with a specific equation to limit emissions to an amount (in pounds per
day) that reflects the furnace's permitted production capacity in tons
of glass produced per day. Additionally, the owner or operator must
maintain operating records as necessary to demonstrate compliance with
the alternative emissions limitations during idling periods. During
idling, the owner or operator must operate the emissions control system
to minimize emissions whenever technologically feasible.
All-Electric Glass Furnaces
    The EPA solicited comment on whether it is feasible or appropriate
to phase out and retire existing glass manufacturing furnaces in the
affected states and replace them with more energy efficient and less
emitting units like all-electric melter installations. The EPA also
requested comment on the time needed to complete such a task. All-
electric melters are glass melting furnaces in which all the heat
required for melting is provided by electric current from electrodes
submerged in the molten glass.\393\ The EPA received numerous comments
from the glass industry regarding their concerns with replacing an
existing glass manufacturing furnace with an all-electric melter. The
commenters stated that various operational restrictions present within
all-electric furnaces prevent these units from being implemented
throughout the industry, including limited glass production output,
reduced glass furnace life, and increased glass plant operating cost
due to high levels of electric current usage. Based on the EPA's review
of comments submitted on this issue, the EPA has decided not to
establish any requirements to replace existing glass manufacturing
furnaces with all-electric furnaces at this time. We provide in the
following paragraphs a summary of the comments and the EPA's responses
thereto.
---------------------------------------------------------------------------

    \393\ See definitions in 40 CFR part 60, subpart CC.
---------------------------------------------------------------------------

    Comment: One commenter stated that the lifetime of an all-electric
glass melting furnace is only about three to five years before it must
be rebricked, compared to well-maintained natural gas or hybrid furnace
that may be operated continuously for as long as fifteen to twenty
years between rebricking events. The commenter also states that
electric furnaces for manufacture of glass containers are limited to a
maximum glass production of about 120 tons per day, which is a stark
contrast to large natural gas fired glass melting furnaces, which are
capable of producing over 400 tons of glass per day. The commenter also
stated that the cullet percentage is greatly reduced in all-electric
furnaces which increases energy consumption in the affected facility.
    Response: At proposal, the EPA solicited comment on whether it is
feasible or appropriate for owners or operators of existing glass
manufacturing furnaces to phase out and retire their units and replace
them with less emitting units like all-electric furnace installations.
As explained in the Final Non-EGU Sectors TSD, over the last few
decades the demand for flat, container, and pressed/blown glass has
continued to grow annually. Nitrogen oxides remain one of the primary
air pollutants emitted during the production and manufacturing of glass
products. However, no current Federal CAA regulation controls
NOX emissions from the industry on a category-wide
basis.\394\ Therefore, the glass manufacturing industry has conducted
various pollution prevention and research efforts to help identify
preferred techniques for the control of NOX. Some of these
studies revealed recent trends to control NOX emissions in
the glass industry, including the use of all-electric glass furnaces.
We understand based on the comments received from the glass
manufacturing industry that significant differences exist in the
design, configuration, age, and replacement cost of glass furnaces and
in the feasibility of controls and raw material compositions. These
differences as well as the production limitations present with all-
electric furnaces create difficulties in implementing all-electric
furnaces across the industry while keeping up with glass product
demands. Therefore, the EPA is not mandating any requirement for owners
or operators of existing glass manufacturing furnaces to replace their
units with all-electric furnaces.
---------------------------------------------------------------------------

    \394\ See Final Non-EGU Sectors TSD.
---------------------------------------------------------------------------

Combustion Modification and Post-Combustion Modification Control
Devices
    According to the EPA's ``Alternative Control Techniques Document--
NOX Emissions from Glass

Manufacturing,'' \395\ glass manufacturing furnaces may utilize
combustion modifications equivalent to low-NOX burners and
oxy-firing. At proposal, the EPA solicited comments on whether it is
feasible or appropriate to require sources with existing glass
manufacturing furnaces in affected states that currently utilize these
combustion modifications to add or operate a post-combustion
modifications control device like SNCR or SCR to further improve their
NOX removal efficiency. The EPA received numerous comments
from the glass industry that detailed the differences present in glass
furnace designs, operations and finished product that influenced the
type of combustion modification or post-combustion modification control
device that is feasible for such unit. Several commenters have
requested that the EPA focus on establishing an emissions limit rather
than specifying the use of a particular control technology given the
significant differences across glass furnaces. As a result of the
comments received, the EPA is not specifically requiring affected units
to install combustion modification and post-combustion controls to meet
the finalized emissions limits. The EPA is finalizing the emissions
limits as proposed, which may be met with combustion modifications
(e.g., low-NOX burners, oxy-firing), process modifications
(e.g., modified furnace, cullet preheat), and/or post-combustion
controls (SNCR or SCR) and thus provide sources some flexibility to
choose the control technology that works best for their unique
circumstances.
---------------------------------------------------------------------------

    \395\ EPA, Alternative Control Techniques Document--
NOX Emissions from Glass Manufacturing, EPA-453/R-94-037,
June 1994.
---------------------------------------------------------------------------

    Comment: Multiple commenters responded to EPA's request for
comments by stating it is unnecessary and unhelpful for the proposed
rule to specify use of particular post-combustion control device. The
commenters note that various flat glass furnaces have a variety of
combustion and post-combustion control options. Each furnace is
different in its design, operations, and finished product produced. The
commenters state that it is more appropriate for EPA to establish an
emissions limit in the proposed rule than it is for the EPA to specify
use of a particular control technology.
    Response: In response to these comments, the EPA is not
establishing any requirements for affected units to install specific
control technologies to meet the emissions limits. The EPA is
finalizing the limits as proposed to offer sources some flexibility to
choose the control technology that works best for their unique
circumstances.
Compliance Assurance Requirements
    The EPA proposed to require owners or operators of an affected
facility that is subject to the NOX emissions standards for
glass manufacturing furnaces to install, calibrate, maintain and
operate a CEMS for the measurement of NOX emissions
discharged. The EPA also solicited comments on alternative monitoring
systems or methods that are equivalent to CEMS to demonstrate
compliance with the emissions limits. The EPA received numerous
comments from the glass industry expressing concern with any
requirement to use CEMS at affected units. After review of the comments
received and EPA's assessment of practices conducted within the glass
manufacturing industry, the EPA is finalizing compliance assurance
requirements that allow affected glass manufacturing furnaces to
demonstrate compliance through annual testing or use CEMS, or similar
alternative monitoring system data in lieu of a performance test. The
EPA is also establishing recordkeeping provisions that require owners
or operators of affected units to conduct parametric monitoring of fuel
use and glass production during performance testing to assure
continuous compliance on a 30-operating day rolling average.
    Comment: Commenters representing the glass industry stated that a
requirement to install and operate CEMS would present significant costs
and technical complexities in a situation where emissions can be
effectively monitored using stack testing rather than continuous
monitoring. Commenters also objected to the EPA's proposal to require
CEMS together with semi-annual stack testing. Commenters stated that a
requirement to both operate CEMS and conduct semi-annual testing would
be unnecessary and excessive and would not provide commensurate benefit
unless a facility's emissions are near or above the proposed emissions
limit. Commenters requested that owners or operators of affected units
be allowed to use alternative monitoring systems, e.g., parametric
emissions monitoring. The commenters stated that parametric monitoring
requires less initial and ongoing manpower requirements, has lower
capital and operating costs than CEMS, does not require spare parts,
and is accurate over a mapped range.
    Response: The EPA is establishing compliance assurance requirements
that provide flexibility to owners or operators of affected units.
Compliance with the emissions limits in this final rule may be
demonstrated through CEMS or via annual performance test and continuous
parametric monitoring. If an affected unit does not use CEMS, the final
rule requires the owner or operator to monitor and record stack exhaust
gas flow rate, hourly production rate, and stack exhaust temperature
during the initial performance test and subsequent annual performance
tests to assure compliance with the applicable emissions limit. The
owner or operator must then continuously monitor and record those
parameters to demonstrate continuous compliance with the NOX
emissions limits. Affected units that operate NOX CEMS
meeting specified requirements may use CEMS data in lieu of performance
testing and monitoring of operating parameters. To avoid challenges in
scheduling and availability of testing firms, the annual performance
test required under this final rule does not have to be performed
during the ozone season.
5. Boilers at Basic Chemical Manufacturing, Petroleum and Coal Products
Manufacturing, Pulp, Paper, and Paperboard Mills, Iron and Steel and
Ferroalloys Manufacturing, and Metal Ore Mining facilities
Applicability
    The EPA is finalizing regulatory requirements for the Iron and
Steel Mills and Ferroalloy Manufacturing industry, Basic Chemical
Manufacturing industry, Petroleum and Coal Products Manufacturing
industry, Pulp, Paper, and Paperboard Mills industry, and the Metal Ore
Mining industry that apply to boilers that have a design capacity of
100 mmBtu/hr or greater. The Non-EGU Screening Assessment memorandum
developed in support of Step 3 of our proposal identified emissions
from large boilers in certain industries (i.e., those projected to emit
more than 100 tpy of NOX in 2026) as having adverse impacts
on downwind receptors. As discussed in the proposed rule, we developed
applicability criteria for boilers based on design capacity (i.e., heat
input), rather than on potential emissions, because use of a boiler
design capacity of 100 mmBtu/hr reasonably approximates the 100 tpy
threshold used in the Non-EGU Screening Assessment memorandum to
identify impactful boilers. In this final rule, we are establishing the
heat input-based applicability criteria described in our proposal, with
some adjustments as explained further in this section. Additionally, we
have determined that boilers meeting these applicability

criteria exist within the following five industries: Basic Chemical
Manufacturing, Petroleum and Coal Products Manufacturing, Pulp, Paper,
and Paperboard Mills, Metal Ore Mining, and Iron and Steel Mills and
Ferroalloy Manufacturing.
    As we explained in the proposed rule, the potential emissions from
industrial boilers with a design capacity of 100 mmBtu/hr or greater
burning coal, residual or distillate oil, or natural gas can equal or
exceed the 100 tpy threshold that we used to identify impactful boilers
within the Non-EGU Screening Assessment memorandum. We are finalizing
NOX emissions limits that apply to boilers with design
capacities of 100 mmBTU/hr or greater located at any of the five
identified industries in any of the 20 covered states with non-EGU
emissions reduction obligations. In response to comments on our
proposed rule, however, the EPA is finalizing a low-use exemption for
industrial boilers that operate less than 10 percent per year and
provisions for EPA approval of alternative emissions limits on a case-
by-case basis, where specific criteria are met. Additionally, only
boilers that combust, on a BTU basis, 90 percent or more of coal,
residual or distillate oil, natural gas, or combinations of these fuels
are subject to the requirements of these final FIPs.
    The EPA has determined that boilers meeting the applicability
criteria of this section exist within the five industrial sectors
identified in Table VI.C.5-1:

  Table VI.C.5--1: Non-EGU Industries With Large Boilers and Associated
                               NAICS Codes
------------------------------------------------------------------------
                       Industry                            NAICS code
------------------------------------------------------------------------
Basic Chemical Manufacturing.........................             3251xx
Petroleum and Coal Products Manufacturing............             3241xx
Pulp, Paper, and Paperboard Mills....................             3221xx
Iron and Steel and Ferroalloys Manufacturing.........             3311xx
Metal Ore Mining.....................................             2122xx
------------------------------------------------------------------------

    Comment: Several commenters requested that the EPA establish PTE-
based applicability criteria for boilers as it had proposed to do for
other non-EGU sectors and stated that using heat input as the basis for
determining applicability would result in low-emitting boilers being
subject to the final rule's control requirements. Commenters stated
that the EPA should provide a low-use exemption for infrequently run
units because these units produce a lower amount of emissions.
    Response: The EPA is finalizing applicability criteria for boilers
based on boiler design capacity for a number of reasons. First, Federal
emissions standards applicable to boilers \396\ and all of the state
RACT rules that we reviewed contain applicability criteria based on
boiler design capacity. Second, as explained in the Final Non-EGU
Sectors TSD, most boilers with design capacities of 100 mmBTU/hr or
greater that are fueled by coal, oil, or gas have the potential to emit
100 tpy or more of NOX. Thus, use of a boiler design
capacity of 100 mmBtu/hr for applicability purposes reasonably
approximates the 100 tpy threshold used in the Non-EGU Screening
Assessment memorandum to identify impactful boilers. Finally, use of a
boiler's design capacity for applicability purposes facilitates
applicability determinations given that a boiler's design capacity is,
in most cases, clearly indicated by the manufacture on the unit's
nameplate.
---------------------------------------------------------------------------

    \396\ See, e.g., 40 CFR 60.44b (subpart Db, Standards of
Performance for Industrial-Commercial-Institutional Steam Generating
Units).
---------------------------------------------------------------------------

    In response to the comments expressing concern that infrequently-
operated boilers would be captured by the EPA's proposed applicability
criteria, the EPA is finalizing a low-use exemption for industrial
boilers that operate less than 10 percent per year on an hourly basis,
based on the three most recent years of use and no more than 20 percent
in any one of the three years. Such boilers will be exempt from the
emissions limits in these FIPs provided they operate less than 10
percent per year, on an hourly basis, based on the three most recent
years of use and no more than 20 percent in any one of the three years,
but will have recordkeeping obligations. The EPA finds it appropriate
to exempt such low-use boilers from the emissions limits in this final
rule because the amount of air pollution emitted from a boiler is
directly related to its operational hours, and installation of controls
on infrequently operated units results in reduced air quality benefits.
    Comment: Commenters asked whether the EPA's proposed emissions
limits for boilers would apply to emissions units that burn fuels other
than coal, residual or distillate oil, or natural gas. For example, one
commenter stated that some biomass boilers start up by co-firing oil or
gas and that some NOX controls such as low-NOX
burners (LNB) cannot be used on biomass boilers. The commenter
requested clarification on whether boilers burning biomass would be
covered by the EPA's proposed requirements. Other commenters noted that
some industrial boilers burn natural gas in conjunction with other
gaseous fuels, such as hydrogen/methane off-gas and vent gas from
various on-site processes, and may not be able to meet the EPA's
proposed 0.08 lb/mmBtu NOX emissions limit for boilers
burning natural gas. One commenter stated that it operated a boiler
that burns hazardous waste and is subject to 40 CFR part 63, subpart
EEE, National Emission Standards for Hazardous Air Pollutants from
Hazardous Waste Combustors, and that this boiler uses natural gas for
start-up and at other times to stabilize operations but also combusts
other fuels such as liquid waste. The commenter asserted that such
boilers should not be covered by the final rule.
    Response: In recognition and consideration of comments received on
our proposal, the EPA is finalizing requirements for boilers that apply
only to boilers burning 90 percent or more coal, residual or distillate
oil, or natural gas or combinations of these fuels on a heat-input
basis. Public commenters presented information indicating that the
burning of fuels other than coal, residual or distillate oil, or
natural gas at levels exceeding 10 percent may interfere with the
functions of the control technologies that may be necessary to the meet
the final rule, like SCR. The EPA does not have sufficient information
at this time to conclude that units burning more than 10 percent fuels
other than coal, residual or distillate oil, or natural gas can operate
the necessary controls effectively and at a reasonable cost. Therefore,
boilers that burn greater than 10 percent fuels other than coal,
residual or distillate oil,

natural gas, or combinations of these three fuels are not subject to
the emissions limits and other requirements of this final rule.
    Comment: Some commenters claimed that the EPA cannot include
emissions limits for boilers that burn combinations of coal, residual
or distillate oil, and natural gas, because the EPA did not propose
limits for such boilers. Other commenters suggested it would be
appropriate to establish emissions limits for such boilers as long as
the EPA provides criteria for establishing such emissions limits.
    Response: The EPA disagrees with the claim that boilers burning
combinations of coal, residual or distillate oil, or natural gas cannot
be covered by the final FIP because the EPA did not propose specific
emissions limits for these boilers and agrees with commenters who
stated that the EPA's proposed emissions limits can be extended to such
boilers provided the EPA provides criteria for doing so. The
applicability criteria in the final rule cover boilers burning
combinations of coal, residual or distillate oil, or natural gas and
include a methodology for determining the emissions limits for such
units based on a simple formula that correlates the amount of heat
input expended while burning each fuel with the corresponding emissions
limit for that particular fuel. For example, a boiler with a heat input
of 85 percent natural gas and 15 percent distillate oil would be
subject to an emissions limit derived by multiplying the natural gas
emissions limit by 0.85 and adding to that the distillate oil emissions
limit multiplied by 0.15. Thus calculated, the NOX emissions
limits for boilers burning combinations of coal, residual or distillate
oil, or natural gas are consistent with the NOX emissions
limits identified in our proposed rule for each of these individual
fuels.
Emissions Limitations and Rationale
    The EPA is finalizing all of the proposed NOX emissions
limits for industrial boilers and adding a formula for calculating
emissions limits for multi-fueled units as shown in Table VI.C.5-2. The
emissions limits apply to boilers with design capacities of 100 mmBtu/
hr or greater located at any of the five industries identified in Table
II.A-1 within any of the 20 states covered by the non-EGU requirements
of this final rule.

     Table VI.C.5-2--NOX Emissions Limits for Boilers >100 mmBtu/hr
                   [Based on a 30-day rolling average]
------------------------------------------------------------------------
                                         Emissions limit (lbs NOX/mmBtu)
               Unit type
------------------------------------------------------------------------
Coal...................................  0.20.
Residual oil...........................  0.20.
Distillate oil.........................  0.12.
Natural gas............................  0.08.
Multi-fueled unit......................  Limit derived by formula based
                                          on heat input contribution
                                          from each fuel.
------------------------------------------------------------------------

    Additional information on the EPA's derivation of these proposed
emissions rates for boilers is provided in the Final Non-EGU Sectors
TSD.
    Comment: Some commenters noted that many boilers are already
subject to other state and Federal controls, and that programs such as
RACT, NSR, BACT, NSPS, and maximum achievable control technology (MACT)
are all achieving emissions reductions from boilers.
    Response: The EPA acknowledges that some affected units may already
be meeting the emissions limits established in this rule as a result of
controls installed to comply with other regulatory programs, such as
the CAA's RACT requirements. However, emissions from the universe of
boilers subject to the applicability requirements of this final rule
are not being uniformly reduced by these programs to the same extent
that the limits we are adopting will require, nor for the same reason,
which is to mitigate the impact of emissions from upwind sources on
downwind locations that are experiencing air quality problems. The EPA
has determined that the limits we are finalizing in this action are
readily achievable and are already required in practice in many parts
of the country.
    Regarding RACT controls, some of the sources covered by the final
rule are not subject to RACT requirements because RACT is only
applicable to sources located in ozone nonattainment areas and in the
OTR, and many sources covered by the final rule are not located within
such jurisdictions. Regarding sources that are subject to RACT, we note
that unlike RACT requirements applicable to sources of VOCs, where a
majority of such sources are covered by state RACT rules adopted to
conform with uniform ``presumptive'' limits contained within the EPA's
Control Technique Guidelines (CTGs), in most cases presumptive
NOX emissions limits have not been established for
industrial sources of this pollutant. In light of this, NOX
RACT requirements are primarily determined on a state-by-state basis
and exhibit a range of stringencies as determined by each state.
Additionally, RACT requirements tend to become more stringent with the
passage of time as existing control options are improved, and new
options become available. Thus, older RACT determinations may not be as
stringent as more recent determinations made for similar equipment
types. As noted in our proposal, we based our NOX emissions
limits for coal, residual or distillate oil, and natural gas-fired
industrial boilers on RACT limits that are already in place in many
areas of the country.
    Regarding NSR control requirements, we note that the NSR program
was created by the 1977 amendments to the CAA and applies only to new
or modified stationary sources. Many of the boilers covered by the
applicability requirement of this final rule were initially installed
or last modified prior to 1977 and have not undergone NSR analysis,
such as a BACT analysis for sources located within an attainment area
or a LAER analysis for sources located within nonattainment areas.
Additionally, BACT and LAER determinations made many years ago are not
likely to be as stringent as more recent determinations.
    Regarding NSPS requirements, 40 CFR part 60, subpart Db, Standards
of Performance for Industrial-Commercial-Institutional Steam Generating
Units, contains NOX emissions limits for boilers with
capacities of 100 mmBTU/hr or greater that were constructed or modified
after June 19, 1984, and so boilers constructed or modified prior to
that date are not subject to its requirements. Additionally, the limits
for coal, residual or distillate oil, and

gas-fired units are not as stringent as more recent limits adopted by
states pursuant to RACT control obligations.
    Lastly, MACT controls are primarily designed to reduce emissions of
hazardous air pollutants, not to reduce NOX emissions. We
anticipate the MACT program's boiler tune-up requirement should reduce
NOX emissions to some extent, but not to the extent that
compliance with the limits adopted within this final rule will achieve.
    Comment: One commenter noted that a 2017 OTC survey found that
boilers, including those used in the paper products, chemical, and
petroleum industries, are already required to achieve more stringent
limits, and pointed to limits for distillate oil that are lower than
what the EPA considered in developing the proposal. The commenter also
noted that California's South Coast Air Quality Management District has
adopted a facility-wide NOX emissions limit of 0.03 lb/mmBtu
at petroleum refineries. The commenter noted that CEMs data shows a
residual oil-fired boiler at the Ravenswood Steam Plant in New York
achieves an average NOX emissions rate of 0.0716 lb
NOX/MMBtu and that CEMS data shows that a gas-fired boiler
in Johnsonville, Tennessee, achieves an average NOX
emissions rate of 0.0058 lb NOX/mmBTU. Regarding coal-fired
boilers, the commenter stated that a coal boiler at the Ingredion
Incorporated Argo Plant in Illinois achieves an average NOX
emissions rate of 0.1153 lb NOX/MMBtu with selective non-
catalytic control technology, and the Axiall Corporation facility in
West Virginia achieves a 0.1162 lb/mmBtu using low-NOX
burner technology with overfire air. The commenter also noted that more
than half of the gas-fired boilers included in the air markets program
database already emit NOX at rates below the EPA's proposed
emissions rate, and that the RACT/BACT/LAER Clearinghouse (RBLC) shows
more stringent limits for gas boilers than the limits the EPA proposed,
with many facilities being required to meet a NOX limit of
less than 0.0400 lb/mmBtu.
    Response: The EPA's intent was not to set the NOX
emissions limits for coal, residual or distillate oil, and natural gas-
fired boilers to match the lowest levels required elsewhere by state or
local authorities, but rather to establish limits that are commensurate
with broadly applicable RACT limits currently in place in a number of
states as noted within our proposal. The limits we selected were not
the most stringent of the state RACT rules we reviewed but were
relatively close to that value. We did not select the most stringent
limits because such limits may reflect case-specific technological and
economic feasibility considerations that do not apply more broadly
across the industry. Furthermore, although the EPA acknowledges that
some industrial boilers powered by coal, residual or distillate oil,
natural gas, or combinations of these fuels can meet very low
NOX emissions limits as noted by the commenter, it is
unlikely that all such units could meet these limits given case-
specific considerations such as boiler design and operation, some of
which limit the types of control technology that may be available to a
particular unit.
a. Coal-Fired Industrial Boilers
    As we proposed, coal-fired industrial boilers subject to the
applicability requirements of this section are required to meet a
NOX emissions limit of 0.2 lb/mmBtu on a 30-day rolling
average basis. Various forms of combustion and post-combustion
NOX control technology exist that should enable most
facilities to retrofit with equipment to meet this emissions limit. As
we explained in our proposal, many states containing ozone
nonattainment areas or located within the OTR have already adopted RACT
emissions limits similar to or more stringent than the limits in this
final rule, and most of those RACT limits apply statewide and extend to
boilers located at commercial and institutional facilities, not just to
boilers located in the industrial sector.
    Comment: One commenter noted that the coal-fired boilers it
operates already use combustion controls to reduce NOX
emissions and contended that the effectiveness of SNCR on these boilers
is unknown but would likely be on the low end of the control
effectiveness range because they experience variable loads, which would
compromise the proper functioning of an SNCR control system. The
commenter stated that the only way their coal-fired boilers would be
able to comply with the EPA's proposed NOX limit would be to
install SCR. The commenter added that for coal-fired industrial boilers
with a heat input rating of 100 MMBtu/hr or more, a review of the
available RBLC records indicates that out of the 23 RBLC entries
identified, nine units (less than half) were subject to an emissions
limit at or below 0.2 lb/mmBtu, and eight of these nine units were
equipped with SNCR. The commenter stated that based on a review of the
available data in the RBLC and given the technical difficulties and low
control efficiencies when applying SNCR to swing boilers, the EPA's
proposed limit for coal firing does not appear achievable for
industrial coal-fired boilers that experience load swings unless SCR is
installed. Other commenters stated that while there have been recent
advancements in SNCR technology, such as the setting up of multiple
injection grids and the addition of sophisticated CEMs-based feedback
loops, implementing SNCR on industrial load-following boilers continues
to pose several technical challenges, including lack of achievement of
optimal temperature range for the reduction reactions to successfully
complete, and inadequate reagent dispersion in the injection region due
to boiler design which can lead to significant amounts of unreacted
ammonia exhausted to the atmosphere (i.e., large ammonia slip). The
commenter noted that at least one pulp mill boiler had to abandon its
SNCR system due to problems caused by poor dispersion of the reagent
within the boiler, and that SNCR has yet to be successfully
demonstrated for a pulp mill boiler with constant swing loads.
    Response: To the extent the commenter's concerns pertain primarily
to SNCR control technology, we note that the final rule does not
mandate the use of any particular type of control technology and that
other types of control equipment such as SCR should be examined as a
means for meeting the final emissions limits. The EPA acknowledges that
some coal-fired industrial boilers subject to this section of the final
rule may need to install SCR to meet the NOX emissions
limits. This is reflected in our evaluation of costs for the non-EGU
sector contained within the Non-EGU Screening Assessment memorandum and
the cost calculations for the final rule discussed in section V and the
Memo to Docket--Non-EGU Applicability Requirements and Estimate
Emissions Reductions and Costs. We note that although the RBLC contains
information on emissions limits and control technology for some units,
it only provides information on a relatively small number of units
subject to NOX emissions limits and operating NOX
controls. Additionally, our final rule provides an exemption for units
that operate infrequently (i.e., ``low-use boilers''), and also allows
a facility owner or operator to submit a request for a case-by-case
alternative emissions limit in cases where compliance with the
emissions limit in this final rule is technically impossible or would
result in extreme economic hardship. We note that non-EGU boilers share
many similarities with EGU boilers, many of which already operate SCR
to control NOX emissions or will be required to

install and operate SCR systems under the requirements for EGUs
contained in this final rule. Lastly, we note that information
collected during the development of updates to the EPA's MACT
requirements for industrial, commercial, and institutional (ICI)
boilers indicates that over 150 ICI boilers have installed SCR control
systems to reduce their NOX emissions. This information is
available in the docket for this final rule.
    All affected units must install and operate NOX control
equipment as necessary to meet the applicable emissions limits in the
final rule, except that if the owner or operator requests, and the EPA
approves, a case-by-case emissions limit based on a showing of
technical impossibility or extreme economic hardship, the affected unit
would be required to comply with the EPA-approved case-by-case
emissions limit instead.
b. Residual or Distillate Oil-Fired Industrial Boilers
    Most oil-fired boilers are fueled by either residual (heavy) oil or
distillate (light) oil. We proposed a NOX emissions limit of
0.2 lb/mmBtu \397\ for residual oil-fired boilers and proposed a
NOX emissions limit of 0.12 lb/mmBtu for distillate oil-
fired boilers. We are finalizing both limits as proposed, based on a
30-day rolling average. As with coal-fired industrial boilers, a number
of combustion and post-combustion NOX control technologies
exist that should generally enable facilities meeting the applicability
criteria of this section to meet these emissions limits, and the Final
Non-EGU Sectors TSD identifies numerous states that have already
adopted emissions limits similar to the limits in this final rule.
There are relatively few boilers fueled by residual or distillate oil
within the industries affected by this final rule that meet the
applicability criteria of this section, and we received relatively few
comments regarding our proposed emissions limits for them.
---------------------------------------------------------------------------

    \397\ Section 52.45(c) of the regulatory text in our proposed
rule identified a proposed emissions limit of 0.15 lb/mmBtu for
residual oil-fired boilers, but the emissions limit that we intended
to propose for this equipment and discussed both in the preamble to
the proposed rule and in the TSD supporting the proposed rule was
0.20 lb/mmBtu.
---------------------------------------------------------------------------

c. Natural Gas-Fired Industrial Boilers
    We proposed a NOX emissions limit of 0.08 lb/mmBtu based
on a 30-day rolling average for natural gas-fired boilers meeting the
applicability criteria of this section, and we are finalizing this
emissions limit and averaging time as proposed. As explained in our
proposal, numerous combustion and post-combustion NOX
control technologies exist that should generally enable facilities
meeting the applicability criteria of this section to meet this
emissions limit. Additionally, many states have already adopted
emissions limits similar to the emissions limit in this final rule, and
some natural gas-fired industrial boilers may be able to meet the 0.08
lb/mmBtu emissions limit by modifying existing NOX control
equipment installed to meet the requirements in 40 CFR 60.44b (subpart
Db of 40 CFR part 60, Standards of Performance for Industrial-
Commercial-Institutional Steam Generating Units), which already
requires that natural gas-fired units meet a NOX emissions
limit of between 0.1 to 0.2 lbs/MMBtu.
Compliance Assurance Requirements
    We proposed compliance provisions for boilers subject to the
requirements of this section similar to the emissions monitoring
requirements found in 40 CFR 60.45 (subpart D of 40 CFR part 60,
Standards of Performance for Fossil-Fuel-Fired Steam Generators). Those
requirements include, among other provisions, the performance of an
initial compliance test and installation of a CEMS unless the initial
performance test indicates the unit's emissions rate is 70 percent or
less of the emissions limit in this final rule. We received a number of
comments on this portion of our proposal and provide responses to some
of these comments in the following paragraphs. Our full responses to
comments are provided in the response to comments document included in
the docket for this action.
    Comment: A number of commenters stated that CEMS monitoring is too
expensive and unnecessary for ensuring compliance with the emissions
limits for boilers and requested that alternative monitoring techniques
be allowed.
    Response: The EPA acknowledges that the installation and operation
of CEMs systems is more expensive than other monitoring techniques and
may not be necessary for smaller sized boilers that typically produce
less emissions than larger ones. In response to these comments, we have
modified the monitoring requirements in the final rule such that
boilers rated with heat-input capacities less than 250 mmBTU/hr can
demonstrate compliance by conducting an annual stack test as an
alternative to monitoring using a CEMs system and by complying with the
provisions of a monitoring plan meeting specific criteria that enables
the facility owner or operator to demonstrate continuous compliance
with the emissions limits of this final rule.
    Comment: One commenter stated that the proposed reporting
obligations require the submittal of excess emissions reports,
continuous monitoring, and quarterly emissions reports. The commenter
suggested that since the NOX emissions standards only apply
during the ozone season (May 1-September 30), the reporting
requirements should only apply during the second and third quarters of
the year and should require that only emissions and monitoring data
from this time period be included in these reports.
    Response: In response to these comments, the EPA is finalizing
recordkeeping, monitoring, and reporting requirements that are designed
to ensure compliance with the applicable emissions limits only during
the ozone season. Additionally, the final rule requires annual reports
rather than the proposed quarterly reports as annual reports are
adequate to determine compliance with the emissions limits during the
ozone season.
    Comment: A number of commenters stated that some of their boilers
that may potentially be subject to a final FIP already have a
NOX CEMS installed and requested that the EPA clarify
whether a 30-day initial compliance test is required in such cases.
    Response: The EPA's final rule provides that in instances where a
boiler meeting the applicability requirements of this section has
already installed a NOX CEMs that meets the requirements for
such equipment located within 40 CFR 60.13 or 40 CFR part 75,
Continuous Emissions Monitoring, pursuant to a federally enforceable
requirement, a 30-day initial compliance test is not required.
    Comment: One commenter stated that Sec.  52.45(d) of the EPA's
proposed rule included requirements to complete an initial 30-day
compliance test within 90 days of installing pollution control
equipment but did not specify whether the test must be complete prior
to the May 1, 2026, ozone season or by some later date.
    Response: In response to this comment, the EPA is finalizing
provisions requiring that initial compliance tests occur prior to the
May 1, 2026 compliance date.
6. Municipal Waste Combustors
Applicability
    The EPA is finalizing regulatory requirements that apply to
municipal solid waste combustors located in a state subject to the non-
EGU requirements of this final rule (i.e., the 20 states with linkages
that persist in 2026 as identified in section II.B) and

that combust greater than or equal to 250 tons per day of municipal
solid waste (``affected units''). See 40 CFR 52.46(d) for guidelines on
calculating municipal waste combustor unit capacity. This applicability
threshold was supported by commenters and is consistent with the
applicability criteria in 40 CFR part 60, subpart Eb, Standards of
Performance for New Stationary Sources and Emission Guidelines for
Existing Sources: Large Municipal Waste Combustors. State RACT rules
for MWCs and the OTC MWC report similarly define large MWC units as
units with a combustion capacity greater than or equal to 250 tons per
day.
    Across the 20 states subject to the non-EGU requirements, this
applicability threshold captures 28 MWC facilities with a total of 80
affected units. The identified affected units include mass burn
waterwall units, mass burn rotary waterwall units, refuse derived fuel
(RDF) units, and one CLEERGAS\TM\ (``Covanta Low Emissions Energy
Recovery Gasification'') modular system.\398\ The EPA analyzed actual
emissions from the facilities captured by this threshold and found that
on average, a unit with a design capacity of 250 tons per day has a PTE
of approximately 138 tons per year,\399\ which is similar to the PTE
threshold applied to other non-EGU sources under this rulemaking.
---------------------------------------------------------------------------

    \398\ See the Final Non-EGU Sectors TSD for additional
information on this inventory.
    \399\ See the Final Non-EGU Sectors TSD for additional
information on the calculation of PTE for large MWCs.
---------------------------------------------------------------------------

Emissions Limitations and Rationale
    Based on the available information for this industry, including
information provided during the public comment period, the OTC MWC
Report, a review of State and local RACT rules that apply to MWCs, and
active air permits issued to MWCs, the EPA is finalizing the following
emissions limits for municipal solid waste combustors.

     Table VI.C.6-1--NOX Emissions Limits for Large Municipal Waste
                               Combustors
------------------------------------------------------------------------
NOX Limit  (ppmvd)  corrected to 7 percent
                  oxygen                          Averaging period
------------------------------------------------------------------------
110.......................................  24-hour.
105.......................................  30-day.
------------------------------------------------------------------------

    At proposal, the EPA noted that the NOX limits for large
MWCs constructed on or before September 20, 1994 under NSPS subpart Cb
are found within Tables 1 and 2 of 40 CFR 60.39b and range from 165 to
250 ppm depending on the combustor design type. The NOX
limits for large MWCs constructed after September 20, 1994 or for which
modification or reconstruction is commenced after June 19, 1996 under
NSPS subpart Eb are found at 40 CFR 60.52b(d) and are 180 ppm during a
unit's first year of operation and 150 ppm afterwards, applicable
across all combustor types. These limits correspond to NOX
emissions rates of 0.31 and 0.26 lb/mmBtu, respectively. In reviewing
active air permits for MWCs, the EPA found that most MWCs are meeting
emissions limits similar to those reflected in the applicable
NSPS.\400\
---------------------------------------------------------------------------

    \400\ For further discussion of the permits reviewed, see the
Final Non-EGU Sectors TSD.
---------------------------------------------------------------------------

    The EPA also cited the OTC's MWC report that evaluated the
emissions reduction potential of large MWCs located in the OTR from two
different control levels, one based on a NOX concentration
of 105 to 110 ppm, and another based on a limit of 130 ppm. The OTC MWC
report found that a control level of 105 ppmvd on a 30-day rolling
average basis and a 110 ppmvd on a 24-hour block averaging period would
reduce NOX emissions from MWCs by approximately 7,300 tons
annually, and that a limit of 130 ppmvd on a 30 day-average could
achieve a 4,000 ton reduction. The OTR MWC Report noted that at the
time of publication, eight MWC units were already subject to permit
limits of 110 ppm, seven in Virginia, and one in Florida. In
consideration of control costs, the report cited multiple studies
evaluating MWCs similar in design to the large MWCs in the OTR and
found NOX reductions could be achieved at costs ranging from
$2,900 to $6,600 per ton of NOX reduced.
    To further inform the EPA's consideration of emissions limits for
MWCs, the EPA requested comment on the emissions limit and averaging
time MWCs should be required to meet, and specifically whether the EPA
should adopt emissions rates of 105 ppmvd on a 30-day rolling averaging
basis and 110 ppmvd on a 24-hour block averaging basis.
    Comment: The agency received several comments regarding emissions
limits and averaging time for MWCs. Many commenters asserted that the
EPA should set a 24-hour emissions limit no higher than 110 ppm, noting
that recent studies have shown that there are a variety of technologies
that can help a wide range of MWC types achieve this limit at costs
that are significantly below the $7,500/ton cost effectiveness
threshold that the EPA identified at proposal. Some commenters
confirmed the accuracy of the OTC workgroup's estimated cost of
controls for reducing NOX emissions from MWCs of $2,900 to
$6,600 while others stated that the cost of controls is well below
$7,500. One commenter asserted that the EPA should set a 24-hour
NOX emissions limit of 50 ppmvd for MWCs, which could be
achieved by the installation of SCR technology. Alternatively, the
commenters stated that the EPA should set a 24-hour emissions limit no
higher than 110 ppm based on less effective, though still widely
available, control technology. Although some commenters stated that
MWCs should not be included in the rulemaking, no commenters
specifically identified units or categories of units that could not
achieve emissions limits of 105 ppmvd on a 30-day rolling averaging
basis and 110 ppmvd on a 24-hour block averaging basis.
    Response: The EPA recognizes that there have been instances where
MWCs have installed SCR and achieved emissions rates of 50 ppmvd on a
24-hr averaging basis and 45 ppmvd on a 30-day rolling averaging basis
with cost effectiveness estimates around $10,296/ton to $12,779/ton of
NOX reduced. Given uncertainties pertaining to whether SCR
can be installed on all types of MWCs, the EPA has decided not to
establish emissions limits as low as 50 ppmvd for MWCs using SCR at
this time. However, as generally supported by most commenters, the EPA
is finalizing emissions limits of 105 ppmvd at 7 percent oxygen
(O2) on a 30-day rolling average and 110 ppmvd at 7 percent
O2 on a 24-hour block average that apply at all times except
during periods of startup and shutdown. The EPA recognizes that the
final emissions limits for steady-state operations cannot be achieved
during periods of startup, shutdown, and malfunction. This is primarily
due to the fact that during periods of startup and shutdown, additional
ambient air is introduced into the units, resulting in higher oxygen
concentrations. Therefore, the EPA is finalizing provisions applicable
during periods of startup and shutdown that do not require correction
of CEMS data to 7 percent oxygen but do require that such data be
measured at stack oxygen content. This approach is consistent with EPA
regulations applicable during startup and shutdown periods for other
solid-waste incinerators under the NSPS for Commercial and Industrial
Solid Waste Incineration Units. See 40 CFR part 60, subparts CCCC and
DDDD.

    Information received from public commenters generally aligned with
the results from studies showing that the emissions limits of 105 ppmvd
on a 30-day rolling averaging basis and 110 ppmvd on a 24-hour block
averaging basis can be reached using ASNCR or low NOX
technology in addition to SNCR.\401\ The EPA recognizes that not all
units can implement low NOX technology, including those
using Aireal grate technology, those operating RFD units, and those
with rotary combustor units. Of the 80 affected MWC units that the EPA
identified, nine units across two facilities are classified as rotary
combustors, four units at a single facility are classified as RDF, and
no units captured are classified as using Aireal grate technology. One
affected unit is classified as CLEERGAS gasification while the
remaining 64 affected units are classified as mass burn waterwall
combustors, which have not been explicitly identified as units unable
to install low NOX technology. For those units unable to
install low NOX technology or SNCR, the EPA has identified
ASCNR as an alternative control technology that has been shown to
enable units to achieve emissions limits of 105 ppmvd on a 30-day
rolling averaging basis and 110 ppmvd on a 24-hour block averaging
basis, either as a new retrofit technology or as a significant upgrade
to existing SNCR. The EPA finds that the availability of ASNCR or SNCR
and low NOX burners provides sufficient flexibility for MWCs
to meet the emissions limits in the final rule, especially considering
74 of the 80 affected units already have SNCR installed. Although there
is uncertainty on the cost effectiveness of ASNCR for achieving
significant NOX reductions in small MWCs, small MWCs that
combust less than 250 tons per day of municipal solid waste are not
included in this rulemaking.
---------------------------------------------------------------------------

    \401\ The only demonstrated use of low NOX technology
in addition to SNCR at MWC facilities is at Covanta facilities using
Covanta's proprietary low NOX combustion system (LN\TM\).
For the purpose of this rule, EPA is assuming Covanta facilities
will take advantage of this technology and others will use ASNCR.
However, other iterations of low NOX technology could
become available, or facilities could work with Covanta to apply
this technology to their units.
---------------------------------------------------------------------------

    While commenters noted discrepancies across cost effectiveness
values for specific types of control technology, no commenters
specifically indicated that emissions control technology could not be
cost effectively installed on large MWCs to achieve an emissions limit
of 105 ppmvd on a 30-day rolling averaging basis and 110 ppmvd on a 24-
hour block averaging basis. Studies show that these limits can be
achieved through a variety of emissions controls, including ASNCR and
the addition of low NOX technology to existing SNCR.\402\ Of
the 80 MWC units subject to this rule, 55 units already have SNCR
installed, 16 units already have SNCR and low NOX technology
installed, and three units already have ASNCR installed. Applying the
cost values provided in the OTC's MWC report to the MWC inventory in
section 7 of the Final Non-EGU Sectors TSD, the estimated weighted
average cost effectiveness of applying advanced SNCR to units with and
without existing SNCR and adding low NOX technology to
eligible units with SNCR was found to be approximately $7,929.02/
ton.\403\ This value is in line with the control technology costs for
other non-EGU sectors and the EGU costs associated with this final
rule.
---------------------------------------------------------------------------

    \402\ See OTC MWC Report at 6-7; Trinity Consultants, Project
Report Covanta Alexandria/Arlington, Inc., Reasonably Available
Control Technology Determination for NOX (September
2017); Trinity Consultants, Project Report Covanta Fairfax, Inc.,
Reasonably Available Control Technology Determination for
NOX (September 2017); Babcock Power Environmental, Waste
to Energy NOX Feasibility Study, Prepared for:
Wheelabrator Technologies Baltimore Waste to Energy Facility
Baltimore, MD (February 20, 2020); White, M., Goff, S., Deduck, S.,
Gohlke, O., New Process for Achieving Very Low NOX, Proceedings of
the 17th Annual North American Waste-to-Energy Conference, NAWTEC17
(May 2009); Letter from the State of New Jersey to Michael Klein, In
Rreference to Covanta Energy Group, Inc. Essex County Resource
Recovery Facility, Newark Annual Stack Test Program (March 14,
2019).
    \403\ See Final Non-EGU Sectors TSD for more information on
these cost effectiveness estimates were generated.
---------------------------------------------------------------------------

Compliance Assurance Requirements
    In this final rule, the EPA is establishing compliance requirements
for MWCs similar to the NSPS requirements for large MWCs under 40 CFR
part 60, subpart Eb. Those requirements include, among other
provisions, the performance of an initial performance test and
installation of a CEMS. At proposal, the EPA requested comment on
whether it would be appropriate to rely on existing testing,
monitoring, recordkeeping, and reporting requirements for MWCs under
applicable NSPS or other requirements.
    Comment: Some commenters noted that all large MWCs are already
required to use CEMS to demonstrate compliance with NOX
limits under the NSPS program. These commenters asserted that the EPA
should improve electronic reporting requirements beyond current
requirements in the NSPS. The commenters suggested that an owner or
operator of an MWC subject to a limit under the final rule should be
required to report NOX CEMS data electronically at least
annually to the EPA's CEDRI and any other database that the EPA will
utilize when considering revisions to the NSPS for large MWCs. The
commenters asserted that MWC operators should be required to report
NOX CEMS data to the EPA's Clean Air Markets database, to
allow the public access to MWC CEMS data on a large scale for the first
time.
    Response: The EPA is finalizing provisions that require MWCs
subject to the requirements of this section to install, calibrate,
maintain, and operate a CEMS for the measurement of NOX
emissions discharged into the atmosphere from the affected facility.
This is consistent with NSPS requirements for large MWCs under 40 CFR
part 60, subparts Ea and Eb, and state RACT rules that are applicable
to MWCs in many of the states covered under this rulemaking.\404\
Additionally, each emissions unit will be required to conduct an
initial performance test. With regard to electronic reporting, the
final rule requires performance tests and reports, including CEMS data,
to be submitted to CEDRI, as required for all non-EGU industries
covered by this final rule.
---------------------------------------------------------------------------

    \404\ For examples of RACT provisions applicable to MWCs that
require CEMS, see Regulations of Connecticut State Agencies section
22a-174-22e; and Virginia Administrative Code section 5-40-6730,
subsection (D).
---------------------------------------------------------------------------

D. Submitting a SIP

    A state may submit a SIP at any time to address CAA requirements
that are covered by a FIP, and if the EPA approves the SIP it would
replace the FIP, in whole or in part, as appropriate. As discussed in
this section, states may opt for one of several alternatives that the
EPA has provided to take over all or portions of the FIP. However, as
discussed in greater detail further in this section, the EPA also
recognizes that states retain the discretion to develop SIPs to replace
a FIP under approaches that differ from those the EPA has finalized.
    The EPA has established certain specialized provisions for
replacing FIPs with SIPs within all the CSAPR trading programs,
including the use of so-called ``abbreviated SIPs'' and ``full SIPs,''
see 40 CFR 52.38(a)(4) and (5) and (b)(4), (5), (8), (9), (11), and
(12); 40 CFR 52.39(e), (f), (h), and (i). For a state to remove all FIP
provisions through an approved SIP revision, a state would need to
address all of the required reductions addressed by the FIP for that
state, i.e., reductions achieved through both EGU control and non-EGU
control,

as applicable to that state. Additionally, tribes in Indian country
within the geographic scope of this rule may elect to work with EPA
under the Tribal Authority Rule to replace the FIP for areas of Indian
country, in whole or in part, with a tribal implementation plan or
reasonably severable portions of a tribal implementation plan.
    Under the FIPs for the 22 states whose EGUs are required to
participate in the CSAPR NOX Ozone Season Group 3 Trading
Program with the modifications finalized in this rule, EPA continues to
offer ``abbreviated'' and ``full'' SIP options for states. An
``abbreviated SIP'' allows a state to submit a SIP revision that
establishes state-determined allowance allocation provisions replacing
the default FIP allocation provisions but leaving the remaining FIP
provisions in place. A ``full SIP'' allows a state to adopt a trading
program meeting certain requirements that allow sources in the state to
continue to use the EPA-administered trading program through an
approved SIP revision, rather than a FIP. In addition, as under past
CSAPR rulemakings, states have the option to adopt state-determined
allowance allocations for existing units for the second control period
under this rule--in this case, the 2024 control period--through
streamlined SIP revisions. See 76 FR 48326-48332 for additional
discussion of full and abbreviated SIP options; see also 40 CFR
52.38(b).
    Comments: Some commenters alleged that by taking this action, EPA
is depriving states of the ability to develop SIPs to implement good
neighbor obligations for the 2015 ozone NAAQS or from choosing their
own compliance strategies. Commenters also claimed that the EPA cannot
require states to implement emissions reductions equivalent to the
emissions control stringency that the EPA determined at Step 3 if their
proposed SIPs are otherwise shown to be adequate to eliminate
significant contribution. Other commenters raised concerns that the
trading program enhancements for EGUs made it too uncertain what a
state could develop as an approvable replacement SIP. At least one
commenter argued that the EPA must give states a single, mass-based
emissions budget so that they can understand how to replace the FIP
with a SIP.
    Response: The EPA disagrees that it is depriving States of the
opportunity to replace the FIP with a SIP or preventing states from
targeting alternative emissions reductions strategies that can be shown
to be equivalent to the FIP. States have always possessed the authority
and the opportunity to revise their SIPs at any point. The EPA has
repeatedly emphasized that states are free to develop a SIP revision to
replace a transport FIP and submit that to the EPA for approval, and
this remains true. See 87 FR 20036, 20051 (April 6, 2022); 86 FR 23054,
23062 (April 30, 2021); 81 FR 74504, 74506 (Oct. 26, 2016). In the FIP
proposal, as in prior transport actions, the EPA discussed a number of
ways in which states could take over or replace a FIP, see 87 FR 20036,
20149-51 (section VII.D: ``Submitting A SIP''); see also id. at 20040
(noting as one purpose in proposing the FIP that ``this proposal will
provide states with as much information as the EPA can supply at this
time to support their ability to submit SIP revisions to achieve the
emissions reductions the EPA believes necessary to eliminate
significant contribution''). The EPA provides further guidance on
submitting SIPs in this section. If, and when, the EPA receives a SIP
submission that satisfies the requirements of CAA section
110(a)(2)(D)(i)(I) and 110(l), the Agency will take action to approve
those SIP submissions and withdraw the FIP.
    At the outset, we note that the Agency does not anticipate
revisiting its findings at Steps 1 or 2 of the transport framework.
Those findings establish that the projected baseline anthropogenic
emissions from these states contribute to downwind nonattainment or
maintenance receptors in 2023, and, for certain states, that
contribution continues through 2026. Those represent critical
analytical years for downwind areas as they are the last full ozone
season before the Moderate and Serious area attainment dates. Those
findings, for those years, establish the basis for an upwind state's
linkage, from which we proceed to evaluate emissions control
opportunities and their implementation at Steps 3 and 4.
    We cannot prejudge now whether state submissions to replace the
EPA's FIP will be approvable, but we note a number of statutory and
implementation considerations states should be aware of if designing a
replacement SIP. We have demonstrated that the EPA's transport FIP is
adequate to eliminate significant contribution to downwind air quality
problems for purposes of the 2015 ozone NAAQS, and that the FIP does
not result in overcontrol. The level of reductions required by the FIP
therefore provides an important benchmark for states in evaluating the
equivalency of possible replacement SIPs. As discussed in more detail
in this section, in order to comply with their obligation under CAA
section 110(a)(2)(D)(i)(I), we generally anticipate that states seeking
to replace the FIP with a SIP that takes an alternative approach would
need to establish, at a minimum, an equivalent level of emissions
reduction to what the FIP requires at Step 3, and any such replacement
SIP will need to comply with CAA section 110(l).
    The concept of equivalency is important for the state to consider.
Under CAA section 110(l), ``the Administrator shall not approve a
revision of a plan if the revision would interfere with any applicable
requirement concerning attainment . . . or any other applicable
requirement of this chapter.'' Section 110(l) applies to all CAA
requirements, including 110(a)(2)(D) requirements relating to
interstate transport. The EPA interprets section 110(l) such that
states have two main options to make a noninterference demonstration.
First, the state could demonstrate that emissions reductions removed
from the SIP are replaced with new control measures that achieve
equivalent or greater emissions reductions. Thus, a 110(l) analysis
would generally need to show that the SIP revision, or, in this case, a
potential SIP submission replacing an existing FIP, will not interfere
with any area's ability to continue to attain or maintain the affected
NAAQS or other CAA requirements. The EPA further has interpreted
section 110(l) as requiring such substitute measures to be
quantifiable, permanent, and enforceable, among other considerations.
For section 110(l) purposes, ``permanent'' means the state cannot
modify or remove the substitute measure without EPA review and
approval. Second, the state could conduct air quality modeling or
develop an attainment or maintenance demonstration based on the EPA's
most recent technical guidance to show that, even without the control
measure or with the control measure in its modified form, significant
contribution from the state would continue to be prohibited as the Act
requires. As discussed further in this section, for purposes of
interstate ozone transport, such an analysis entails important
questions of consistency and equity among states for resolving air
quality problems that the EPA would need to carefully evaluate.\405\
---------------------------------------------------------------------------

    \405\ For instance, future circumstances in which the receptor
or receptors to which a state is linked come fully into attainment
or to which the upwind state's linkage drops below 1 percent of the
NAAQS would likely not, solely on those grounds, be sufficient to
relax transport requirements established by the FIP or justify
approving a less stringent SIP. First, the emissions reductions
achieved by the FIP are part of the reason that a receptor may come
into attainment or a linkage may drop below 1 percent of the NAAQS.
Simply removing emissions control requirements the moment this
occurs is illogical, since those reductions are part of the solution
by which the attaining air quality was achieved or the linkage was
resolved. See CAA section 107(d)(3)(E)(iii) (areas cannot be
redesignated unless based on permanent and enforceable reductions);
see also Wisconsin, 938 F.3d at 324-25 (explaining that upwind
states are held to a contribution standard, not a but-for causation
standard and thus cannot escape good neighbor obligations on the
basis that other emissions ``cause'' the NAAQS to be exceeded).
There is a risk of inconsistency and inequity in removing any
requirements in this manner in that any increase in emissions that
could occur in one upwind state would likely need to be reviewed in
relation to the obligations other upwind states would continue to
meet. Further, any such relaxation in upwind state requirements
could then unreasonably shift the burden for maintaining air quality
onto the downwind states where receptors are located. These issues
may entail complex state- or case-specific analyses that would need
to be evaluated at the time such a SIP revision is submitted; these
issues are not ripe for resolution in this action.

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

    In the EPA's experience implementing the CAA criteria pollutant
program, reductions arising from the good neighbor provision have been
critically important to the improvement of air quality in downwind
areas struggling with attainment and maintenance of the NAAQS, and
states' reliance on good neighbor FIP reductions will need to be taken
into account in any replacement SIP. In order for a nonattainment area
to be redesignated to attainment, the CAA requires not only that an
area attain the standard, but also the Administrator must determine
``that the improvement in air quality is due to permanent and
enforceable reductions in emissions resulting from implementation of
the applicable implementation plan and applicable Federal air pollutant
control regulations and other permanent and enforceable reductions.''
CAA section 107(d)(3)(E)(i) and (iii). Many nonattainment areas across
the country that have attained various PM2.5 and ozone NAAQS
have done so in part due to the imposition of Federal good neighbor
emissions control measures, and, per CAA section 107(d)(3)(E)(iii),
states have specifically relied on the emissions reductions required by
those programs in order to be redesignated to attainment. See, e.g., 84
FR 8422, 8425 (March 8, 2019) (noting that ``[a]t least 140 EPA final
actions redesignating areas in 20 states to attainment with an ozone
NAAQS or a fine particulate matter (PM2.5) NAAQS--because
NOX is a precursor to PM2.5 as well as ozone--
have relied in part on the NOX SIP Call's emissions
reductions''); see also Sierra Club v. EPA, 774 F.3d 383, 397-99 (7th
Cir. 2014) (upholding EPA's approval of a redesignation, and
specifically EPA's determination that reductions from Federal good
neighbor transport trading programs could reasonably be considered
``permanent and enforceable'' under the statute); Sierra Club v. EPA,
793 F.3d 656, 665-68 (6th Cir. 2015) (same). States seeking area
redesignations are also required under CAA section 107(d)(3)(E)(iv) to
develop revisions to their state implementation plans that provide for
maintenance of the NAAQS. In so doing, states develop air quality
modeling, in which they project future air quality based on emissions
inputs that account for enforceable emissions reductions, or states
project emissions in the future relative to emissions in an attainment
year, showing that the future emissions (which, again, account for on-
the-books, enforceable emissions limits) do not exceed emissions in the
baseline attainment year. See ``Procedures for Processing Requests to
Redesignate Areas to Attainment,'' Memo from John Calcagni to EPA
Regions, September 4, 1992, at 9. Reductions required by Federal good
neighbor programs may therefore also be relied upon by states seeking
area redesignations in the context of how states demonstrate that areas
will maintain the NAAQS.
    We anticipate that air quality in areas struggling to attain and
maintain the 2015 ozone NAAQS will improve due to the emissions
reductions required by EPA's FIP. We also anticipate that, consistent
with EPA's historical experience implementing the NAAQS and acting on
state requests for nonattainment area redesignations, emissions
reductions associated with EPA's transport FIP for the 2015 ozone NAAQS
are likely to be a critical component in those requests for
redesignation. Where states have relied and are relying on the FIP's
reductions in order to attain and maintain the NAAQS, EPA will look
very critically at any replacement SIP that appears to fall short of
equivalent emissions reductions--in terms of the level of reductions or
the permanence of those reductions.
    Finally, we disagree with commenters that the absence of fixed,
mass-based emissions budgets for each state make it impossible to
replace the FIP with an equivalent SIP. In the case of the trading
program enhancements for EGUs, the EPA recognizes that the dynamic
budgeting methodology will generally function to impose a continuous
incentive on relevant EGUs to continue to implement the emissions
control strategies determined at Step 3. Further, the backstop rate and
banking recalibration enhancements also are designed to ensure that
EGUs implement emissions controls consistent with Step 3 determinations
on a continuous basis throughout each ozone season. As explained in
section V.D.4 of this document, these aspects of the trading program do
not in themselves introduce an overcontrol concern. Nonetheless,
consistent with the more general principles discussed in this section
with respect to the potential bases on which states may replace the FIP
with SIPs, we reserve judgment at this time on whether some future
demonstration could successfully establish that revision of the FIP or
its replacement with a SIP could be acceptable even if the way that
significant contribution is eliminated is through means that differ
from the trading program enhancements included for EGUs in this action.
As discussed further in this section, a state may choose to withdraw
its EGUs from the trading program and instead subject those EGUs to
daily emissions rates commensurate with installation and optimization
of state-of-the-art combustion and post-combustion controls as the EPA
determined at Step 3. Likewise, states are free to explore an
alternative set of emissions controls on non-EGU industrial sources (or
other sources in the state), so long as they can demonstrate that an
equivalent amount of emissions is eliminated. In any case, we need not
resolve these questions here. The EPA, in promulgating a FIP, is not
obligated to identify each way a state could replace it with a SIP
revision. Several options are discussed further in this section, and,
as always, EPA Regional Offices will work closely with states who wish
to explore these options or other alternatives.
1. SIP Option To Modify Allocations for 2024 Under EGU Trading Program
    As with the start of past CSAPR rulemakings, the EPA is finalizing
the option to allow a state to use a similar process to submit a SIP
revision establishing allowance allocations for existing EGU units in
the state for the second control period of the new requirements, i.e.,
in 2024, to replace the EPA-determined default allocations. A state
must submit a letter to EPA by August 4, 2023, indicating its intent to
submit a complete SIP revision by September 1, 2023. The SIP would
provide in an EPA-prescribed format a list of existing units within the
state and their allocations for the 2024 control period. If a state
does not submit a letter of intent to submit a SIP revision, the EPA-
determined default allocations will be recorded by September 5, 2023.
If a state submits a timely letter of intent but fails to submit a SIP
revision, the EPA-determined default allocations will be recorded by
September 15, 2023. If a state submits a timely letter of intent

followed by a timely SIP revision that is approved, the approved SIP
allocations will be recorded by March 1, 2024.
    The EPA received no comments on the proposed option to modify
allowance allocations under the Group 3 trading program for EGUs for
the 2024 control period through a SIP revision and is finalizing the
provisions as proposed.
2. SIP Option To Modify Allocations for 2025 and Beyond Under EGU
Trading Program
    For the 2025 control period and later, states in the CSAPR
NOX Ozone Season Group 3 Trading Program can modify the EPA-
determined default allocations with an approved SIP revision. For the
2025 control period and later, SIPs can be full or abbreviated SIPs.
See 76 FR 48326-48332 for additional discussion of full and abbreviated
SIP options; see also 40 CFR 52.38(b).
    In this final rule, the EPA is removing the previous regulatory
text defining specific options for states to expand CSAPR
NOX Ozone Season Group 3 trading program applicability to
include EGUs between 15 MWe and 25 MWe or, in the case of states
subject to the NOX SIP Call, large non-EGU boilers and
combustion turbines. These options for expanding trading program
applicability through SIP revisions have been available to states since
the start of the CSAPR trading programs for small EGUs and since the
CSAPR Update for large non-EGU boilers and combustion turbines, and no
state has chosen to use the SIP process for this purpose. Additionally,
the EPA did not receive comment supporting these expansion options
during the comment period for this rule. The EPA is finalizing a
methodology for updating the affected EGU portion of the budget in this
rule, and the regulatory text defining the applicability expansion to
non-EGUs did not include a mechanism for updating the incremental non-
EGU portion of a state's budget based on changes over time of the non-
EGU fleet; therefore, continuation of the option to expand
applicability to certain non-EGUs subject to the NOX SIP
Call would be inconsistent with the trading program as applied to EGUs
in this rule.
    However, the EPA recognizes that states may seek to include non-
EGUs covered in this action in an emissions trading program, subject to
important considerations to ensure equivalency in emissions reductions
is maintained. While the EPA is not offering specific regulatory text
to implement an option to expand the trading program applicability, a
state could submit a SIP to expand the CSAPR NOX Ozone
Season Group 3 Trading Program applicability, which the EPA would
evaluate on a case-by-case basis. The SIP revision would need to
address critical program elements, and include: (1) high-quality
baseline data, (2) ongoing Part 75 monitoring, and (3) provisions to
update the non-EGU portion of the budget to appropriately reflect
changes to the fleet over time.
    For states that want to modify the EPA-determined default
allocations, the EPA proposed that a state could submit a SIP revision
that makes changes only to that provision while relying on the FIP for
the remaining provisions of the EGU trading program. This abbreviated
SIP option allows states to tailor the FIP to their individual choices
while maintaining the FIP-based structure of the trading program. To
ensure the availability of allowance allocations for units in any
Indian country within a state not covered by the state's CAA
implementation planning authority, if the state chose to replace the
EPA's default allocations with state-determined allocations, the EPA
would continue to administer any portion of each state emissions budget
reserved as a new unit set-aside or an Indian country existing unit
set-aside.
    The SIP submittal deadline for this type of revision is December 1,
2023, if the state intends for the SIP revision to be effective
beginning with the 2025 control period. For states that submit this
type of SIP revision, the deadline to submit state-determined
allocations beginning with the 2025 control period under an approved
SIP is June 1, 2024, and the deadline for the EPA to record those
allocations is July 1, 2024. Similarly, a state can submit a SIP
revision beginning with the 2026 control period and beyond by December
1, 2024, with state allocations for the 2026 control period due June 1,
2025, and EPA recordation of the allocations by July 1, 2025.
    The EPA received no comment on the option to replace certain
allowance allocation provisions under the Group 3 trading program for
EGUs for control periods in 2025 and later years through a SIP revision
and is finalizing the provisions generally as proposed, with the
exception that any potential expansion of trading program applicability
under a SIP revision would be evaluated on a case-by-case basis.
3. SIP Option To Replace the Federal EGU Trading Program With an
Integrated State EGU Trading Program
    For the 2025 control period and later, states in the CSAPR
NOX Ozone Season Group 3 Trading Program can choose to
replace the Federal EGU trading program with an integrated State EGU
trading program through an approved SIP revision. Under this option, a
state can submit a SIP revision that makes changes only to modify the
EPA-determined default allocations and that adopts identical provisions
for the remaining portions of the EGU trading program. This SIP option
allows states to replace these FIP provisions with state-based SIP
provisions while continuing participation in the larger regional
trading program. As with the abbreviated SIP option discussed
previously, to ensure the availability of allowance allocations for
units in any Indian country within a state not covered by the state's
CAA implementation planning authority, if the state chooses to replace
the EPA's default allocations with state-determined allocations, the
EPA would continue to administer any portion of each state emissions
budget reserved as a new unit set-aside or an Indian country existing
unit set-aside. Also, for the same reasons discussed with respect to
the abbreviated SIP option, the EPA is removing the option for states
to expand CSAPR NOX Ozone Season Group 3 trading program
applicability to include EGUs between 15 MWe and 25 MWe or, in the case
of states subject to the NOX SIP Call, large non-EGU boilers
and combustion turbines.
    Deadlines for this type of SIP revision are the same as the
deadlines for abbreviated SIP revisions. For the SIP-based program to
start with the 2025 control period, the SIP deadline is December 1,
2023, the deadline to submit state-determined allocations for the 2025
control period under an approved SIP is June 1, 2024, and the deadline
for the EPA to record those allocations is July 1, 2024, and so on.
    The EPA received no comment on the option to replace the Federal
trading program for EGUs with an integrated state trading program for
EGUs for control periods in 2025 and later years through a SIP revision
and is finalizing the provisions generally as proposed, with the
exception that any potential expansion of trading program applicability
under a SIP revision would be evaluated on a case-by-case basis.
4. SIP Revisions That Do Not Use the Trading Program
    States can submit SIP revisions to replace the FIP that achieve the
necessary EGU emissions reductions but do not use the CSAPR
NOX Ozone Season Group 3 Trading Program. For a transport
SIP revision that does not use the CSAPR NOX Ozone Season
Group 3 Trading Program, the EPA would evaluate the transport SIP based
on the

particular control strategies selected and whether the strategies as a
whole provide adequate and enforceable provisions ensuring that the
necessary emissions reductions (i.e., reductions equal to or greater
than what the Group 3 trading program will achieve) will be achieved.
To address the applicable CAA requirements, the SIP revision should
include the following general elements: (1) a comprehensive baseline
2023 statewide NOX emissions inventory (which includes
existing control requirements), which should be consistent with the
2023 emissions inventory that the EPA used to calculate the required
state budget in this final rule (unless the state can explain the
discrepancy); (2) a list and description of control measures to satisfy
the state emissions reduction obligation and a demonstration showing
when each measure would be implemented to meet the 2023 and successive
control periods; (3) fully-adopted state rules providing for such
NOX controls during the ozone season; (4) for EGUs greater
than 25 MWe, monitoring and reporting under 40 CFR part 75, and for
other units, monitoring and reporting procedures sufficient to
demonstrate that sources are complying with the SIP (see 40 CFR part
51, subpart K (``source surveillance'' requirements)); and (5) a
projected inventory demonstrating that state measures along with
Federal measures will achieve the necessary emissions reductions in
time to meet the 2023 and successive compliance deadlines (e.g.,
enforceable reductions commensurate with installation of SCR on coal-
fired EGUs by the 2027 ozone season). The SIPs must meet procedural
requirements under the Act, such as the requirements for public
hearing, be adopted by the appropriate state board or authority, and
establish by a practically enforceable regulation or permit(s) a
schedule and date for each affected source or source category to
achieve compliance. Once the state has made a SIP submission, the EPA
will evaluate the submission(s) for completeness before acting on the
SIP. EPA's criteria for determining completeness of a SIP submission
are codified at 40 CFR part 51, appendix V.
    For further background information on considerations for replacing
a FIP with a SIP, see the discussion in the final CSAPR rulemaking (76
FR 48326).
5. SIP Revision Requirements for Non-EGU or Industrial Source Control
Requirements
    EPA's promulgation of a non-EGU transport FIP would in no way
affect the ability of states to submit, for review and approval, a SIP
that replaces the requirements of the FIP with state requirements. To
replace the non-EGU portion of the FIP in a state, the state's SIP must
provide adequate provisions to prohibit NOX emissions that
contribute significantly to nonattainment or interfere with maintenance
of the 2015 ozone NAAQS in any other state. The state SIP submittal
must demonstrate that the emissions reductions required by the SIP
would continue to ensure that significant contribution from that state
has been eliminated through permanent and enforceable measures. The
non-EGU requirements of the FIP would remain in place in each covered
state until a state's SIP has been approved by the EPA to replace the
FIP.
    The most straightforward method for a state to submit a
presumptively approvable SIP revision to replace the non-EGU portion of
the FIPs for the state would be to provide a SIP that includes
emissions limits at an equivalent or greater level of stringency than
is specified for non-EGU sources meeting the applicability criteria and
associated compliance assurance provisions for each of the unit types
identified in section VI.C of this document.
    Comment: One commenter stated that they believed EPA's assertion in
the proposal that any SIP submittal would have to achieve equal or
greater reductions for non-EGUs than the FIP was unlawful. The
commenter asserted that a state's ability to replace the FIP must be
tied to whether it has addressed the underlying nonattainment/
maintenance concerns by reducing significant contribution from sources
in the state below the significance threshold, (as opposed to whether
it prohibits equivalent emissions to the FIP).
    Response: The EPA recognizes that states may select emissions
reductions strategies that differ from the emissions limitations
included in the proposed non-EGU FIP; this is discussed in response to
comments earlier in this section. For example, some states may desire
to include non-EGUs in a trading program. This may be possible subject
to taking into account a number of considerations as discussed earlier
in this section to ensure equivalency between the different approaches.
But the state must still demonstrate that the replacement SIP provides
an equivalent or greater amount of emissions reductions as the proposed
FIP to be presumptively approvable. The EPA anticipates that such
emissions reductions strategies would have to achieve reductions
equivalent to or beyond those emissions reductions already projected to
occur in EPA's emissions projections and air quality modeling conducted
at Steps 1 and 2. Such reductions must also be achieved by the 2026
ozone season.
    EPA further acknowledges that a demonstration of equivalency using
other control strategies is complicated by the fact that the final
emissions limits for non-EGU sources are generally unit-specific and
expressed in a variety of forms; comparative analysis with alternative
control requirements to determine equivalency would need to take this
into account. Similarly, we recognize that the emissions trading
program for EGUs in this action includes a number of enhancements to
ensure that the Step 3 determination of which emissions are
``significant'' and must be eliminated continues to be implemented over
time. Although there is not a fixed, mass-based emissions budget
established for each state in this action, there are other objective
metrics that could guide states in developing replacement SIPs. For
example, for non-EGUs, states may choose to conduct an analysis of
their industrial stationary sources and present an alternative set of
emissions limits applying to specific units that it believes would
achieve an equivalent level of emissions reduction. States could apply
cost-effectiveness thresholds for emissions control technologies that
could be applied to establish that some alternative emissions control
strategy results in equivalent or greater improvement at downwind
receptors. The EPA anticipates that such a comparison may entail review
of both baseline emissions information and growth projections between
the different sets of units to ensure that a truly equivalent or
greater degree of emissions reduction is achieved; additionality and
emissions shifting potential may also need to be considered. We note
that the CAMx policy case run for 2026 provides a benchmark for
assessing the level of air quality improvement anticipated at receptors
with implementation of the FIP. This data may be of use to states as
part of a demonstration that a replacement SIP achieves an equivalent
or greater level of air quality improvement to the FIP; however, the
use of such modeling in such a demonstration would need to be more
fully evaluated at the time of such a SIP revision.
    In all cases, a SIP submitted by a state to replace the non-EGU
components of the FIPs would very likely need to rely on permanent and
practically enforceable controls measures that are included in the SIP
and, once approved by the EPA, rendered federally enforceable. So-
called ``demonstration-

only'' or ``non-regulatory'' SIPs would very likely be insufficient;
see discussion in response to comments earlier in this section.
Further, the EPA anticipates that states would bear the burden of
establishing that the state's alternative approach achieves at least an
equivalent level of emissions reduction as the FIP.

E. Title V Permitting

    This final rule, like CSAPR, the CSAPR Update, and the Revised
CSAPR Update does not establish any permitting requirements independent
of those under Title V of the CAA and the regulations implementing
Title V, 40 CFR parts 70 and 71.\406\ All major stationary sources of
air pollution and certain other sources are required to apply for title
V operating permits that include emissions limitations and other
conditions as necessary to ensure compliance with the applicable
requirements of the CAA, including the requirements of the applicable
SIP. CAA sections 502(a) and 504(a), 42 U.S.C. 7661a(a) and 7661c(a).
The ``applicable requirements'' that must be addressed in title V
permits are defined in the title V regulations (40 CFR 70.2 and 71.2
(definition of ``applicable requirement'')).
---------------------------------------------------------------------------

    \406\ Part 70 addresses requirements for state title V programs,
and part 71 governs the Federal title V program.
---------------------------------------------------------------------------

    The EPA anticipates that, given the nature of the units subject to
this final rule, most if not all of the sources at which the units are
located are already subject to title V permitting requirements and
already possess a title V operating permit. For sources subject to
title V, the interstate transport requirements for the 2015 ozone NAAQS
that are applicable to them under the FIPs finalized in this action
would be ``applicable requirements'' under title V and therefore must
be addressed in the title V permits. For example, EGU requirements
concerning designated representatives, monitoring, reporting, and
recordkeeping, the requirement to hold allowances covering emissions,
the compliance assurance provisions, and liability, and for non-EGUs,
the emissions limits and compliance requirements are, to the extent
relevant to each source, ``applicable requirements'' that must be
addressed in the permits.
    Consistent with EPA's approach under CSAPR, the CSAPR Update and
the Revised CSAPR Update, the applicable requirements resulting from
the FIPs generally will have to be incorporated into affected sources'
existing title V permits either pursuant to the provisions for
reopening for cause (40 CFR 70.7(f) and 71.7(f)), significant
modifications (40 CFR 70.7(e)(4)) or the standard permit renewal
provisions (40 CFR 70.7(c) and 71.7(c)).\407\ For sources newly subject
to title V that are affected sources under the FIPs, the initial title
V permit issued pursuant to 40 CFR 70.7(a) should address the final FIP
requirements.
---------------------------------------------------------------------------

    \407\ A permit is reopened for cause if any new applicable
requirements (such as those under a FIP) become applicable to an
affected source with a remaining permit term of 3 or more years. If
the remaining permit term is less than 3 years, such new applicable
requirements will be added to the permit during permit renewal. See
40 CFR 70.7(f)(1)(i) and 71.7(f)(1)(i).
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    As was the case in the CSAPR, the CSAPR Update and the Revised
CSAPR Update, the new and amended FIPs impose no independent permitting
requirements and the title V permitting process will impose no
additional burden on sources already required to be permitted under
title V.
1. Title V Permitting Considerations for EGUs
    Title V of the CAA establishes the basic requirements for state
title V permitting programs, including, among other things, provisions
governing permit applications, permit content, and permit revisions
that address applicable requirements under final FIPs in a manner that
provides the flexibility necessary to implement market-based programs
such as the trading programs established in CSAPR, the CSAPR Update,
the Revised CSAPR Update and this final rule. 42 U.S.C. 7661a(b); 40
CFR 70.6(a)(8) & (10); 40 CFR 71.6(a)(8) & (10).
    In CSAPR, the CSAPR Update and the Revised CSAPR Update, the EPA
established standard requirements governing how sources covered by
those rules would comply with title V and its regulations.\408\ 40 CFR
97.506(d), 97.806(d) and 97.1006(d). For any new or existing sources
subject to this rule, identical title V compliance provisions will
apply with respect to the CSAPR NOX Ozone Season Group 3
Trading Program. For example, the title V regulations provide that a
permit issued under title V must include ``[a] provision stating that
no permit revision shall be required under any approved . . . emissions
trading and other similar programs or processes for changes that are
provided for in the permit.'' 40 CFR 70.6(a)(8) and 71.6(a)(8).
Consistent with these provisions in the title V regulations, in CSAPR,
the CSAPR Update and the Revised CSAPR Update, the EPA included a
provision stating that no permit revision is necessary for the
allocation, holding, deduction, or transfer of allowances. 40 CFR
97.506(d)(1), 97.806(d)(1) and 97.1006(d)(1). This provision is also
included in each title V permit for an affected source. This final rule
maintains the approach taken under CSAPR, the CSAPR Update and the
Revised CSAPR Update that allows allowances to be traded (or allocated,
held, or deducted) without a revision to the title V permit of any of
the sources involved.
---------------------------------------------------------------------------

    \408\ The EPA has also issued a guidance document and template
that includes instructions for how to incorporate the applicable
requirements into a source's Title V permit. See Memorandum dated
May 13, 2015, from Anna Marie Wood, Director, Air Quality Policy
Division, and Reid P. Harvey, Director, Clean Air Market Division,
EPA, to Regional Air Division Directors, Subject: ``Title V Permit
Guidance and Template for the Cross-State Air Pollution Rule''
(``2015 Title V Guidance''), available at https://www.epa.gov/sites/default/files/2016-10/documents/csapr_title_v_permit_guidance.pdf.
---------------------------------------------------------------------------

    Similarly, this final rule would also continue to support the means
by which a source in the final trading program can use the title V
minor modification procedure to change its approach for monitoring and
reporting emissions, in certain circumstances. Specifically, sources
may use the minor modification procedure so long as the new monitoring
and reporting approach is one of the prior-approved approaches under
CSAPR, the CSAPR Update and the Revised CSAPR Update (i.e., approaches
using a continuous emissions monitoring system under subparts B and H
of 40 CFR part 75, an excepted monitoring system under appendices D and
E to 40 CFR part 75, a low mass emissions excepted monitoring
methodology under 40 CFR 75.19, or an alternative monitoring system
under subpart E of 40 CFR part 75), and the permit already includes a
description of the new monitoring and reporting approach to be used.
See 40 CFR 97.506(d)(2), 97.806(d)(2) and 97.1006(d)(2); 40 CFR
70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B). As described in EPA's 2015 Title
V Guidance, sources may comply with this requirement by including a
table of all of the approved monitoring and reporting approaches under
CSAPR, the CSAPR Update and the Revised CSAPR Update trading programs
in which the source is required to participate, and the applicable
requirements governing each of those approaches.\409\ Inclusion of such
a table in a source's title V permit therefore allows a covered unit
that seeks to change or add to its chosen monitoring and recordkeeping
approach to easily comply with the regulations

governing the use of the title V minor modification procedure.
---------------------------------------------------------------------------

    \409\ Id.
---------------------------------------------------------------------------

    Under CSAPR, the CSAPR Update and the Revised CSAPR Update, to
employ a monitoring or reporting approach different from the prior-
approved approaches discussed previously, unit owners and operators
must submit monitoring system certification applications to the EPA
establishing the monitoring and reporting approach actually to be used
by the unit, or, if the owners and operators choose to employ an
alternative monitoring system, to submit petitions for that alternative
to the EPA. These applications and petitions are subject to the EPA
review and approval to ensure consistency in monitoring and reporting
among all trading program participants. EPA's responses to any
petitions for alternative monitoring systems or for alternatives to
specific monitoring or reporting requirements are posted on EPA's
website.\410\ The EPA maintains the same approach for the trading
program in this final rule.
---------------------------------------------------------------------------

    \410\ https://www.epa.gov/airmarkets/part-75-petition-responses.
---------------------------------------------------------------------------

2. Title V Permitting Considerations for Industrial Stationary Sources
    For non-EGU sources, affected sources will need to work with their
local, state, or tribal permitting authority to determine if the new
applicable requirements should be incorporated into their existing
title V permit under the reopening for cause, significant modification,
or permit renewal procedures of the approved permitting program. Title
V permits for existing sources will need to be updated to include the
applicable requirements of this final rule and any necessary
preconstruction permits obtained in order to comply with this final
rule.

F. Relationship to Other Emissions Trading and Ozone Transport Programs

1. NOX SIP Call
    Sources in states affected by both the NOX SIP Call for
the 1979 ozone NAAQS and the requirements established in this final
rule for the 2015 ozone NAAQS will be required to comply with the
requirements of both rules. With respect to EGUs larger than 25 MW, in
this rule the EPA is requiring NOX ozone season emissions
reductions from these sources in many of the NOX SIP Call
states, and at greater stringency than required by the NOX
SIP Call, by requiring the EGUs to participate in the CSAPR
NOX Ozone Season Group 3 Trading Program. The emissions
reductions required under this rule are therefore sufficient to satisfy
the emissions reduction requirements under the NOX SIP Call
for these large EGUs.
    With respect to the large non-EGU boilers and combustion turbines
that formerly participated in the NOX Budget Trading Program
under the NOX SIP Call, the EPA provided options under both
the CSAPR Update and the Revised CSAPR Update for states to address
these sources' ongoing NOX SIP Call requirements by
expanding applicability of the relevant CSAPR trading programs for
ozone season NOX emissions to include the sources, and no
state chose to use these options. As discussed in sections VI.D.2 and
VI.D.3, in this rule the EPA is removing the previous regulatory text
defining specific options for states to expand trading program
applicability to include these sources and instead will evaluate any
SIP revisions seeking to include these sources in the Group 3 trading
program on a case-by-case basis.\411\
---------------------------------------------------------------------------

    \411\ Only one NOX SIP Call state--Tennessee--
continues to participate in the Group 2 trading program, and the EPA
has already approved other SIP provisions addressing the ongoing
NOX SIP Call obligations for Tennessee's large non-EGU
boilers and combustion turbines. See 84 FR 7998 (March 6, 2019); 86
FR 12092 (March 2, 2021).
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2. Acid Rain Program
    This rule does not affect any SO2 and NOX
requirements under the Acid Rain Program, which are established
separately under 40 CFR parts 72 through 78 and will continue to apply
independently of this rule's provisions. Sources subject to the Acid
Rain Program will continue to be required to comply with all
requirements of that program, including the requirement to hold
sufficient allowances issued under the Acid Rain Program to cover their
SO2 emissions after the end of each control period.
3. Other CSAPR Trading Programs
    This rule does not substantively affect any provisions of the CSAPR
NOX Annual, CSAPR SO2 Group 1, CSAPR
SO2 Group 2, CSAPR NOX Ozone Season Group 1, or
CSAPR NOX Ozone Season Group 2 trading programs for sources
that continue to participate in those programs. Sources subject to any
of the CSAPR trading programs will continue to be required to comply
with all requirements of all such trading programs to which they are
subject, including the requirement to hold sufficient allowances issued
under the respective programs to cover emissions after the end of each
control period.
    The EPA also notes that where a state's good neighbor obligations
with respect to the 1997 ozone NAAQS or the 2008 ozone NAAQS have
previously been met by participation of the state's large EGUs in the
CSAPR NOX Ozone Season Group 2 Trading Program (or earlier
by the CSAPR NOX Ozone Season Group 1 Trading Program), the
EPA will deem those obligations to be satisfied by the participation of
the same sources in the CSAPR NOX Ozone Season Group 3
Trading Program. Specifically, for all states covered by the Group 3
trading program under this rule except Minnesota, Nevada, and Utah,
participation of the state's EGUs in the Group 3 trading program will
be deemed to satisfy not only the EGU-related portion of the state's
good neighbor obligations with respect to the 2015 ozone NAAQS but also
the state's good neighbor obligations with respect to the 2008 ozone
NAAQS. In addition, for Alabama, Arkansas, Illinois, Indiana, Kentucky,
Louisiana, Michigan, Mississippi, Missouri, Oklahoma, and Wisconsin,
participation of the state's EGUs in the Group 3 trading program will
also be deemed to satisfy the state's good neighbor obligations with
respect to the 1997 ozone NAAQS.\412\
---------------------------------------------------------------------------

    \412\ For the remaining state transitioning from the Group 2
trading program to the Group 3 trading program under this rule--
Texas--as well as the remaining states that transitioned from the
Group 2 trading program to the Group 3 trading program under the
Revised CSAPR Update--Maryland, New Jersey, New York, Ohio,
Pennsylvania, Virginia, and West Virginia--participation of the
states' EGUs in the Group 2 trading program as required by the CSAPR
Update was addressing good neighbor obligations of the states with
respect to only the 2008 ozone NAAQS, not the 1997 ozone NAAQS. See
81 FR 74523-74526.
---------------------------------------------------------------------------

VII. Environmental Justice Analytical Considerations and Stakeholder
Outreach and Engagement

    Consistent with EPA's commitment to integrating environmental
justice in the agency's actions, and following the directives set forth
in multiple Executive orders, the Agency has analyzed the impacts of
this final rule on communities with environmental justice concerns and
engaged with stakeholders representing these communities to seek input
and feedback. Executive Order 12898 is discussed in section X.J of this
final rule and analytical results are available in Chapter 7 of the
RIA. This analysis is being provided for informational purposes only.

A. Introduction

    Executive Order 12898 directs EPA to identify the populations of
concern who are most likely to experience unequal burdens from
environmental harms; specifically, minority populations, low-income
populations, and indigenous peoples.\413\ Additionally, Executive

Order 13985 is intended to advance racial equity and support
underserved communities through Federal Government actions.\414\ The
EPA defines environmental justice as the fair treatment and meaningful
involvement of all people regardless of race, color, national origin,
or income, with respect to the development, implementation, and
enforcement of environmental laws, regulations, and policies. The EPA
further defines the term fair treatment to mean that ``no group of
people should bear a disproportionate burden of environmental harms and
risks, including those resulting from the negative environmental
consequences of industrial, governmental, and commercial operations or
programs and policies.'' \415\ In recognizing that minority and low-
income populations often bear an unequal burden of environmental harms
and risks, the EPA continues to consider ways of protecting them from
adverse public health and environmental effects of air pollution.
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    \413\ 59 FR 7629, February 16, 1994.
    \414\ 86 FR 7009, January 20, 2021.
    \415\ https://www.epa.gov/environmentaljustice.
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B. Analytical Considerations

    The EPA's environmental justice (EJ) technical guidance \416\
states that:
---------------------------------------------------------------------------

    \416\ U.S. Environmental Protection Agency (EPA), 2015. Guidance
on Considering Environmental Justice During the Development of
Regulatory Actions.

    The analysis of potential EJ concerns for regulatory actions
should address three questions:
    1. Are there potential EJ concerns associated with environmental
stressors affected by the regulatory action for population groups of
concern in the baseline?
    2. Are there potential EJ concerns associated with environmental
stressors affected by the regulatory action for population groups of
concern for the regulatory option(s) under consideration?
    3. For the regulatory option(s) under consideration, are
potential EJ concerns created or mitigated compared to the baseline?

    To address these questions in the EPA's first quantitative EJ
analysis in the context of a transport rule, the EPA developed a unique
analytical approach that considers the purpose and specifics of the
final rulemaking, as well as the nature of known and potential
exposures and impacts. However, due to data limitations, it is possible
that our analysis failed to identify disparities that may exist, such
as potential environmental justice characteristics (e.g., residence of
historically red lined areas), environmental impacts (e.g., other ozone
metrics), and more granular spatial resolutions (e.g., neighborhood
scale) that were not evaluated.
    For the final rule, we employ two types of analytics to respond to
the previous three questions: proximity analyses and exposure analyses.
Both types of analyses can inform whether there are potential EJ
concerns for population groups of concern in the baseline (question
1).\417\ In contrast, only the exposure analyses, which are based on
future air quality modeling, can inform whether there will be potential
EJ concerns after implementation of the regulatory options under
consideration (question 2) and whether potential EJ concerns will be
created or mitigated compared to the baseline (question 3). While the
exposure analysis can respond to all three questions, several caveats
should be noted. For example, the air pollutant exposure metrics are
limited to those used in the benefits assessment. For ozone, that is
the maximum daily 8-hour average, averaged across the April through
September warm season (AS-MO3) and for PM2.5 that is the
annual average. This ozone metric likely smooths potential daily ozone
gradients and is not directly relatable to the National Ambient Air
Quality Standard (NAAQS), whereas the PM2.5 metric is more
similar to the long term PM2.5 standard. The air quality
modeling estimates are also based on state level emissions data paired
with facility-level baseline emissions, and provided at a resolution of
12km\2\. Additionally, here we focus on air quality changes due to this
final rulemaking and infer post-policy exposure burden impacts.
---------------------------------------------------------------------------

    \417\ The baseline for proximity analyses is current population
information (e.g., 2021), whereas the baseline for ozone exposure
analyses are the future years in which the regulatory options will
be implemented (e.g., 2023 and 2026).
---------------------------------------------------------------------------

    Exposure analytic results are provided in two formats: aggregated
and distributional. The aggregated results provide an overview of
potential ozone exposure differences across populations at the
national- and state-levels, while the distributional results show
detailed information about ozone concentration changes experienced by
everyone within each population.
    In Chapter 7 of the RIA we utilize the two types of analytics to
address the three EJ questions by quantitatively evaluating: (1) the
proximity of affected facilities to potentially disadvantaged
populations (section 7.3); and (2) the potential for disproportionate
ozone and PM2.5 concentrations in the baseline and
concentration changes after rule implementation across different
demographic groups (section 7.4). Each of these analyses depends on
mutually exclusive assumptions, was performed to answer separate
questions, and is associated with unique limitations and uncertainties.
    Baseline demographic proximity analyses can be relevant for
identifying populations that may be exposed to local pollutants, such
as NO2 emitted from affected sources in this final rule.
However, such analyses are less useful here as they do not account for
the potential impacts of this final rule on long-range concentration
changes. Baseline demographic proximity analysis presented in the RIA
suggest that larger percentages of Hispanics, African Americans, people
below the poverty level, people with less educational attainment, and
people linguistically isolated are living within 5 km and 10 km of an
affected EGU, compared to national averages. It also finds larger
percentages of African Americans, people below the poverty level, and
with less educational attainment living within 5 km and 10 km of an
affected non-EGU facility. Relating these results to question 1 from
section 7.2 of the RIA, we conclude that there may be potential EJ
concerns associated with directly emitted pollutants that are affected
by the regulatory action (e.g., NO2) for certain population
groups of concern in the baseline. However, as proximity to affected
facilities does not capture variation in baseline exposure across
communities, nor does it indicate that any exposures or impacts will
occur, these results do not in themselves demonstrate disproportionate
impacts of affected facilities in the baseline and should not be
interpreted as a direct measure of exposure or impact.
    Whereas proximity analyses are limited to evaluating the
representativeness of populations residing nearby affected facilities,
the ozone and PM2.5 exposure analyses can provide insight
into all three EJ questions. Even though both the proximity and
exposure analyses can potentially improve understanding of baseline EJ
concerns (question 1), the two should not be directly compared. This is
because the demographic proximity analysis does not include air quality
information and is based on current, not future, population
information.
    The baseline analysis of ozone and PM2.5 concentration
burden responds to question 1 from EPA's environmental justice
technical guidance document more directly than the proximity analyses,
as it evaluates a form of the environmental stressor targeted by the
regulatory action. Baseline ozone and PM2.5 analyses show
that certain populations, such as Hispanics, Asians, those
linguistically isolated, those less

educated, and children may experience somewhat higher ozone and
PM2.5 concentrations compared to the national average.
Therefore, also in response to question 1, there likely are potential
environmental justice concerns associated with ozone and
PM2.5 exposures affected by the regulatory action for
population groups of concern in the baseline. However, these baseline
exposure results have not been fully explored and additional analyses
are likely needed to understand potential implications. In addition, we
infer that disparities in the ozone and PM2.5 concentration
burdens are likely to persist after implementation of the regulatory
action or alternatives under consideration due to similar modeled
concentration reductions across population demographics (question 2).
    Question 3 asks whether potential EJ concerns will be created or
mitigated as compared to the baseline. Due to the very small
differences observed in the distributional analyses of post-policy
ozone and PM2.5 exposure impacts across populations, we do
not find evidence that potential EJ concerns related to ozone and
PM2.5 concentrations will be created or mitigated as
compared to the baseline.\418\
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    \418\ Please note, exposure results should not be extrapolated
to other air pollutant. Detailed environmental justice analytical
results can be found in Chapter 7 of the RIA.
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C. Outreach and Engagement

    Prior to proposal, the EPA hosted an outreach webinar with
environmental justice stakeholders to share information about the
proposed rule and solicit feedback about potential environmental
justice considerations. The webinar was attended by representatives of
state governments, federally recognized tribes, environmental NGOs,
higher education institutions, industry, and the EPA.\419\ Participants
were invited to comment on pre-proposal environmental justice
considerations during the webinar or submit written comments to a pre-
proposal non-regulatory docket.
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    \419\ This does not constitute EPA's tribal consultation under
E.O. 13175, which is described in section XI.F of this rule.
---------------------------------------------------------------------------

    After proposal, the EPA opened a public comment period to invite
the public to submit written comments to the regulatory docket for this
rulemaking.\420\ The EPA also invited the public to participate in a
public hearing held on April 21, 2022. A transcript of the public
hearing is available in the docket for this rulemaking. Additionally,
on March 31, 2022, the EPA hosted an informational webinar with non-
governmental groups and environmental justice stakeholders to answer
questions and share information about the proposed rule. A record of
this webinar, including the informational power point shared at the
webinar is available in the docket for this rulemaking.
---------------------------------------------------------------------------

    \420\ Comments and responses regarding environmental justice
considerations are available in Section 6 of the RTC document for
this rulemaking.
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VIII. Costs, Benefits, and Other Impacts of the Final Rule

    In the RIA for the Federal Good Neighbor Plan Addressing Regional
Ozone Transport for the 2015 Ozone National Ambient Air Quality
Standards, the EPA estimated the health and climate benefits,
compliance costs, and emissions changes that may result from the final
rule for the analysis period 2023 to 2042. The estimated health and
climate benefits and compliance costs are presented in detail in this
RIA. The EPA notes that for EGUs the estimated benefits and compliance
costs are directly associated with fully operating existing SCRs during
ozone season; fully operating existing SNCRs during ozone season;
installing state-of-the-art combustion controls; imposing a backstop
emissions rate on certain units that lack SCR controls; and installing
SCR and SNCR post-combustion controls. The EPA also notes that for non-
EGUs the estimated health benefits and compliance costs are directly
associated with installing controls to meet the NOX
emissions requirements presented in section I.B of this document.
    For EGUs, the EPA analyzed this action's emissions budgets using
uniform control stringency represented by $1,800 per ton of
NOX (2016$) in 2023 and $11,000 per ton of NOX
(2016$) in 2026. The EPA also analyzed a more and a less stringent
alternative. The more and less stringent alternatives differ from the
rule in that they set different NOX ozone season emissions
budgets for the affected EGUs and different dates for large, coal-fired
EGUs' compliance with the backstop emissions rate.
    For non-EGUs, the EPA developed an analytical framework to
determine which industries and emissions unit types to include in a
proposed Transport FIP for the 2015 ozone NAAQS transport obligations.
A February 28, 2022 memorandum, titled ``Screening Assessment of
Potential Emissions Reductions, Air Quality Impacts, and Costs from
Non-EGU Emissions Units for 2026,'' documents the analytical framework
used to identify industries and emissions unit types included in the
proposed FIP. To further evaluate the industries and emissions unit
types identified and to establish the proposed emissions limits, the
EPA reviewed Reasonably RACT rules, NSPS rules, NESHAP rules, existing
technical studies, rules in approved SIP submittals, consent decrees,
and permit limits. That evaluation is detailed in the Proposed Non-EGU
Sectors TSD prepared for the proposed FIP. The EPA is retaining the
industries and many of the emissions unit types included in the
proposal in this final action. For the non-EGU industries, in the final
rule we made some minor changes to the non-EGU emissions units covered,
the applicability criteria, as well as provided for facility-wide
emissions averaging for engines and for a low-use exemption to
eliminate the need to install controls on low-use boilers.
    Table VIII-1 provides the projected 2023 through 2027, 2030, 2035,
and 2042 EGU NOX, SO2, PM2.5, and CO2
emissions reductions for the evaluated regulatory control alternatives.
For additional information on emissions changes, see Table 4-6 and
Table 4-7 in Chapter 4 of the RIA.

Table VIII-1--EGU Ozone Season NOX Emissions Changes and Annual Emissions Reductions (Tons) for NOX, SO2, PM2.5,
                         and CO2 for the Regulatory Control Alternatives From 2023-2042
----------------------------------------------------------------------------------------------------------------
                                                                               Less stringent    More stringent
                                                                Final rule       alternative       alternative
----------------------------------------------------------------------------------------------------------------
2023:
    NOX (ozone season).....................................           10,000            10,000            10,000
    NOX (annual)...........................................           15,000            15,000            15,000
    SO2 (annual)...........................................            1,000             3,000             1,000
    CO2 (annual, thousand metric tons).....................  ...............  ................  ................

    PM2.5 (annual).........................................  ...............  ................  ................
2024:
    NOX (ozone season).....................................           21,000            10,000            33,000
    NOX (annual)...........................................           25,000            15,000            57,000
    SO2 (annual)...........................................           19,000             5,000            59,000
    CO2 (annual, thousand metric tons).....................           10,000             4,000            20,000
    PM2.5 (annual).........................................            1,000  ................             1,000
2025:
    NOX (ozone season).....................................           32,000            10,000            56,000
    NOX (annual)...........................................           35,000            15,000            99,000
    SO2 (annual)...........................................           38,000             7,000           118,000
    CO2 (annual, thousand metric tons).....................           21,000             8,000            40,000
    PM2.5 (annual).........................................            2,000             1,000             2,000
2026:
    NOX (ozone season).....................................           25,000             8,000            49,000
    NOX (annual)...........................................           29,000            12,000            88,000
    SO2 (annual)...........................................           29,000             5,000           104,000
    CO2 (annual, thousand metric tons).....................           16,000             6,000            34,000
    PM2.5 (annual).........................................            1,000  ................             2,000
2027:
    NOX (ozone season).....................................           19,000             6,000            43,000
    NOX (annual)...........................................           22,000             9,000            78,000
    SO2 (annual)...........................................           21,000             4,000            91,000
    CO2 (annual, thousand metric tons).....................           10,000             3,000            28,000
    PM2.5 (annual).........................................            1,000  ................             2,000
2030:
    NOX (ozone season).....................................           34,000            33,000            31,000
    NOX (annual)...........................................           62,000            59,000            50,000
    SO2 (annual)...........................................           93,000            98,000            51,000
    CO2 (annual, thousand metric tons).....................           26,000            23,000             8,000
    PM2.5 (annual).........................................            1,000             1,000  ................
2035:
    NOX (ozone season).....................................           29,000            30,000            27,000
    NOX (annual)...........................................           46,000            46,000            41,000
    SO2 (annual)...........................................           21,000            19,000            15,000
    CO2 (annual, thousand metric tons).....................           16,000            15,000             8,000
    PM2.5 (annual).........................................            1,000             1,000  ................
2042:
    NOX (ozone season).....................................           22,000            22,000            22,000
    NOX (annual)...........................................           23,000            22,000            21,000
    SO2 (annual)...........................................           15,000            15,000             7,000
    CO2 (annual, thousand metric tons).....................            9,000             8,000             4,000
    PM2.5 (annual).........................................
----------------------------------------------------------------------------------------------------------------
Emissions changes for NOX, SO2, and PM2.5 are in tons.

    Table VIII-2 provides a summary of the ozone season NOX
emissions for non-EGUs for the 20 states subject to the non-EGU
emissions requirements starting in 2026, along with the estimated ozone
season NOX reductions for 2026 for the rule and the less and
more stringent alternatives. The analysis in the RIA assumes that the
estimated reductions in 2026 will be the same in later years.

Table VIII-2--Ozone Season NOX Emissions and Emissions Reductions (Tons) for Non-EGUs for the Final Rule and the
                                      Less and More Stringent Alternatives
----------------------------------------------------------------------------------------------------------------
                                                              Final rule--    Less stringent--  More stringent--
                                             2019 Ozone     ozone season NOX  ozone season NOX  ozone season NOX
                  State                   season emissions     reductions        reductions        reductions
                                                 \a\
----------------------------------------------------------------------------------------------------------------
AR......................................             8,790             1,546               457             1,690
CA......................................            16,562             1,600             1,432             4,346
IL......................................            15,821             2,311               751             2,991