starting with the 2024 control period and therefore will not weaken
sources' incentives to control emissions on a permanent basis.
    The rule's provisions relating to the creation of an incremental
Group 3 allowance bank are being finalized as proposed. Comments on the
creation of the incremental allowance bank are discussed in section 5
of the RTC.
c. Recall of Group 2 Allowances Allocated for Control Periods After
2022
    To maintain the previously established levels of stringency of the
Group 2 trading program for the states and sources that remain subject
to that program, the EPA is recalling CSAPR NOX Ozone Season
Group 2 allowances equivalent in amount and usability to all vintage
year 2023-2024 CSAPR NOX Ozone Season Group 2 allowances
previously allocated to sources in states and areas of Indian country
transitioning to the Group 3 trading program and recorded in the
sources' compliance accounts. The recall provisions apply to all
sources in jurisdictions newly added to the Group 3 trading program in
whose compliance accounts CSAPR NOX Ozone Season Group 2
allowances for a control period in 2023 or 2024 were recorded,
including sources where some or all units have permanently retired or
where the previously recorded 2023-2024 allowances have been
transferred out of the compliance account. The recall provisions
provide a flexible compliance schedule intended to accommodate any
sources that have already transferred the previously recorded 2023-2024
allowances out of their compliance accounts and allow Group 2
allowances of earlier vintages to be surrendered to achieve compliance.
Like the similar recall provisions finalized in the Revised CSAPR
Update, the recall provisions include specifications for how the recall
provisions apply in instances where a source and its allowances have
been transferred to different parties and for the procedures that the
EPA will follow to implement the recall.
    Under the Group 2 trading program regulations, each Group 2
allowance is a ``limited authorization to emit one ton of
NOX during the control period in one year,'' where the
relevant limitations include the EPA Administrator's

authority ``to terminate or limit the use and duration of such
authorization to the extent the Administrator determines is necessary
or appropriate to implement any provision of the Clean Air Act.'' 40
CFR 97.806(c)(6)(ii). The Administrator is determining that, to
effectively implement the Group 2 trading program as a compliance
mechanism through which states not subject to the Group 3 trading
program may continue to meet their obligations under CAA section
110(a)(2)(D)(i)(I) with regard to the 2008 ozone NAAQS, it is necessary
to limit the use of Group 2 allowances equivalent in quantity and
usability to all Group 2 allowances previously allocated for the 2023-
2024 control periods and recorded in the compliance accounts of sources
in the newly added Group 3 jurisdictions. The Group 2 allowances that
have already been allocated to sources in the newly added Group 3
states for the 2023-2024 control periods and recorded in the sources'
compliance accounts represent the substantial majority of the total
remaining quantity of Group 2 allowances that have been allocated and
recorded for the 2023-2024 control periods and that were not already
made subject to recall when other jurisdictions were transferred from
the Group 2 trading program to the Group 3 trading program in the
Revised CSAPR Update. Because allowances can be freely traded, if the
use of the 2023-2024 Group 2 allowances previously recorded in newly
added Group 3 sources' compliance accounts (or equivalent Group 2
allowances) were not limited, the effect would be the same as if the
EPA had issued to sources in the states that will remain covered by the
Group 2 trading program a quantity of allowances available for
compliance under the 2023-2024 control periods many times the levels
that the EPA determined to be appropriate emissions budgets for these
states in the CSAPR Update. Through the use of banked allowances, the
excess Group 2 allowances would affect compliance under the Group 2
trading program in control periods after 2024 as well. Continued
implementation of the Group 2 trading program at levels of stringency
consistent with the levels contemplated under the CSAPR Update
therefore requires that the EPA limit the use of the excess allowances,
as the EPA is doing through the recall provisions.
    In this rule, the EPA is implementing limitations on the use of the
excess 2023-2024 Group 2 allowances through requirements to surrender,
for each 2023-2024 Group 2 allowance recorded in a newly added Group 3
source's compliance account, one Group 2 allowance of equivalent
usability under the Group 2 trading program. The surrender requirements
apply to the owners and operators of the Group 3 sources in whose
compliance account the excess 2023-2024 Group 2 allowances were
initially recorded. In general, each source's current owners and
operators are required to comply with the surrender requirements for
the source by ensuring that sufficient allowances to complete the
deductions are available in the source's compliance account by one of
two possible deadlines discussed later in this section. However, an
exception is provided if a source's current owners and operators
obtained ownership and operational control of the source in a
transaction that did not include rights to direct the use and transfer
of some or all of the 2023-2024 Group 2 allowances allocated and
recorded (either before or after that transaction) in the source's
compliance account. The rule provides that in such a circumstance, with
respect to the 2023-2024 Group 2 allowances for which rights were not
included in the transaction, the surrender requirements apply to the
most recent former owners and operators of the source before any such
transactions occurred. Because in this situation a source's former
owners and operators might lack the ability to access the source's
compliance account for purposes of complying with the surrender
requirements, the former owners and operators would instead be allowed
to meet the surrender requirements with Group 2 allowances held in a
general account.\372\
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    \372\ The EPA is currently unaware of any source that would need
to use this flexibility but has included the option in the rule to
address the theoretical possibility of such a situation.
---------------------------------------------------------------------------

    To provide as much flexibility as possible consistent with the need
to limit the use of the excess Group 2 allowances, for each 2023-2024
Group 2 allowance recorded in a Group 3 source's compliance account,
the EPA will accept the surrender of either the same specific 2023-2024
Group 2 allowance or any other Group 2 allowance with equivalent (or
greater) usability under the Group 2 trading program. Thus, a surrender
requirement with regard to a Group 2 allowance allocated for the 2023
control period could be met through the surrender of any Group 2
allowance allocated for the 2023 control period or the control period
in any earlier year--in other words, any 2017-2023 Group 2
allowance.\373\ Similarly, the surrender requirement with regard to a
2024 Group 2 allowance could be met through the surrender of any 2017-
2024 Group 2 allowance.
---------------------------------------------------------------------------

    \373\ The first control period for the Group 2 trading program
was in 2017.
---------------------------------------------------------------------------

    Owners and operators subject to the surrender requirements can
choose from two possible deadlines for meeting the requirements. The
optional first deadline will be 15 days after the effective date of
this rule.\374\ As soon as practicable or after this date, the EPA will
make a first attempt to complete the deductions of Group 2 allowances
required for each Group 3 source from the source's compliance account.
The EPA will deduct Group 2 allowances first to address any surrender
requirements for the 2023 control period and then to address any
surrender requirements for the 2024 control period. When deducting
Group 2 allowances to address the surrender requirements for each
control period, EPA will first deduct allowances allocated for that
control period and then will deduct allowances allocated for each
successively earlier control period. This order of deductions is
intended to ensure that whatever Group 2 allowances are available in
the account are applied to the surrender requirements in a manner that
both maximizes the extent to which all of the source's surrender
requirements will be met and also ensures that any Group 2 allowances
left in the source's compliance account after completion of all
required deductions will be the earliest allocated, and therefore most
useful, Group 2 allowances possible. Among the Group 2 allowances
allocated for a given control period, The EPA will first deduct
allowances that were initially recorded in that account, in the order
of recordation, and will then deduct allowances that were transferred
into that account after having been initially recorded in some other
account, in the order of recordation.
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    \374\ As discussed later in this section and in section
VI.B.9.b, the EPA has conditioned recordation of any allocations of
Group 3 allowances in a source's compliance account on the source's
prior compliance with the recall requirements for Group 2
allowances. The purpose of providing an optional first deadline for
the recall provisions 15 days after a final rule's effective is to
ensure that sources have an early opportunity to comply with the
recall provisions to be eligible to have allocations of Group 3
allowances recorded in their accounts 30 days after the final rule's
effective date. Because the vast majority of sources subject to the
recall provisions already hold sufficient Group 2 allowances to
comply with the recall provisions, the EPA anticipates that the
sources will easily be able to comply with the optional first recall
deadline.
---------------------------------------------------------------------------

    Following the first attempt to deduct Group 2 allowances to address
Group 3 sources' surrender requirements, the

EPA will send a notification to the designated representative for each
such source (as well as any alternate designated representative)
indicating whether all required deductions were completed and, if not,
the additional amounts of Group 2 allowances usable in the 2023 or 2024
control periods that must be held in the appropriate account by the
second surrender deadline of September 15, 2023. Each notification will
be sent to the email addresses most recently provided to the EPA for
the recipients and will include information on how to contact the EPA
with any questions. The EPA has provided that no allocations of Group 3
allowances will be recorded in a source's compliance account until all
the source's surrender requirements with regard to 2023-2024 Group 2
allowances have been met. For this reason, the principal consequence to
a source of failure to fully comply with the surrender requirements by
15 days after the effective date of this rule will be that any Group 3
allowances allocated to the units at the source for the 2023 and 2024
control periods that would otherwise have been recorded in the source's
compliance account by 30 days after the effective date of a final rule
will not be recorded as of that recordation date.
    If all surrender requirements of 2023-2024 Group 2 allowances for a
source have not been met in EPA's first attempt, the EPA will make a
second attempt to complete the required deductions from the source's
compliance account (or from a specified general account, in the limited
circumstance noted previously) as soon as practicable on or after
September 15, 2023. The order in which Group 2 allowances are deducted
will be the same as described previously for the first attempt.
    If the second attempt to deduct Group 2 allowances to meet the
surrender requirements through deductions from the source's compliance
account (or from a specified general account) is unsuccessful for a
given source, as soon as practicable on or after November 15, 2023, to
the extent necessary to address the unsatisfied surrender requirements
for the source, the EPA will deduct the 2023-2024 Group 2 allowances
that were initially recorded in the source's compliance account from
whatever accounts the allowances are held in as of the date of the
deduction, except for any allowances where, as of April 30, 2022, no
person with an ownership interest in the allowances was an owner or
operator of the source, was a direct or indirect parent or subsidiary
of an owner or operator of the source, or was directly or indirectly
under common ownership with an owner or operator of the source.\375\
Before making any deduction under this provision, the EPA will send a
notification to the authorized account representative for the account
in which the allowance is held and will provide an opportunity for
submission of objections concerning the data upon which the EPA is
relying. In EPA's view, this provision does not unduly interfere with
the legitimate expectations of participants in the allowance markets
because the provision will not be invoked in the case of any allowance
that was transferred to an independent party in an arms-length
transaction before EPA's intent to recall 2023-2024 Group 2 allowances
became widely known. The provision would apply only to a Group 2
allowance that, as of April 30, 2022, was still controlled either by
the owners and operators of the source in whose compliance account it
was initially recorded or by an entity affiliated with such an owner or
operator. The EPA believes that by April 30, 2022, all market
participants had ample opportunity to become informed of the proposed
rule provisions to recall 2023-2024 Group 2 allowances recorded in
Group 3 sources' compliance accounts, particularly since the EPA
implemented a closely analogous recall of Group 2 allowances in the
Revised CSAPR Update.\376\
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    \375\ The provision under which the EPA will not deduct Group 2
allowances transferred to unrelated parties before April 30, 2022
from the transferees' accounts does not relieve the source to which
the Group 2 allowances were originally allocated from the obligation
to comply with the recall requirements. Specifically, the source
would be required to comply with the recall requirements by
obtaining and surrendering other Group 2 allowances.
    \376\ Even before publication of the proposed rule, the EPA
posted information on its websites to notify market participants
that a pending rulemaking could have consequences for the value and
usability of Group 2 allowances. The posted locations included the
electronic portal that authorized account representatives use to
enter allowance transfers for recordation by the EPA in the
Allowance Management System. Additionally, the EPA emailed a notice
identifying the possibility of such consequences to the
representatives for all Allowance Management System accounts.
---------------------------------------------------------------------------

    The final revised regulations provide that failure of a source's
owners and operators to comply with the surrender requirements will be
subject to possible enforcement as a violation of the CAA, with each
allowance and each day of the control period constituting a separate
violation.
    To eliminate any possible uncertainty regarding the amounts of
Group 2 allowances allocated for the 2023-2024 control periods (or
earlier control periods) that the owners and operators of each Group 3
source are required to surrender under the recall provisions, the EPA
has prepared a list of the sources in the additional Group 3 states and
areas of Indian country in whose compliance accounts allocations of
2023-2024 Group 2 allowances were recorded, with the amounts of the
allocations recorded in each such compliance account for the 2023 and
2024 control periods. An additional list shows, for each newly added
Group 3 source, the specific Group 2 allowances (batched by serial
number) allocated for each control period and recorded in the source's
compliance account and indicates whether, as of April 30, 2022, that
batch of allowances was held in the source's compliance account, in an
account believed to be partially or fully controlled by a related party
(i.e., an owner or operator of the source or an affiliate of an owner
or operator of the source), or in an account believed to be fully
controlled by independent parties. The lists are in a spreadsheet
titled, ``Recall of Additional CSAPR NOX Ozone Season Group
2 Allowances,'' available in the docket for this rule. After the first
and second surrender deadlines, the EPA intends to update the lists to
indicate for each Group 3 source whether the surrender requirements for
the source under the recall provisions have been fully satisfied. The
EPA will post the updated lists on a publicly accessible website to
ensure that all market participants have the ability to determine which
specific 2023-2024 Group 2 allowances initially recorded in any given
Group 3 source's compliance account do or do not remain subject to
potential deduction to address the source's surrender requirements
under the recall provisions.
    The recall provisions have been finalized without change from the
proposal. The EPA received no comments on the proposed provisions.
13. Conforming Revisions to Regulations for Other CSAPR Trading
Programs
    As noted in section VI.B.1.a of this document, in addition to the
Group 3 trading program, EPA currently administers five other CSAPR
trading programs, all of which have provisions that in most respects
parallel the provisions of the Group 3 trading program.\377\ In this
rulemaking, in addition to the revisions to the Group 3 trading
program, the EPA is finalizing a set of conforming revisions that
concern how various areas of Indian country are

treated for purposes of the allowance allocation provisions of the
regulations for all the CSAPR trading programs.\378\
---------------------------------------------------------------------------

    \377\ The regulations for the Group 3 Trading Program are at 40
CFR part 97, subpart GGGGG. The regulations for the other five CSAPR
trading programs are at 40 CFR part 97, subparts AAAAA, BBBBB,
CCCCC, DDDDD, and EEEEE.
    \378\ Additional conforming revisions concerning the schedules
for the EPA to record allowance allocations in source's compliance
accounts and for states to submit state-determined allowance
allocations to the EPA for subsequent recordation were finalized in
an earlier final rule in this docket. See 87 FR 52473 (August 26,
2022).
---------------------------------------------------------------------------

    As discussed in section VI.B.9.a of this document, to reflect the
D.C. Circuit's holding in ODEQ v. EPA that states have initial CAA
implementation planning authority in non-reservation areas of Indian
country until displaced by a demonstration of tribal jurisdiction over
such an area, the EPA is revising the allowance allocation provisions
in the Group 3 trading program regulations so that, instead of
distinguishing between the sets of units within a given state's borders
that either are not or are in Indian country, the revised regulations
distinguish between (1) the set of units within the state's borders
that are not in Indian country or are in areas of Indian country
covered by the state's CAA implementation planning authority and (2)
the set of units within the state's borders that are in areas of Indian
country not covered by the state's CAA implementation planning
authority. For the same reasons stated in section VI.B.9.a of this
document for the Group 3 trading program, the EPA is revising the
allowance allocation provisions in the regulations for all the other
CSAPR trading programs establishing the same substantive distinction
among the sets of units within each state's borders. The specific
regulatory provisions that are affected are identified in section IX.D
of this document. The EPA is unaware of any currently operating units
that would be affected by this revision to the regulations for the
other CSAPR trading programs.
    The conforming revisions to the regulations for the other CSAPR
trading programs concerning Indian country are being finalized as
proposed with no changes. The EPA received no comments on this portion
of the proposal.

C. Regulatory Requirements for Stationary Industrial Sources

    The EPA is finalizing FIPs with requirements for certain non-EGU
industry sources for 20 of the states covered in this final rule. See
section II.B of this document for the list of states. The FIPs include
new emissions limitations for units in nine non-EGU industries that the
EPA finds (as discussed in sections IV and V of this final rule) are
significantly contributing to nonattainment or interfering with
maintenance in other states. The emissions control requirements of
these FIPs for non-EGU sources apply only during the ozone season (May
through September) each year, beginning in 2026.
    To achieve the necessary non-EGU emissions reductions for these 20
states, the EPA is finalizing the proposed emissions limitations with
some adjustments as a result of information received during the public
comment period. The final emissions limits apply to the most impactful
types of units in the relevant industries and are achievable with the
control technologies identified in this preamble and further discussed
in the Final Non-EGU Sectors TSD. The non-EGU regulatory requirements
unique to each industry that EPA is finalizing after considering public
comments are discussed in sections VI.C.1 through VI.C.6 of this
document.
    These final FIP requirements apply to both new and existing
emissions units. The non-EGU emissions limits and compliance
requirements will apply in all 20 states (and, as discussed in section
III.C.2 of this document, in areas of Indian country within the borders
of those states), even if some of those states do not currently have
emissions units in a particular source category. This approach is
consistent with the approach that the EPA proposed, and the EPA did not
receive any comments specifically objecting to our proposal to regulate
new units. This approach will ensure that all new sources constructed
in any of the 20 states will be subject to the same good neighbor
requirements that apply to existing units under this final rule. This
will also avoid creating incentives to move production from an existing
non-EGU source to a new non-EGU source of the same type but lacking the
relevant emissions control requirements either within a linked state or
in another linked state.
    Comment: The EPA received several comments regarding the proposed
approach of establishing unit-specific emissions limitations for non-
EGUs instead of an emissions trading program. Some commenters suggested
that a trading program for non-EGUs could provide for operational
flexibility and that EPA should allow sources to work with regulatory
authorities to develop a trading program. Other commenters generally
supported EPA's proposed approach and the decision to not include non-
EGUs in an emissions trading program, because the EPA would not need to
require sources to unnecessarily install CEMS. Commenters from several
states and industry groups generally supported other monitoring options
over CEMS, such as parametric monitoring, performance testing, and
predictive emissions monitoring systems (PEMS). Additional commenters
voiced concern with the expense and burden of continuous parametric
monitoring and semi-annual performance tests. Specifically, commenters
explained that semi-annual testing should not be required when the
emissions limits only apply during the ozone season. Commenters also
noted that many non-EGU boilers have recently been relieved from
meeting the CEMS requirements under the 1998 NOX SIP Call
and that implementing CEMS on many of the non-EGU sources would be
difficult and unnecessary.
    Response: The EPA is finalizing a unit-specific approach with rate-
based emissions limitations set on a uniform basis for the different
segments of non-EGU emissions units using applicability criteria based
on size and type of unit and, in some cases, emissions thresholds. In
response to public comments, the EPA has adjusted these requirements as
necessary to ensure that the emissions control requirements are
achievable while ensuring that the FIPs achieve the necessary emissions
reductions from the covered units to eliminate significant contribution
to nonattainment and interference with maintenance as discussed in
section V of this document. The EPA has concluded that a unit-specific
approach is more appropriate for non-EGUs at this time than
implementing a trading program and requiring all units to implement
rigorous part 75 monitoring and reporting requirements. As explained in
the proposal, to be considered for a trading program, non-EGU sources
would have to comply with requirements for monitoring and reporting of
hourly mass emissions in accordance with 40 CFR part 75 as we have
required for all previous trading programs. Monitoring and reporting
under part 75 include CEMS (or an approved alternative method),
rigorous initial certification testing, and periodic quality assurance
testing thereafter, such as relative accuracy test audits and daily
calibrations. Consistent and accurate measurement of emissions is
necessary to ensure that each allowance actually represents one ton of
emissions and that one ton of reported emissions from one source would
be equivalent to one ton of reported emissions from another source. See
75 FR 45325 (August 2, 2010). Moreover, these monitoring requirements
generally would need to be in place for at least

one full ozone season to establish baseline data before it would be
appropriate to rely on a trading program as the mechanism to achieve
the required emissions reductions. Many industry and state commenters
provided information confirming that many non-EGU units subject to this
rulemaking do not currently utilize CEMS and specifically requested
that EPA avoid requiring CEMS for all non-EGU industries. The EPA
generally agrees that CEMS is not necessary for all non-EGU industries
under the approach of this final rule and is finalizing other
continuous monitoring, recordkeeping, and reporting requirements, as
appropriate, that are specific to each non-EGU industry. The EPA has
determined that establishing unit-specific emissions limitations for
non-EGUs is a preferable approach in part because it avoids the
rigorous monitoring requirements that would be applied to non-EGUs for
the first time under a trading program.
    Furthermore, to address commenters' concerns regarding non-EGU
requirements for performance testing on a semi-annual basis, the EPA
has also reduced the frequency of all required performance testing for
non-EGU sources to once per calendar year. As commenters correctly
pointed out, the emissions limits in these final FIPs only apply during
the ozone season and testing once per calendar year should be
sufficient to confirm the accuracy of the parameters being monitored to
demonstrate continuous compliance during the ozone season. The EPA also
agrees with commenters that the annual testing requirements need not
occur during the ozone season.
    In addition, the EPA is modifying the applicability criteria and
other regulatory requirements in response to public comments to provide
certain compliance flexibilities for non-EGU industries where
appropriate. As discussed further in section V.C.1 of this document,
the EPA is modifying the requirements for Pipeline Transportation of
Natural Gas by finalizing an exemption for emergency engines and
allowing any owner or operator of an affected unit to propose a
``Facility-Wide Averaging Plan'' that would, if approved by EPA,
provide an alternative means for compliance with the emissions limits
in this final rule. Further, as discussed in section VI.C.5 of this
document, the EPA is finalizing a low-use exemption for non-EGU boilers
that operates 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. These final rule provisions require
controls on the most impactful non-EGU industrial sources while
providing the flexibility needed to accommodate unique circumstances on
a case-by-case basis.
    Comment: Commenters from several non-EGU industries and states
raised general concerns regarding the ability for all sources to comply
with the proposed emissions limits. Some commenters suggested that the
EPA allow for case-by-case limits where necessary, similar to case-by-
case RACT determinations. Specifically, commenters operating boilers,
furnaces, and MWCs provided general explanations of how some units
might not be able to meet the proposed emissions limits and requested
that EPA provide for compliance flexibility where a source can
demonstrate technical and economical infeasibility.
    Response: As explained more in sections VI.C.1 through VI.C.6, the
EPA has made several adjustments to the proposed applicability
criteria, emissions limits, and compliance requirements in response to
public comments and to reduce the costs of compliance with the final
rule. For Pipeline Transportation and Natural Gas, the EPA is
finalizing emissions averaging provisions and exemptions for emergency
engines to allow facilities to avoid installing controls on units with
lower actual emissions where the installation of controls would be less
cost effective compared to higher-emitting units. For Cement and
Concrete Product Manufacturing, the EPA has removed the daily source
cap that would have resulted in an artificially restrictive
NOX emissions limit for affected cement kilns that have
operated at lower levels due to the COVID-19 pandemic. For Iron and
Steel and Ferroalloy Manufacturing, the EPA is finalizing a ``test-and-
set'' requirement for reheat furnaces that will require the
installation of low-NOX burners or equivalent technology.
The EPA has addressed the economic concerns raised by commenters
regarding installation of controls at Iron and Steel facilities by not
finalizing the other ten proposed emissions limits that were intended
to require the installation of SCR at these facilities. For Glass and
Glass Product Manufacturing, the EPA is finalizing alternative
standards that apply during startup, shutdown, and idling conditions.
For boilers in Basic Chemical Manufacturing, Petroleum and Coal
Products Manufacturing, Pulp, Paper, and Paperboard Mills, Metal Ore
Mining, and the Iron and Steel Industry, the EPA is finalizing a low-
use exemption to eliminate the need to install controls on boilers that
would have resulted in relatively small reductions in emissions.
Finally, the EPA has modified the monitoring and recordkeeping
requirements for all non-EGU industries where possible to reduce the
testing frequency to once a year and to provide for alternative
monitoring protocols where appropriate, which should further reduce the
costs of compliance on non-EGU sources. With these modifications to the
final rule in response to comments, the non-EGU sources subject to this
rule should be able to meet the applicable control requirements
established in this final rule.
    The EPA also recognizes, however, that there may be unique
circumstances the Agency cannot anticipate that would, for a particular
source, render the final emissions control requirements technically
impossible or impossible without extreme economic hardship. To address
these limited circumstances, the EPA is finalizing a provision that
allows a source to request EPA approval of a case-by-case emissions
limit based on a showing that an emissions unit cannot meet the
applicable standard due to technical impossibility or extreme economic
hardship. The EPA has modeled the case-by-case emissions limit
mechanism on case-by-case RACT requirements and certain facility-
specific emissions limits under 40 CFR part 60 identified by
commenters.\379\ The owner or operator of a source seeking a case-by-
case emissions limit must submit a request meeting specific
requirements to the EPA by August 5, 2024, one year after the effective
date of this final rule. The applicable emissions limits established in
this final rule remain in effect until the EPA approves a source's
request for a case-by-case emissions limit. Given the May 1, 2026
compliance date that generally applies to all affected units in the
non-EGU industries covered by this final rule, we encourage owners and
operators of affected units who believe they must seek case-by-case
emissions limits to submit their requests to the EPA before the one-
year deadline for such requests, if possible, to ensure adequate time
for EPA review and to install the necessary controls.
---------------------------------------------------------------------------

    \379\ For examples of case-by-case RACT provisions and source
specific limits for boilers in subpart Db of the EPA's NSPS, see 40
CFR 60.44b(f); Regulations of Connecticut State Agencies section
22a-174-22e; Code of Maryland Regulations section <IP_ADDRESS>(B)(3);
and Code of Maine Rules section 096-138-3, subsection (I).
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    For a source requesting a case-by-case limit due to technical
impossibility, the final rule requires that the request include
emissions data obtained through CEMS or stack tests, an analysis

of all available control technologies based on an engineering
assessment by a professional engineer or data from a representative
sample of similar sources, and a recommendation concerning the most
stringent emissions limit the source can technically achieve.
    For a source requesting a case-by-case limit on the basis of
extreme economic hardship, the final rule requires that the request
include at least three vendor estimates from three separate vendors
that do not have a corporate or business-affiliation with the source of
the costs of installing the control technology necessary to meet the
applicable emissions limit and other information that demonstrates, to
the satisfaction of the Administrator, that the cost of compliance with
the applicable emissions limit for that particular source would present
an extreme economic hardship relative to the costs borne by other
comparable sources in the industry under this rule. In evaluating a
source's request for a case-by-case limit due to extreme economic
hardship, the EPA will consider the emissions reductions and costs
identified in this final rulemaking (and related support documents) for
other sources in the relevant industry and whether the costs of
compliance for the source seeking the case-by-case limit would
significantly exceed the highest representative end of the range of
estimated cost-per-ton figures identified for any source in the
relevant industry as discussed in section V of this document.
    As discussed in section VI.A of this document, in Wisconsin the
court held that some deviation from the CAA's mandate to eliminate
prohibited transport by downwind attainment deadlines may be allowed
only ``under particular circumstances and upon a sufficient showing of
necessity,'' e.g., when compliance with the statutory mandate amounts
to an impossibility.\380\ Given these directives, the EPA cannot allow
a covered source to avoid complying with the emissions limits
established in this final rule unless the source can demonstrate that
compliance with the limit would either be impossible as a technical
matter or result in an extreme economic hardship--i.e., exceed the high
end of the cost-effectiveness estimates that informed the EPA's Step 3
determination of significant contribution, as discussed in section V of
this document. The criteria that must be met to qualify for a case-by-
case limit are designed to meet this statutory mandate.
---------------------------------------------------------------------------

    \380\ Wisconsin, 938 F.3d at 316 and 319-320 (noting that any
such deviation must be ``rooted in Title I's framework'' and
``provide a sufficient level of protection to downwind States'').
---------------------------------------------------------------------------

    Comment: Several commenters raised concerns about the EPA's
differing applicability criteria for the various non-EGU industries.
Specifically, the commenters questioned why EPA set applicability
criteria for engines in Pipeline Transportation of Natural Gas and non-
EGU boilers based on design capacity instead of potential to emit
(PTE). Commenters also requested that the EPA allow each non-EGU
category to rely on operating permits or other federally enforceable
instruments to avoid being subject to the rule, such as limits to the
PTE or limits on fuels used.
    Response: The 100 tpy PTE threshold and comparable design capacity
thresholds of 1,000 horsepower (hp) for engines and 100 mmBtu/hr for
boilers are appropriate to ensure that the final rule reduces emissions
from the most impactful units. The EPA finds the control technologies
assumed to be installed to meet the final emissions limits would not be
as readily available or cost effective for emissions units with PTE or
design capacities lower than the applicability thresholds in this final
rule.
    With regard to the selection of design capacity thresholds for
boilers and engines, the EPA finds that most RACT requirements and
other standards reviewed by the EPA establish applicability criteria
for engines and boilers based on design capacity rather than PTE. We
further explain our basis for establishing applicability thresholds
based on design capacity for these two source categories in sections
VI.C.1. and VI.C.5. For consistency with preexisting requirements for
engines and boilers and to capture the sizes of units identified in
Step 3 of our analysis, the EPA selected design capacities of 1,000 hp
for engines and 100 mmBtu/hr for boilers. The EPA recognizes that these
applicability thresholds captured more units than the EPA intended,
particularly some low-use units. Therefore, as explained in sections
VI.C.1 and VI.C.5., the EPA is establishing exemptions for low-use
boilers and emergency engines, as well as new emissions averaging
provisions for engines, to ensure that this final rule focuses on
larger, more impactful units.
    The EPA also agrees with commenters that the applicability criteria
should allow for sources to rely on enforceable requirements that limit
a source's PTE and is finalizing a regulatory definition of PTE that is
generally consistent with the definitions of that term in the EPA's
title V and NSR permit programs. See, e.g., 40 CFR 51.165(a)(1)(iii),
70.2. In constructing the list of potential sources subject to the
final rule, the EPA relied on available information to identify the PTE
of the emissions units in the various non-EGU industries that are
captured by the applicability criteria. See Memo to Docket titled
Summary of Final Rule Applicability Criteria and Emissions Limits for
Non-EGU Emissions Units, Assumed Control Technologies for Meeting the
Final Emissions Limits, and Estimated Emissions Units, Emissions
Reductions, and Costs. Thus, the EPA's Step 3 analysis takes into
account available information about currently enforceable emissions
limits and physical and operational limitations identified in existing
permits. The EPA finds it necessary to define PTE consistent with its
use in the title V and NSR permit programs to ensure that the
requirements of the final FIPs apply to the most impactful units
identified in Step 3 of our analysis. However, to ensure that these
FIPs achieve the emissions reductions necessary to eliminate
significant contribution or interference with maintenance as described
in this final rule, the applicability criteria for the Cement and
Concrete Manufacturing, Iron and Steel and Ferroalloy Manufacturing,
and Glass and Glass Product Manufacturing industries take into account
only those enforceable PTE limits in effect as of the effective date of
this final rule. Thus, any emissions unit in these three industries
that has a PTE equal to or greater than 100 tons per year and thus
meets the definition of an ``affected unit'' as of August 4, 2023, will
remain subject to the applicable FIPs, without regard to any PTE limit
that the emissions unit may subsequently become subject to. Each
affected unit in these three industries must submit an initial
notification of applicability to the EPA by December 4, 2023, that
identifies its PTE as of the effective date of this final rule.
Additionally, any owner or operator of an existing emissions unit that
is not an affected unit as of August 4, 2023, but subsequently meets
the applicability criteria (e.g., due to a change in fuel use that
increases the unit's PTE) will become an affected unit subject to the
applicable requirements of this final rule at that time.
    Comment: In responding to the EPA's request for comment on whether
some non-EGU units would need to run controls required by the final FIP
year-round, one commenter anticipated that control equipment would be
operated as necessary to achieve applicable emissions limits, but that
operational

flexibility, cost considerations and equipment longevity would warrant
operation of certain control equipment on a schedule such that the
equipment would not be used when unnecessary to meet emissions limits
and/or outside of ozone season (i.e., during winter months). The
commenter further explained that flexibility in the operation of
certain control equipment when unnecessary to meet emissions limits
will allow for routine maintenance and repairs without requiring
variances or similar exemptions from continuous operation requirements.
    Response: Based on the feedback received during the public comment
period, the EPA is finalizing requirements for non-EGU sources that
will apply only during the ozone season, which runs annually from May
to September. As discussed in the proposed rule, this is consistent
with EPA's prior practice in Federal actions to eliminate significant
contribution of ozone in the 1998 NOX SIP Call, CAIR, CSAPR,
CSAPR Update, and the Revised CSAPR Update. In addition, the EPA did
not receive any information during the public comment period suggesting
that sources would have to run the necessary controls year-round due to
the nature of those controls. We note, however, that certain emissions-
control technologies, such as combustion controls that are integrated
into the unit itself, would likely function to reduce NOX
emissions year-round as a practical engineering matter.
    Comment: Regarding electronic reporting through the Compliance and
Emissions Data Reporting Interface (CEDRI), one commenter requested
that CEDRI reporting requirements be consolidated in one location
rather than repeated in each section. Another commenter requested that
EPA include electronic reporting requirements for MWCs and specifically
require that MWCs report CEMS data to CEDRI. Another commenter
requested that EPA allow for extensions of time for electronic reports
due to technical glitches.
    Response: To increase the ease and efficiency of data submittal and
data accessibility, the EPA is finalizing, as proposed, a requirement
that owners and operators of non-EGU sources subject to the final FIPs,
including MWCs, submit electronic copies of required initial
notifications of applicability, performance test reports, performance
evaluation reports, quarterly and semi-annual reports, and excess
emissions reports through EPA's Central Data Exchange (CDX) using the
CEDRI. The final rule requires that performance test results collected
using test methods that are supported by the EPA's Electronic Reporting
Tool (ERT) as listed on the ERT website \381\ at the time of the test
be submitted in the format generated through the use of the ERT or an
electronic file consistent with the XML schema on the ERT website and
that other performance test results be submitted in portable document
format (PDF) using the attachment module of the ERT. Similarly, the EPA
is finalizing a requirement that performance evaluation results of CEMS
measuring relative accuracy test audit (RATA) pollutants that are
supported by the ERT at the time of the test be submitted in the format
generated through the use of the ERT or an electronic file consistent
with the XML schema on the ERT website, and a requirement that other
performance evaluation results be submitted in PDF using the attachment
module of the ERT. The final rule also requires that initial
notifications of applicability, annual compliance reports, and excess
emissions reports be submitted in PDF uploaded in CEDRI.
---------------------------------------------------------------------------

    \381\ The ERT website is located at https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
---------------------------------------------------------------------------

    Furthermore, the EPA is finalizing, as proposed, provisions that
allow owners and operators to seek extensions of time to submit
electronic reports due to circumstances beyond the control of the owner
or operator (e.g., due to a possible outage in CDX or CEDRI or a force
majeure event) in the time just prior to a report's due date, as well
as provisions specifying how to submit such a claim. Public commenters
supported these proposed provisions.
    The EPA agrees with commenters that the CEDRI reporting
requirements could be centralized and has moved the CEDRI reporting
requirements to 40 CFR 52.40.
1. Pipeline Transportation of Natural Gas
Applicability
    The EPA is finalizing regulatory requirements for the Pipeline
Transportation of Natural Gas industry that apply to stationary,
natural gas-fired, spark ignited reciprocating internal combustion
engines (``stationary SI engines'') within these facilities that have a
maximum rated capacity of 1,000 hp or greater. Based on our review of
the potential emissions from stationary SI engines, we find that use of
a maximum rated capacity of 1,000 hp reasonably approximates the 100
tpy PTE threshold used in the Screening Assessment of Potential
Emissions Reductions, Air Quality Impacts, and Costs from Non-EGU
Emissions Units for 2026, as described in section V.B of this document.
    The EPA is also modifying certain provisions in response to public
comments to provide compliance flexibilities for the Pipeline
Transportation of Natural Gas industry sector in order to focus
emissions reduction efforts on the highest emitting units.
Specifically, the EPA is finalizing an exemption for emergency engines,
and establishing provisions that allow any owner or operator of an
affected unit to propose a Facility-Wide Averaging Plan that would, if
approved by EPA, provide an alternative means for compliance with the
emissions limits in this final rule.
    For purposes of this rule, the EPA is clarifying and narrowing the
definition of ``pipeline transportation of natural gas'' to mean the
transport or storage of natural gas prior to delivery to a local
distribution company custody transfer station or to a final end-user
(if there is no local distribution company custody transfer station).
The revised definition of this term in Sec.  52.41(a) is consistent
with the EPA's regulatory definition of ``natural gas transmission and
storage segment'' in 40 CFR 60.5430(a) (subpart OOOOa, Standards of
Performance for Crude Oil and Natural Gas Facilities for Which
Construction, Modification, or Reconstruction Commenced After September
18, 2015).
    The EPA is also adding definitions of the terms ``local
distribution company'' and ``local distribution company custody
transfer station'' that are consistent with the definitions found in 40
CFR 98.400 (subpart NN, Suppliers of Natural Gas and Natural Gas
Liquids) and 40 CFR 60.5430(a) (subpart OOOOa, Standards of Performance
for Crude Oil and Natural Gas Facilities for Which Construction,
Modification, or Reconstruction Commenced After September 18, 2015),
respectively.
    Comment: Several commenters asked EPA to exclude emergency engines
in the final rule and one commenter recommended that the EPA revise the
definition of affected unit to specifically exempt emergency engines.
Commenters stated that doing so would not only be consistent with other
regulations applicable to stationary SI engines, but it would also be
more consistent with EPA's applicability analysis, which assumes
stationary SI engines will operate for 7,000 hours a year, something
emergency engines are prohibited from doing by Federal regulation.
Commenters also stated that emergency generators are currently exempt
from requirements applicable to non-emergency RICE covered by both

the relevant NSPS rule (subpart JJJJ), as well as the relevant NESHAP
rule (subpart ZZZZ), and that although the NSPS and NESHAP standards
EPA has adopted for emergency RICE do not limit the amount of time they
may run for emergency purposes, EPA has recognized in the past that
states may assume a maximum of 500 hours of operation to estimate the
``potential to emit'' in issuing air permits for emergency RICE. One
commenter asserted that emergency engines operating under other
standards currently only operate for emergencies or for a few hours at
a time to periodically conduct regular maintenance, that their
emissions are low, and that their contribution to the ozone transport
issues EPA's proposal seeks to address is negligible. Another commenter
stated that the EPA has traditionally exempted emergency engines in
past standards because the EPA has typically found that the use of add-
on emissions controls cannot be justified due to the cost of the
technology relative to the emissions reduction that would be obtained.
    Response: With respect to stationary SI emergency engines, the EPA
has reviewed the information submitted by the commenters and has
decided to exempt such engines from the requirements of the final rule.
Exemption of emergency engines is generally consistent with the EPA's
treatment of emergency engines in other CAA rulemakings. See, e.g., 40
CFR 63.6585(f). The EPA expects that this change from the proposed rule
addresses the concerns expressed by the commenters about the
requirements for stationary emergency engines.
    The final rule defines emergency engines as engines that are
stationary and operated to provide electrical power or mechanical work
during an emergency situation. These engines are typically used only a
few hours per year, and the costs of emissions control are not
warranted when compared to the emissions reductions that would be
achieved.
    In the final rule, emergency engines are subject to certain
compliance requirements on a continuous basis. Continuous compliance
requirements include operating limitations that apply during non-
emergency use but do not include emissions testing of emergency
engines.
    Comment: Several commenters raised concerns about the EPA's
proposal to establish applicability criteria for engines in Pipeline
Transportation of Natural Gas based on design capacity rather than PTE.
Other commenters asserted that the horsepower rating of an engine does
not necessarily correspond to its annual emissions and that engines
with a rated capacity of more than 1,000 hp in this industry sector may
operate at low load and/or infrequently and be associated with limited
NOX emissions. One commenter stated that most of the subject
facilities in their state that have natural gas fired SI engines with a
nameplate capacity rating of 1,000 hp or greater have annual
NOX emissions less than 100 tpy, with nearly 25 percent of
them less than 25 tpy. The commenter suggested that the 1,000 hp
applicability threshold would result in overcontrol. According to one
commenter, the EPA has overestimated the emissions rates and operating
hours of engines with a rated capacity of more than 1,000 hp and thus
underestimated the size of pipeline RICE that would be expected to emit
more than 100 tpy of NOX annually. According to this
commenter, only engines much larger than 1,000 hp are likely to emit at
the level EPA deemed appropriate for regulation.
    Another commenter suggested that the EPA should use a 150 ton per
year threshold that the commenter alleges was used in the Revised CSAPR
Update rulemaking so that stationary SI engines are regulated on equal
footing with EGUs and raise the 1,000 hp threshold to 2,000 hp, which
according to the commenter would not sacrifice the emissions reductions
to be achieved.
    Response: As explained in the proposal, the EPA found that most
RACT requirements and other standards reviewed by the EPA establish
applicability criteria for engines based on design capacity rather than
PTE. For consistency with preexisting requirements for engines, the EPA
selected a design capacity of 1,000 hp for engines to capture the sizes
of units identified in Step 3 of our analysis. Based on the Non-EGU
Screening Assessment memorandum, engines with a potential to emit of
100 tpy or greater had the most significant potential for
NOX emissions reductions. The EPA recognizes that the use of
a 1,000 hp design capacity as part of the applicability criteria may
capture low-use units and some units with emissions of less than 100
tons per year. However, it is also not possible to guarantee without an
effective emissions control program that all such units could not
increase emissions in the future. As discussed in section V of this
document, we continue to find that collectively engines with a design
capacity of 1,000 hp or higher in the states and industries covered by
this final rule emit substantial amounts of NOX that
significantly contribute to downwind air quality problems.
    However, in response to concerns raised by commenters while
continuing to ensure that this rule establishes an effective emissions
control program for these units that is consistent with our Step 3
determinations, the EPA is establishing a compliance alternative using
facility-wide emissions averaging, which will allow facilities to
prioritize emissions reductions from larger, higher-emitting units. (As
previously discussed, we are also establishing an exemption for
emergency engines, which also helps ensure that this final rule focuses
on larger, more impactful units in this industry.) The facility-wide
emissions averaging alternative is explained in the following
paragraphs.
Emissions Limitations and Rationale
    In developing the emissions limits for the Pipeline Transportation
of Natural Gas industry, the EPA reviewed RACT NOX rules,
air permits, and OTC model rules. While some permits and rules express
engine emissions limits in parts per million by volume (ppmv), the
majority of rules and source-specific requirements express the
emissions limits in grams per horsepower per hour (g/hp-hr). The EPA
has historically set emissions limits for these types of engines using
g/hp-hr and finds that method appropriate for this final FIP as well.
    Based on the available information for this industry, including
applicable State and local air agency rules and active air permits
issued to sources with similar engines, the EPA is finalizing the
following emissions limits for stationary SI engines in the covered
states. Beginning in the 2026 ozone season and in each ozone season
thereafter, the following emissions limits apply, based on a 30-day
rolling average emissions rate during the ozone season:

    Table VI.C-1--Summary of Final NOX Emissions Limits for Pipeline
                      Transportation of Natural Gas
------------------------------------------------------------------------
                                                           Final NOX
                 Engine type and fuel                   emissions limit
                                                           (g/hp-hr)
------------------------------------------------------------------------
Natural Gas Fired Four Stroke Rich Burn..............                1.0
Natural Gas Fired Four Stroke Lean Burn..............                1.5
Natural Gas Fired Two Stroke Lean Burn...............                3.0
------------------------------------------------------------------------

    The EPA anticipates that, in some cases, affected engines will need
to install NOX controls to comply with the final emissions
limits in Table VI.C-1. The emissions limits for four stroke rich burn
engines, four stroke lean burn engines and two stroke lean burn engines
are designed to be achievable by installing Non-Selective Catalytic
Reduction (NSCR) on existing four stroke rich burn engines; installing
SCR on existing four stroke lean burn engines; and retrofitting layer
combustion on existing two stroke lean burn engines as identified in
the Final Non-EGU Sectors TSD. Sources have the flexibility to install
any other control technologies that enable the affected units to meet
the applicable emissions limit on a continuous basis.
    The EPA is establishing provisions that allow any owner or operator
of an affected unit in the Pipeline Transportation of Natural Gas
Industry to propose a Facility-Wide Averaging Plan that would, if
approved by EPA, provide an alternative means for compliance with the
emissions limits in this final rule. These provisions will provide some
flexibility to owners and operators of affected units to determine
which engines to control and at what level, so long as the average
emissions across all covered units, on a weighted basis, meet the
applicable emissions limits for each engine type. This approach allows
facilities to target the most cost-effective emissions reductions and
to avoid installing controls on equipment that is infrequently
operated.
    We provide a more detailed discussion of the basis for the final
emissions limits and the anticipated control technologies to be
installed in the Final Non-EGU Sectors TSD.
Four Stroke Rich Burn and Four Stroke Lean Burn Engines
    The EPA requested comment on whether a lower emissions limit is
appropriate for four stroke rich burn engines since even an assumed
reduction of 95 percent would result in most engines being able to
achieve an emissions rate of 0.5 g/hp-hr. The EPA also requested
comment on whether a lower or higher emissions limit is appropriate for
four stroke lean burn engines.
    Comment: One commenter stated that the limits as proposed were not
technically feasible in all circumstances. The commenter explained that
its company has 150 four stroke rich burn engines in its fleet and that
some of those engines cannot achieve the proposed 1.0 g/hp-hr limit
even with both NSCR and layered combustion due to the vintage design of
the individual cylinder geometry and the fact that most of these
engines are not in production today, which limits availability of parts
and retrofit technologies. The commenter asserted that 10 of its four
stroke rich burn engines have all available controls on them and half
of those still exceed the proposed limits. The commenter estimated that
10 of its four stroke lean burn engines would require SCR to meet the
1.5 g/hp-hr limit and that this control installation would require
custom retrofit due to the age of these engines. Furthermore, the
commenter stated that if current limits are not achievable in all
circumstances, then lower limits are likewise impossible for four
stroke rich burn engines and four stroke lean burn engines in even more
circumstances. The commenter stated that the technical feasibility of
installing controls on any single existing engine varies and depends,
in part, on site-specific and engine-specific considerations such as
space for the installation of the control, the availability of
sufficient power, the emissions reductions required to meet the
applicable standards, and the vintage, make, and model of a particular
engine. Another commenter recommended tightening the proposed emissions
standards for four stroke lean burn engines to an emissions limit
similar to Colorado's limit of 1.2 g/hp-hr. A third commenter noted
that the District of Columbia Department of Energy and Environment has
NOX emissions limits for both rich- and lean burn engines
burning natural gas at 0.7 g/hp-hr.
    Response: The EPA is finalizing the emissions limits for both four
stroke rich burn engines and four stroke lean burn engines as proposed
but also establishing alternative compliance provisions and criteria
for establishing case-by-case alternative emissions limits in response
to the concerns raised by commenters. NSCR can achieve NOX
reductions of 90 to 99 percent, and engines in California, Colorado,
Pennsylvania and Texas have achieved the emissions limits that the EPA
had proposed. Based on this information and the emissions limits and
NOX controls analysis developed by the OTC in a report
entitled Technical Information Oil and Gas Sector Significant
Stationary Sources of NOX Emissions (October 17, 2012), the EPA is
finalizing a 1.0 g/hp-hr emissions limit for four stroke rich burn
engines and a 1.5 g/hp-hr emissions limit for four stroke lean burn
engines. The Final Non-EGU Sectors TSD provides a more detailed
explanation of the basis for these emissions limits.
    To address the concerns raised by some commenters that not all
engines may be able to achieve the emissions limits as proposed due to
engine vintage and technical constraints, the final rule allows any
owner or operator of an affected unit to request a Facility-Wide
Averaging Plan that would, if approved by EPA, provide an alternative
means for compliance with the emissions limits in the final rule. An
approved Facility-Wide Averaging Plan would allow the owner or operator
of the facility to identify the most cost-effective means for
installing the necessary controls (i.e., by installing controls on the
subset of engines that provide the greatest emissions reduction
potential at lowest costs). In addition to the Facility-Wide Averaging
Plan provisions, the final rule allows owners and operators to seek EPA
approval of alternative emissions limits, on a case-by-case basis,
where necessary due to technical impossibility or to avoid extreme
economic hardship. The provisions governing case-by-case alternative
limits are explained in more detail in section VI.C of this document.
Two Stroke Lean Burn Engines
    The EPA requested comment on whether a lower emissions limit would
be achievable with layered combustion alone for the two stroke lean
burn engines covered by this final rule. The

EPA also sought comment on whether these engines could install
additional control technology at or below the marginal cost threshold
to achieve a lower emissions rate.
    Comment: Commenters did not specifically address whether a lower
emissions limit would be achievable with layered combustion alone at
two stroke lean burn engines. However, one commenter stated that older
two stroke lean burn engines generally would not be able to achieve the
proposed NOX emissions limits. The commenter stated that
conversion kits are available for several models that can reduce
emissions but that such kits are not made for all models, especially
older stationary engines. Commenters further stated that where
conversion kits are not available, a company would likely have no
choice but to replace the older four stroke or two stroke stationary
engines, typically at a cost of $2 million to $4 million each.
    Two commenters stated that they are required by their state agency
to have RACT, BACT, or BART controls, at minimum. Commenters stated
that requiring additional controls at facilities already equipped with
RACT, BACT or BART control technologies would not achieve the
anticipated emissions reductions due to operational factors inherent in
the preexisting and pre-controlled equipment and that the achievability
of targeted control levels is highly dependent upon a number of
variables at each facility.
    Another commenter suggested that the EPA set lower limits for two
stroke lean burn engines similar to the OTC-recommended limits in the
range of 1.5-2.0 g/hp-hr.
    Response: Information currently available to the EPA indicates that
the amount of emissions reductions achievable with layered combustion
controls is unit specific and can range from a 60 to 90 percent
reduction in NOX emissions. The EPA estimates that existing
uncontrolled two stroke lean burn engines would need to reduce
emissions by up to 80 percent to comply with a 3.0 g/hp-hr emissions
limit. The EPA has found that engines in California, Colorado,
Pennsylvania and Texas have achieved these emissions rates. Based on
this information and the emissions limits and NOX controls
analysis developed by the OTC in a report entitled Technical
Information Oil and Gas Sector Significant Stationary Sources of NOX
Emissions (October 17, 2012), the EPA is finalizing a 3.0 g/hp-hr
emissions limit for two stroke lean burn engines. Although some
affected units may be able to achieve a lower emissions rate, we find
that a 3.0 g/hp-hr emissions limit generally reflects a level of
control that is cost-effective for the majority of the affected units
and sufficient to achieve the necessary emissions reductions. As
explained in the proposed rule and expressed by public commenters, if
the EPA were to establish an emissions limit lower than 3.0 g/hp-hr,
some two stroke lean burn engines would not be able to meet the
emissions limit with the installation of layered combustion control
alone. In that case, the lower limit might require the installation of
SCR, which the EPA did not find to be cost-effective for two stroke
lean burn engines in its Step 3 analysis.\382\ The Final Non-EGU
Sectors TSD provides a more detailed explanation of the basis for this
emissions limit.
---------------------------------------------------------------------------

    \382\ 87 FR 20036, 20143 (noting that an emissions limit below
3.0 g/hp-hr may require some two stroke lean burn engines to install
additional controls beyond the EPA's cost threshold).
---------------------------------------------------------------------------

    In response to commenters' concerns about the difficulties involved
in retrofitting or replacing older stationary engines to achieve the
EPA's proposed emissions limit, the final rule allows any owner or
operator of an affected unit to request a Facility-Wide Averaging Plan
that would, if approved by EPA, provide an alternative means for
compliance with the emissions limits in the final rule. In addition to
the Facility-Wide Averaging Plan provisions, the final rule allows
owners and operators to seek EPA approval of alternative emissions
limits, on a case-by-case basis, where necessary due to technical
impossibility or to avoid extreme economic hardship. However, in the
context of older or ``vintage,'' high-emitting engines in this industry
for which commenters claim emissions control technology retrofit is not
feasible, the Agency anticipates taking into consideration the cost
associated with alternative compliance strategies, such as replacement
with new, far more efficient and less polluting engines, in evaluating
claims of extreme economic hardship.
Facility-Wide Averaging Plan
    The EPA is finalizing regulatory text that provides for an
emissions limit compliance alternative using facility-level emissions
averaging. An approved Facility-Wide Averaging Plan will allow the
owner or operator of the facility to average emissions across all
participating units and thus to select the most cost-effective means
for installing the necessary controls (i.e., by installing controls on
the subset of engines that provide the greatest emissions reduction
potential at lowest costs and avoiding installation of controls on
equipment that is infrequently operated or otherwise less cost-
effective to control). So long as all of the emissions units covered by
the Facility-Wide Averaging Plan collectively emit less than or equal
to the total amount of NOX emissions (in tons per day) that
would be emitted if each covered unit individually met the applicable
NOX emissions limitations, the covered units will be in
compliance with the final rule. Under this alternative compliance
option, facilities have the flexibility to prioritize emissions
reductions from larger, dirtier engines.
    Comment: Several commenters recommended that the EPA promulgate
emissions averaging provisions, as it did in the 2004 NOX
SIP Call Phase 2 rule (69 FR 21604), in which the EPA evaluated and
supported reliance on emissions averaging for RICE in the Pipeline
Transportation of Natural Gas industry sector. The commenter stated
that the EPA's guidance to states on developing an appropriate SIP in
response to the SIP Call provided companies the ``flexibility'' to use
a number of control options, as long as the collective result achieved
the required NOX reductions, and that many states built
their revised SIPs around the emissions averaging approach addressed in
this guidance document.\383\ One commenter recommended that the EPA
allow intra-state emissions averaging across all pipeline RICE owned or
operated by the same company. Another commenter asserted that units of
certain vintages and units from certain manufacturers will not be able
to meet the emissions rate limits the EPA had proposed. The commenter
claimed that, absent a system based on source-specific emissions
limits, emissions averaging is one of the only practical mechanisms for
addressing these challenges.
---------------------------------------------------------------------------

    \383\ The commenter refers to an August 22, 2002 memorandum from
Lydia N. Wegman, Director, EPA, Air Quality Strategies and Standards
Division to EPA Air Division Directors, entitled ``State
Implementation Plan (SIP) Call for Reducing Nitrogen Oxides
(NOX)--Stationary Reciprocating Internal Combustion
Engines.''
---------------------------------------------------------------------------

    One commenter stated that it had evaluated the cost of controls for
engines in its fleet and that the variety in cost-per-ton for each
potential project counsels for a more flexible approach, like an
averaging program. Another commenter advocated for an emissions
averaging plan that would allow an engine-by-engine showing of economic
infeasibility to ensure a cost-effective application of the emissions
standards, a reduced impact on natural gas capacity, and a means for
addressing the problem presented by achieving

compliance on engines that are technically impossible to retrofit.
    One commenter stated that the EPA should also consider allowing
companies to choose a mass-based alternative that would ensure
emissions reductions align with the tons per year reductions upon which
the EPA based its significant contribution and over-control analyses.
    Response: Based upon the EPA's 2019 NEI emissions inventory data,
the EPA estimates that a total of 3,005 stationary SI engines are
subject to the final rule. The EPA recognizes that many low-use engines
are captured by the 1,000 hp design capacity applicability threshold.
In the process of reviewing public comments, the EPA reviewed emissions
averaging plans found in state air quality rules for Colorado,
Illinois, Louisiana, New Jersey, and Tennessee.\384\ Based on these
additional reviews, the EPA is finalizing in Sec.  52.41(c) of this
final rule an emissions limit compliance alternative using facility-
level emissions averaging. Emissions averaging plans will allow
facility owners and operators to determine how to best achieve the
necessary emissions reductions by installing controls on the affected
engines with the greatest emissions reduction potential rather than on
units with lower actual emissions where the installation of controls
would be less cost effective. The final rule defines ``facility''
consistent with the definition of this term as it generally applies in
the EPA's NSR and title V permitting regulations,\385\ with one
addition to make clear that, for purposes of this final rule, a
``facility'' may not extend beyond the boundaries of the 20 states
covered by the FIP for industrial sources, as identified in Sec.
52.40(b)(2). Because a facility cannot extend beyond this geographic
area, a Facility-Wide Averaging Plan also cannot extend beyond the 20-
state area covered by the FIP.
---------------------------------------------------------------------------

    \384\ See Code of Colorado Regulations, Regulation Number 7 (5
CCR 1001-9), Part E, Section I.D.5.c., Illinois Administrative Code,
Title 35, Section 217.390, Louisiana Administrative Code, Title 33,
Section 2201, New Jersey Administrative Code, Title 7, Chapter 27,
Section 19.6, and Rules of the Tennessee Dept. of Environment and
Conservation, Rule 1200-03-27-.09.
    \385\ See 40 CFR 51.165(a)(1)(ii)(A), 51.166(b)(6)(i), and
52.21(b)(6)(i) (defining ``building, structure, facility, or
installation'' for Nonattainment New Source Review and Prevention of
Significant Deterioration permits) and Natural Resources Defense
Council v. EPA, 725 F.2d 761 (D.C. Cir. 1984) (vacating and
remanding EPA's categorial exclusion of vessel activities from this
definition); see also 40 CFR 70.2 (defining ``major source'' for
title V operating permits).
---------------------------------------------------------------------------

    To estimate the number of facilities that may take advantage of the
Facility-Wide Averaging Plan provisions, and the number of affected
units that would install controls under such an emissions averaging
plan, the EPA conducted an analysis on a subset of the estimated 3,005
stationary IC engines subject to the final rule. The EPA evaluated the
reported actual NOX emissions data in tpy from a subset of
facilities in the covered states using 2019 NEI data for stationary IC
engines with design capacities of 1,000 hp or greater. The EPA then
identified a number of facilities that have more than one affected
engine, calculated each facility's emissions ``cap'' as the total
NOX emissions (in tpy) allowed facility-wide based on the
unit-specific NOX emissions limits applicable to all
affected units at the facility, and identified a number of higher-
emitting engines at each facility that were candidates for having
controls installed. For engines that EPA identified were likely to
install controls, the EPA assumed that four stroke rich burn engines,
four stroke lean burn engines, and two stroke lean burn engines could
achieve a NOX emissions rate of 0.5 g/hp-hr with the
installation of SCR based on data obtained from the Ozone Transport
Commission report entitled Technical Information Oil and Gas Sector
Significant Stationary Sources of NOX Emissions (October 17, 2012). For
the remaining engines identified as uncontrolled, the EPA assumed a
NOX emissions rate of 16 g/hp-hr for all engine types. Thus,
under the assumed averaging scenarios, engines with controls installed
would achieve emissions levels below the emissions limits in the final
rule and would offset the higher emissions from the remaining
uncontrolled units.
    The EPA then calculated the total facility-wide emissions (in tpy)
under various assumed averaging scenarios and compared those totals to
each facility's calculated emissions cap (in tpy) to estimate the
number of affected units at each facility that would need to install
controls to ensure that total facility-wide emissions remained below
the emissions cap. Based on these analyses, the EPA found that
emissions averaging should allow most facilities to install controls on
approximately one-third of the engines at their sites, on average,
while complying with the applicable NOX emissions cap on a
facility-wide basis. For a more detailed discussion of the EPA's
analysis and related assumptions, see the Final Non-EGU Sectors TSD.
    The Facility-Wide Averaging Plan provisions that the EPA is
finalizing provide the flexibility needed to address the concerns about
the costs of emissions control installations for certain stationary SI
engines, by allowing facility owners and operators to average emissions
across all participating units and thus to select the most cost-
effective means for installing the necessary controls (i.e., by
installing controls on the subset of engines that provide the greatest
emissions reduction potential at lowest costs and avoiding installation
of controls on equipment that is infrequently operated or otherwise
less cost-effective to control).
    An owner or operator of a facility containing more than one
affected unit may elect to use an EPA-approved Facility-Wide Averaging
Plan as an alternative means of compliance with the NOX
emissions limits in Sec.  52.41(c). The owner or operator of such a
facility must submit a request to the EPA that, among other things,
specifies the affected units that will be covered by the plan, provides
facility and unit-level identification information, identifies the
facility-wide emissions ``cap'' (in tpd) that the facility must comply
with on a 30-day rolling average basis, and provides the calculation
methodology used to demonstrate compliance with the identified
emissions cap. The EPA will approve a request for a Facility-Wide
Averaging Plan if the EPA determines that the facility-wide emissions
total (in tpd), based on a 30-day rolling emissions average basis
during the ozone season, is less than the emissions cap (in tpd) and
the plan establishes satisfactory means for determining initial and
continuous compliance, including appropriate testing, monitoring, and
recordkeeping requirements.
Compliance Assurance Requirements
    The EPA is requiring owners and operators of affected units to
conduct annual performance tests in accordance with 40 CFR 60.8 to
demonstrate compliance with the NOX emissions limit in this
final rule. The EPA is also requiring owners and operators to monitor
and record hours of operation and fuel consumption and to use
continuous parametric monitoring systems to demonstrate ongoing
compliance with the applicable NOX emissions limit. For
example, owners and operators of engines that utilize layered
combustion controls will need to monitor and record temperature, air to
fuel ratio, and other parameters as appropriate to ensure that
combustion conditions are optimized to reduce NOX emissions
and assure compliance with the emissions limit. For engines using SCR
or NSCR, owners and operators must monitor and record parameters such
as inlet temperature to the catalyst

and pressure drop across the catalyst. For affected engines that meet
the certification requirements of Sec.  60.4243(a), however, the
facility-wide emissions calculations may be based on certified engine
emissions standards data pursuant to Sec.  60.4243(a), instead of
performance tests.
    In calculating the facility-wide emissions total during the ozone
season, affected engines covered by the Facility-Wide Averaging Plan
must be identified by each engine's nameplate capacity in horsepower,
its actual operating hours during the ozone season, and its emissions
rates in g/hp-hr from certified engine data or from the most recent
performance test results for non-certified engines according to Sec.
52.41(e).
    Comment: Several commenters stated that semi-annual performance
testing would not be appropriate due to its high costs and limited
benefits. One commenter proposed a ``step-down'' testing alternative
that could be conducted after establishing an engine's initial
compliance via performance testing. Under this approach, owners and
operators would conduct one performance test and would only need to
conduct a second performance test within a given year if the first
performance test demonstrated that an engine was not meeting the
applicable emissions standards.
    Another commenter asserted that to test all of its 950 units, a
minimum of 12 months would be needed rather than the six months the EPA
had proposed to provide (or five months if the EPA would require one of
the semi-annual tests to be conducted during the ozone season). The
commenter stated that the EPA had accounted for these operational
realities in the past and that under the NSPS and NESHAP, testing is
generally required only once for every 8,760 hours of run time. The
commenter asserted that there is no reason to require more frequent
testing than those required under the NSPS and NESHAP.
    Several commenters requested that the EPA allow for reduction in
the frequency of testing to once every two years if testing shows that
NOX emissions are no more than 75 percent of permitted
NOX emissions limits. In addition, several commenters stated
that since the rule is intended to address the ozone season, a single,
annual test is more feasible than semi-annual testing and reporting.
    Response: For the stationary SI engines subject to this final rule,
the EPA is revising the frequency of required performance tests from a
semi-annual basis to once per calendar year. As commenters correctly
pointed out, the emissions limits in these final FIPs only apply during
the 5-month ozone season and testing once per calendar year should be
sufficient to confirm the accuracy of the parameters being monitored to
determine continuous compliance during the ozone season. The EPA also
agrees with commenters that the annual tests required under the final
rule need not occur during the ozone season. However, where sources are
able to do so, we recommend conducting a stack test in the period
relatively soon before the start of the ozone season. This would
provide the greatest assurance that the emissions control systems are
working as intended and the applicable emissions limit will be met when
the ozone season starts.
    Comment: Commenters generally stated that requiring CEMS would add
an unnecessary cost and complexity, would provide no emissions
reduction benefit for the affected units the proposed FIP intends to
control and are not warranted due to the availability of other
established methods of compliance assurance, such as parametric
monitoring and periodic testing. One commenter stated that requiring
CEMS would add unnecessary CEMS testing obligations. Another commenter
stated that the costs associated with CEMS and frequent performance
testing on affected RICE would be as much, if not more, than the costs
associated with installation and operation of some of the control
technologies EPA has considered in setting the proposed emissions
limits. According to one commenter, the EPA has traditionally agreed
with this viewpoint on the high cost of CEMS, as most stationary
engines are not currently required under the NSPS or NESHAP to install
or operate CEMS.
    Another commenter stated that in addition to cost, there are other
barriers to installing CEMS on RICE across the Pipeline Transportation
of Natural Gas industry. Many RICE in the Pipeline Transportation of
Natural Gas industry are located at remote, unstaffed locations,
meaning that there would be no staff available to respond and react to
communication or alarms from CEMS.
    Response: The EPA acknowledges the costs associated with the
installation and maintenance of CEMS at affected units in the Pipeline
Transportation of Natural Gas industry and agrees that it is not
necessary to require CEMS for purposes of compliance with the
requirements of this final rule for this industry. Accordingly, the EPA
is not finalizing requirements for affected units in this industry
sector to install or operate CEMS. Instead, the EPA is requiring
parametric monitoring protocols, as described earlier, coupled with an
annual performance test, which will ensure that the emissions limits
are legally and practically enforceable on a continuous basis, and that
data are recorded, reported, and can be made publicly available,
ensuring the ability of state and Federal regulators and other persons
under CAA sections 113 and 304 to enforce the requirements of the Act.
2. Cement and Concrete Product Manufacturing
Applicability
    For cement kilns in the Cement and Cement Product Manufacturing
industry, the EPA is finalizing the proposed applicability provisions
without change. The affected units in this industry are cement kilns
that emit or have a PTE of 100 tpy or more of NOX. The EPA
received comments regarding the definition of PTE, which we address in
section VI.C, but no comments concerning the 100 tpy PTE threshold for
applicability purposes.
Emissions Limitations and Rationale
    As explained in the proposal, the EPA based the proposed emissions
limits for cement kilns on the types of limits being met across the
nation in RACT NOX rules, NSPS, air permits, and consent
decrees. Based on these requirements, the EPA proposed emissions limits
in the form of mass of pollutant emitted (in pounds) per kiln's clinker
output (in tons), i.e., pounds of NOX emitted per ton of
clinker produced during a 30-operating day rolling average period.
Further, the EPA proposed specific emissions limits for long wet, long
dry, preheater, precalciner, and combined preheater/precalciner kilns.
The EPA also proposed a daily source cap limit that would apply to all
units at a facility. Based on information received from public
comments, the EPA is removing the daily source cap limit but finalizing
the emissions limits as proposed in all other respects, as shown in
Table VI.C-2.

 Table VI.C-2--Summary of NOX Emissions Limits for Kiln Types in Cement
                   and Concrete Product Manufacturing
------------------------------------------------------------------------
                                                    NOX emissions limit
                    Kiln type                       (lb/ton of clinker)

------------------------------------------------------------------------
Long Wet.........................................                    4.0
Long Dry.........................................                    3.0
Preheater........................................                    3.8
Precalciner......................................                    2.3
Preheater/Precalciner............................                    2.8
------------------------------------------------------------------------

    Comment: Numerous commenters raised concerns about designing a
source cap limit based on average annual production in tons of clinker
and kiln type. Commenters stated that the source cap limit equation as
used in a prior action applied to long wet and dry preheater-
precalciner or precalciner kilns and did not include other kiln types.
Commenters expressed concern that the CAP2015 Ozone Transport equation
the EPA proposed in this rule could lead to artificially low and
restrictive daily emissions caps for facilities that experienced a
temporary decrease in production due to the COVID-19 pandemic, during
the historical three-year period proposed for use in determining the
NOX source cap. Also, commenters expressed concern that the
proposed daily emissions cap limit originated as a local or regional
limit for a single county and would not be appropriate for national
application without further evaluation taking into account the specific
characteristics of cement kilns in other states. One commenter
suggested more stringent emissions limits than those the EPA had
proposed for individual kiln types.
    Response: The EPA is not finalizing the proposed daily source cap
limit as the Agency agrees with the commenters that this proposed limit
would be unnecessarily restrictive and was based on a formula that did
not include all kiln types. Given the unusual reduction in cement
production activities due to the COVID-19 pandemic, production rates
during the 2019-2021 period are not representative of cement plants
activities generally. Accordingly, use of the proposed daily source cap
limit would result in an artificially restrictive NOX
emissions limit for affected cement kilns, particularly when this
sector operates longer hours during the spring and summer construction
season. With respect to those comments supporting more stringent
emissions limits than those the EPA proposed for individual kiln types,
we disagree given the significant differences among different kilns in
design, configuration, age, fuel capabilities, and raw material
composition. The EPA finds that the ozone season emissions limits for
individual kiln types listed in Table VI.C-2 will achieve the necessary
emissions reductions for purposes of eliminating significant
contribution as defined in section V and is, therefore, finalizing
these emissions limitations without change.
    Comment: One commenter supported retirement of existing long wet
kilns and replacement of these kilns with modern kilns. Other
commenters opposed the phase out and retiring of these kilns, stating
that many of the screened kilns have SNCR already installed and
questioning whether replacement of existing long wet kilns is cost-
effective. Some commenters also stated that according to EPA's
``NOX Control Technologies for the Cement Industry, Final
Report,'' SNCR is not an appropriate NOX control technique
for long wet kilns.
    Response: The EPA appreciates the challenges identified by
commenters, such as site-specific technical evaluation and review and
significant capital investment associated with undertaking kiln
conversions or to install new kilns and is not finalizing any
requirements to replace existing long wet kilns in this rule.
    Comment: Several commenters expressed concern about the supply
chain issues relevant to the procurement, design, construction, and
installation of control devices, as well as securing related contracts,
for the cement industry, particularly when cement sources will be
competing with the EGU and other industrial sectors for similar
services. One commenter stated that many preheater/precalciner kilns
are already equipped with SNCR and that one facility not equipped with
SNCR is already meeting NOX emissions levels of 1.95 lb/ton
of clinker or less. The commenter stated that the EPA should revise its
assessment of potential NOX reductions and cost estimates by
accurately accounting for existing operating efficiencies and control
devices at cement kilns.
    Response: The EPA's response to comments on the time needed for
installation of controls for non-EGU sources is provided in section
VI.A. Regarding the comment that certain facilities may already have
SNCR control technology installed, we recognize that many sources
throughout the EGU sector and non-EGU industries covered by this rule
may already be achieving enforceable emissions performance commensurate
with the requirements of this action. This is entirely consistent with
the logic of our 4-step interstate transport framework, which is
designed to bring all covered sources within the region of linked
upwind states up to a uniform level of NOX emissions
performance during the ozone season. See EME Homer City, 572 U.S. at
519. Sources that are already achieving that level of performance will
face relatively limited compliance costs associated with this rule.
Compliance Assurance Requirements
    The EPA received no comments on the proposed test methods and
procedures provisions for the cement industry. Therefore, we are
finalizing the proposed test methods and procedures for affected cement
kilns without change.
    Comment: Commenters generally supported requiring performance
testing or installation of CEMS on affected cement kilns. Some
commenters suggested that no performance testing should be required and
others suggested that performance testing should only be required when
a title V permit is due for renewal (every 5 years). One commenter
suggested requiring sources to conduct stack tests during the ozone
season.
    Response: Affected kilns that operate a NOX CEMS may use
CEMS data consistent with the requirements of 40 CFR 60.13 in lieu of
performance tests to demonstrate compliance with the requirements of
this final rule. For affected kilns subject to this final rule that do
not employ NOX CEMS, the EPA is adjusting the performance
testing frequency and requiring kilns to conduct a performance test on
an annual basis during a given calendar

year.\386\ The EPA finds that annual performance testing and
recordkeeping of cement production and fuel consumption during the
ozone season will assure compliance with the emissions limits during
the ozone season (May through September) each year for purposes of this
rule. The required annual performance test may be performed at any time
during the calendar year. However, where sources are able to do so, we
recommend conducting a stack test in the period relatively soon before
the start of the ozone season. This would provide the greatest
assurance that the emissions control systems are working as intended
and the applicable emissions limit will be met when the ozone season
starts.
---------------------------------------------------------------------------

    \386\ 40 CFR 63.11237 ``Calendar year'' defined as the period
between January 1 and December 31, inclusive, for a given year.
---------------------------------------------------------------------------

    Comment: One commenter stated that CEMS has been used successfully
at its facility. Another commenter explained that the inside of a
cement kiln is an extremely challenging environment for making any kind
of continuous measurement as temperatures are high, and there is a lot
of dust and tumbling clinker can damage in situ measuring instruments.
    Response: The majority of cement kilns in the United States are
already equipped with CEMS. However, in response to commenters concerns
regarding the installation of CEMS, the EPA is finalizing alternative
compliance requirements in lieu of CEMS. Owners or operators of
affected emissions units without CEMS installed must conduct annual
performance testing and continuous parametric monitoring to demonstrate
compliance with the emissions limits in this final rule. Specifically,
owners or operators of affected units without CEMS must 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.
3. Iron and Steel Mills and Ferroalloy Manufacturing
Applicability
    The EPA is establishing emissions control requirements for the Iron
and Steel Mills and Ferroalloy Manufacturing source category that apply
to reheat furnaces that directly emit or have the potential to emit 100
tpy or more of NOX. After review of all available
information received during public comment, the EPA has determined that
there is sufficient information to determine that low-NOX
burners can be installed on reheat furnaces. As explained further in
the Final Non-EGU Sectors TSD, the EPA identified 32 reheat furnaces
with low-NOX burners installed and has concluded that low-
NOX burners are a readily available and widely implemented
emissions reduction strategy.\387\ This rule defines reheat furnaces to
include all furnaces used to heat steel product--metal ingots, billets,
slabs, beams, blooms and other similar products--to temperatures at
which it will be suitable for deformation and further processing.
---------------------------------------------------------------------------

    \387\ See Final Non-EGU Sectors TSD, Section 4.
---------------------------------------------------------------------------

    Comment: Several industry commenters requested that the EPA not
include certain iron and steel emissions units--including blast
furnaces, basic oxygen furnaces (BOFs), ladle and tundish preheaters,
annealing furnaces, vacuum degassers, taconite kilns, coke ovens, and
electric arc furnaces (EAFs)--in the final rule as proposed due to,
among other things, the uniqueness of each emissions unit, various
design-related challenges, and expected impossibility of successful
implementation of add-on NOX control technology. Commenters
expressed concern about requirements to install SCR for all iron and
steel units for which the EPA proposed emissions limits. The commenters
stated that iron and steel units had not installed SCR except in a few
rare instances for experimental reasons and that SCR technology was not
readily available or known for the iron and steel industry, unlike the
control technologies expected to be installed in other non-EGU
industries. Furthermore, commenters stated that SCR had not been
applied for RACT, BACT, or LAER purposes on iron and steel units.
    Response: In light of the comments we received on the complex
economic and, in some cases, technical challenges associated with
implementation of NOX control technologies on certain
emissions units in this sector, the EPA is not finalizing the proposed
emissions limits for blast furnaces, BOFs, ladle and tundish
preheaters, annealing furnaces, vacuum degassers, taconite kilns, coke
ovens, or EAFs.
    The EPA is aware of many examples of low-NOX technology
utilized at furnaces, kilns, and other emissions units in other sectors
with similar stoichiometry, including taconite kilns, blast furnace
stoves, electric arc furnaces (oxy-fuel burners), and many other
examples at refineries and other large industrial facilities. The EPA
anticipates that with adequate time, modeling, and optimization
efforts, such NOX reduction technology may be achievable and
cost-effective for these emissions units in the Iron and Steel Mills
and Ferroalloy Manufacturing sector as well. However, the data we have
reviewed is insufficient at this time to support a generalized
conclusion that the application of NOX controls, including
SCR or other NOX control technologies such as LNB, is
currently both technically feasible and cost effective on a fleetwide
basis for these emission source types in this industry. We provide a
more detailed discussion of the economic and technical issues
associated with implementation of NOX control technologies
on these emissions units, including information provided by commenters,
in section 4 of the Final Non-EGU Sectors TSD.
    Reheat furnaces are the only type of emissions unit within the Iron
and Steel Mills and Ferroalloy Manufacturing industry that this final
rule applies to. Low-NOX controls (e.g., low-NOX
burners) are a demonstrated control technology that many reheat
furnaces have successfully employed.
    Comment: One commenter claimed that the proposed definition of
``reheat furnaces'' is overly vague and requested that the EPA amend
the definition. Specifically, the commenter asserted that the EPA's
proposed definition does not indicate what counts as ``steel product''
and whether this includes only products that have already been
manufactured into some form before being introduced to a reheat
furnace, or whether it also includes steel that has never left the
original production process, such as hot steel coming directly from a
connected casting process which has not yet been formed into a
definitive product. The commenter referenced the definition of reheat
furnaces in Ohio's RACT regulations as an example to consider.
    Response: In response to these comments, the EPA is finalizing a
definition of reheat furnaces that is consistent with the definition in
Ohio's NOX RACT regulations. See Ohio Admin. Code 3745-110-
01(b)(35) (March 25, 2022). Specifically, the EPA is defining reheat
furnaces to mean ``all furnaces used to heat steel product, including
metal ingots, billets, slabs, beams, blooms and other similar products,
to temperatures at which it will be suitable for deformation and
further processing.''

Emissions Control Requirements, Testing, and Rationale
    Based on the available information for this industry, applicable
Federal and state rules, and active air permits or enforceable orders
issued to affected facilities in the iron and steel and ferroalloy
manufacturing industry, the EPA is finalizing requirements for each
facility with an affected reheat furnace to design, fabricate and
install high-efficiency low-NOX burners designed to reduce
NOX emissions from pre-installation emissions rates by at
least 40 percent by volume, and to conduct performance testing before
and after burner installation to set emissions limits and verify
emissions reductions from pre-installation emissions rates. Each low-
NOX burner shall be designed to achieve at least 40 percent
NOX reduction from existing reheat furnace exhaust emissions
rates. Each facility with an affected reheat furnace shall, within 60
days of conclusion of the post-installation performance test, submit
testing results to the EPA to establish NOX emissions limits
over a 30-day rolling average. Each proposed emissions limit must be
supported by performance test data and analysis.
    In evaluating potential emissions limits for the Iron and Steel and
Ferroalloy Manufacturing industry, the EPA reviewed RACT NOX
rules, NESHAP rules, air permits and related emissions tests, technical
support documents, and consent decrees. These rules and source-specific
requirements most commonly express emissions limits for this industry
in terms of mass of pollutant emitted (pounds) per operating hour
(hour) (i.e., pounds of NOX emitted per production hour),
pounds per energy unit (i.e., million British thermal unit (mmBtu)), or
pounds of NOX per ton of steel produced. Regulated iron and
steel facilities, including facilities operating reheat furnaces in
this sector, routinely monitor and keep track of production in terms of
tons of steel produced per hour (heat rate) as it pertains to each
facility's rate of iron and steel production. Several facilities,
including Steel Dynamics, Columbia, Indiana, Cleveland-Cliffs,
Cleveland, Ohio, and Cleveland-Cliffs, Burns Harbor, Indiana, are
already operating various types of reheat furnaces with low-
NOX burners and achieving emissions rates as low as 0.11 lb/
mmBtu of NOX. The EPA identified at least nine reheat
furnaces with a PTE greater than 100 tpy, including slab, rotary
hearth, and walking beam furnaces, that have installed low-
NOX burners and are achieving various emissions rates.\388\
---------------------------------------------------------------------------

    \388\ Specifically, through a review of title V permits, the EPA
identified reheat furnaces with low-NOX burners installed
at Steel Dynamics in Columbia City, Indiana (two furnaces), Steel
Dynamics in Butler, Indiana (one furnace), Cleveland Cliffs in Burns
Harbor, Indiana (four furnaces), Cleveland Cliffs in East Chicago,
Indiana (one furnace), and Cleveland Cliffs in Cleveland, Ohio (one
furnace). For a further discussion of the limits and information on
these facilities, see the Final Non-EGU Sectors TSD.
---------------------------------------------------------------------------

    Due to variations in the emissions rates that different types of
reheat furnaces can achieve, the EPA is not finalizing one emissions
limit for all reheat furnaces and is instead requiring the installation
of low-NOX burners or equivalent low-NOX
technology designed to achieve a minimum 40 percent reduction from
baseline NOX emission levels, together with source specific
emissions limits to be set thereafter based on performance testing.
Specifically, the final rule requires that each owner or operator of an
affected unit submit to the EPA, within one year after the effective
date of the final rule, a work plan that identifies the low-
NOX burner or alternative low-NOX technology
selected, the phased construction timeframe by which the owner or
operator will design, install, and consistently operate the control
device, an emissions limit reflecting the required 40 percent reduction
in NOX emission levels, and, where applicable, performance
test results obtained no more than five years before the effective date
of the final rule to be used as baseline emissions testing data
providing the basis for the required emissions reductions. If no such
data exist, then the owner or operator must perform pre-installation
testing to establish baseline emissions data.
    Comment: One commenter stated that the standard practice for
setting NOX limits for iron and steel sources often requires
consideration of site or unit-specific issues. Similarly, another
commenter stated that a single limit would not provide an adequate
basis for establishing NOX emissions limits that will
universally apply to multiple, unique facilities. The same commenter
stated that NOX reduction in certain furnaces is routinely
achievable by combustion controls or measures other than SCR.
    Response: The EPA acknowledges the difficulty in crafting one
emissions limit for multiple iron and steel facilities and units of
varying size, age, and design, in light of the unique issues associated
with varying unit types in this particular industry. We also
acknowledge that in some cases, reheat furnaces are equipped with
recently installed, high-efficiency low-NOX burners. Many
sources throughout the EGU sector and non-EGU industries covered by
this rule may already be achieving enforceable emissions performance
commensurate with the requirements of this action. This is entirely
consistent with the logic of our 4-step interstate transport framework,
which is designed to bring all covered sources within the region of
linked upwind states up to a uniform level of NOX emissions
performance during the ozone season. See EME Homer City, 572 U.S. at
519. Sources that are already achieving that level of performance will
face relatively limited compliance costs associated with this rule.
    The EPA is finalizing requirements for reheat furnaces to install
high-efficiency low-NOX burners designed to reduce
NOX emissions from pre-installation emissions rates by 40
percent by volume, and to perform pre- and post-installation
performance testing at exhaust outlets to determine rate-based
emissions limits for reheat furnaces in lb/hour, lb/mmBtu, or lb/ton on
a rolling 30-operating day average. Owners and operators of affected
units must also monitor NOX emissions from reheat furnaces
using CEMS or annual performance testing and recordkeeping and operate
low-NOX burners in accordance with work practice standards
set forth in the regulatory text. Due to the many types of emissions
units within the Iron and Steel Mills and Ferroalloy Manufacturing
industry, and the limited information available at this time regarding
NOX control options that are achievable for these units, the
EPA is finalizing requirements only for reheat furnaces at this time.
    Comment: Commenters expressed concern that the proposed emissions
limits identified both a 3-hour and a 30-day averaging time for the
same limits and requested that the EPA clarify the averaging time in
the final rule. Commenters requested that the EPA finalize limits with
a 30-day averaging time consistent with the requirements for other non-
EGU industries.
    Response: In determining the appropriateness of 30-day rolling
averaging times, the EPA initially reviewed the NESHAP for Iron and
Steel Foundries codified at 40 CFR part 63, subpart EEEEE, the NESHAP
for Integrated Iron and Steel manufacturing facilities codified at 40
CFR part 63, subpart FFFFF, the NESHAP for Ferroalloys Production:
Ferromanganese and Silicomanganese codified at 40 CFR part 63, subpart
XXX, and the NESHAP for Ferroalloys Production Facilities codified at
40 CFR part 63, subpart YYYYYY. The EPA also reviewed

various RACT NOX rules from states located within the OTR,
several of which have chosen to implement OTC model rules and
recommendations. Based on this information and the information provided
by public commenters, the EPA is requiring a 30-operating day rolling
average period as the averaging timeframe for reheat furnaces. The EPA
finds that a 30-operating day rolling average period provides a
reasonable balance between short term (hourly or daily) and long term
(annual) averaging periods, while providing the flexibility needed to
address fluctuations in operations and production.
Compliance Assurance Requirements
    The EPA is finalizing requirements for each owner or operator of an
affected unit in the Iron and Steel Mills and Ferroalloy Manufacturing
industry to use CEMS or annual performance tests and continuous
parametric monitoring to determine compliance with the 30-day rolling
average emissions limit during the ozone season. Facilities choosing to
use CEMS must perform an initial RATA per CEMS and maintain and operate
the CEMS according to the applicable performance specifications in 40
CFR part 60, appendix B. Facilities choosing to use testing and
continuous parametric monitoring for compliance purposes must use the
test methods and procedures in 40 CFR part 60, appendix A-4, Method 7E,
or other EPA-approved (federally enforceable) test methods and
procedures.
    Comment: Several commenters raised concerns with the requirement to
install and operate CEMS to monitor NOX emissions.
Commenters cited the high relative costs of installing CEMS, especially
for smaller units with lower actual emissions, and the complexities
with installing CEMS on mobile reheat furnaces. Further, commenters
explained that due to the unique configuration of certain facilities,
it would be impossible for a CEMS to differentiate emissions from a
reheat furnace and other units, like waste heat boilers. As an
alternative to CEMS, commenters requested that the EPA finalize similar
monitoring and recordkeeping requirements as proposed for the Cement
and Concrete Product Manufacturing industry in the proposed rule, which
allow for CEMS or performance testing and recordkeeping. Commenters
explained that for reheat furnaces that are natural gas-fired,
emissions can be tracked by relying on vendor guarantees and emissions
factors and natural gas throughput.
    Response: The EPA reviewed comments received from the industry
regarding their concerns of affected units within the iron and steel
mills and ferroalloy manufacturing sector being required to demonstrate
compliance through CEMS. The EPA acknowledges the cost associated with
the installation and maintenance of CEMS to demonstrate compliance with
the finalized emissions standards for reheat furnaces. In this final
rule, the EPA is revising the compliance assurance requirements to
provide flexibility to owners or operators of affected units.
Compliance may be demonstrated through CEMS or annual performance
testing and continuous parametric monitoring to demonstrate compliance
with the emissions limits in this final rule. 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. For sources relying on annual
performance tests and continuous parametric monitoring to assure
compliance, the EPA is requiring that sources keep records of
production and fuel usage during the ozone season to assure compliance
with the emissions limits on a 30-day rolling average basis. 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. However, where sources are able to
do so, we recommend conducting a stack test in the period relatively
soon before the start of the ozone season. This would provide the
greatest assurance that the emissions control systems are working as
intended and the applicable emissions limit will be met when the ozone
season starts.
4. Glass and Glass Product Manufacturing
Applicability
    The EPA is finalizing regulatory requirements for the Glass and
Glass Product Manufacturing source category that apply to furnaces that
directly emit or have a PTE of 100 tpy or more of NOX. For
this industry, the EPA is finalizing the proposed applicability
provisions without change.
    Comment: One commenter requested that the applicability threshold
for glass manufacturing furnaces should be based on a unit's design
production capacity instead of the proposed applicability criteria
(i.e., units that directly emit or have the potential to emit 100 TPY
or more of NOX). The commenter stated that the production
capacity for glass manufacturing furnaces is a more relevant basis for
applicability and would focus the EPA analysis on cost-effective
regulations.
    Response: During the EPA's development of the proposed emissions
limits, the EPA reviewed the applicability provisions in various state
RACT NOX rules, air permits, consent decrees, and Federal
regulations applicable to glass manufacturing furnaces. Most of these
applicability provisions were expressed in terms of actual emissions or
PTE. Given the significant differences in the types, designs,
configurations, ages, and fuel capabilities among glass furnaces, and
differences in raw material compositions within the sector, the EPA
finds that applicability criteria based on emissions or potential to
emit are the most appropriate way to capture higher-emitting glass
manufacturing furnaces that contribute NOX emissions to
downwind receptors.
Emissions Limitations and Rationale
    The EPA is finalizing the proposed NOX emissions limits
for furnaces within the Glass and Glass Product Manufacturing industry,
except that for flat glass manufacturing furnaces the EPA is finalizing
an emissions limit slightly lower than the limit we had proposed, based
on a correction to a factual error in our proposal. For further
discussion of the basis for the form and level of the final emissions
limits, see the proposed rule, 87 FR 20036, 20146 (April 6, 2022)
(discussing EPA review of state RACT rules, NSPS, and other regulations
applicable to the Glass and Glass Product Manufacturing industry).
Several comments supported the EPA's effort to regulate sources within
the Glass and Glass Product Manufacturing industry but also requested
that the EPA establish more stringent emissions limits for this
industry.
    Comment: One commenter stated that NOX emissions from
the Glass and Glass Product Manufacturing industry are not currently
subject to any Federal NSPS and that the industry is expected to grow
in the coming years. The commenter stated that while the EPA's proposed
limits on glass furnaces fell within the ranges of limits required by

various states and air districts, they fell at the weakest levels
within those ranges. For example, the commenter stated that the EPA had
proposed a 4.0 lb/ton NOX emissions limit for container
glass manufacturing furnaces, while state and local NOX
emissions limits for these emissions units range from 1 to 4 lb/ton.
Similarly, the commenter stated that the EPA had proposed a 4.0 lb/ton
NOX emissions limit for pressed/blown glass manufacturing
furnaces, while state and local NOX emissions limits for
these emissions units range from 1.36 to 4 lb/ton, and that EPA had
proposed a 9.2 lb/ton NOX emissions limit for flat glass
manufacturing furnaces, while state NOX emissions limits for
these emissions units range from 5-9.2 lb/ton. The commenter urged the
EPA to establish emissions limits lower than those the EPA had
proposed.
    Response: The EPA is finalizing the emissions limits for affected
units in the glass and glass product manufacturing industry as proposed
for all but flat glass manufacturing furnaces, for which the EPA is
finalizing a slightly lower emissions limit to reflect a correction to
a factual error in our proposal. During the EPA's development of the
proposed emissions limits, the EPA reviewed the control requirements or
recommendations and related analyses in various RACT NOX
rules, air permits, Alternative Control Techniques (ACT) documents, and
consent decrees to determine the appropriate NOX emissions
limits for the different types of glass manufacturing furnaces. Based
on these reviews and given the significant differences in the types,
designs, configurations, ages, and fuel capabilities among glass
furnaces, and differences in raw material compositions within the
sector, the EPA has concluded that it is appropriate to finalize the
emissions limits for this industry as proposed, except for the limit
proposed for flat glass manufacturing furnaces. For flat glass
manufacturing furnaces, the EPA had proposed a NOX emissions
limit of 9.2 pounds (lbs) per ton of glass pulled but is finalizing a
limit of 7.0 lbs/ton of glass pulled on a 30-day rolling average basis.
This is based on our review of specific state RACT NOX
regulations that contain a 9.2 lbs/ton limit averaged over a single day
but contain a 7.0 lbs/ton limit over a 30-day averaging period. This
change aligns the final limit for flat glass manufacturing furnaces
with the correct averaging time and is consistent with both the state
RACT regulations that we reviewed \389\ and our evaluation of cost-
effective controls for this industry in the supporting documents for
the proposed and final rule.
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    \389\ For example, Pennsylvania's RACT NOX emission
limits for flat glass furnaces are 7.0 lbs of NOX per ton
of glass produced on 30-day rolling average. See Title 25, Part I,
Subpart C, Article III, Section 129.304, available at https://casetext.com/regulation/pennsylvania-code-rules-and-regulations/title-25-environmental-protection/part-i-department-of-environmental-protection/subpart-c-protection-of-natural-resources/article-iii-air-resources/chapter-129-standards-for-sources/control-of-nox-emissions-from-glass-melting-furnaces/section-129304-emission-requirements.
---------------------------------------------------------------------------

    The EPA acknowledges that NOX emissions from some glass
manufacturing furnaces are subject to control under other regulatory
programs, such as those adopted by states to meet CAA RACT
requirements, and that some of these programs have implemented more
stringent emissions limits than those the EPA is finalizing in these
FIPs. However, as noted in the preamble to the proposed rule and
related TSD, many OTR states do not establish specific NOX
emissions limits for glass manufacturing sources.\390\ See 87 FR 20146.
In addition to state RACT rules, air permits, ACT documents, and
consent decrees applicable to this industry, the EPA reviewed reports
and recommendations from the National Association of Clean Air Agencies
(NACAA), the European Union Commission, and EPA's Menu of Control
Measures (MCM) to identify potentially available control measures for
reducing NOX emissions from the glass manufacturing
industry. The EPA also reviewed permit data for existing glass
manufacturing furnaces to identify control devices currently in use at
these sources. Based on these reviews, we find that the final emissions
limits for the Glass and Glass Product Manufacturing industry provided
in Table VI.C.3-1 generally reflect a level of control that is cost-
effective for the majority of the affected units and sufficient to
achieve the necessary emissions reductions. The Final Non-EGU Sectors
TSD provides a more detailed explanation of the basis for these
emissions limits.
---------------------------------------------------------------------------

    \390\ See Proposed Non-EGU Sectors TSD at 56, EPA-HQ-OAR-2021-
0668-0145.

  Table VI.C.3-1--Summary of Finalized NOX Emissions Limits for Furnace
           Unit Types in Glass and Glass Product Manufacturing
------------------------------------------------------------------------
                                                    NOX emissions limit
                                                     (lbs/ton of glass
                   Furnace type                         produced, 30
                                                   operating-day rolling
                                                          average)
------------------------------------------------------------------------
Container Glass Manufacturing Furnace............                    4.0
Pressed/Blown Glass Manufacturing Furnace or                         4.0
 Fiberglass Manufacturing Furnace................
Flat Glass Manufacturing Furnace.................                    7.0
------------------------------------------------------------------------

Alternative Emissions Standards During Periods of Start-Up, Shutdown,
and Idling
    Comment: Numerous commenters urged the EPA to provide additional
flexibilities, alternative NOX emissions limits, or
exceptions to the NOX emissions limits for glass
manufacturing furnaces during periods of startup, shutdown and idling.
Commenters requested that the EPA consider excluding days with low
glass pull (e.g., abnormally low production rate), furnace start-up
days, furnace maintenance days, and malfunction days from the
definition of ``operating day'' to allow for exclusion of these days
from the calculation of an emissions unit's 30-operating day rolling
average emissions. The commenters argued that because the glass furnace
temperature is much lower during these periods than they are during
normal operating conditions, it would be technologically infeasible to
equip furnaces with NOX control devices including SCR.
Commenters also stated that because control equipment cannot be
operated during these periods without damaging the equipment, it would
be very difficult or impossible to meet the proposed NOX
limits during these periods.
    Response: After review of the comments received and the EPA's
assessment of current practices within

the glass manufacturing industry, the EPA is establishing provisions
for alternative work practice standards and emissions limits that may
apply in lieu of the emissions limits in Sec.  52.44(c) during periods
of start-up, shutdown, and idling. The emissions limits for glass
melting furnaces in Sec.  52.44(c) do not apply during periods of
start-up, shutdown, and/or idling at affected units that comply instead
with the alternative requirements for start-up, shutdown, and/or idling
periods specified in Sec.  52.44(d), (e), and/or (f), respectively. The
EPA has modeled these alternative requirements that apply during
startup, shutdown, and idling to some extent on State RACT requirements
identified by commenters.\391\ These alternative work practice
standards adequately address the seven criteria that the EPA has
recommended states consider when establishing appropriate alternative
emissions limitations for periods of startup and shutdown.\392\ We
provide a more detailed evaluation of these provisions in the TSD
supporting this final rule.
---------------------------------------------------------------------------

    \391\ See Pennsylvania Code, Title 25, Part I, Subpart C,
Article III, Sections 129.305-129.307 (effective June 19, 2010),
available at https://www.pacodeandbulletin.gov/Display/pacode?file=/secure/pacode/data/025/chapter129/chap129toc.html&d=reduce and San
Joaquin Valley Unified Air Pollution Control District, Rule 4354,
``Glass Melting Furnaces,'' sections 5.5-5.7 (amended May 19, 2011),
available at https://www.valleyair.org/rules/currntrules/R4354%20051911.pdf.
    \392\ See 80 FR 33840, 33914 (June 12, 2015) (identifying the
EPA's recommended criteria for developing and evaluating alternative
emissions limitations applicable during startup and shutdown).
---------------------------------------------------------------------------

    Specifically, each owner or operator of an affected unit seeking to
comply with alternative work practice standards in lieu of emissions
limits during startup or shutdown periods must submit specific
information to the Administrator no later than 30 days prior to the
anticipated date of startup or shutdown. The required information is
necessary to ensure that the furnace will be properly operated during
the startup or shutdown period, as applicable. The final rule
establishes limits on the number of days when the owner or operator may
comply with alternative work practice standards in lieu of emissions
limits during startup and shutdown, depending on the type of glass
furnace. Additionally, the owner or operator must maintain operating
records and additional documentation as necessary to demonstrate
compliance with the alternative requirements during startup or shutdown
periods. For startups, the owner or operator must place the emissions
control system in operation as soon as technologically feasible to
minimize emissions. For shutdowns, the owner or operator must operate
the emissions control system whenever technologically feasible to
minimize emissions.
    For periods of idling, the owner or operator of an affected unit
may comply with an alternative emissions limit calculated in accordance