Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, New York,
Ohio, Pennsylvania, Virginia, and West Virginia. Based on the maximum
downwind contributions in Table V.D-1, the following 12 states
contribute at or above the 0.75 ppb threshold to downwind maintenance-
only receptors: Illinois, Indiana, Kentucky, Louisiana, Maryland,
Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia, and West
Virginia. The levels of contribution between each of these linked
upwind state and downwind nonattainment receptors and maintenance-only
receptors are provided in Table V.D-2 and Table V.D-3, respectively.

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

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

    In conclusion, as described above, states with contributions that
equal or exceed 1 percent of the NAAQS to either nonattainment or
maintenance receptors are identified as ``linked'' at step 2 of the
good neighbor framework and warrant further analysis for significant
contribution to nonattainment or interference with maintenance under
step 3. EPA is determining that the following 12 States are linked at
step 2: Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New
Jersey, New York, Ohio, Pennsylvania, Virginia, and West Virginia.

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

A. The Multi-Factor Test

    This section describes EPA's methodology at step 3 of the 4-step
framework for identifying upwind emissions that constitute
``significant'' contribution for the states subject to this final rule.
This analysis focuses on the 12 states linked at steps 1 and 2 of the
framework, as identified in the sections above. Following the existing
framework as applied in the CSAPR Update, EPA's assessment of linked
upwind state emissions reflects analysis of uniform NOX
emission control stringency. The analysis has been extended to include
assessment of non-EGU sources in addition to EGU sources in the linked
upwind states.
    Each level of uniform NOX control stringency is
characterized by a set of pollution control measures. EPA applies a
multi-factor test--the same multi-factor test that was used in the
CSAPR and the CSAPR Update \108\--to evaluate increasing levels of
uniform NOX control stringency. The multi-factor test, which
is central to EPA's step 3 quantification of significant contribution,
considers cost, available emission reductions, and downwind air quality
impacts to determine the appropriate level of uniform NOX
control stringency that addresses the impacts of interstate transport
on downwind nonattainment or maintenance receptors. The uniform
NOX emission control stringency, represented by marginal
cost (or a weighted average cost in the case of EPA's non-EGU
analysis), also serves to apportion the reduction responsibility among
collectively contributing upwind states. This approach to quantifying
upwind state emission-reduction obligations using uniform cost was
reviewed by the Supreme Court in EME Homer City Generation, which held
that using such an approach to apportion emission reduction
responsibilities among upwind states that are collectively responsible
for downwind air quality impacts ``is an efficient and equitable
solution to the allocation problem the Good Neighbor Provision requires
the Agency to address.'' 572 U.S. at 519.
---------------------------------------------------------------------------

    \108\ See CSAPR, Final Rule, 76 FR 48208 (Aug. 8, 2011).
---------------------------------------------------------------------------

    There are four stages in developing the multi-factor test: (1)
Identify levels of uniform NOX control stringency; (2)
evaluate potential NOX emission reductions associated with
each identified level of uniform control stringency; (3) assess air
quality improvements at downwind receptors for each level of uniform
control stringency; and (4) select a level of control stringency
considering the identified cost, available NOX emission
reductions, and downwind air quality impacts, while also ensuring that
emission reductions do not unnecessarily over-control relative to

the contribution threshold or downwind air quality.
    Comment: Some commenters suggested EPA also consider regulating
volatile organic compounds (VOCs) as it represents another precursor to
ozone formation. They assert EPA's failure to reduce significant
contributions to downwind nonattainment/maintenance by reducing upwind
VOC emissions disproportionately harms communities of color, low-income
communities, and children, perpetuating environmental injustice.
    Response: EPA agrees that VOCs are a precursor along with
NOX in forming ground-level ozone and that ozone formation
chemistry can be ``NOX-limited'', where ozone production is
primarily determined by the amount of NOX emissions or
``VOC-limited'', where ozone production is primarily determined by the
amount of VOC emissions.\109\ EPA also acknowledges that VOCs can
contain toxic chemicals that affect public health. EPA's obligation in
this action is to complete the elimination of significant contribution
to nonattainment or interference with maintenance of NAAQS in other
states for 12 states in the East to meet the requirements of section
110(a)(2)(D)(i)(I) of the Act. Provisions for local NAAQS attainment
and exposure to toxic pollutant concentrations are addressed by other
sections of the statute. EPA and others have long regarded
NOX to be the more significant ozone precursor in the
context of interstate ozone transport.\110\ In response to this
comment, EPA examined the results of the contribution modeling
performed for this rule to identify the portion of the ozone
contribution attributable to anthropogenic NOX emissions
versus VOC emissions from each linked upwind state to each downwind
receptor. Table VI.A provides the ozone contribution from each upwind
state linked to the receptors in Connecticut along with the percent (in
parenthesis) of the contribution that is formed under ``NOX-
limited'' photochemistry. The data show that NOX is the
determinative precursor for over 80 percent of the total contribution
from each upwind state to each of these receptors. In addition to the
Connecticut receptors, ozone primarily formed from NOX
emissions is 95 percent of the 4.58 ppb contribution from Louisiana to
the receptor in Harris County, Texas. Therefore, EPA's review of the
data leads to the finding that, as proposed, a focus on NOX
emission reductions is appropriate for the purpose of addressing
interstate ozone transport.
---------------------------------------------------------------------------

    \109\ ``Ozone Air Pollution.'' Introduction to Atmospheric
Chemistry, by Daniel J. Jacob, Princeton University Press,
Princeton, New Jersey, 1999, pp. 231-244.
    \110\ 81 FR 74514.

         Table VI.A.--Contribution (ppb) From Each Linked Upwind State to Receptors in Connecticut and the Percent of the Contribution From NOX
--------------------------------------------------------------------------------------------------------------------------------------------------------
   State         Receptor          IL         IN         KY         MD         MI         NJ          NY          OH         PA         VA         WV
--------------------------------------------------------------------------------------------------------------------------------------------------------
CT.........  Stratford.......        Not       0.96       0.76       1.18       1.13       7.48  14.01 (81%)       2.27       6.53       1.25       1.41
                                  Linked      (95%)      (96%)      (90%)      (95%)      (83%)                   (95%)      (93%)      (93%)      (97%)
CT.........  Westport........       0.79       1.23       0.85       1.18       1.67       8.44  14.14 (81%)       2.50       6.72       1.27       1.45
                                   (94%)      (95%)      (96%)      (89%)      (94%)      (83%)                   (95%)      (92%)      (92%)      (96%)
CT.........  Madison.........       0.78       1.04       0.77       1.51       1.57       5.53  12.15 (86%)       2.27       5.47       1.63       1.51
                                   (95%)      (96%)      (96%)      (91%)      (95%)      (84%)                   (95%)      (92%)      (93%)      (96%)
--------------------------------------------------------------------------------------------------------------------------------------------------------

    For both EGUs and non-EGUs, section VI.B describes the available
NOX emission controls considered and their associated cost
levels (in 2016$). Section VI.C discusses EPA's application of that
information to assess emission reduction potential of the identified
control stringencies. Finally, section VI.D describes EPA's assessment
of associated air quality impacts and EPA's subsequent identification
of appropriate control stringencies considering the relevant factors
(cost, available emission reductions, and downwind air quality
impacts). As discussed in greater detail in section VI.D, the multi-
factor test informed EPA's determination of appropriate EGU
NOX ozone season emission budgets necessary to reduce
emissions that significantly contribute to nonattainment or interfere
with maintenance of the 2008 ozone NAAQS for the 2021 ozone season and
subsequent control periods.
    This multi-factor approach is consistent with EPA's approach in the
prior CSAPR and CSAPR Update actions. In addition, as was done in the
CSAPR Update, EPA evaluated possible over-control by determining if an
upwind state is linked solely to downwind air quality problems that
could have been resolved at a lower representative cost threshold, or
if upwind states could reduce their emissions below the 1 percent air
quality contribution threshold at a lower representative cost
threshold. This analysis is described in section VI.D.
    In the proposed rule, EPA identified a control stringency that
reflects the optimization of existing SCR controls and installation of
state-of-the-art NOX combustion controls at EGUs, with an
estimated marginal cost of $1,600 per ton. As explained in greater
detail in section VI.D, EPA is finalizing an EGU control stringency
that also includes optimizing existing SNCR controls. Application of
the multi-factor test to non-EGU sources has led EPA to conclude, as
the Agency proposed, that emission reductions from non-EGU sources are
not necessary to address significant contribution or interference with
maintenance under the 2008 ozone NAAQS.

B. Identifying Levels of Control Stringency

1. EGU NOX Mitigation Strategies
    In identifying levels of uniform control stringency for EGUs, EPA
reassessed the same NOX emission controls that it had
analyzed in the CSAPR Update, all of which are considered to be widely
available in this sector: (1) Fully operating existing SCR, including
both optimizing NOX removal by existing operational SCRs and
turning on and optimizing existing idled SCRs; (2) installing state-of-
the-art NOX combustion controls; (3) fully operating
existing SNCRs, including both optimizing NOX removal by
existing operational SNCRs and turning on and optimizing existing idled
SNCRs; (4) installing new SNCRs; and (5) installing new SCRs. For the
reasons explained in the EGU NOX Mitigation Strategies Final
Rule TSD included in the docket for this final rule, EPA determined
that for the regional, multi-state scale of this rulemaking, only EGU
NOX emission controls 1 and 3 are possible for the 2021
ozone season (fully operating existing SCRs and SNCRs). As discussed

in section VI.B.1.b, EPA finds that it is not possible to install
state-of-the-art NOX combustion controls by the 2021 ozone
season on a regional scale. EPA determined state-of-the-art
NOX combustion controls at EGUs are available by the
beginning of the 2022 ozone season.
a. Optimizing Existing SCRs
    Optimizing (i.e., turning on idled or improving operation of
partially operating) existing SCRs can substantially reduce EGU
NOX emissions quickly using investments that have already
been made in pollution control technologies. With the promulgation of
the CSAPR Update, most operators improved their SCR performance and
have continued to maintain that level of improved operation. However,
this SCR performance is not universal and some drop has been observed
as the CSAPR Update ozone-season allowance price has declined steadily
since 2017. For example, recent power sector data from 2019 reveal
that, in some cases, operating units have SCR controls that have been
idled or are operating partially, and therefore suggest that there
remains reduction potential through optimization.\111\ EPA determined
that optimizing all of these remaining SCRs in the 12 linked states is
a readily available approach for EGUs to reduce NOX
emissions.
---------------------------------------------------------------------------

    \111\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason.
---------------------------------------------------------------------------

    EPA estimates a representative cost of optimizing SCR controls to
be approximately $1,600 per ton. EPA's analysis of this emission
control is informed by comment on the CSAPR Update proposed rule and
updated information on operation and industrial-input costs that have
become available since the CSAPR Update.\112\ While the costs of
optimizing existing, operational SCRs include only variable costs, the
cost of optimizing SCR units that are currently idled back into service
considers both variable and fixed costs. Variable and fixed costs
include labor, maintenance and repair, parasitic load, and ammonia or
urea for use as a NOX reduction reagent in SCR systems. EPA
performed an in-depth cost assessment for all coal-fired units with
SCRs. More information about this analysis is available in the EGU
NOX Mitigation Strategies Final Rule TSD, which is found in
the docket for this rule. The TSD notes that, for the subset of SCRs
that are already partially operating, the cost of optimizing is often
much lower than the $1,600 per ton marginal cost and often under $800
per ton.
---------------------------------------------------------------------------

    \112\ The CSAPR Update found $1,400 per ton was a level of
uniform control stringency that represented turning on idled SCR
controls. EPA uses the same costing methodology, but updating for
input cost increases (e.g., urea reagent) to arrive at $1,600 per
ton in this rule (while also updated from 2011 dollars to 2016
dollars).
---------------------------------------------------------------------------

    EPA is using the same methodology to identify SCR performance as it
did in the CSAPR Update. To estimate EGU NOX reduction
potential from optimizing, EPA considers the difference between the
non-optimized NOX emission rates and an achievable operating
and optimized SCR NOX emission rate. To determine this rate
in the CSAPR Update, EPA evaluated nationwide coal-fired EGU
NOX ozone season emissions data from 2009 through 2015 and
calculated an average NOX ozone season emission rate across
the fleet of coal-fired EGUs with SCR for each of these seven years.
EPA found it prudent to not consider the lowest or second-lowest ozone
season NOX emission rates, which may reflect new SCR systems
that have all new components (e.g., new layers of catalyst). Data from
these new systems are not representative of ongoing achievable
NOX emission rates considering broken-in components and
routine maintenance schedules. To identify the potential reductions
from SCR optimization in this final action, EPA followed the same
methodology and incorporated the latest reported coal-fired EGU
NOX ozone season emissions data. EPA updated the timeframe
to include the most recent and best available operational data (i.e.,
2009 through 2019). Considering the emissions data over the full time
period of available data results in a third-best rate of 0.08 pounds
per million British thermal units (lb/mmBtu). EPA notes that over half
of the SCR-controlled EGUs achieved a NOX emission rate of
0.068 lbs/mmBtu or less over their third-best entire ozone season.
Moreover, for the SCR-controlled coal units that EPA identified as
having a 2019 emission rate greater than 0.08 lb/mmBtu, EPA verified
that in prior years, the majority (approximately 95 percent) of these
same units had demonstrated and achieved a NOX emission rate
of 0.08 lb/mmBtu or less on a seasonal and/or monthly basis. This
further supports EPA's determination that 0.08 lb/mmBtu reflects a
reasonable emission rate for representing SCR optimization in
quantifying state emission budgets as discussed in section VII.B. This
fleet-level emission rate assumption of 0.08 lb/mmBtu for non-optimized
units reflects, on average, what those units would achieve when
optimized. Some of these units may achieve rates that are lower than
0.08 lb/mmBtu, and some units may operate above that rate based on
unit-specific configuration and dispatch patterns.
    EPA evaluated the feasibility of optimizing idled SCRs for the 2021
ozone season. Based on industry past practice, EPA determined that
idled controls can be restored to operation quickly (less than two
months). This timeframe is informed by many electric utilities'
previous long-standing practice of utilizing SCRs to reduce EGU
NOX emission during the ozone season while putting the
systems into protective lay-up during the non-ozone season months. For
example, this was the long-standing practice of many EGUs that used SCR
systems for compliance with the NOX Budget Trading Program.
It was quite typical for SCRs to be turned off following the September
30 end of the ozone season control period. These controls would then be
put into protective lay-up for several months of non-use before being
returned to operation by May 1 of the following ozone season.\113\
Therefore, EPA believes that optimization of existing SCRs is possible
for the portion of the 2021 ozone season covered under this final rule.
---------------------------------------------------------------------------

    \113\ In the 22 state CSAPR Update region, 2005 EGU
NOX emissions data suggest that 125 EGUs operated SCR
systems in the summer ozone season while idling these controls for
the remaining 7 non-ozone season months of the year. Units with SCR
were identified as those with 2005 ozone season average
NOX rates that were less than 0.12 lbs/mmBtu and 2005
average non-ozone season NOX emission rates that exceeded
0.12 lbs/mmBtu and where the average non-ozone season NOX
rate was more than double the ozone season rate.
---------------------------------------------------------------------------

    The vast majority of SCR controlled units (nationwide and in the 12
linked states) are already partially operating these controls during
the ozone season based on historical 2019 emissions rates. EPA believes
that this widely demonstrated seasonal behavior of turning on idled
SCRs also supports the Agency's determination that optimizing existing
SCR systems currently being operated to some degree within the ozone
season, which would necessitate fewer changes to SCR operation relative
to restarting idled systems, is also feasible for the 2021 ozone
season. Full operation of existing SCRs that are already operating to
some extent involves increasing reagent (i.e., ammonia or urea) flow
rate, and maintaining and replacing catalyst to sustain higher
NOX removal rate operations. Increasing NOX
removal by SCR controls that are already operating can be implemented
by procuring more reagent and catalyst. EGUs with SCR routinely procure
reagent and catalyst as

part of ongoing operation and maintenance of the SCR system. In many
cases, where EPA has identified EGUs that are operating their SCR at
non-optimized NOX removal efficiencies, EGU data indicate
that these units historically have achieved more efficient
NOX removal rates. Therefore, EPA determined that optimizing
existing SCRs currently being operated could generally be done by
reverting back to previous operation and maintenance plans. Regarding
full operation activities, existing SCRs that are only operating at
partial capacity still provide functioning, maintained systems that may
only require increased chemical reagent feed rate up to their design
potential and catalyst maintenance for mitigating NOX
emissions. Units must have adequate inventory of chemical reagent and
catalyst deliveries to sustain operations. Considering that units have
procurement programs in place for operating SCRs, this may only require
updating the frequency of deliveries. This may be accomplished within a
few weeks.
    Comment: EPA received comments supporting the 0.08 lb/mmBtu
emission rate as achievable and, according to some commenters,
conservative. Some of these commenters went on to provide their own
analysis demonstrating that the 0.08 lb/mmBtu was achievable not only
on average for the non-optimized fleet, but also for these individual
units and that the resulting state emission budgets were likewise
achievable. Some commenters suggested that the rate should be lower and
premised on EPA using a longer historical baseline (e.g., extending
baseline back to year 2006) and relying on the first- or second-best
year instead of the third best year of SCR performance. In addition to
supporting the 0.08 lb/mmBtu optimization rate as viable for 2021,
these same commenters noted the 2021 attainment data and suggested
implementation by 2021 was not only achievable, but necessary under
Clean Air Act requirements and the Wisconsin directive.
    Response: As explained above, EPA chose 2009 for the start of its
baseline period of SCR performance examination because that is the
first year of annual compliance under the CAIR NOX program.
The analysis focuses on the third best ozone season average rate
because EPA believes that the first or second best rate, as discussed
in the CSAPR Update final rule, could continue to capture
disproportionately new SCR components and/or the onset of new
regulatory programs and does not necessarily reflect achievable ongoing
NOX emission rates. Therefore, EPA is finalizing analysis
using the third best rate starting from 2009--consistent with its
approach in the CSAPR Update.
    Comment: Other commenters suggested that EPA should apply a higher
emission rate than 0.08 lb/mmBtu premised on considerations such as: A
generally reduced average capacity factor for coal units in recent
years, the age of the boiler, coal rank (bituminous or subbituminous),
or other unit-specific considerations that make the 0.08 lb/mmBtu rate
unattainable for a specific unit. They also suggested that EPA's
determination of the rate should be premised on EPA using a shorter
historical baseline (e.g., shortening the baseline to year 2013).
    Response: EPA did not find sufficient justification to apply a
higher average emission rate than 0.08 lb/mmBtu or for shortening the
baseline to exclude representative operational data starting in 2009.
EPA found that some commenters were misunderstanding or misconstruing
both EPA's assumption and implementation mechanism as a unit-level
requirement for every SCR-controlled unit instead of a reflection of a
fleet-wide average based on a third-best rate. The commenters'
observation--that 0.08 lb/mmBtu may be difficult for some units to
achieve or may not be a preferred compliance strategy for a given unit
given its dispatch levels--does not contradict EPA's assumption, but
rather supports its methodology and assumptions. As EPA pointed out in
the proposed rule, ``this fleet-level emission rate assumption of 0.08
lb/mmBtu for non-optimized units reflects, on average, what those units
would achieve when optimized. Some of these units may achieve rates
that are lower than 0.08 lb/mmBtu, and some units may operate above
that rate based on unit-specific configuration and dispatch patterns.''
\114\ In other words, EPA is using this assumption as the average
performance of a unit that optimizes its SCR, recognizing that
heterogeneity within the fleet will likely lead some units to
overperform and others to underperform this rate. Moreover, a review of
unit-specific historical data indicates that this is a reasonable
assumption: Not only has the group of units with SCR optimization
potential demonstrated they can perform at or better than the 0.08 lb/
mmBtu rate on average, but 95 percent of the individual units in this
group have met this rate on a seasonal and/or monthly basis based on
their reported historical data.\115\ Additionally, EPA's examination of
units with the largest emission reduction potential based on SCR
optimization levels of 0.08 lb/mmBtu indicates the ability of units to
improve emission rate performance. As an example, Miami Fort Unit 7 had
considerably more hours operating at a 70 to 79 percent capacity factor
in 2019 compared to previous years. However, Miami Fort Unit 7's ozone-
season NOX emission rate substantially increased in 2019
compared to previous years. This runs counter to the notion that an
increase in emission rates is purely driven by reduced capacity factor,
as suggested by commenters. This substantial deterioration in the
median emission rate performance is observable even when comparing
specific hours in 2019 to specific hours in prior years when the unit
operated in the same 70 to 79 percent capacity factor range. In fact,
in 2019 the unit experienced notable emission rate increases from prior
years across multiple capacity factor ranges as low as 40 percent to as
high as 80 percent. This type of data indicates instances where the
increase in emission rate (and emissions) is not necessitated by load
changes but is more likely due to the erosion of the existing incentive
to optimize controls (i.e., the ozone-season NOx allowance
price has fallen so low that unit operators find it more economic to
surrender additional allowances instead of continuing to operate
pollution controls at an optimized level). This type of decline in
emission rate performance at some SCR-controlled units is what EPA
disincentivizes with the full remedy nature of this action.
---------------------------------------------------------------------------

    \114\ 85 FR 68991.
    \115\ See ``Optimizing SCR Units With Best Historical
NOX Rates Final'' file included in the docket for this
rulemaking.

---------------------------------------------------------------------------

[GRAPHIC] [TIFF OMITTED] TR30AP21.000

    EPA observed this pattern in other units identified in this
rulemaking as having significant SCR optimization emission reduction
potential. In the accompanying Emissions Data TSD for the supplemental
notice that EPA recently released in a proceeding to address a
recommendation submitted to EPA by the Ozone Transport Commission under
CAA section 184(c), EPA noted, ``In their years with the lowest average
ozone season NOX emission rates in this analysis, these EGUs
had relatively low NOX emission rates at mid- and high-
operating levels; moreover, there was little variability in
NOX emission rates at these operating levels. However,
during the 2019 ozone season, these EGUs had higher NOX
emission rates and greater variability in NOX emission rates
across operating levels than in the past, particularly at mid-operating
levels.'' \116\ That hourly data analysis, included in this docket,
controls for operating level changes and still finds there to be
instances across multiple SCR-controlled units in the 12-state region
where hourly emission rates are increasing even when compared to the
same load levels in previous years.
---------------------------------------------------------------------------

    \116\ ``Analysis of Ozone Season NOX Emissions Data
for Coal-Fired EGUs in Four Mid-Atlantic States''. EPA Clean Air
Markets Division. December 2020. Available at https://www.epa.gov/sites/production/files/2020-12/documents/184c_emission_data_tsd.pdf.
---------------------------------------------------------------------------

    To the extent commenters have alleged that in recent years coal-
fired EGUs have declined in capacity factor and that SCR performance
declines at those lower operating levels, EPA notes that this does not
necessarily result in a compliance feasibility challenge. First, as
explained elsewhere in this section, EPA believes the 0.08 rate
assumption is achievable on a fleetwide average basis. Second, the
implementation mechanism of a mass-based emission trading program
eliminates any compliance feasibility concern. Even if reduced
operation of a unit were to affect the rate-based performance of a
unit, it would also lower emissions-producing generation from that
unit, which in turn reduces the number of allowances the unit operator
must hold for compliance under this emission trading program.
Commenters have failed to establish that compliance with the mass-based
implementation mechanism of this rule is actually unachievable.
Further, hourly data indicate that maintaining consistent SCR
performance at lower capacity factors is possible. For example, the
unit-level performance data in the graph below show the emission rate
at a plant staying relatively low (consistent with our optimization
assumption of 0.08 lb/mmBtu) and stable across a wide range of capacity
factors.\117\
---------------------------------------------------------------------------

    \117\ EPA, Air Markets Program Data. Available at www.epa.gov/ampd.

---------------------------------------------------------------------------

[GRAPHIC] [TIFF OMITTED] TR30AP21.001

    Comment: EPA received comment suggesting that EPA subcategorize its
SCR optimization rate assumption by coal rank (i.e., bituminous or
subbituminous) as the difference between the two would imply that the
0.08 lb/mmBtu rate is not appropriate.
    Response: EPA reviewed historical data for SCR operation by coal
rank and assessed it against its 0.08 lb/mmBtu fleet-wide average
assumption and did not find any change necessary or appropriate. EPA
found many instances of both SCR-controlled coal units combusting
subbituminous coal and SCR-controlled coal units combusting bituminous
coal (including instances in earlier years where these very same units
that EPA is identifying as having optimization potential relative to
their 2019 levels) operating at emission rate levels at or below the
0.08 lb/mmBtu rate. In other words, although these units may not be
operating at this emission rate in 2019, it is not due to coal rank as
they have--in the vast majority of cases--met that rate in some period
prior to 2019. In this case, the use of the average rate and the third
best year accommodates any heterogeneity in emission rate that may stem
from a unit's coal choice and makes 0.08 lb/mmBtu a reasonable average
performance rate regardless of coal rank. Moreover, EPA notes that the
covered fleet with the identified SCR optimization potential identified
in this rule is composed of sources who have purchased and consumed
both subbituminous and bituminous coal. The presence of both types of
coal burning units within the region coupled with this observation that
some units have utilized both types of coal, further support the use of
a single fleet-wide average for purposes of estimating reduction
potential and implementing state emission budgets--consistent with the
CSAPR Update. This use of an average value, instead of two separate
values is also consistent with EPA's approach in the CSAPR Update. EPA
further examines and addresses this comment in the EGU NOX
Mitigation Strategies Final Rule TSD.
    Comment: EPA also received comment suggesting it should deviate
from its approach in the CSAPR Update of using a nationwide set of data
to establish a third best year, and instead use an average from just
the 12 covered states.
    Response: EPA reviewed the data and its methodology and evaluated
it against its intention to identify a technology-specific
representative emission rate for SCR optimization. In doing so, EPA did
not identify any need to make the suggested change. EPA is interested
in the performance potential of a technology, and a larger dataset
provides a superior indication of that potential as opposed to a
smaller, state-limited dataset. In both the CSAPR Update and in this
rule, EPA appropriately relied on the largest dataset possible (i.e.,
nationwide) to derive technology performance averages that it then
applied respectively to the CSAPR Update 22-state region and this
rule's 12-state region. Finally, as noted above, in affirming the
reasonableness of this approach, EPA examined the historical reported
data (pre-2019) for the units in the 12 states with SCR optimization
potential and found the nationwide derived average appropriate and
consistent with demonstrated capability and performance of units within
those states. That is, the vast majority of units for which this
resulting emission rate assumption was being applied had demonstrated
the ability to achieve this rate in some prior time period. This
information is discussed further in the EGU NOx Mitigation Strategies
Final Rule TSD in the docket.
    In the proposed rule, EPA relied on the same SCR optimization
timing assumptions it utilized in the CSAPR Update. EPA received
comments on the feasibility of implementing SCR optimization mitigation
measures by the start of the 2021 ozone season.
    Comment: While many commenters supported the feasibility of 2021
ozone-season implementation by noting the ``immediate availability'' of
SCR optimization, those that did not focused on two concerns: (1) That
the engineering, procurement, and other steps required for SCR
optimization were not feasible given the anticipated 1.5 months between
rule finalization and the start of the 2021 ozone season and (2) that
the short implementation time frame may not allow enough time

for allowance trading to occur, and thus jeopardize allowance market
liquidity and the overall that the implementation mechanism of a
trading program.
    Response: EPA disagrees that these concerns justify a change in
approach, as explained below, and is finalizing the same SCR
optimization timing assumptions it proposed.
    As an initial matter, sources will have more than two months
between the date of signature on this final action and the rule's
effective date when the enhanced control stringency being adopted in
this rule will take effect.\118\ Further, EPA has determined that this
implementation schedule is achievable and necessary in order to address
good neighbor obligations by the July 20, 2021 Serious area attainment
date for certain downwind receptors, in accordance with the Wisconsin
decision of the D.C. Circuit.\119\ While EPA observes that
implementation of this control stringency is viable during the 2021
ozone season at the unit level as described below, it also notes that
the flexible implementation mechanism of a trading program, starting
bank, and safety valve (as discussed in VII.C.4) obviate any unit-
specific compliance challenges raised by commenters.
---------------------------------------------------------------------------

    \118\ As discussed in section VII.C.4.a, EPA is ensuring that
the enhanced control stringency represented by the new budgets will
not take effect until the rule's effective date by issuing
supplemental allowances for the portion of the 2021 ozone season
occurring before the rule's effective date.
    \119\ EPA further disagrees with these commenters to the extent
they are suggesting that they could not have prudently taken steps
to prepare for compliance with this control stringency by the 2021
ozone season at least from the date of the proposed rule in October
of 2020. See Americans for Clean Energy v. EPA, 864 F.3d 691, 721-22
(D.C. Cir. 2017) (rejecting industry claims of insufficient time for
compliance when proposed rule provided ``many months'' notice of the
likely obligations established in the final rule). EPA notes that
all reductions finalized in this rule were discussed in those
proposed rule materials, and SCR optimization-driven reductions--
accounting for the vast majority of 2021 reductions--were proposed
in that October notice.
---------------------------------------------------------------------------

    As indicated in the discussion and graphics above, data in the EGU
NOX Mitigation Strategies Final Rule TSD, and in the CSAPR
Update, there is ample evidence of units restoring their optimal
performance within a two-month timeframe. Not only do units reactivate
SCR performance level at the start of an ozone-season when tighter
emission limits begin, but unit-level data also shows instances where
sources have demonstrated the ability to quickly alter their emission
rate within an ozone-season and even within the same day in some cases.
Moreover, this emission control is familiar to sources and was analyzed
and included in the CSAPR Update emission budgets finalized in 2016.
With this experience, and notice through the October 2020 proposed
rule, as well as over two months from final rule to effective date, the
viability of this emission control for the 2021 ozone season is
entirely consistent with the 2-week to 2-month timeframe that EPA
identified as reasonable in both the CSAPR Update and the proposed
rule. Similar to prior rules, commenters provide some unit-level
examples where it has taken longer. Also similar to those prior rules,
EPA does not find those unit-level examples compelling in the context
of its fleet average assumptions and in the implementation context of a
trading program which provides compliance alternatives in the event a
specific unit prefers more time to implement the control stringency. As
noted in Wisconsin, ``. . . all those anecdotes show is that
installation can drag on when companies are unconstrained by the
ticking clock of the law.'' 938 F.3d at 330. Commenters also provide
logistical details for certain engineering steps (e.g., procuring
catalyst replacement) that will not be necessary in many instances to
improve performance at existing SCRs. The majority of emission
reductions from units with SCRs would be available within hours (from
turning on and fully operating those existing control devices) even in
the absence of catalyst that is not as optimally configured or with
reagent sprayers that have not been recently tuned as commenters
suggest they must be. And as noted previously, a prudent EGU operator
has had since at least the publication date of the proposed rule in
October 2020 to take steps to prepare for compliance, such as planning
for the necessary products to run their controls.
    EPA further disagrees with commenters' assertions that the 2021
emission budgets are not feasible. Claiming that ultimate compliance
with the emissions trading program is infeasible ignores the
flexibilities of EPA's trading program implementation mechanism,
including the starting allowance bank and the ``safety valve''
mechanism for accessing even more allowances. EPA uses a fleet-wide
average assumption that non-optimized units with SCR will optimize to
0.08 lb/mmBtu on average by 2021. EPA uses this average assumption in
its derivation of state-emission budgets, but then implements the
reductions through a trading program that provides sources the
flexibility to operate at different emission rates, as they need only
hold allowances adequate to cover their emissions for the relevant
control period. Not every unit need implement this emission control or
meet this rate in order to comply with the state budget under the
trading program. For some units, the timing and rate performance will
likely be easier to meet than estimated by EPA, creating space for
other sources to achieve different rates on different schedules while
collectively complying with the state emission budget. Additionally,
while given the large amount of historical data demonstrating that
units can operate their controls (often within hours of startup), unit
operation (i.e., seasonal capacity factor) is another variable that
operators can utilize to reduce seasonal emissions. In short, because
compliance is based on seasonal emission totals, variation in emission
rates is not on its own a barrier to meeting a seasonal total state
emission target. In short, commenters concerned about 2021
implementation viability largely neglected these critical aspects of
the trading program and did not provide any comprehensive state or
system modeling showing the 2021 implementation of the state budgets
was not achievable when factoring in the program's trading program.
Instead of performing this critical evaluation step, commenters most
often limited their arguments to a hypothetical unit-specific rate
requirement evaluation, ignoring the broader mechanisms of EPA's
quantification and implementation of good neighbor obligations.
    EPA notes that historical emission data and program experience
support its assumption regarding timing of these emission controls.
Similar arguments regarding next-season implementation challenges were
made against the CSAPR Update but were not borne out in the data as
both unit-level and state-level emissions adjusted consistent with
EPA's assumptions for that first season of implementation (the emission
rate at SCR controlled units dropped by nearly half in the 2017 ozone
season, the first ozone-season of the CSAPR Update implementation) when
EPA examined this challenge in the context of EPA's Response to CAA
section 126(b) petitions from Maryland and Delaware.\120\ Moreover, the
future modeling data, as well as some commenters' own analysis,
supported the viability of EPA's 2021 implementation. Finally, some
utilities with a significant footprint in this region even have their
own near-term and medium-term emission reduction goals, which, if
realized, reflect even

more fleet alignment with emission reductions.121 122 For
all of these reasons, EPA determined it was not necessary to change its
emission control implementation timing assumptions from those utilized
in the CSAPR Update.
---------------------------------------------------------------------------

    \120\ 83 FR 50465.
    \121\ https://www.duke-energy.com/Our-Company/Environment/Global-Climate-Change.
    \122\ Proctor, Darrell. Indiana Utility Will Close Coal Units,
Transition to Renewable. Power Magazine. November, 2018. Available
at https://www.powermag.com/indiana-utility-will-close-coal-units-transition-to-renewables/.
---------------------------------------------------------------------------

    With regard to market liquidity concerns, EPA notes that those same
concerns have been voiced in the lead-up to past trading programs but
ultimately did not materialize. For example, a functioning allowance
market formed and resulted in 100 percent compliance with the allowance
holding requirements during the first year of implementation. See more
discussion on this issue in section VII.C.3. EPA notes that the date by
which sources must hold allowances to cover their emissions for the
first control period under this final rule is June 1, 2022--more than
14 months after the date of signature of the rule. Moreover, shortly
after the final rule's effective date and well before the end of the
2021 control period, the allowances allocated to most sources from both
the state emission budgets and from the initial Group 3 bank will be
recorded in sources' accounts and available for trading. Finally, as an
additional measure promoting market liquidity, EPA will allow the use
of Group 2 allowances at an 18:1 trade-in ratio to provide additional
assurance to sources that allowances will be available, but ensuring
that the cost of this compliance option is such that entities will take
it only in the very unlikely event that access to such additional
allowances proves to be necessary. The safety valve is described
further in section VII.C.4.c., The presence of the safety valve,
combined with the recordation of allowances from the state budgets and
the starting bank shortly after the rule's effective date, should
obviate any market liquidity concerns, as the number of allowances
available for trading in the market for the first control period well
in advance of the compliance deadline will accommodate a variety of
compliance pathways and unit operational decisions.
b. Installing State-of-the-Art NOX Combustion Controls
    EPA estimates that the representative cost of installing state-of-
the-art combustion controls is comparable to, if not notably less than,
the estimated cost of optimizing existing SCR (represented by $1,600
per ton). State-of-the-art combustion controls such as low-
NOX burners (LNB) and over-fire air (OFA) can be installed
and/or updated quickly and can substantially reduce EGU NOX
emissions. In the 12 states linked to downwind receptors in this final
rule, approximately 99 percent of coal-fired EGU capacity is equipped
with some form of combustion control; however, the control
configuration and/or corresponding emission rates at a few units
indicate they do not currently have state-of-the-art combustion control
technology. As discussed in EPA's response to comments below, the
Agency has updated its NOX emission rates for upgrading
existing combustion controls to state-of-the-art combustion control
from the proposed rule, where EPA estimated a range of 0.139 to 0.155
lbs/mmBtu. In this final rule, EPA is determining that NOX
emission rates of 0.146 to 0.199 lbs/mmBtu can be achieved on average
depending on the unit's boiler configuration,\123\ and, once installed,
reduce NOX emissions at all times of EGU operation.
---------------------------------------------------------------------------

    \123\ Details of EPA's assessment of state-of-the-art
NOX combustion controls are provided in the EGU
NOX Mitigation Strategies Final Rule TSD.
---------------------------------------------------------------------------

    The feasibility of installing combustion controls was examined by
EPA in the CSAPR where industry demonstrated the ability to install
state-of-the-art LNB controls on a large unit (800 MW) in under six
months when including the pre-installation phases (design, order
placement, fabrication, and delivery).\124\ In the proposed rule, EPA
discussed comments it had received on the CSAPR Update regarding
installation of combustion controls from the Institute of Clean Air
Companies.\125\ Those comments provided information on the equipment
and typical installation time frame for new combustion controls,
accounting for all steps, and noted it generally takes between 6-8
months on a typical boiler--covering the time through bid evaluation
through start-up of the technology. The deployment schedule was
described as:

    \124\ EPA finds that, generally, the installation phase of
state-of-the-art combustion control upgrades--on a single-unit
basis--can be as little as four weeks to install with a scheduled
outage (not including the pre-installation phases such as
permitting, design, order placement, fabrication, and delivery) and
as little as six months considering all implementation phases.
    \125\ EPA-HQ-OAR-2015-0500-0093.
---------------------------------------------------------------------------

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

Given the above timeframe of approximately 6 to 8 months to complete
combustion control installation in the region, EPA is determining that
the installation of state-of-the-art combustion controls is a readily
available approach for EGUs to reduce NOX emissions by the
start of the 2022 ozone season. More details on these analyses can be
found in the EGU NOX Mitigation Strategies Final Rule TSD.
    The cost of installing state-of-the-art combustion controls per ton
of NOX reduced is dependent on the combustion control type
and unit type. EPA estimates the cost per ton of state-of-the-art
combustion controls to be $400 per ton to $1,200 per ton of
NOX removed using a representative capacity factor of 70
percent. See the NOX Mitigation Strategies Final Rule TSD
for additional details.
    Comment: EPA received comment on the proposed timing, cost, and
performance rate of combustion controls.
    Response: EPA is finalizing its proposed assumptions on the cost
and timing for upgrading combustion controls. These assumptions are
consistent with the CSAPR Update. They are described above and further
discussed in the RTC document and in the EGU NOx Mitigation Strategies
Final Rule TSD. EPA is updating its assumed performance rate for state-
of-the-art combustion controls from the proposed rule based on two
factors. First, as commenters pointed out, EPA was in the process of
updating these assumptions based on the latest representative-year data
and an updated inventory of units with like controls. This update and
corresponding emission rates were in the October 2020 NEEDS file placed
in the docket for the proposed rule, but the data were not available in
time to be included in EPA's proposed rule analysis. This adjustment
raised the average emission rate assumption to 0.199 lb/mmBtu for
combustion controls on dry bottom wall fired units and 0.146 lb/mmBtu
for tangentially fired units. Additionally, commenters provided
detailed analysis of how other unit considerations, such as coal rank,
can result in large deviations from what has been historically
demonstrated with this combustion control technology. Based

on these comments and EPA's review of historical performance data for
tangentially-fired units by coal rank with state-of-the-art combustion
controls, EPA determined it was appropriate to use the 0.199 lb/mmBtu
rate for both tangentially and wall-fired units in this final rule. As
noted by commenters, many of the likely impacted units burn bituminous
coal, and the 0.146 lb/mmBtu nationwide average for tangentially-fired
(inclusive of subbituminous units) appeared to be below the
demonstrated emission rate of state-of-the-art combustion controls for
bituminous coal units of this boiler type. EPA notes that its analysis
of illustrative units indicates the costs are often lower than the
$1,600 per ton level EPA assumes in this rule. Similarly, the
pervasiveness of this technology (i.e., 99 percent of units have some
form of combustion controls) in response to previous EPA actions
indicates the wide spread cost-effectiveness of this control and
therefore its inclusion in the final EGU NOx emission budgets beginning
in the 2022 ozone season (noting that the trading program gives units
flexibility in compliance options to accommodate their specific
circumstances).
c. Optimizing Already Operating SNCRs or Turning on Idled Existing
SNCRs
    Optimizing already operating SNCRs or turning on idled existing
SNCRs can also reduce EGU NOX emissions quickly, using
investments in pollution control technologies that have already been
made. Compared to no post-combustion controls on a unit, SNCRs can
achieve a 25 percent reduction on average in EGU NOX
emissions (with sufficient reagent). They are less capital intensive
but less efficient at NOx removal than SCRs. These controls are in use
to some degree across the U.S. power sector. In the 12 states
identified in this final rule, approximately 14 percent of coal-fired
EGU capacity is equipped with SNCR. Recent power sector data suggest
that, in some cases, SNCR controls have been operating less in 2019
relative to performance in prior years.\126\
---------------------------------------------------------------------------

    \126\ See ``Ozone Season Data 2018 vs. 2019'' and ``Coal-fired
Characteristics and Controls'' at https://www.epa.gov/airmarkets/power-plant-data-highlights#OzoneSeason.
---------------------------------------------------------------------------

    In the proposed rule, EPA determined that optimizing already
operating SNCRs or turning on idled SNCRs is an available approach for
EGUs to reduce NOX emissions, has similar implementation
timing to restarting idled SCR controls (less than two months for a
given unit), and therefore could be done in time for the 2021 ozone
season. EPA is finalizing its proposed determination that this emission
control technology can be implemented in the 2021 ozone season. As
explained in section VI.D.1 below, EPA is including optimization of
existing SNCRs in its selected EGU control stringency. Thus, EPA
provides further discussion here confirming the implementation timing
of this emission control technology.
    First, as noted with respect to SCR optimization, this rule will
have an effective date over two months from the date of signature. In
light of EPA's timing estimates of roughly 0.5 to 2 months for EGU
operators to optimize their controls, this timing provides sufficient
advance notice for operators of SNCR-equipped units to undertake any
preparatory activities that may be needed prior to the effective date
of the rule, and the onset of the increased stringency represented by
the new emission budgets. Furthermore, because the emission reduction
obligation is implemented through a mass-based trading program, these
sources (and all others in the newly established Group 3 trading
program) have abundant flexibility to choose other means of complying
with their emission budget. Finally, as explained in section VII.C.4.d,
EPA is providing a safety valve allowing access to additional
allowances usable in the Group 3 trading program (through exchange of
banked 2017-2020 Group 2 allowances at an 18:1 conversion ratio). As
the amount of additional Group 3 allowances made available through the
safety valve mechanism exceeds the effect on the emission budgets of
including the optimization of existing SNCR controls several times
over, there is no basis to believe that there will be compliance
difficulty for any covered units.
    In the proposed rule, EPA estimated a representative cost of
approximately $3,900 per ton for turning on and fully operating idled
SNCRs. For existing SNCRs that have been idled, unit operators may need
to restart payment of some fixed and variable operating costs
associated with these controls. Fixed and variable costs include labor,
maintenance and repair, parasitic load, and ammonia or urea. The
majority of the total fixed and variable operating costs for SNCR is
related to the cost of the reagent used (e.g., ammonia or urea) and the
resulting cost per ton of NOX reduction is sensitive to the
NOX rate of the unit prior to SNCR operation. EPA is
finalizing its adjusted representative cost of $1,800 per ton as
described in the response to comments below, but applies the same
performance, and timing assumptions for SNCRs that are idled as in the
proposed rule.
    Comment: Commenters observed that many SNCRs are already operating
over the past several years (in an environment with an allowance price
signal much lower than the $3,900 per ton threshold that EPA proposed
represented turning on and optimizing idled controls). This observation
suggests that the representative cost for this technology to optimize
is likely less than estimated by EPA in the proposed rule when these
operating patterns are accounted for.
    Response: First, EPA examined the portion of the fleet with SNCR
optimization potential and determined that the majority of units were
already partially operating their controls. Therefore, EPA revisited
the cost for SNCR optimization for units that are partially operating
their controls. At proposal, EPA had noted a representative cost of
$1,800 per ton for SNCR-controlled unit to optimize their controls if
that control was already on and partially operating reflecting the cost
of adding more reagent. This is similar to its analysis for SCR
optimization that revealed an $800 per ton cost for SCR optimization at
units with partially operating controls (as opposed to $1,600 per ton
at units with idled SCR controls). EPA revisited this assessment of
SNCR optimization cost at units with partially operating controls and
found $1,800 per ton to still be a representative cost.\127\ Therefore,
given the majority of the SNCR-controlled fleet with identified
optimization potential was already partially operating their controls
based on 2019 historical data, EPA determined that $1,800 per ton (as
opposed to the $3,900 per ton cost estimated in the proposed rule for
turning on idled SNCRs) was a more representative cost for the
mitigation strategy in this rulemakng. The representative cost of
optimizing SNCR that is already partially operating excludes the fixed
operating and maintenance (FOM) cost associated with starting up an
idled SNCR control. For more details on this assessment, refer to the
EGU NOX Mitigation Strategies Final Rule TSD in the docket
for this rule. This adjustment in the expected cost of implementing
this emission control has factored into EPA's determination to include
optimization of existing SNCRs in its selected control stringency as

discussed in more detail in section VI.D.1.
---------------------------------------------------------------------------

    \127\ See
``EGU_SCR_and_SNCR_costs_Revised_CSAPR_Proposal.xlsx''file, Summary
Page cell E19. Available in the docket for this rulemaking at
proposal at EPA-HQ-OAR-2020-0272-0006.
---------------------------------------------------------------------------

d. Installing New SNCRs
    EPA is finalizing its determination not to include installation of
new SNCRs in its selected control stringency in this rule. The amount
of time needed to retrofit an EGU with new SNCR extends beyond the 2021
Serious area attainment date. However, similar to SCR retrofits
discussed in section VI.B.1.e, and consistent with the Wisconsin
decision, EPA evaluated potential emission reductions and associated
costs from this emission control technology, and assessed the impacts
and need for this emission control at the earliest point in time when
post combustion control installation could be achieved. SNCR
installations, while generally having shorter project timeframes (i.e.,
as little as 16 months (including pre-contract award steps) for an
individual power plant installing controls on more than one boiler),
share similar implementation steps with and also need to account for
the same regional factors as SCR installations.\128\ One recent example
of installation timing took over a year--SNCR installation at the
Jeffrey power plant (Kansas) was in the planning phase in 2013 but not
in service until 2015.\129\ Therefore, EPA is determining that at least
16 months would be needed to complete all necessary steps of SNCR
development and installation at the EGUs not currently equipped with
SNCRs in the 12 states linked to downwind receptors in this final rule.
EPA discusses the timing of SNCR and SCR post-combustion retrofits
together and in more detail in section VI.C.1.
---------------------------------------------------------------------------

    \128\ A month-by-month evaluation of SNCR installation is
discussed in EPA's ``Engineering and Economic Factors Affecting the
Installation of Control Technologies for Multipollutant Strategies''
in EPA's NOX Mitigation Strategies Final Rule TSD. As
noted in the proposed rule, the analysis in this exhibit estimates
the installation period from contract award as within a 10-13-month
timeframe. The exhibit also indicates a 16-month timeframe from
start to finish, inclusive of pre-contract award steps of the
engineering assessment of technologies and bid request development.
The timeframe cited for installation of SNCR at an individual source
in this final action is consistent with this more complete timeframe
estimated by the analysis in the exhibit.
    \129\ 2013 EIA Form 860, Schedule 6, Environmental Control
Equipment.
---------------------------------------------------------------------------

    SNCR technology provides owners a relatively less capital-intensive
option for reducing NOX emissions compared to SCR
technology, albeit at the expense of higher operating costs on a per-
ton basis and less total emission reduction potential. EPA examined the
remaining nationwide coal-fired fleet that lack SNCR or other
NOX post-combustion control to estimate a representative
cost of SNCR installation on a dollar per ton basis. Costs were
estimated using the operating and unit characteristics specific to this
fleet. As described in the EGU NOX Mitigation Strategies
Final Rule TSD, EPA estimated that $5,800 per ton reflects a
representative cost level at which they are available for a majority of
the uncontrolled fleet.
    Comment: EPA received some comments on timing and performance
assumptions of this technology that largely focused on the decision to
couple timing considerations for reduction evaluation purposes of SCR
and SNCR retrofits together.
    Response: EPA used the same cost, performance, and timing
assumptions for this technology as it used in the proposed rule. EPA
evaluates new retrofit technologies (i.e., SCR and SNCR) timing in
tandem at step 3, and therefore it addresses this timing component in
section VI.C.1. Remaining comments on SNCR performance potential are
addressed in the RTC Document and in the EGU NOx Mitigation Strategies
Final Rule TSD.
e. Installing New SCRs
    The amount of time needed to retrofit an EGU with new SCR extends
beyond the 2021 Serious area attainment date. However, similar to SNCR
retrofits discussed above, and consistent with the Wisconsin decision,
EPA evaluated potential emission reductions and associated costs from
this control technology, as well as the impacts and need for this
emissions control strategy, at the earliest point in time when their
installation could be achieved. The amount of time to retrofit EGUs
with new SCR varies between approximately 2 and 4 years depending on
site-specific engineering considerations and on the number of
installations being considered. In prior actions, EPA has noted 39-48
months as appropriate for regionwide actions when EPA is evaluating
multiple installations at multiple locations.\130\
---------------------------------------------------------------------------

    \130\ Final Report: Engineering and Economic Factors Affecting
the Installation of Control Technologies for Multipollutant
Strategies, EPA- 600/R-02/073 (Oct. 2002), available at https://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf.
---------------------------------------------------------------------------

    The Agency examined the cost for retrofitting a unit with new SCR
technology, which typically attains controlled NOX rates of
0.07 lbs/mmBtu or less. Based on the characteristics of the remaining
nationwide coal fleet that does not have a post-combustion control
retrofit, EPA estimated that for unit and performance characteristics
representative of that subgroup, $9,600 per ton reflects a
representative cost level at which the SCR retrofit technology was
typically available for the majority of these sources.
    Comment: EPA received comments on the cost and performance of this
technology, as well as comment on its timing assumption (as part of the
collective timing assumptions in step 3).
    Response: For this final rule's analyses, EPA used the same cost,
performance, and timing assumptions that it used for this technology in
the proposed rule. For more details on this assessment, refer to the
EGU NOX Mitigation Strategies Final Rule TSD in the docket
for this final rule and the RTC Document. Section VI.C.1 presents
comments and EPA responses on the timing assumptions for installation
of new SCRs.
f. Generation Shifting.
    Finally, EPA evaluates emission reduction potential from generation
shifting across the representative dollar per ton levels estimated for
the other emission controls considered above. Shifting generation to
lower NOX-emitting or zero-emitting EGUs occurs in response
to economic factors (including regulatory signals such as pollution
control costs). As the cost of emitting NOX increases, it
becomes increasingly cost-effective for units with lower NOX
rates to increase generation, while units with higher NOX
rates reduce generation. Because the cost of generation is unit-
specific, this generation shifting occurs incrementally on a continuum.
Consequently, there is more generation shifting at higher cost
NOX-control levels. It is reasonable for EPA to quantify and
include the emission reduction potential from generation shifting at
cost levels that are representative of the emission control
technologies evaluated in the multi-factor analysis. Including emission
reductions from generation shifting is important, ensuring that other
cost-effective reductions (e.g., fully operating controls) can be
expected to occur in a competitive electricity marketplace where
generation shifting will inevitably occur in response to pollution
control requirements. Generation shifting treatment and results are
discussed in greater detail in the EGU NOX Mitigation
Strategies Final Rule TSD.
    In general, when EPA estimates emission reduction potential from
generation shifting, EPA finds small amounts of generation shifting to
existing lower NOX-emitting or zero-emitting units could
occur consistent with the near-term implementation timing for this
final rule. As a proxy for

limiting the amount of generation shifting that is feasible for the
near-term ozone seasons, EPA limits its assessment to shifting
generation to other EGUs within the same state. EPA believes that
limiting its evaluation of shifting generation (which EPA sometimes
refers to as re-dispatch) to the amount that could occur within the
state represents a conservatively small amount of generation-shifting
because it does not capture further potential emission reductions that
would occur if generation was shifted more broadly among units in
different states within the interconnected electricity grid.
    Comment: Commenters suggested that EPA should have included
additional reductions from generation shifting beyond those levels that
are commensurate with the emission controls identified. Commenters note
that the statutory command is to eliminate significant contribution to
downwind nonattainment or maintenance problems, 42 U.S.C.
7410(a)(2)(D)(i)(I), not merely to create a strong enough incentive
that sources will likely install certain control technology. Because
generation shifting is an independent measure that EGUs have widely
deployed to reduce NOX emissions, EPA has no basis for
evaluating only the emission reductions that result from a
NOX price that matches--but goes no further than--the
estimated representative NOX control costs of other emission
control technologies assessed.
    Response: EPA is finalizing the same approach to generation
shifting that it proposed and that it included in the CSAPR Update.
This rule's approach to capturing emission reduction potential from
generation shifting in the state's emission budgets focuses on
preserving the incentive for combustion and post-combustion controls to
operate. Factoring generation shifting into the state emissions budgets
helps promote an allowance price that will incentivize these controls
to operate.
    EPA recognizes that looking at higher levels of reductions purely
through generation shifting is possible, assuming the availability for
dispatch of lower or zero emitting generation assets that could
substitute for the higher emitting EGUs. Shifting to such generators
that are already in existence and operating at capacity factors that
allow for some increase in their generation is the most economically
efficient form of generation shifting, assuming other considerations
such as availability, cost, reliability, and other factors are
accounted for. Even greater shifting of generation to lower or zero
emitting assets may be considered with the construction of new assets,
although cost, timing, and economic considerations are generally of a
greater magnitude and complexity in this context. Sophisticated power
sector modeling tools, such as EPA's Integrated Planning Model (IPM)
platform, can provide realistic and reliable assessments of the degree
of generation shifting that may be accomplished at different cost
levels. Indeed, in the Regulatory Impact Analysis for the proposed rule
and for this final rule, EPA assessed a less-stringent control
alternative for EGUs at the $500 per ton level, which was based solely
on generation shifting rather than any at-the-source control
technology. In general, EPA continues to stand by its discussion of its
legal authority for and the technical viability of generation shifting
as a method of emission reduction under the good neighbor provision, as
set forth in the final CSAPR Update rule. See especially 81 FR 74504,
74545-47; see also CSAPR Update Response to Comment Document at 546-550
(legal authority); id. 528-533 (technical feasibility). (EPA had no
occasion and did not reopen this portion of the CSAPR Update in this
action on remand.)
    Nonetheless, while generation shifting as a stand-alone strategy
for emission reductions is available for both states' and EPA's
consideration in the context of good neighbor SIPs or FIPs, EPA
maintains the position discussed in the proposed rule for this action
that further generation shifting than is captured by the methodology of
the proposed rulemaking is unnecessary in the context of the resolution
of good neighbor obligations for the 2008 ozone NAAQS in this action.
The remaining timeframe for addressing upwind contribution to downwind
nonattainment and maintenance receptors is through the 2024 ozone
season, as downwind air quality problems for the 2008 ozone NAAQS are
projected to be resolved by the 2025 ozone season. In EPA's judgment,
the capital intensive nature of new builds and the likely multi-year
timeframe necessary for the permitting and construction of new units
make generation shifting to new generating resources, beyond those
already planned and included in the baseline, not possible before
downwind receptors are already resolved. With respect to generation
shifting to existing generation resources with excess capacity, again,
this rule already incorporates a certain amount of such generation
shifting at cost levels representative of the other control
technologies selected to quantify the state emission budgets in this
rule. EPA believes that this degree of emission reduction through
generation shifting is appropriate to include under the step 3 multi-
factor analysis for the circumstances and compliance timetable
currently presented by the 2008 ozone NAAQS, particularly the finding
that downwind receptors will be resolved under this NAAQS by the 2025
ozone season.
    Comment: Other commenters suggest that EPA should not factor in any
generation shifting based reductions into state emission budgets,
noting that EPA rejected the use of generation shifting in rescinding
the Clean Power Plan and should do the same here in establishing
emission reduction obligations under the good neighbor provision of
section 110 of the Clean Air Act. According to these commenters, the
emission budgets should be based on cost-effective emission reduction
strategies that reflect technologies that can be implemented within the
affected source's fence line.
    Response: EPA notes again that its treatment of generation shifting
here is consistent with both the CSAPR Update and the CSAPR, and the
statute. Moreover, this comment incorrectly conflates the question of
statutory authority under section 111 of the Act, the authority at
issue in the Clean Power Plan and its repeal and subsequent litigation,
with the question of statutory authority under section 110. As EPA
explained in the CSAPR Update:

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

reduction requirements, and it does not limit those measures to
individual source controls. The EPA reasonably interprets this
provision to authorize consideration of a wide range of measures to
reduce emissions from sources, which is consistent with the broad
scope of this provision, as noted immediately above.

81 FR 74545.\131\
---------------------------------------------------------------------------

    \131\ EPA also noted in the CSAPR Update, ``Interpreting the
Good Neighbor Provision to be sufficiently broad to authorize
reliance on generation shifting is also consistent with the
legislative history for the 1970 CAA Amendments. The Senate Report
stated that to achieve the NAAQS, `[g]reater use of natural gas for
electric power generation may be required,' S. Rep. No. 91-1196 at
2.'' 81 FR 74545 n.141.
---------------------------------------------------------------------------

    Finally, EPA notes that its interpretation of section 111 of the
Act as unambiguously precluding the use of generation shifting as a
``best system of emission reduction'' under that provision was recently
rejected by the D.C. Circuit. American Lung Association v. EPA, No. 19-
1140 (D.C. Cir. Jan. 19, 2021). The court there also rejected arguments
that generation shifting in the Clean Power Plan runs afoul of the
federalism doctrine, slip op. 92 (``Interstate air pollution is not an
area of traditional state regulation. And federalism concerns do not
bar the United States government from addressing areas of Federal
concern just because its actions have incidental effects on areas of
state power.'') (emphasis in original) (citing FERC v. EPSA, 136 S. Ct.
760, 775-778 (2016)), or conflicts with FERC's authority, id. 95 n.12
(``The effects of environmental regulations on the power grid do not
amount to power regulation statutorily reserved to FERC.''). In this
rule, as in prior transport rules, EPA has established emission budgets
that capture a certain degree of generation shifting that is modeled to
occur as an economical response by the power sector to a particular
cost threshold associated with at-the-plant control technologies. EPA
has not mandated or ordered any particular degree of generation
shifting to occur or that it occurs in a particular way. Further, this
action is related solely to air pollution, in this case NOX
as an ozone-precursor, and does not affect or purport to regulate any
particular type of generation or achieve any type of generation mix,
except as related to those NOX emissions. Cf. id. 88 (``The
Clean Power Plan was aimed not at regulating the grid, but squarely and
solely at controlling air pollution--a task at the heart of the EPA's
mandate.''). The budgets here simply reflect an expectation that the
power sector can and will take advantage of the compliance flexibility
of a mass-based emission trading program to shift generation when it is
economical to do so in response to an environmental mandate.
    Finally, EPA solicited comment on whether other ozone-season
NOX mitigation technologies should be considered. EPA
invited comments on the cost and performance of the above listed
technologies and any other potential mitigation technologies. For
example, in January of 2020 the New York Department of Environmental
Conservation adopted a rule to limit emissions from combustion turbines
that operate as peaking units. EPA has not historically considered
NOX mitigation technologies for these sources in its
rulemakings, such as the CSAPR and the CSAPR Update, but invited
comment on their appropriateness for this rulemaking. Separately,
location and high emission rates of grid-connected municipal solid
waste combustors, generally not covered under EPA's transport rules
given their small size and differing purpose, have also led some
stakeholders to suggest mitigation measures be considered for those
sources.
    Comment: EPA received comments calling on the Agency to reduce
NOX from peaking units and municipal waste combustors and
claimed that the agency's focus in its proposed rule on the suite of
EGU emission controls above failed to address large sources of
NOX emissions that are relatively close to the Connecticut
receptors. Some of these commenters go one step further and say not
only should EPA regulate these sources, but that EPA should only
require emission reductions from local sources in place of reductions
from larger emitting sources upwind.
    Response: EPA is finalizing its evaluation of the same suite of
emission controls as in the proposed rule. EPA notes that several
states close to, or that have, nonattainment or maintenance receptors
are already taking some of these measures. For example, New York
finalized the state regulation mentioned above and New Jersey notes in
their comment that the measures documented in New Jersey's Good
Neighbor SIP include controls for sources such as behind-the-meter
distributed generation/demand response (DG/DR) electric generators and
municipal waste combustors. Even with these local measures,
nonattainment and maintenance receptors persist in the region with
demonstrable upwind state contribution, and thus the presence of these
initiatives does not absolve upwind states and sources from the
responsibility of addressing their significant contribution.\132\ In
the proposed rule, EPA inquired whether these additional emission
controls should be considered in addition to, not in place of, the
other proposed controls. EPA did not receive determinative evidence
that (1) there were meaningful, upwind reductions from these emission
controls that are not already being addressed by state rules, or (2)
that any further reductions could be implemented in a timeframe
consistent with the remaining nonattainment and maintenance receptors
that resolve after 2024. EPA notes the New York rule referenced above
was finalized in early 2020, but its control measures will phase in
during the 2023-2025 period. Therefore, EPA is not finalizing any
additional reductions from new control measures at these sources in
this final rule, but, pending further analysis, doing so may be
appropriate in a future context (e.g., under a different NAAQS).
Finally, EPA notes to the extent that any of the sources meet the
applicability requirements and are covered in the Group 3 trading
program under this rulemaking, they would have an incentive to reduce
emissions consistent with the ozone NOX allowance price.
Moreover, as identified in the discussion the EGU NOX
Mitigation Final Rule TSD, a significant number of units with this
technology are located in states with rules addressing those sources.
---------------------------------------------------------------------------

    \132\ For instance, despite these measures, EPA does not agree
with comments from New Jersey that there is therefore no basis for
including New Jersey in the Group 3 trading program in this action.
New Jersey is projected to remain linked to the Connecticut
receptors well above the 1 percent threshold.
---------------------------------------------------------------------------

2. Non-EGU NOX Mitigation Strategies
    EPA has not regulated emissions from non-EGU sources as part of its
regional transport rulemakings since the 1998 NOX SIP Call.
In Wisconsin, the DC Circuit held that EPA must, on remand, implement a
full remedy by the next attainment date (2021 for this final rule), or
as soon as possible thereafter on a showing of impossibility, to
achieve necessary reductions by that date. 938 F.3d at 320. The court
also directed the Agency to address non-EGU sources, unless ``the
scientific uncertainty is so profound that it precludes EPA from making
a reasoned judgment.'' Id. at 318-20 (quoting Massachusetts v. EPA, 549
U.S. 497, 534 (2007)). The DC Circuit found that the practical
obstacles EPA identified with respect to its evaluation of non-EGUs in
the CSAPR Update did not rise to the level of an ``impossibility,'' id.
The court also found that EPA must make a higher

showing of uncertainty regarding non-EGU point-source NOX
mitigation potential before declining to regulate such sources on the
basis of ``uncertainty.'' Id. Thus, in the proposed rule, EPA extended
its analysis to include all major stationary source sectors in the
linked upwind states, including non-EGU emissions sources in various
industry sectors. As discussed in section V, of the 22 states
originally included in the CSAPR Update, EPA has determined that 12
states warrant analysis at step 3 for significant contribution to
downwind nonattainment and/or maintenance receptors for the 2008 ozone
NAAQS. Therefore, the Agency focused its step 3 assessment on non-EGU
sources in these 12 states. For these sources, EPA retained its focus
on NOX as the most effective precursor pollutant for
addressing interstate ozone transport at a regional scale. See 82 FR
51238, 51248 (Nov. 3, 2017) (citing 76 FR 48222) and 63 FR 57381.
    The remainder of this section summarizes the analysis EPA conducted
in the proposed rule. EPA is finalizing this analysis using the best
available current data, largely as proposed, and determines on the
basis of this analysis that emission reductions from non-EGU sources/
units in the 12 states are not needed to eliminate their significant
contribution to nonattainment or interference with maintenance in any
other state. EPA made some minor updates to its analysis of non-EGU
emission reduction potential, and these changes did not affect its
overall conclusion that reductions are not warranted under the step 3
multi-factor test. EPA responds to significant comments on its
assessment of non-EGU emission reduction potential at the end of the
relevant section below, and addresses remaining comments on potential
non-EGU emission reductions in the RTC document located in the docket
for this action.
    For non-EGU sources, there are many types of emissions sources or
units that emit NOX and many control technologies or
combinations of control technologies for these sources or units. As
such, there are many approaches to assessing emission reduction
potential from non-EGU emission sources or units. In this final rule,
EPA applied the multi-factor test used for EGUs in an effort to
determine an appropriate stringency level for non-EGU sources/units in
linked upwind states. EPA identified available control technologies and
estimated their costs and potential emission reductions. The Agency
considered the information it has regarding control technology
implementation timeframes, including information on such timeframes
provided by commenters on the proposed rule, to determine potential air
quality impacts in relevant future years.
    To identify levels of control for non-EGU sources/units, EPA used
the Control Strategy Tool (CoST),\133\ the Control Measures Database
(CMDb), and the projected 2023 inventory from the 2016v1 modeling
platform. EPA assessed potential emission reductions associated with
applying controls to emissions units with 150 tons per year (tpy) or
more of pre-control NOX emissions in 2023, which is an
emissions threshold that represents a comparable unit size to 25 MW for
EGUs used in prior interstate transport rulemakings. To derive this
emissions threshold, EPA used emissions expected from an average 25 MW
EGU unit operating at a median heat rate, emission rate, and capacity
factor for a coal-fired unit.\134\ In CoST, the Agency used the maximum
emission reduction strategy\135\ to estimate the largest quantity of
potential emission reductions from each emissions source or unit
located in the 12 upwind states linked to downwind receptors in this
final rule. Eleven of the 12 upwind states had sources/units with 150
tpy or more of pre-control NOX emissions in 2023; the
projected 2023 emissions inventory did not include non-EGU point
sources/units in New Jersey with pre-control NOx emissions greater than
150 tpy for which CoST had applicable control measures.\136\
---------------------------------------------------------------------------

    \133\ Further information on CoST can be found at the following
link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-air-pollution.
    \134\ For additional details on calculating the 150 tpy
emissions threshold, please see the section titled Background for
Determining Source Size/Threshold for Non-EGU Emissions Sources in
the memorandum titled Assessing Non-EGU Emission Reduction
Potential, available in the docket for this rule.
    \135\ The maximum emission reduction algorithm assigns to each
source the single measure (if a measure is available for the source)
that provides the maximum reduction to the target pollutant,
regardless of cost. For more information, see the CoST User's Guide
available at the following link: https://www.cmascenter.org/cost/documentation/3.5/CoST%20User's%20Guide/.
    \136\ Total NOx emissions at the facility level in this analysis
are likely much larger than NOx emissions at the emissions source/
unit level, and facilities often have several individual emissions
units. In New Jersey there are facilities with total NOx emissions
greater than 150 tpy. EPA did not, however, identify any individual
emissions units at those facilities with pre-control NOx emissions
greater than 150 tpy for which CoST had applicable control measures.
---------------------------------------------------------------------------

    For the 12 linked states, EPA categorized the CoST results for
control technologies that comprise approximately 92 percent of the
total estimated potential emission reductions from the non-EGU sources/
units with 150 tpy or more of NOX emissions in these states;
\137\ those technologies and related emissions sources/units are
summarized in Table VI.B.2-1 below. In tranche one before further
refinement and verification, the number of emissions units CoST applied
SCR to was 51 and the number of emissions units CoST applied SNCR to
was 23. The estimated emission reductions from those control
applications were 12,724 ozone season tons. In tranche two, before
further refinement and verification, the number of emissions units to
which CoST applied layered combustion (a type of combustion control
technology) was 49, the number of emissions units to which CoST applied
NSCR \138\ or layered combustion was 65, and the number of emissions
units to which CoST applied ultra-low NOx burner and SCR was 56. The
estimated emission reductions from those control applications were
17,283 ozone season tons. EPA then calculated a weighted average cost
per ton (in 2016$) for estimated potential reductions associated with
each control technology and plotted the weighted average cost per ton
values. From the resulting curve, EPA identified a clear break point
that defined two tranches of potential emission reduction, as shown in
Table VI.B.2-1. For additional details on the curve and the potential
emission reductions in tranches one and two, please see the memorandum
titled Assessing Non-EGU Emission Reduction Potential, available in the
docket for this rule.
---------------------------------------------------------------------------

    \137\ CoST applied a few additional controls that are not
commonly used and did not result in significant additional emission
reductions. Ten different control technology applications make up
the remaining 8 percent of the control technology applications.
Compared to the five technologies EPA assessed further, these ten
control technology applications do not, individually or
collectively, have the potential to result in significant additional
emission reductions. For additional details, see the technical
memorandum titled Assessing Non-EGU Emission Reduction Potential and
the Excel workbook titled Control Summary--Max Emission Reduction
$10k 150 tpy cutoff 12 States Updated Modeling--No Replace--05-18-
2020.xlsx in the docket for this rule.
    \138\ NSCR is non-selective catalytic reduction, a control
technology applicable to rich-burn natural gas-fired internal
combustion (IC) engines.

                Table VI.B.2-1--Details on Tranches One and Two of Potential Emission Reductions
----------------------------------------------------------------------------------------------------------------
                                                                             Weighted average
                 Tranche                  Technologies/industry sectors or   cost (2016$ per   Cost range (2016$
                                                    source groups                  ton)             per ton)
----------------------------------------------------------------------------------------------------------------
Tranche One.............................  SCR/Glass Manufacturing, IC                   2,000     \139\ 64-5,700
                                           Engines.
                                          SNCR/Cement Manufacturing.......
Tranche Two.............................  Layered Combustion/Lean Burn IC         5,000-6,600        1,400-9,700
                                           Engines.
                                          NSCR or Layered Combustion/
                                           Industrial Rich Burn Natural
                                           Gas IC Engines.
                                          Ultra-low NOX Burner and SCR/
                                           Industrial Boilers.
----------------------------------------------------------------------------------------------------------------

    Given the large number of emissions units in one or more industry
sectors that could require control installation, EPA does not have
detailed information on the time needed to install all of the control
technologies identified in Table VI.B.2-1. Any installation timing
estimates would need to reflect the time needed to install controls
across a potentially large number of sources, the time needed to have
appropriate NOX monitoring installed, the time needed to
raise the necessary financing, and other steps in the permitting,
construction and procurement processes. EPA previously examined the
time necessary to install some of the controls indicated in Table
VI.B.2-1 for different industries in the 2016 Final Technical Support
Document (TSD) for the Final Cross-State Air Pollution Rule for the
2008 Ozone NAAQS, Assessment of Non-EGU NOX Emission
Controls, Cost of Controls, and Time for Compliance Final TSD (``CSAPR
Update Non-EGU TSD''), which is discussed in section VI.C.2. EPA
expects that the controls for glass furnaces and cement kilns would
take at least 2 years to install on a sector-wide basis across the 12-
state region affected by this final rule. Information available to the
Agency, including information provided by commenters, does not
establish that implementation of NOX control technologies
for non-EGU emission sources/units could take place in less than 2
years. Therefore, EPA has determined that the 2023 ozone season is the
earliest ozone season by which these non-EGU controls could be
installed. EPA thus concludes that no NOX controls for non-
EGUs included in this cost analysis can be installed by the 2021 ozone
season. Additional information on installation times for non-EGU
NOX controls can be found in section VI.C.
---------------------------------------------------------------------------

    \139\ For the emissions unit estimated to generate emission
reductions at $64 per ton, the emissions and cost estimates were
incorrect. The 2023 projected emissions for the unit were
significantly overestimated as a result of a growth factor EPA
received for these emissions from a multi-jurisdictional partner
organization. Further, the equation used to estimate the cost was
mis-specified in CoST, and the true cost is likely on the order of
$800 per ton. However, these emission reductions were still
assessed, as discussed in section VI.C.2 below.
---------------------------------------------------------------------------

3. Mobile Source NOX Mitigation Strategies
    Under a variety of CAA programs, EPA has established federal
emissions and fuel quality standards that reduce emissions from cars,
trucks, buses, nonroad engines and equipment, locomotives, marine
vessels, and aircraft (i.e., ``mobile sources''). Because states are
generally preempted from regulating new vehicles and engines with
certain exceptions (see generally CAA sections 209, 177), mobile source
emissions are primarily controlled through EPA's federal programs. EPA
has been regulating mobile source emissions since it was established as
a federal agency in 1970, and all mobile source sectors are currently
subject to NOX emissions standards. EPA factors these
standards and associated emission reductions into its baseline air
quality assessment in good neighbor rulemaking, including in this
action. Such reductions are an important reason for the historical and
long-running trend of improving air quality in the United States. These
trends help explain why the overall number of receptors and severity of
ozone nonattainment problems under the 2008 ozone NAAQS continues to
decline. Such data are factored into EPA's analysis at steps 1 and 2 of
the 4-step framework. As a result of this long history, NOX
emissions from onroad and nonroad mobile sources have substantially
decreased (73 percent and 57 percent since 2002, for onroad and
nonroad, respectively) \140\ and are predicted to continue to decrease
into the future as newer vehicles and engines that are subject to the
most recent, stringent standards replace older vehicles and
engines.\141\
---------------------------------------------------------------------------

    \140\ U.S. EPA. Our Nation's Air: Status and Trends Through
2019. https://gispub.epa.gov/air/trendsreport/2020/#home.
    \141\ National Emissions Inventory Collaborative (2019). 2016v1
Emissions Modeling Platform. Retrieved from http://views.cira.colostate.edu/wiki/wiki/10202.
---------------------------------------------------------------------------

    For example, in 2014 EPA promulgated new, more stringent emissions
and fuel standards for light-duty passenger cars and trucks.\142\ The
fuel standards took effect in 2017, and the vehicle standards are
phasing in between 2017 and 2025. Other EPA actions that are continuing
to reduce NOX emissions include the Heavy-Duty Engine and
Vehicle Standards and Highway Diesel Fuel Sulfur Control Requirements
(66 FR 5002; January 18, 2001); the Clean Air Nonroad Diesel Rule (69
FR 38957; June 29, 2004); the Locomotive and Marine Rule (73 FR 25098;
May 6, 2008); the Marine Spark-Ignition and Small Spark-Ignition Engine
Rule (73 FR 59034; October 8, 2008); the New Marine Compression-
Ignition Engines at or Above 30 Liters per Cylinder Rule (75 FR 22895;
April 30, 2010); and the Aircraft and Aircraft Engine Emissions
Standards (77 FR 36342; June 18, 2012).
---------------------------------------------------------------------------

    \142\ Control of Air Pollution from Motor Vehicles: Tier 3 Motor
Vehicle Emission and Fuel Standards, 79 FR 23414 (April 28, 2014).
---------------------------------------------------------------------------

    EPA is currently developing a new regulatory effort to reduce
NOX and other pollution from heavy-duty trucks (known as the
Cleaner Trucks Initiative), as described in the January 21, 2020,
Advance Notice of Proposed Rulemaking (85 FR 3306). Heavy-duty vehicles
are the largest contributor to mobile source emissions of
NOX and will be one of the largest mobile source
contributors to ozone in 2025.\143\ Reducing heavy-duty vehicle
emissions nationally would improve air quality where the trucks are
operating as well as downwind. As required by CAA section 202(a)(3)(A)
of the Act, EPA will be proposing NOX emission standards
that ``reflect the greatest degree of emission reduction achievable
through the application of technology which the Administrator
determines will be available for the model year to which such standards
apply, giving appropriate consideration to cost, energy, and safety
factors associated with the application of such technology.'' Section
202(a)(3)(C)

requires that standards apply for no less than 3 model years and apply
no earlier than 4 years after promulgation.
---------------------------------------------------------------------------

    \143\ Zawacki et al, 2018. Mobile source contributions to
ambient ozone and particulate matter in 2025. Atmospheric
Environment. Vol 188, pg 129-141. Available online: https://doi.org/10.1016/j.atmosenv.2018.04.057.
---------------------------------------------------------------------------

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

C. Emission Reduction Potential of Control Stringencies

1. EGU Emission Reduction Potential
    For EGUs, as discussed in section VI.A, the multi-factor test
considers increasing levels of uniform control stringency in
combination with consideration of total NOX reduction
potential and corresponding air quality improvements. EPA evaluated EGU
NOX emission controls that are widely available (described
previously in section VI.B.1), that were assessed in previous rules to
address ozone transport, and that have been incorporated into state
requirements to address ozone nonattainment.
    The tables below summarize the emission reduction potentials (in
absolute ozone season tons) from these emission controls across the 12-
state region. Table VI.C.1-2 focuses on near-term mitigation emission
controls while Table VI.C.1-3 includes emission controls with extended
time frames for implementation.

                       Table VI.C.1-2--EGU Ozone-Season Emission Reduction Potential--2021
----------------------------------------------------------------------------------------------------------------
                                                             Reduction potential (tons) for varying levels of
                                                                           technology inclusion
                                       Baseline 2021 OS --------------------------------------------------------
                State                        NOX                                                    SCR/SNCR
                                                          SCR optimization   SCR optimization    optimization +
                                                                              + LNB upgrade       LNB upgrade
----------------------------------------------------------------------------------------------------------------
Illinois............................              9,368                171                171                267
Indiana.............................             15,856              2,771              2,771              2,805
Kentucky............................             15,588                282              1,531              1,538
Louisiana...........................             15,476                 87                 87                658
Maryland............................              1,501                  1                  1                  1
Michigan............................             13,898              1,166              1,284              1,288
New Jersey..........................              1,346                 92                 92                 92
New York............................              3,469                 53                 53                 53
Ohio................................             15,829              6,140              6,140              6,140
Pennsylvania........................             11,896              3,517              3,517              3,517
Virginia............................              4,664                 50                320                380
West Virginia.......................             15,165              1,479              1,960              2,281
                                     ---------------------------------------------------------------------------
    Total...........................            124,057             15,809             17,927             19,021
----------------------------------------------------------------------------------------------------------------
* EPA shows reduction potential from state-of-the-art LNB upgrade as a near-term reduction emission control but
  explains in sections VI.B and VI.D that this reduction potential would not be implemented until 2022. Sum of
  state values may vary slightly from total due to rounding.

                       Table VI.C.1-3--EGU Ozone-Season Emission Reduction Potential--2025
----------------------------------------------------------------------------------------------------------------
                                                    Reduction potential (tons) for varying levels of technology
                                                                            inclusion*
                                                 ---------------------------------------------------------------
                                                                                SCR/SNCR        SCR/SNCR
              State                Baseline 2025                                  optimization +  optimization +
                                      OS NOX            SCR          SCR/SNCR      LNB upgrade +   LNB upgrade +
                                                  optimization +  optimization +  SNCR  retrofit  SCR retrofit +
                                                    LNB upgrade     LNB upgrade    +  generation    generation
                                                                                shifting        shifting
----------------------------------------------------------------------------------------------------------------
Illinois........................           8,281             138             233           1,053           1,401
Indiana.........................          12,232           2,648           2,668           3,309           3,802
Kentucky........................          14,551           1,199           1,205           2,755           5,022
Louisiana.......................          15,476              87             659           1,098           2,854
Maryland........................           1,350               2               2             181             181
Michigan........................          11,009           1,205           1,209           2,331           3,656
New Jersey......................           1,346              92              92              89              89
New York........................           3,456              53              53             159             159
Ohio............................          15,927           6,155           6,155           6,284           6,706
Pennsylvania....................          11,896           3,523           3,523           3,975           4,045
Virginia........................           4,162             323             367             417             850
West Virginia...................          15,165           1,960           2,281           2,328           4,597
                                 -------------------------------------------------------------------------------

    Total.......................         114,850          17,384          18,448          23,978          33,363
----------------------------------------------------------------------------------------------------------------
* Both tables VI.C.1-2 and VI.C.1-3 include limited generation shifting (reflecting that which would occur at
  the price level consistent with control operation). It does not factor in generation shifting reduction
  potential that may be attributable to incremental new builds or incremental retirements. Sum of state values
  may vary slightly from total due to rounding.

    Comment: Some commenters suggested that the emission reduction
estimates for an identified technology needed to be updated based on
new or updated data.
    Response: EPA has updated the total emission reduction potential
for each technology based on information provided by commenters.
Further details are provided in the RTC Document included in the
docket, the EGU NOx Mitigation Strategies Final Rule TSD, and in the
Ozone Transport Policy Analysis Final Rule TSD. In summary, comments
containing new data, information, or analysis that resulted in changes
to the values in the tables above included information on (1) shared
stack emissions apportionment, (2) updated information and data on
retirements and new builds, (3) updated information and data on
combustion control performance, and (4) and updated information on SNCR
optimization cost. In the first three instances, the resulting impact
was a change in the inventory of units with identified emission
reduction potential (and therefore overall emission reduction potential
from that category). For instance, multiple commenters provided EPA
with data on shared stack emissions apportionment not readily available
in unit-level data reported to EPA. In some cases where stack data are
measured and reported, and that stack is shared by two units (one with
an SCR and one without), the apportionment method of those reported
stack emissions for reporting purposes is heat input-based and
therefore may not reflect the unit-level operation of the control at
that unit, even when that control is operating. In other words, it may
have apportioned those stack emissions (e.g., 10 tons) as 5 tons to
each unit, while the actual operation is 9 tons from the uncontrolled
unit and 1 ton from the controlled unit. This can give the appearance
of a controlled unit emitting above the optimized rate, when in fact it
is already operating below the 0.08 lb/mmBtu threshold. Similar to the
CSAPR Update, EPA incorporated the information from this comment and
new data into this final rule, and EPA has adjusted the Agency's
inventory of units that may have SCR reduction potential accordingly.
Likewise, EPA received some updated information on unit-level
retirement status such as changes to the retirement status of the
Colver Power Plant in Pennsylvania and the Pleasants Power Station in
West Virginia. As these units are no longer retiring, their retirement
is not factored into the step 3 baseline or resulting state emission
budgets. Similarly, EPA also incorporated comments and new data
regarding new units expected to come online and retiring units expected
to go offline after 2019 but prior to 2024 ozone season.\144\ Also, as
noted above, EPA updated its performance rate assumption for LNB
controls based on updated data and comments, resulting in less emission
reduction potential from this technology category. Finally, the
emission reduction levels associated with SNCR optimization were
updated to be consistent with the representative cost (and commensurate
generation shifting-based reductions) adjustments discussed above.
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    \144\ EPA relied on unit-level data from the proposal, commenter
data, and the latest EIA Form 860m (October 2020) available at the
time of the final rule analysis.
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    Comment: Some commenters asserted that EPA should change its timing
assumptions for post-combustion control retrofits by parsing out
different timing assumptions for SNCR and SCR retrofits. They claim
that doing so would result in more emission reductions available
starting in earlier years (e.g., 2023) given that SNCR retrofit
technology could be installed by that year.
    Response: EPA is finalizing the same timing assumptions that it
proposed for the installation of post-combustion controls. As discussed
in section VI.B.1.e and noted in prior actions, EPA generally views 39-
48 months as an appropriate implementation timeframe for regionwide
installation of new post-combustion control technologies when EPA is
evaluating multiple installations at multiple locations. As discussed
further below, this is primarily based on SCR retrofit rather than
SNCR. The period from finalization of this rule until the start of the
2024 ozone-season would allow less than 39 months for post combustion
controls to be regionally installed and operating. The 2025 ozone
season represents a period approximately 48 months after finalization
of this rule and reflects a more demonstrably possible window for
making retrofits on a regional scale. Therefore, EPA finds that 2025 is
the earliest ozone season by which new SNCR or SCR may be installed
across multiple EGUs on a regional basis.
    Installing new SCR or SNCR controls for EGUs generally involves the
following steps: Conducting an engineering review of the facility to
determine suitability and project scope; advertising and awarding a
procurement contract; obtaining a construction permit; installing the
control technology; testing the control technology; and obtaining or
modifying an operating permit. These timeframes are intended to
accommodate a plant's need to conduct an engineering assessment of the
possible NOX mitigation technologies necessary to then
develop and send a bid request to potential suppliers. Control
specifications are variable based on individual plant configuration and
operating details (e.g., operating temperatures, location restrictions,
and ash loads). Before making potential large capital investments,
plants need to complete these careful reviews of their system to inform
and develop the control design they request. They then need to solicit
bids, review bid submissions, and award a procurement

contract--all before construction can begin.
    Scheduled curtailment, or planned outage, for pollution control
installation would also be necessary to complete SCR or SNCR projects
on a regional scale. Given that peak demand and rule compliance would
both fall in the ozone season, sources would likely need to schedule
installation projects for the ``shoulder'' seasons (i.e., the spring
and/or fall seasons), when electricity demand is lower than in the
summer, reserves are higher, and ozone season compliance requirements
are not in effect. If multiple units were under the same timeline to
complete the retrofit projects as soon as feasible from an engineering
perspective, this could lead to bottlenecks of scheduled outages as
each unit attempts to start and finish its installation in roughly the
same compressed time period. Thus, any compliance timeframe that would
assume installation of new SCR or SNCR controls should be developed to
reasonably encompass multiple shoulder seasons to accommodate
scheduling of curtailment for control installation purposes and better
accommodate the regional nature of the program.\145\
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    \145\ The workforce disruption experienced at the onset of the
COVID-19 pandemic has resulted in a backlog of scheduled outages for
power plant maintenance. According to Genscape, PJM (a regional
transmission organization covering a substantial portion of the EGUs
affected by this rule) observed a shortfall of more than a quarter
of planned outages for power plant maintenance in the spring 2020
shoulder season. Finn, Pat; Szumloz, Zach; Gordon, Elliot. Impacts
of the Coronavirus on the PJM Power Market, Taking a Closer Look at
Demand, Supply, Energy Prices, and Congestion. Genscape, A Wood
Mackenzie Business. April 2020.
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    Finally, the time lag observed between the planning phase and in-
service date of SCR operations in certain cases also illustrates that
site-specific conditions can lead to installation times of four years
or longer--even for individual power plants. For instance, SCR projects
for units at the Ottumwa power plant (Iowa), Columbia power plant
(Wisconsin), and Oakley power plant (California) were all in the
planning phase in 2014. By 2016, these projects were under construction
with estimated in-service dates of 2018.\146\ Further, large-scale
projects also illustrate that timelines can extend beyond the general
estimate for a single power plant when the project is part of a larger,
multifaceted air pollution reduction goal. For instance, the Big Bend
power plant in Florida completed a multifaceted project that involved
adding SCRs to all four units as well as converting furnaces, over-fire
air changes, and making windbox modifications, during which a decade
elapsed between the initial planning stages and completion.\147\
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    \146\ 2014 EIA Form 860. Schedule 6. Environmental Control
Equipment.
    \147\ Big Bend's Multi-Unit SCR Retrofit. Power Magazine. March
1, 2010. Available at http://www.powermag.com/big-bends-multi-unit-scr-retrofit/.
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    EPA notes that differences between these control technologies exist
with respect to the potential viability of achieving cost-effective,
regional NOX reductions from EGUs. SCR controls generally
achieve greater EGU NOX reduction efficiency (up to 90
percent) than SNCR controls (25 percent). EPA observes that for the
remaining uncontrolled coal fleet in the 12 states, SCRs are, on
average, more expensive on a cost per ton basis. However, the analysis
in the EGU NOX Mitigation Strategies Final Rule TSD notes
that the cost range varies widely for units depending on inlet
NOX rate and capacity factor. Therefore, for some units, it
is possible that SCR retrofit costs are lower than SNCR costs on a cost
per ton basis. Moreover, there are a host of other market and policy
drivers that may lead a specific unit to prefer an SCR retrofit over an
SNCR retrofit. As a result, EPA finds it is reasonable to allow
sufficient time for EGU operators to select installation of SCR in
response to a multi-state emission control program whose emission
budgets would reflect emission reductions from new post-combustion
controls. Therefore, EPA is using an SCR-inclusive planning and
installation schedule to represent new post-combustion retrofit
potential on a regional basis (be it SNCR or SCR as determined by
individual EGU owners under our flexible market-based emission trading
program).
    Furthermore, SNCR installation at an individual source would render
later installation of an SCR less cost-effective, because such a unit
would have already expended some unrecoverable capital on the less-
effective pollution control technology. As a result, it would be
counterproductive to assume EGUs should install the less effective SNCR
control technology to address a short-run air quality concern under an
older and less stringent NAAQS when it may later prove necessary to
require the more effective SCR control technology to address longer-run
air quality concerns under a more stringent NAAQS for the same
pollutant. Considering these factors, EPA finds it is appropriate to
give particular weight to the timeframe required for implementation of
SCR across the region as compared to SNCR to allow sources the
flexibility to make the most efficient post-combustion control
investment. Historically, units have chosen to retrofit with higher
performing SCR at a much greater rate than they have chosen SNCR. For
SCR, the total time associated with project development is estimated to
be up to 39 months for an individual power plant installing controls on
more than one boiler. However, more time is needed when considering
installation timing for new SCR controls regionally. EPA has previously
determined that a minimum of 48 months (four years) is a reasonable
time period to allow to complete all necessary steps of SCR projects at
EGUs on a regional scale. This timeframe would allow for regional
implementation of these controls (i.e., at multiple power plants with
multiple boilers) considering the necessary stages of post-combustion
control project planning, shepherding of labor and material supply,
installation, coordination of outages, testing, and operation.\148\
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    \148\ Final Report: Engineering and Economic Factors Affecting
the Installation of Control Technologies for Multipollutant
Strategies, EPA-- 600/R-02/073 (Oct. 2002), available at https://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf.
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    In addition to its engineering assessment, EPA looked at historical
data to validate this 39-48 month installation timeframe. EPA observed
over 12 GW of uncontrolled coal capacity in the linked states covered
in this rule. For comparison, EPA looked at the last 15 years of data
to see if a similar amount of capacity had come online in a shorter
time frame. It observed that it had not. Most notably, the CAIR was
finalized in March of 2005 covering much of the Eastern U.S. and drove
significant SCR retrofit activity, with incentives for early
installation and reductions. From this date, 39-48 months would have
placed the SCRs online in the mid 2008 to 2009 time frame. The graphic
below illustrates an uptick in coal-fired capacity retrofitted with
SCRs in response to the rule (Figure VI.D.2). Most of this capacity
comes online in 2009 and 2010. Although EPA's data on when sources
started planning these controls and whether it was driven purely by
CAIR or other factors are not perfect, the Agency finds the chart below
consistent with its determination that a 39-48 month time frame is
reasonable for SCR retrofit possibility on a regional level.

[GRAPHIC] [TIFF OMITTED] TR30AP21.002

    Comment: EPA received comment on the timing assumptions regarding
SCR and SNCR retrofit. Commenters noted that EPA should require SNCR
installation as it can be installed in as little as 16 months, and that
EPA's reliance on SCR timing to justify not considering SNCR is not
reasonable given that EPA is not considering SCR installation.
Moreover, the commenter also suggested that if these controls are not
available on a region-wide level by the start of 2024, that EPA should
still include them for a limited number of units (e.g., 30 percent of
the unretrofitted fleet) as the Clean Air Act requires that upwind
states limit emissions ``as expeditiously as practicable.''
    Response: EPA believes its proposed collective timing assumptions
for post-combustion control retrofit are practicable given that the
preferable capital-intensive investment retrofit decision would be
highly unit-specific and subject to a unit's compliance strategy
choices with respect to multiple regulatory requirements. For the
reasons described above, EPA believes that separating the post-
combustion retrofit timing consideration would create a framework that
potentially inhibits greater emission reductions from technologies like
SCR that may be both preferable to the unit's operator and beneficial
to overall emission reductions. While the commenter observed that SCR
installation is not included as part of EPA's proposed control
stringency, states and EPA may consider requiring this emission control
technology to address good neighbor obligations or other attainment
planning requirements for the 2015 ozone NAAQS or other CAA programs.
Therefore, while the commenter suggests that the exclusion of new SCR
installations from the control stringency selected for this rule should
result in the decoupling of SNCR and SCR for timing considerations, EPA
observes that the broader regulatory context potentially presents
situations where a better performing emission reduction technology is
the preferred retrofit choice. If EPA were to ignore the observation
that this post-combustion retrofit technology decision is a binary
choice, as these technologies substitute for rather than complement one
another, it would potentially eliminate or make more costly the
eventual decision to implement a better performing SCR technology by
implementing on a schedule that did not allow for that compliance
strategy.
    With regard to the suggestion that, if it is not possible to
require all non-retrofitted units to install new controls, EPA should
at least require some units to retrofit with SNCR and SCR, EPA observed
that doing so would result in making selective choices about which
linked upwind states should face more stringent requirements and would
upset the uniform control stringency scheme allowing for ``equitable
and efficient'' implementation of good neighbor obligations. EME Homer
City, 572 U.S. at 519. In addition, it would necessitate far greater
unit-level analysis, which would likely have prevented EPA from