
are widely available. While the EPA could evaluate additional cost
thresholds in between those selected, this would not yield meaningful
insights as to NOX reduction potential. The EPA has
identified cost thresholds where control technologies are 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 VI.C-1 lists the EGU NOX cost thresholds
evaluated and the NOX reduction strategy or policy used to
identify each cost threshold.

                              Table VI.C-1
------------------------------------------------------------------------
      EGU NOX cost threshold
------------------------------------------------------------------------
$500/ton.........................  CSAPR ozone season NOX cost
                                    threshold; fully operating post-
                                    combustion controls that are already
                                    running.
$1,300/ton.......................  Widespread availability of restarting
                                    idled SCRs and state of the art
                                    combustion controls.
$3,400/ton.......................  NOX SIP Call ozone season NOX cost
                                    threshold, adjusted to 2014$;
                                    Widespread availability of
                                    restarting idled SNCRs.
$5,000/ton.......................  Widespread availability of new
                                    SCRs.\96\
$6,400/ton.......................  Widespread availability of new
                                    SNCRs.\97\
$10,000/ton......................  Upper bound.
------------------------------------------------------------------------

    The EPA proposes that this range and selection of interim uniform
cost thresholds are appropriate to evaluate potential EGU
NOX reduction obligations to address interstate ozone
transport for the 2008 ozone NAAQS. Because these cost thresholds are
linked to costs at which EGU NOX mitigation strategies
become widely available in each state, the cost thresholds represent
the break points at which the most significant step-changes in EGU
NOX mitigation are expected. The EPA seeks comment on the
appropriateness of evaluating these uniform cost thresholds for the
purpose of quantifying EGU NOX reductions to reduce
interstate ozone transport for the 2008 ozone NAAQS.
---------------------------------------------------------------------------

    \96\ The cost assessment for new SCR is available in the EGU
NOX Mitigation Strategies TSD. While chosen to define a
cost-threshold, new SCRs were not considered a feasible control on
the compliance timeframe being proposed for this rule.
    \97\ The cost assessment for new SNCR is available in the EGU
NOX Mitigation Strategies TSD. While chosen to define a
cost-threshold, new SNCRs were not considered a feasible control on
the compliance timeframe being proposed for this rule.
---------------------------------------------------------------------------

D. Assessing Cost, EGU NOX Reductions, and Air Quality

    The EPA analyzed ozone season NOX emission reductions
available from the power sector in each state using IPM.\98\ The agency
analyzed levels of uniform control stringency, where each level is
represented by uniform EGU NOX cost thresholds listed in
Table VI.C-1 above and repeated here: $500 per ton; $1,300 per ton;
$3,400 per ton; $5,000 per ton; $6,400 per ton; and $10,000 per ton.
The EPA limited IPM's NOX mitigation strategies to those
that could be implemented for 2017, as described in section VI.B.
---------------------------------------------------------------------------

    \98\ IPM version 5.14 is discussed in preamble section IV.B, and
as noted in preamble section V, for purposes of this quantification
analysis EPA used an adjusted base case reflecting IPM version 5.15,
including the Clean Power Plan. IPM documentation is in the docket
and available at www.epa.gov/powersectormodeling.
---------------------------------------------------------------------------

    The analysis applied these uniform EGU NOX cost
thresholds to EGUs in the 48 contiguous United States and the District
of Columbia, starting in 2017. The analysis covered EGUs with a
capacity (electrical output) greater than 25 MW to make the analysis
similar to previous analyses done for interstate transport purposes.
The EGU Emission Reduction Cost Analysis TSD, which is in the docket
for this proposed rule, provides further details of EPA's analysis of
ozone season NOX emission reductions occurring at the
representative EGU NOX cost thresholds analyzed for the 2017
ozone season.
    Table VI.D--1 shows the 2017 baseline EGU emissions and ozone
season NOX reduction potential in each state corresponding
to the uniform cost levels.

                          Table VI.D-1--EGU Ozone Season NOX Emission Reductions (Tons)
----------------------------------------------------------------------------------------------------------------
                                        2017 emissions         Reduction potential (short tons) at various
                                         (short tons)        representative marginal costs per ton (in 2011$)
                State                ---------------------------------------------------------------------------
                                          Base case           $500/ton          $1,300/ton         $3,400/ton
----------------------------------------------------------------------------------------------------------------
Alabama.............................             13,289              1,729              3,582              3,670
Arkansas............................              6,224                 13                104                859
Illinois............................             10,021                395                472                546
Indiana.............................             41,748              6,611             12,173             12,989
Iowa................................              7,911                186                423                717
Kansas..............................             11,332                428                438                465
Kentucky............................             27,141              3,608             11,896             12,382
Louisiana...........................             10,897                 64                117                400
Maryland............................              6,470              1,028              1,026              1,164
Michigan............................             20,049                403              3,033              3,528
Mississippi.........................              7,871                 82                297                893
Missouri............................             17,050                934                996              1,152
New Jersey..........................              3,302                370                372                378
New York............................              4,948                115                284                359
North Carolina......................             14,435              1,922              1,922              3,526

Ohio................................             27,795              5,746              9,646              9,666
Oklahoma............................             19,593                703              2,170              3,169
Pennsylvania........................             41,533              2,210             26,759             26,791
Tennessee...........................              5,554                 74                113                146
Texas...............................             58,199                685              3,610              5,810
Virginia............................              7,196                423                539              1,587
West Virginia.......................             25,384                592             10,908             12,014
Wisconsin...........................              5,257                  5                 36                107
                                     ---------------------------------------------------------------------------
    Total...........................            393,198             28,325             90,916            102,318
----------------------------------------------------------------------------------------------------------------

                    Table VI.D-1 (continued)--EGU Ozone Season NOX Emission Reductions (Tons)
----------------------------------------------------------------------------------------------------------------
                                                               Reduction potential (short tons) at various
                                                             representative marginal costs per ton (in 2011$)
                         State                          --------------------------------------------------------
                                                             $5,000/ton         $6,400/ton        $10,000/ton
----------------------------------------------------------------------------------------------------------------
Alabama................................................              4,780              5,418              5,840
Arkansas...............................................              1,147              1,242              1,935
Illinois...............................................                622                640                761
Indiana................................................             13,770             13,437             17,109
Iowa...................................................                717                717              1,317
Kansas.................................................                677                838              1,150
Kentucky...............................................             12,473             13,456             14,503
Louisiana..............................................                461                467                706
Maryland...............................................              1,176              1,369              1,369
Michigan...............................................              3,756              3,889              4,411
Mississippi............................................              1,165              1,479              2,208
Missouri...............................................              1,298              1,930              2,775
New Jersey.............................................                381                384                465
New York...............................................                370                661                906
North Carolina.........................................              3,626              4,415              4,643
Ohio...................................................              9,773             10,078             10,231
Oklahoma...............................................              3,821              5,702              6,609
Pennsylvania...........................................             26,913             26,932             27,091
Tennessee..............................................                224                241                285
Texas..................................................              6,940              7,772              8,380
Virginia...............................................              3,104              3,560              3,610
West Virginia..........................................             12,211             12,243             12,243
Wisconsin..............................................                131                276                618
                                                        --------------------------------------------------------
    Total..............................................            109,535            117,145            129,166
----------------------------------------------------------------------------------------------------------------

    Next, the EPA performed a combined multi-factor assessment of costs
(i.e., the uniform cost thresholds evaluated), EGU NOX
reductions (i.e., the reductions in Table VI.D-1), and corresponding
improvements in downwind ozone concentrations. For this assessment, the
EPA used simplifying assumptions regarding the relationship between EGU
NOX emissions and corresponding ozone concentrations at
nonattainment and maintenance receptors of concern. For more
information about how this assessment was performed, refer to the Ozone
Transport Policy Analysis Technical Support Document.
    For each nonattainment or maintenance receptor identified for this
proposal, the EPA evaluated the air quality improvement at that
receptor that is expected from progressively more stringent upwind EGU
NOX reductions in states that are linked to that receptor.
For example, the EPA evaluated the Harford County Maryland receptor
with all linked states controlling their emissions at $500 per ton.
This assessment showed a 0.35 ppb reduction in expected ozone design
values at $500 per ton. The residual design values at this site are
still expected to exceed the 2008 ozone NAAQS with an average design
value of 81.2 ppb and a maximum design value of 83.9 ppb. Next, the EPA
evaluated this receptor with all linked states controlling their
emissions at $1,300 per ton. This assessment showed a 0.94 ppb
reduction in expected ozone design values. At a cost threshold of
$1,300 per ton, the residual design values at this site are expected to
continue to exceed the 2008 ozone NAAQS with an average design value of
80.6 ppb and a maximum design value of 83.3 ppb. With respect to this
receptor, the EPA then evaluated each progressively more stringent
uniform control stringency (i.e. $3,400 per ton; $5,000 per ton; $6,400
per ton; and $10,000 per ton). Generally, the EPA evaluated the air
quality improvements at each monitoring site for each progressively
more stringent uniform EGU NOX control level. This
information is available in the Ozone Transport Policy Analysis TSD.
    This approach evaluates interstate ozone transport for each
receptor independently. Also, by evaluating the downwind ozone impact
of upwind

reductions that are made in all linked states at the same uniform
control stringency, this approach provides equitable treatment of all
upwind states as to their contribution to each downwind receptor to
which they are linked.
    The EPA aggregates the relevant data (i.e., cost of control, EGU
NOX reduction potential, and downwind ozone reduction
metrics) in a multi-factor test that allows the EPA to evaluate the
cost-effectiveness of various levels of emission reductions and the
resulting improvements in downwind ozone concentrations.
    This evaluation shows that meaningful EGU NOX reductions
are available at reasonable cost and that these reductions can provide
meaningful improvements in downwind ozone concentrations at the
identified nonattainment and maintenance receptors for this proposal.
For example, the combined downwind ozone improvement across
nonattainment and maintenance receptors is approximately 19 ppb at the
$1,300 per ton level. See Figure VI.1.
[GRAPHIC] [TIFF OMITTED] TP03DE15.000

    Combining costs, EGU NOX reductions, and corresponding
improvements in downwind ozone concentrations results in a ``knee in
the curve'' at $1,300 per ton. This uniform cost of reduction
represents the threshold at which EGU NOX reduction
potential and corresponding downwind ozone air quality improvements are
maximized with respect to marginal cost. That is, the ratio of emission
reductions to marginal cost and the ratio of ozone improvements to
marginal cost are maximized relative to the other uniform cost
thresholds evaluated. Further, at higher cost thresholds, as a result
of this analysis we do not anticipate significant additional reductions
that would justify these higher costs.
    As part of this analysis, the EPA evaluates potential over-control
with respect to whether (1) the expected ozone improvements would be
sufficient or greater than necessary to resolve the downwind ozone
pollution problem (i.e., resolving nonattainment or maintenance
problems) or (2) the expected ozone improvements would reduce upwind
state ozone contributions to below the screening threshold (i.e., 1% of
the NAAQS).
    In EME Homer City, the Supreme Court held that EPA cannot
``require[ ] an upwind State to reduce emissions by more than the
amount necessary to achieve attainment in every downwind State to which
it is linked.'' 134 S.Ct. at 1608. On remand from the Supreme Court,
the D.C. Circuit held that this means that EPA might overstep its
authority ``when those downwind locations would achieve attainment even
if less stringent emissions limits were imposed on the upwind States
linked to those locations.'' EME Homer City II, 795 F.3d at 127. The
D.C. Circuit qualified this statement by noting that this ``does not
mean that every such upwind State would then be entitled to less
stringent emission limits. Some of those upwind States may still be
subject to the more stringent emissions limits so as not to cause other
downwind locations to which those States are linked to fall into
nonattainment.'' Id. at 14-15.

    Consistent with these instructions from the Supreme Court and the
D.C. Circuit, the EPA evaluated whether reductions quantified under the
evaluated cost thresholds can be anticipated to resolve any downwind
nonattainment or maintenance problems (as defined in section V) and by
how much.
    The EPA's assessment shows that the uniform control stringency
represented by $500 per ton would resolve the maintenance problem at
two downwind maintenance receptors--Ocean County, New Jersey (maximum
design value of 75.9 ppb) and Oldham County, Kentucky (maximum design
value of 75.8 ppb). Because no state is linked solely to one of these
maintenance receptors, resolving these downwind air quality impact does
not fully address any individual upwind state's good neighbor
obligation.
    This assessment shows that the uniform control stringency
represented by $1,300 per ton would resolve maintenance problems at
three additional downwind maintenance receptors--Baltimore County,
Maryland (maximum design value of 75.6 ppb), Hamilton County, Ohio
(maximum design value of 75.1 ppb), and Gloucester County, New Jersey
(maximum design value of 75.8 ppb). The EPA's assessment shows that
this control level does resolve the only identified nonattainment or
maintenance problem to which North Carolina is linked for this
proposal--the Baltimore County, Maryland maintenance receptor. The EPA
therefore proposes that this EGU control level would fully address
North Carolina's good neighbor obligation with respect to the 2008
ozone NAAQS. The EPA seeks comment on this determination.
    The EPA also proposes that, based on the information supporting
this proposal, this level of EGU NOX control for North
Carolina would not constitute over-control as to the Baltimore County
receptor. The level of the 2008 ozone standard NAAQS is 75 ppb. At the
uniform $1,300 per ton cost threshold, EPA's assessment demonstrates
that the receptor would just be maintaining the standard, with a
maximum design value of 75.6 ppb. Therefore, the emissions reductions
that would be achieved at the $1,300 per ton cost threshold would not
result in air quality improvements at the Baltimore County receptor
significantly better than the standard such the emission reductions
might constitute over-control as to that receptor. On the contrary, the
emission reductions achieved in upwind states at the $1,300 per ton
cost threshold are necessary to bring the maximum design value at the
Baltimore County receptor into alignment with the standard. The EPA
also seeks comment on this determination.
    For the remainder of the states for which the EPA is proposing FIPs
in this action, none of these states are linked solely to one of these
maintenance receptors with air quality resolved at the $1,300 per ton
cost threshold. Therefore, resolving these downwind air quality impacts
does not fully address any other individual upwind state's good
neighbor obligation.
    As noted above the EPA is proposing that the $1,300 per ton EGU
control level would fully address North Carolina's good neighbor
obligation with respect to the 2008 ozone NAAQS. As such, based on the
data supporting this proposal, North Carolina was excluded from
assessment of air quality improvements at more stringent uniform EGU
NOX control levels.
    The EPA's assessment shows that the uniform control stringency
represented by $3,400 per ton would resolve the maintenance problem at
two additional downwind maintenance receptors--Denton County, Texas
(481211032) (maximum design value of 75.9 ppb) and Harris County, Texas
(482011050) (maximum design value of 75.9 ppb). Because no state is
linked solely to one of these maintenance receptors, resolving these
downwind air quality impacts does not fully address any individual
upwind state's good neighbor obligation.
    The EPA provides this summary of the evaluation for the $500 per
ton; $1,300 per ton; and $3,400 per ton uniform cost thresholds
because, as described below, the EPA is proposing to use the $1,300 per
ton level and is taking comment on using the $500 per ton level or
$3,400 per ton level to quantify ozone season EGU NOX
requirements to reduce interstate ozone transport for the 2008 ozone
NAAQS. Further information on the EPA's evaluation of these cost
thresholds as well as additional cost thresholds ($5,000 per ton;
$6,400 per ton; and $10,000 per ton) are provided in the Ozone
Transport Policy Analysis Technical Support Document. Additionally,
Table VI.D-2 provides a summary of the expected number of nonattainment
and maintenance-only receptors at the adjusted base case and cost
thresholds.

Table VI.D-2--Number of Nonattainment or Maintenance Receptors After EGU
                             NOX Mitigation
------------------------------------------------------------------------
                                           Nonattainment   Maintenance-
             Cost threshold                  receptors    only receptors
------------------------------------------------------------------------
Base Case (IPM 5.15 w/CPP)..............              12              21
$500 per ton............................              12              19
$1,300 per ton..........................              12              14
$3,400 per ton..........................              12              13
$5,000 per ton..........................              12              13
$6,400 per ton..........................              12              13
$10,000 per ton.........................              12              12
------------------------------------------------------------------------

    In EME Homer City, the Supreme Court also held that ``EPA cannot
require a State to reduce its output of pollution . . . at odds with
the one-percent threshold the Agency has set.'' 134 S.Ct. at 1608. The
Court explained that ``EPA cannot demand reductions that would drive an
upwind State's contribution to every downwind State to which it is
linked below one percent of the relevant NAAQS.'' Id. Accordingly, the
EPA also evaluated the potential for over-control with respect to the
1% threshold proposed to be applied in this rulemaking at each relevant
cost threshold. Specifically, the EPA evaluated whether the uniform
cost thresholds would reduce upwind EGU emissions to a level where the
contribution from each upwind state would be below the 1% threshold
that linked the upwind state to the downwind receptors. If the EPA
found that any state's reduction obligation at the applied cost
threshold decreased its contribution to every downwind receptor to
which it is linked below the 1% threshold, we would need to adjust the
state's reduction obligation accordingly. The EPA's assessment

reveals that there is not over-control with respect to the 1% threshold
at any of the evaluated uniform costs in any upwind state; in fact,
even at the highest uniform cost threshold evaluated (e.g., $10,000 per
ton), all upwind states that contributed greater than or equal to the
1% threshold in the base case continued to contribute greater than or
equal to 1% of the NAAQS to at least one downwind nonattainment or
maintenance receptor.\99\ Therefore, the EPA does not expect any of the
uniform cost thresholds evaluated to result in over-control relative to
the 1% threshold. For more information about this assessment, refer to
the Ozone Transport Policy Analysis Technical Support Document.
---------------------------------------------------------------------------

    \99\ As discussed above, North Carolina would not be regulated
at any level higher than $1300/ton and at that level, there's no
over-control as to the 1% threshold. In fact, while the receptor to
which North Carolina is linked resolves its maintenance problem at
the $1,300/ton level, North Carolina would continue to contribute
equal to or greater than 1% to that air quality monitor.
---------------------------------------------------------------------------

    The EPA proposes to determine ozone season EGU NOX
control requirements for upwind states to reduce interstate ozone
transport for the 2008 ozone NAAQS based on the reduction potential
quantified from pollution control measures that are cost-effective at
the $1,300 per ton level. The EPA seeks comment on potentially basing
these ozone season NOX control requirements on uniform cost
levels that are less stringent ($500 per ton) or more stringent ($3,400
per ton), including comments on the proposed approach to addressing a
state like North Carolina in such a situation, which is explained
below.
    The EPA notes that the evaluation of cost, NOX
reductions, and ozone improvements for the final rule could show
different results for different states. For example, one or more states
could fully address their good neighbor obligation based on ozone
season NOX control requirements represented by one cost
level while one or more other states would not fully address their good
neighbor obligation at that level and would have ozone season
NOX control requirements based on a more stringent cost
level in order to fully address or make further progress toward
partially addressing their good neighbor obligation. In this situation,
the EPA proposes that it would quantify requirements for these
different groups of states based on different uniform control
stringencies. This could be similar to EPA's establishing two different
SO2 groups under the original CSAPR as to addressing
PM2.5 transport. The EPA seeks comment on this proposed
approach for quantifying requirements.
    The EPA also seeks comment on implementation of the resulting
emissions budgets. The EPA proposes that if there are groups of states
with ozone season NOX control requirements based on
different cost levels, we would nevertheless finalize FIPs for the
states in these groups of states that incorporate participation in a
trading program that allows them to trade allowances with each other
subject to limitations described in section VII of this proposal.
    By way of example and as noted above, the EPA is also seeking
comment on potentially basing ozone season NOX control
requirements on the $3,400 per ton uniform cost levels. If the EPA were
to finalize ozone season NOX control requirements based on
this level, given the specific data informing this proposal, then the
EPA would set North Carolina's requirements based on the less stringent
$1,300 per ton level because, as discussed above, the sole receptor to
which North Carolina is linked for this proposal is resolved at the
$1,300 per ton level with a maximum design value of 75.6 ppb.
Therefore, because the $1,300 per ton level fully addresses North
Carolina's good neighbor obligation, if EPA were to determine ozone
season NOX control requirements based on the $3,400 per ton
level for the remainder of states, the EPA would finalize good neighbor
requirements for these two groups of states using different uniform
control stringencies. The EPA proposes that it would finalize FIPs for
the states that incorporate participation in a trading program that
allows them to trade allowances with each other subject to limitations
described in section VII of this proposal.
    The EPA's selection of reductions for this proposed rule is
specific to, and appropriate for, defining near-term achievable upwind
obligations with respect to the 2008 ozone NAAQS in states where a FIP
is necessary. We do not intend--nor do we believe we would be justified
in doing so in any event--that the cost-level-based determinations in
this proposed rule impose a constraint for selection of cost levels in
addressing transported pollution with respect to future NAAQS and/or
any revisions to these FIPs for any other future transport rules that
the EPA may develop to address any potential remaining obligation as to
the current NAAQS, for which different cost levels may be appropriate.
    As described above, the EPA is proposing that the NOX
emission reductions associated with uniform control stringency
represented by $1,300 per ton would not result in over-control at any
of the identified non-attainment or maintenance receptors and it is
reasonable to require such reductions from upwind states.
    The EPA requests comment on its proposal to quantify ozone season
EGU NOX reductions to reduce interstate transport with
respect to the 2008 ozone NAAQS using the $1,300 per ton uniform cost
threshold.
    Note that our assessment of EGU NOX reduction potential
shows zero reductions available in Delaware in 2017 at any evaluated
cost threshold. At this time, because the assessment shows no EGU
NOX reduction potential within Delaware up to $10,000 per