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    Modification. In the November 2021 proposal, the EPA proposed
specific provisions to specify what circumstances constitute a
modification of an existing storage vessel or tank battery, and thus
subject it to the proposed NSPS OOOOb. The EPA proposed that a single
storage vessel or tank battery is modified when certain physical or
operational changes are made (86 FR 63178; November 15, 2021) to the
single storage vessel or tank battery which result in an increase in
the potential methane or VOC emissions. The EPA proposed that the owner
or operator would be required to recalculate the potential VOC
emissions when any of these actions occurred on an existing tank
battery, to determine if a modification occurred. The EPA proposed that
an existing tank battery would become subject to the proposed NSPS
OOOOb if it is modified pursuant to this definition of modification and
its potential VOC emissions exceeded the proposed 6 tpy VOC emissions
threshold.
    Legally and Practicably Enforceable. The EPA proposed to clarify
the term ``legally and practicably enforceable'' as it related to
determining applicability of the storage vessel standards, The intent
of this proposed definition (86 FR 63201; November 15, 2021) was to
provide clarity to owners and operators claiming the storage vessel is
not an affected facility in NSPS OOOOb, due to legally and practicably
enforceable limits that limit their potential for VOC emissions below 6
tpy.
b. Changes From November 2021 Proposal
    Storage Vessel Affected Facility. In this supplemental proposal,
the EPA is proposing that a storage vessel affected facility is a tank
battery which has the potential for VOC emissions equal to or greater
than 6 tpy or the potential for methane emissions equal to or greater
than 20 tpy. Specifically, the EPA is proposing to define a tank
battery as a group of all storage vessels that are manifolded together
for liquid transfer. A tank battery may consist of a single storage
vessel if there is only one storage vessel is present, or the
individual storage vessels at the site are not manifolded for liquid
transfer. Commenters generally supported basing the potential for
emissions on a tank battery instead of an individual storage vessel.
The EPA received several comments that suggested changes to the
definition of tank battery relating to how the tanks were manifolded
and the proximity of tanks within the tank battery. Specifically, these
commenters recommended that the definition of tank battery not include
the term ``adjacent'' and should be based on tanks that are manifolded
by liquid line.\231\ Commenters suggested these changes to avoid
confusion around applicability and to align with existing state
programs.\232\ The EPA agrees that these changes reflect our intent
that a group of storage vessels which are manifolded together by liquid
line operate as a system and, as such, share the same control, the cost
of which was the basis for defining the applicability threshold; the
total throughput to the tank battery is the basis for determining the
potential for VOC and methane emissions for the tank battery, based on
the maximum average daily throughput to the tank battery. This
rationale holds regardless of the physical proximity to each other and
therefore the term ``adjacent'' does not add additional clarity. Also,
because tank batteries with the potential for VOC and methane emissions
(greater than or equal to the thresholds) are: (1) Storage vessel
affected facilities which require control; and (2) those standards
require that all vapors from the tank battery are routed through a CVS
(i.e., manifolded), it is not necessary to include the provision that
vapor lines are manifolded in the definition of tank battery.
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    \231\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0810, EPA-HQ-
OAR-2021-0317-0814 and EPA-HQ-OAR-2021-0317-0831.
    \232\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
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    As stated above, the EPA is also proposing to include the 20 tpy

potential for methane emission threshold for determining applicability
to NSPS OOOOb. As discussed in the November 2021 proposal, the EPA
determined that it is cost-effective to reduce methane emissions by 95
percent from existing tank batteries with potential methane emissions
of 20 tpy. The EPA focused the November 2021 proposed NSPS OOOOb
requirements on the 6 tpy VOC threshold because the EPA expects that
most tank batteries will exceed the 6 tpy VOC threshold well before
they exceed the 20 tpy methane threshold. However, based on our cost
estimates, the EPA determined it is cost effective to control tank
batteries if their methane emissions exceed 20 tpy, but the potential
VOC emissions remain below 6 tpy. As such, in the unusual case that the
methane threshold is triggered prior to the VOC threshold, the EPA
determined it necessary to directly include the 20 tpy potential
methane emissions threshold in the storage vessel affected facility
definition.
    The EPA also is proposing that a ``generally accepted model or
calculation methodology'' used to determine VOC and methane emissions
must account for flashing, working, and breathing losses. As discussed
in the November 2021 proposal, both methane and VOC emissions from
storage vessels are a result of working, breathing, and flashing
losses. Flashing losses occur when a liquid with dissolved gases is
transferred from a vessel with higher pressure (e.g., separator) to a
vessel with lower pressure (e.g., storage vessel), thus allowing
dissolved gases and a portion of the liquid to vaporize or flash. In
the Crude Oil and Natural Gas source category, flashing losses occur
when crude oils or condensates flow into a storage vessel from a
separator operated at a higher pressure. Typically, the higher the
operating pressure of the upstream separator, the greater the flash
emissions from the storage vessel. See 86 FR 63198 (November 15, 2021).
For tank batteries with flashing losses, those emissions can dwarf
working and breathing losses from the same tank battery. There are many
``generally accepted'' models or calculation methodologies for
estimating storage vessel emissions, but they do not all estimate flash
emissions. Therefore, it is important to specify in the rule the EPA's
requirement that emissions calculations account for such emissions when
flash emissions occur.
    Additionally, the EPA is including in this supplemental proposal
regulatory text which instructs the owner or operator on how to
determine the potential for VOC or methane emissions as the cumulative
emissions from all storage vessels within the tank battery according to
certain timelines; for each tank battery located at a well site or
centralized production facility the determination must occur 30 days
after startup of production, or within 30 days after a physical or
operational action which may trigger a modification or reconstruction;
or for each tank battery located at a compressor station or onshore
natural gas processing plan, the determination must occur prior to
startup of the compressor station or onshore natural gas processing
plant (or within 30 days after an action which may trigger
reconstruction or modification). These timelines are consistent with
the timelines provided in NSPS OOOOa for determining the potential for
VOC emissions after startup of production (for a well site) or startup
of the compressor station or onshore natural gas processing plant but
are being proposed to also include timelines for centralized production
facilities as well as timelines for determining the potential for VOC
and methane emissions following an action which may trigger
reconstruction or modification. The EPA believes this proposed
regulatory text will provide direction and clarity to owners and
operators for when the potential for VOC and methane emissions
determinations must be made based on potentially triggering events. See
the following discussion regarding reconstruction and modification.
    Reconstruction and Modification. The EPA is proposing the following
changes from the November 2021 proposal related to definitions for
reconstruction and modification for storage vessels. This proposal
includes a definition of ``reconstruction'' as well as ``modification''
at 40 CFR 60.5365b(e)(3) for determining if an existing tank battery
becomes a storage vessel affected facility subject to NSPS OOOOb. The
proposed rule will apply to sources that are new, reconstructed, and
modified sources after November 15, 2021. In the November 2021 proposal
the EPA discussed our rationale for proposing specific actions which
lead to an increase in VOC and methane emissions and therefore,
constitute a modification of an existing tank battery. Generally, that
rationale was to provide clarity on actions which are considered a
modification of a tank battery. See 86 FR 63198 (November 15, 2021).
    In this proposed rule, the EPA is proposing two actions which
constitute reconstruction: (1) Over half of the storage vessels are
replaced in an existing tank battery that consists of more than one
storage vessel; or (2) the provisions of 40 CFR 60.15 are met for the
existing tank battery that consists of a single storage vessel. Section
60.15 of the General Provisions to part 60 states that reconstruction
occurs when the replacement of new components exceeds 50 percent of the
capital cost that would be required to construct a comparable entirely
new facility and it is technologically and economically feasible to
meet the applicable standard under part 60. Reconstruction applies
irrespective of any change in emissions rate. ``Fixed'' capital cost is
further defined at 40 CFR 60.15(c) as the capital needed to provide all
of the depreciable components and 40 CFR 60.15(g) allows for individual
subparts to include specific provisions to refine or delimit the
concept of reconstruction. Finally, 40 CFR 60.15(d) and (e) provide
that the owner or operator must notify the Administrator prior to the
proposed replacement with an estimate of the fixed capital cost of
replacement (among other items, see 40 CFR 60.15(d)) and upon receipt,
the Administrator will determine if the proposed replacement
constitutes reconstruction.
    Based on our experience from NSPS OOOO and NSPS OOOOa, the
predominant type of storage vessel expected to be covered by the
proposed NSPS are fixed roof storage vessels, and as part of the
storage vessel affected facility, have limited depreciable components
beyond the storage vessel itself (e.g., thief hatches and pressure
relief devices). Because the EPA expects that each affected facility
will undertake similar fixed capital cost replacements at storage
vessel affected facilities, namely replacing one or more storage
vessels, replacing thief hatches, and replacing pressure relief
devices, we believe that it will serve as a burden reduction to
industry to establish uniform criteria which constitute reconstruction.
For a tank battery which consists of a single storage vessel, it may be
possible that the cost of replacing the thief hatch, pressure relief
device or other depreciable components could exceed 50 percent of the
cost of an entirely new storage vessel, therefore the EPA is proposing
that the provisions of 40 CFR 60.15 would apply. The EPA requests
comment on this assumption that the costs of replacement of all
depreciable components on a single storage vessel could exceed 50
percent of the cost of an entirely new storage vessel. For a tank
battery which consists of more than a single storage vessel, we believe
that the cost of replacing storage vessel components such as thief
hatches and pressure relief devices, in comparison to the cost of
constructing

an entirely new storage vessel affected facility, will not exceed 50
percent of the cost of constructing a comparable new storage vessel
affected facility. Therefore, the EPA is proposing to simplify and
streamline the reconstruction determination for tank batteries by
defining reconstruction at a tank battery with more than a single
storage vessel as replacement of 50 percent of the storage vessels in
the tank battery. This defined reconstruction action will eliminate the
need for the owner or operator to submit the notification in 40 CFR
60.15(d) and await the EPA's response under 40 CFR 60.15(e), before
undertaking a replacement.
    An important factor in determining whether over 50 percent of the
storage vessels in an existing tank battery has been replaced is the
time period for making such assessment. Consider the following
scenario: an owner replaces one-third of the storage vessels in an
existing tank battery and, shortly thereafter, replaces another third
of the storage vessels in that tank battery. The owner has replaced 60
percent of the storage vessels in that tank battery in total; however,
without specifying the time frame for assessing reconstruction, it is
unclear whether the tank battery is ``reconstructed'' because over half
of the storage vessels in the tank battery have been replaced, or the
replacements are two separate programs and therefore should not be
aggregated for purposes of determining reconstruction. For the reasons
discussed in section IV.D and IV.E of this preamble, the EPA is
proposing to interpret natural gas-drive pneumatic controller and
pneumatic pump replacements to include all natural gas-driven pneumatic
controllers and pneumatic pumps which commence replacement (but are not
necessarily completed) within any 2-year period in determining whether
the replacements constitute reconstruction. The EPA solicits comment on
whether to similarly set a specific time period (or rolling time
period) within which replaced storage vessels in an existing tank
battery will be aggregated towards determining whether the 50 percent
replacement threshold has been exceeded, and if so, whether a 2-year
time frame or another time frame is appropriate for determining
reconstruction to a tank battery with more than a single storage
vessel.
    Related to modifications, the EPA explained in the November 2021
proposal that actions occurring at a well site, such as refracturing a
well or adding a new well that sends these liquids to the tank battery
at the well site or centralized production facility, would result in an
increase in VOC and methane emissions based on an increase in
volumetric throughput to the tank battery. See 86 FR 63199 (November
15, 2021). However, this does not always hold true for tank batteries
located at a compressor stations or onshore natural gas processing
plants. In the September 15, 2020, rule (see 85 FR 57404), the EPA
finalized a different framework for determining the potential for VOC
emissions from storage vessels located at compressor stations and
onshore natural gas processing plants, based on comments received on
the September 15, 2020, rule that storage vessels located at these
types of facilities are designed to receive liquids from multiple well
sites that may startup production over a longer period of time.\233\ To
account for this future throughput to the storage vessels, compressor
stations and natural gas processing plants use analysis based on the
future maximum throughput capacity which is then used to obtain
permits. Therefore, the EPA agrees that when a tank battery at a
compressor station or onshore natural gas processing plant receives
additional throughput which has already been accounted for in the
design capacity of that tank battery and included as a legally and
practically enforceable limit in a permit for the tank battery, that
additional throughput does not result in an emission increase from the
tank battery because those emissions have already been accounted for in
the permit.
---------------------------------------------------------------------------

    \233\ See Document ID No. EPA-HQ-OAR-2017-0473-1261.
---------------------------------------------------------------------------

    In summary, the EPA is proposing that a modification occurs to an
existing tank battery located at a well site or centralized production
facility when the tank battery receives additional crude oil,
condensate, intermediate hydrocarbons, or produced water throughput and
the potential for VOC or methane emissions increases above the
applicable thresholds. Separately, the EPA is proposing that a
modification occurs to an existing tank battery located at a compressor
station or onshore natural gas processing plant when the tank battery
receives additional fluids which cumulatively exceed the throughput
used in the most recent determination for VOC or methane missions
(e.g., permit) based on the design capacity of such tank battery. In
addition, as proposed in November 2021, modification is also triggered
by the following two events: (1) A storage vessel is added to an
existing tank battery; and/or (2) one or more storage vessels are
replaced such that the cumulative storage capacity of the existing tank
battery increases.
    One commenter expressed concerns that the change to a tank battery
(in NSPS OOOOb) versus a single tank (in NSPS OOOOa) will cause
confusion with the requirements of NSPS OOOOa because it creates a
disconnect with how the previous NSPS for this source category applies
the affected facility status to storage tanks. The commenter states
that creating separate ``classifications'' within the NSPS based on
dates of construction or modification will create additional burden
when reviewing authorizations within the specified legislatively
mandated time frames.\234\ The EPA discusses the interplay and
effective dates between prior standards applicable to the Crude Oil and
Natural Gas source category in sections III.B, III.C and III.D of this
preamble. However, to address specific questions regarding
applicability to storage vessels which may be subject to NSPS OOOO,
NSPS OOOOa, or EG OOOOc, the EPA is providing a discussion of
applicability for several anticipated scenarios which may be triggered
by a potential modification action described above. For purposes of the
scenarios below, the EPA is using the proposed definition of a tank
battery, which includes a single storage vessel if only one storage
vessel is present.
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    \234\ See Document ID No. EPA-HQ-OAR-2021-0317-0763.
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    Scenario One--An existing tank battery has the potential for
methane emissions greater than or equal to 20 tpy methane, therefore it
is a designated facility for purposes of EG OOOOc. Subsequently, one of
the proposed physical or operational changes in NSPS OOOOb at 40 CFR
60.5365b(e)(3)(ii) (i.e., adds a storage vessel to an existing tank
battery; adds capacity to an existing tank battery; or receives
additional fluids) occurs. In order to determine if modification has
occurred to the existing tank battery, the owner or operator would
calculate the potential for VOC and methane emissions in accordance
with the proposed 40 CFR 60.5365b(e)(2). If the potential for either
VOC or methane is above the proposed threshold, the tank battery is a
modified storage vessel affected facility subject to NSPS OOOOb. If the
potential for both VOC and methane is not above the threshold, the tank
battery is not a modified (or reconstructed) storage vessel affected
facility for purposes of NSPS OOOOb and remains a designated facility
for purposes of EG OOOOc.

    Scenario Two--An existing tank battery is not a designated facility
under EG OOOOc (i.e., the potential for methane emissions is less than
20 tpy). Like scenario 1, subsequently, one of the proposed physical or
operational changes in NSPS OOOOb occurs and the owner or operator
calculates the potential for VOC and methane emissions. If the
potential for either VOC or methane emissions is above the proposed
threshold, the tank battery is a modified storage vessel affected
facility subject to NSPS OOOOb. If the potential for both VOC and
methane is not above the proposed threshold, the tank battery is not a
modified storage vessel affected facility for the purposes of NSPS
OOOOb and is also not a designated facility under EG OOOOc.
    Scenario Three--An existing storage vessel is a single storage
vessel subject to either NSPS OOOO or NSPS OOOOa and is part of a tank
battery. One of the proposed physical or operational changes in NSPS
OOOOb occurs and the owner or operator calculates the potential for VOC
and methane emissions from the entire tank battery. If the potential
for either VOC or methane is above the threshold, the tank battery is a
modified storage vessel affected facility subject to NSPS OOOOb, and
the single storage vessel would continue to be subject to the
applicable NSPS OOOO or NSPS OOOOa. However, where a facility is
subject to multiple standards, the general practice is to streamline
compliance by complying with the more stringent standard, which would
in effect meet the less stringent standards. If the potential for both
VOC and methane is not above the proposed threshold, the single storage
vessel is not modified for the purposes of NSPS OOOOb and remains
subject to NSPS OOOO or NSPS OOOOa.
    Scenario Four--An existing storage vessel is a single storage
vessel and is subject to either NSPS OOOO or NSPS OOOOa. The single
storage vessel is not a designated facility under EG OOOOc because the
potential for methane emissions is less than 20 tpy. One of the
proposed physical or operational changes in NSPS OOOOb occurs and the
owner or operator calculates the potential for VOC and methane
emissions from the single storage vessel. If the potential for either
VOC or methane is above the proposed threshold, the single tank is a
tank battery which is a modified storage vessel affected facility
subject to NSPS OOOOb, as well as NSPS OOOO or NSPS OOOOa. Where a
facility is subject to multiple standards, the general practice is to
streamline compliance by complying with the more stringent standard,
which would in effect meet the less stringent standards; however,
streamlining may not be necessary here if the EPA finalized the
proposed 95 percent reduction, which is the storage vessel standard in
NSPS OOOO and NSPS OOOOa. If the potential for both VOC and methane is
not above the threshold, the single tank is not modified for the
purposes of NSPS OOOOb and remains subject to NSPS OOOO or NSPS OOOOa.
    Removed From Service. Finally, in NSPS OOOO and NSPS OOOOa, the EPA
includes provisions to address the status of storage vessel affected
facilities which are physically isolated and disconnected from the
process for purposes other than maintenance, which is referred to as
``removed from service''.\235\ Those regulations also include a
framework for determining the affected facility status of such storage
vessels when they are ``returned to service'', either by: (1) Being
reconnected to the original source of liquids, (2) used to replace any
storage vessel affected facility, or (3) installed in any location
covered by the subpart and introduced with crude oil, condensate,
intermediate hydrocarbon liquids or produced water. The EPA is
including these same provisions in the proposed NSPS OOOOb for
situations where there is more than one storage vessel in a tank
battery and the entire tank battery is removed from or returned to
service. Additionally, the EPA is proposing language to address
situations when only a portion of the tank battery is removed from, or
returned to, service. Specifically, the EPA is proposing to require
complete emptying and degassing of the entire tank battery, or the
portion of the tank battery that is being removed, for it to be
considered ``removed from service''. Submission of a notification that
these emptying and degassing requirements are met would also be
required. Further, when a portion of a storage vessel affected facility
is removed from service, in addition to the requirements above, the
portion of the tank battery must be disconnected from the tank battery
such that the portion is no longer manifolded to the tank battery by
liquid or vapor transfer. When a tank battery is returned to service,
it would retain the same applicability status that applied prior to
removal from service. For tank batteries where only a portion of the
tank battery is returned to service and it is reconnected to the
original source of liquids, it remains a storage vessel affected
facility subject to the same requirements that applied before being
removed from service. If a storage vessel is used to replace a storage
vessel affected facility, or portion of a storage vessel affected
facility, or used to expand a storage vessel affected facility, it
assumes the affected facility status of the storage vessel affected
facility being replaced or expanded.
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    \235\ See 78 FR 58435 (September 23, 2013), 79 FR 79022
(December 31, 2014), 80 FR 48262 (August 12, 2015), and 81 FR 35824
(June 3, 2016).
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    Request for Additional Comment. In addition to the proposed changes
or clarifications described above, the EPA is soliciting comment on
including a requirement to equip thief hatches with alarms, automated
systems to monitor for pressure changes, or use of automatically
closing thief hatches. Commenters noted that open thief hatches and
deteriorated seals around tank openings are significant emissions
sources at tank batteries. The EPA is aware that some owners and
operators utilize automated systems to alert when pressure changes
occur that could signal an open thief hatch. Additionally, where
automated systems are not available, there are alarms that could be
utilized to alert (via audible alarm or remote notification to the
nearest field office) that an unseated thief hatch is present.\236\ The
EPA is soliciting information on the costs, operation, and feasibility
of installing these automated systems, alarms, or the use of
automatically closing thief hatches.
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    \236\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
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c. Summary of Proposed Requirements
    In this proposed rule, owners and operators of storage vessel
affected facilities must reduce methane and VOC emissions by 95
percent. Consistent with provisions of NSPS OOOO and NSPS OOOOa, the
proposed rule also includes the option where if the owner or operator
maintains the uncontrolled actual VOC emissions at less than 4 tpy and
the actual methane emissions at less than 14 tpy as determined monthly
for 12 consecutive months, controls are no longer required. Storage
vessel affected facilities which use a control device to reduce
emissions must equip each storage vessel in the tank battery with a
cover and manifold all storage vessels in the tank battery such that
all vapors are shared among the headspaces of the storage vessel
affected facility. The tank battery must be equipped with a CVS which
routes all emissions to a control device. The proposed rule would
require that when using a flare, the flare must meet the requirements
in 40 CFR 60.18, which the EPA is proposing to strengthen by including
additional

requirements (as discussed in section IV.H of this preamble), and that
monitoring, recordkeeping, and reporting be conducted to ensure that
the flare is constantly achieving the required 95 percent reduction.
More information on the control device monitoring and compliance
provisions is provided in section IV.G of this preamble; additionally,
notifications made through the super-emitter response program could
help identify potential violations as provided in section IV.C of this
preamble. If the storage vessel affected facility does not have
flashing emissions and is not located at a well site or centralized
production site, the owner or operator may use an internal or external
floating roof to reduce emissions.
    In each annual report, owners and operators would be required to
identify each storage vessel affected facility that was constructed,
modified, or reconstructed during the reporting period and must
document the emission rates of both VOC and methane individually. The
annual report must include deviations that occurred during the
reporting period and information for control devices tested by the
manufacturer or the date and results of the control device performance
test for control devices not tested by the manufacturer. The report
also must include the results of inspections of covers and CVS and the
identification of storage vessel affected facilities (or portion of
storage vessel affected facility) removed from service or returned to
service. For storage vessel affected facilities which comply with the
uncontrolled 4 tpy VOC limit or 14 tpy methane limit, the report must
include changes which resulted in the source no longer complying with
those limits and the dates that the source began to comply with the 95
percent reduction standard.
    Required records include documentation of the methane and VOC
emissions determination and methodology, records of deviations and
duration, records for the number of consecutive days a skid-mounted or
permanently mobile-mounted storage vessel is on the site, the latitude
and longitude coordinates of each storage vessel affected facility, and
records associated with a manufacturer tested control device. Required
records also include records demonstrating continuous compliance
including inlet gas flow rate, presence of pilot flame, operation with
no visible emissions, maintenance and repair logs, manufacturer's
operating instructions, and dates that each storage vessel affected
facility (or portion of storage vessel affected facility) is removed
from service or returned to service. For storage vessel affected
facilities which comply with the uncontrolled 4 tpy VOC or 14 tpy
methane limit, records of changes which resulted in the source no
longer complying with those limits and the dates that the source began
to comply with the 95 percent reduction standard, including records of
the methane and VOC determination and methodology. All associated
records that demonstrate proper design and operation of the CVS, cover
and control device also must be maintained (see section IV.G and IV.J.
of this preamble).
2. EG OOOOc
    The EPA is also proposing presumptive standards to reduce methane
for existing storage vessel affected facilities in this action that
remain unchanged from the November 2021 proposal and are similar to
those proposed for NSPS OOOOb. Because the BSER for reducing VOC and
methane emissions are the same, the proposed presumptive standard is to
reduce methane emissions by 95 percent. Some commenters expressed that
creating separate classifications (e.g., tank batteries vs single
tanks) within the NSPS based on dates of construction or modification
will create additional burden when reviewing authorizations within the
specified legislatively mandated time frames. Another commenter
requested that EPA clarify whether other individual storage vessels in
an existing tank battery remain affected facilities under NSPS OOOO or
NSPS OOOOa, as applicable, or become part of the modified tank battery
under NSPS OOOOb.\237\ The EPA discusses the interplay and effective
dates between prior standards applicable to the Crude Oil and Natural
Gas source category in sections III.B, III.C and III.D of this preamble
and provides example scenarios, which the EPA believes will provide
guidance to regulators and the regulated community.
---------------------------------------------------------------------------

    \237\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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K. Covers and Closed Vent Systems

1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, the EPA proposed CVS requirements
for certain affected facilities to ensure that emissions are captured
and routed to a process or control device, dependent on the standard
for the affected/designated facility. The affected/designated
facilities for which the EPA proposed the use of a CVS were wells (oil
wells when routing associated gas to a control device), storage
vessels, centrifugal compressors (wet seal), reciprocating compressors,
pneumatic pumps, and process unit equipment affected/designated
facilities. Additionally, for storage vessels using a control device to
reduce emissions and centrifugal compressors with wet seals using a
degassing system, the EPA proposed the use of covers to form a
continuous impermeable barrier over the entire surface area of the
liquid in the storage vessel or the centrifugal compressor wet seal
fluid degassing system. The cover requirements ensure that all
emissions are captured from those emissions sources and routed through
a CVS to a control device, or in the case of centrifugal compressors,
to a control device or to a process. This section discusses the cover
and CVS requirements for those affected/designated facilities that are
located at well sites, centralized production facilities, and
compressor stations. See the discussion on CVS in section IV.L of this
preamble for covers and CVS located at natural gas processing plants.
    In the November 2021 proposal, the EPA proposed that covers and CVS
must be designed and operated with no detectable emissions (NDE).
Further, the EPA proposed that where a CVS is used to route emissions
from an affected facility, the owner or operator would demonstrate
there are no detectable emissions from the covers and CVS through OGI
or EPA Method 21 monitoring conducted during the fugitive emissions
survey. Where emissions are detected, the emissions would be considered
a violation of the NDE standard and thus a deviation,\238\ and
corrective actions to complete all necessary repairs as soon as
practicable would be required. The EPA also solicited comment on
whether to include the option to continue utilizing monthly AVO surveys
as demonstrations of NDE from a CVS associated with a pneumatic pump
but did not propose that option specifically. We stated that because we
anticipated that CVS associated with pneumatic pumps would be located
at well sites subject to fugitive emissions monitoring, the monthly AVO
option was not necessary. However, we solicited comment on whether
there are circumstances where a CVS associated with a pneumatic pump is
located at a well site not otherwise subject to

fugitive emissions monitoring and where OGI (or EPA Method 21) would be
an additional burden.
---------------------------------------------------------------------------

    \238\ A deviation includes any instance in which an affected
source fails to meet any emission limit, operating limit, or work
practice standard; a deviation suggests potential violation with the
applicable performance standard.
---------------------------------------------------------------------------

b. Changes From November 2021 Proposal
    In this supplemental proposal, the EPA is proposing specific
revisions to the requirements for CVS associated with the affected/
designated facilities located at well sites, centralized production
facilities, and compressor stations in the proposed NSPS OOOOb and EG
OOOOc. First, the EPA is proposing the same design and operational
requirements for all CVS when routing emissions to a control device or
when routing emissions to a process, regardless of which affected/
designated facility is using the CVS. These proposed standards would
apply to wells (oil wells when routing associated gas to a control
device), centrifugal compressor, reciprocating compressor, pneumatic
controller, pneumatic pump, storage vessel, and process unit equipment
affected/designated facilities. See section IV.L of this preamble for
additional discussion related to process unit equipment affected/
designated facilities at onshore natural gas processing plants.
    For these affected/designated facilities, the EPA is proposing the
capture and routing of emissions through a CVS to a control device or
process as part of the BSER, or an alternative to the BSER for specific
situations such as technical infeasibility to apply BSER. The EPA finds
that the demonstration of continuous compliance for these CVS should
include the same robust standards to ensure the CVS are designed and
operated to capture and route all emissions to the control device
regardless of which affected/designated facility is using the CVS. The
proposed standards for CVS include upfront engineering (Professional
Engineer or in-house engineer) design analysis and certifications, an
emissions limit that requires design and operation with no identifiable
emissions, initial and periodic inspections of the CVS, and continuous
monitoring of CVS bypass systems (unless equipped with a seal or
closure mechanism). Therefore, in this proposal, the EPA is
standardizing the design and operational requirements for CVS,
regardless of their location or use (route to a control device or route
to a process).
    The EPA is proposing to change the design and operational
requirements for CVS (except for those associated with self-contained
pneumatic controllers) from operation with NDE to operation with no
identifiable emissions. The proposed change of terminology is not
intended to change the stringency of the CVS requirements, which
require that each CVS capture and route all gases, vapors, and fumes to
a control device or a process, but it will clarify the design and
operational standards, and the obligations on the part of the owner or
operator if a leak is detected from the CVS during the inspections to
ensure compliance with the no identifiable emissions standard.
    Based on comments received on the November 2021 proposal, there
appears to be confusion whether the proposed NDE standard would be an
emissions limit or a work practice standard. For example, one commenter
\239\ stated that as written, the NDE standard would be a work practice
standard because ``[a]s with all other fugitive emissions components,
detection of a leak (in this case, defined as detectable emissions)
through routine LDAR monitoring triggers the obligation to repair the
leak. If that repair is accomplished according to the specific
requirements in the rule, then there is no violation because the work
practice has been fully implemented.'' This interpretation of the
standard is not correct. In fact, CVS must be designed and operated to
route all gases, vapors, and fumes to a control device or to a process,
which is defined as an emission limit of NDE. The corrective actions
(in the form of the repair provisions) are provided to ensure that
owners and operators bring the CVS back into compliance with the NDE
emission limit as quickly as possible.
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    \239\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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    Past efforts in NSPS OOOO and NSPS OOOOa to apply an NDE standard
as an emission limitation, while still allowing repair, delay of repair
or exceptions for unsafe and difficult to inspect equipment, may appear
to condone a ``grace period'' during which compliance with an emissions
limit is not required. Because the NDE standard in NSPS OOOO and NSPS
OOOOa was established as an emissions limit, operation in exceedance of
that limit is a deviation,\240\ even if the repair provisions are
followed.
---------------------------------------------------------------------------

    \240\ A deviation signals possible violation with the
performance standard for an affected facility because compliance is
no longer demonstrated due to such exceedance.
---------------------------------------------------------------------------

    Similarly, the EPA is proposing an emissions limit for covers and
CVS in this supplemental proposal for NSPS OOOOb and EG OOOOc. However,
NDE is a term closely linked with EPA Method 21, and is defined based
on an instrument reading in units of ppmv. Because the EPA is proposing
compliance inspections for covers and CVS using optical gas imaging and
AVO, no instrument reading in ppmv is available. Therefore, the EPA is
proposing the design and operational standard as an emissions limit of
no identifiable emissions, which is more appropriate for the methods of
detection required.
    To ensure compliance with the no identifiable emissions design and
operational standard for covers and CVS located at well sites,
centralized production facilities, and compressor stations, the EPA is
proposing that owners or operators would conduct initial and quarterly
OGI inspections (except for the Alaska North Slope which is annually).
Any identified emissions would be a violation of this emissions limit
and would be subject to repair with a first attempt completed within 5
days and final repair within 30 days of identification. If the owner or
operator is using the EPA Method 21 alternative for their fugitive
emissions components, then any instrument reading greater than 500 ppmv
above background is considered identified emissions, would be a
potential violation of the no identifiable emissions standard, and
would require repair within the same 5- and 30-day timeframe to bring
the CVS back into compliance.
    The EPA is also proposing to require AVO inspections for CVS and
covers located at well sites, centralized production facilities and
compressor stations. The EPA is proposing that AVO inspections of CVS
and covers must occur at the same frequency specified for fugitive
emissions components affected facilities located at the same type of
site. As discussed in section IV.A.1.a.ii of this preamble, the EPA is
proposing that CVS and covers located at a well site, centralized
production facility, or compressor station site, which are not
associated with a well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, or storage vessel
affected facility, are fugitive emissions components and subject to
those standards, which include periodic OGI (or EPA Method 21 as an
alternative) and monthly or bimonthly AVO inspections. Because we are
aligning the CVS associated with well, centrifugal compressor,
reciprocating compressor, pneumatic controller, pneumatic pump, or
storage vessel affected facilities inspections with the frequency of
inspections under the fugitives program, there should be no additional
cost associated with conducting these AVO inspections of CVS that are
not fugitive emissions

components at the same time and at the same place, and we believe that
identifying and repairing such leaks is consistent with the proposed
requirement at 40 CFR 60.5370b(b) in a manner consistent with good air
pollution control practice for minimizing emissions. See section IV.A
of this preamble for a full discussion of the fugitive emissions
requirements.
    The EPA did not receive comment in response to our request
regarding the burden of OGI (or EPA Method 21) monitoring for CVS
associated with pneumatic pumps at well sites. Therefore, the EPA is
not proposing separate standards for those CVS associated with
pneumatic pumps and is proposing consistent standards for all CVS
associated with affected/designated facilities under NSPS OOOOb or EG
OOOOc.
    As discussed in section IV.D of this preamble, the EPA is proposing
that pneumatic controllers may comply with the zero-emission methane
and VOC standard for pneumatic controllers by installing a self-
contained pneumatic controller, which is a natural gas-driven
controller designed so that there are no emissions to the atmosphere.
These controllers are designated as ``no identifiable emissions'' in
the proposed rule. Because these are designed to contain all gases,
vapors, or fumes from the controller, the EPA finds it appropriate to
apply the same continuous compliance requirements to self-contained
controllers as those for covers and CVS described in this section. That
is, the EPA is proposing to require the operation of self-contained
pneumatic controllers with no identifiable emissions, as demonstrated
through quarterly OGI monitoring. Any emissions identified would be a
violation of the zero emissions standard. The repair requirements
described for CVS would also apply to bring the self-contained
pneumatic controller back into compliance with the zero emissions
standard.
    As discussed in section IV.B of this preamble, the EPA also is
proposing provisions for the use of alternative test methods that
employ alternative periodic screening technologies or continuous
monitoring systems. The EPA is proposing to allow use of alternative
test methods to replace the use of OGI for demonstrating continuous
compliance of the no identifiable emissions standard for covers and
CVS. The EPA recognizes that the allowable minimum detection thresholds
of the screening technologies used in the alternative periodic
screening approach may not be capable of identifying all of the
potential emissions from these sources; however we find that well
designed, maintained, and certified covers and CVS systems are not
prone to leaks, and the majority of emission events from these systems
can be attributed to short-term operational events or malfunctions that
would be at a level easily identified by screening technology meeting
the allowable minimum detection thresholds. The EPA considers the use
of more frequent surveys (monthly to quarterly) using approved
screening technologies and either annual (if required based on minimum
detection threshold and frequency) or OGI surveys resulting from
emissions detected during screening would ensure equivalent compliance
assurance of the no identifiable emissions standard as the quarterly
OGI surveys paired with monthly or bimonthly AVO inspections. The EPA
solicits comments on the use of the alternative periodic screening
approach as an alternative compliance assurance for covers and CVS
associated with affected/designated facilities, and we solicit comments
that the minimum detection thresholds summarized in Tables 20 and 21
(section IV.B of this preamble) are suitable for this purpose.
c. Summary of Proposed Requirements
    The EPA is proposing standards which apply to CVS at a well,
centrifugal compressor, reciprocating compressor, pneumatic controller,
pneumatic pump, storage vessel, or process unit equipment affected/
designated facility. The EPA also is proposing standards for covers at
a centrifugal compressor and storage vessel affected/designated
facility. This summary is limited to covers and CVS located at well
sites, centralized production facilities, and compressor stations.
Covers and CVS located at natural gas processing plants (process unit
equipment affected/designated facilities) are discussed in section IV.L
of this preamble.
    Each CVS must be designed and operated to capture and route all
gases, vapors, and fumes to a process or to a control device and comply
with an emissions limit of no identifiable emissions. Initial and
continuous compliance of the no identifiable emissions standard would
be demonstrated through OGI monitoring and AVO inspections conducted at
the same frequency as the fugitive emissions monitoring for the type of
site. Specifically, for the well sites and centralized production
facilities where a CVS is present, quarterly OGI and bimonthly AVO
would be required; for compressor stations, quarterly OGI and monthly
AVO would be required. If the CVS is equipped with a bypass, the bypass
must include a flow monitor and sound an alarm to alert personnel that
a bypass is being diverted to the atmosphere, or it must be equipped
with a car-seal or lock-and-key configuration to ensure the valve
remains in a non-diverting position. To ensure proper design, an
assessment must be conducted and certified by a qualified professional
engineer or in-house engineer. Covers must form a continuous
impermeable barrier over the entire surface area of the liquid in the
storage vessel or over the centrifugal compressor wet seal fluid
degassing system and each cover opening shall be secured in a closed,
sealed position (e.g., covered by a gasketed lid or cap) whenever
material is in the unit on which the cover is installed except during
those times when it is necessary to use an opening.
    Each CVS must be inspected using OGI or EPA Method 21 to ensure
that the CVS operates with no identifiable emissions. Annual visual
inspections to check for defects, such as cracks, holes, or gaps) must
be conducted and monthly (compressor stations) or bimonthly (well sites
and centralized production facilities) AVO inspections for leaks must
be conducted would be a potential violation of the no identifiable
emissions standard. Further, any leak detected would be subject to
repair, with a first attempt at repair at five days and final repair
within 30 days. While awaiting final repair, covers must have a gasket-
compatible grease applied to improve the seal. Delay of repair is
allowed where the repair is infeasible without a shutdown, or it is
determined that immediate repair would result in emissions greater than
delaying repair. In all instances, repairs must be completed by the end
of the next shutdown. Unsafe to inspect and difficult to inspect parts
of the closed vent system may be designated as such but must be
inspected according to a plan as frequently as possible, or every five
years, respectively.
    Records of CVS and cover inspections, CVS bypass monitoring, and
CVS design and certifications must be maintained. The CVS certification
must be submitted in the initial annual report. Because the
requirements for CVS and covers have been aligned for all affected
facilities which use a CVS or cover, a new reporting section has been
created to contain the similar requirements. Recordkeeping sections for
CVS inspections, covers, bypass monitoring and CVS design assessment
also have been created which are applicable to all sources which use
CVS and covers. This will streamline

compliance as all affected facilities using the CVS and cover
requirements of the rule will be subject to the same reporting and
recordkeeping requirements.

L. Equipment Leaks at Natural Gas Processing Plants

1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, the EPA proposed new standards of
performance for equipment leaks at natural gas processing plants by
revising the equipment leak standards for onshore natural gas plants to
apply more readily to process unit equipment that has the potential to
emit methane even though not ``in VOC service.'' The EPA also proposed
appendix K to provide a standard method for OGI monitoring, which
allowed the EPA to consider a wider range of LDAR programs when
evaluating BSER for equipment leaks at onshore natural gas processing
plants. Specifically, the EPA proposed to require bimonthly OGI
monitoring of valves, pumps, and connectors that have the potential to
emit methane and VOC following the protocol specified in the proposed
appendix K. As an alternative, the EPA proposed to allow for monthly
monitoring of pumps, quarterly monitoring of valves, and annual
monitoring of connectors that have the potential to emit methane and
VOC following EPA Method 21, with a leak defined as any instrument
reading above 2,000 ppm for pumps or 500 ppm for valves and connectors.
The EPA utilized a Monte Carlo analysis to compare these programs and
determined that they achieved equivalent emissions reductions. See 86
FR 63232 (November 15, 2021) for additional information. The November
2021 proposal also included requirements for a ``first attempt at
repair'' for all identified leaks within five days of detection, as
well as final repair completed within 15 days of detection (except when
delay would be allowed).
    Finally, in the November 2021 proposal, the EPA requested comments
on certain topics. First, we requested comment on ways to streamline
approval of alternative LDAR programs using remote sensing techniques,
sensor networks, or other alternatives for equipment leaks at onshore
natural gas processing plants, including whether providing an emission
reduction target and equipment leak modeling tool to simulate LDAR
under similar ``ideal'' program implementation conditions might
facilitate future equivalency determinations. Second, we requested
comment on: (1) Adding a requirement of OGI monitoring (or EPA Method
21 monitoring for sources opting for the alternative) on open-ended
valves or lines equipped with closure devices to ensure no emissions
are going to the atmosphere (e.g., to ensure the cap seals the open
end); and (2) allowing the use of OGI monitoring according to the
proposed appendix K, to demonstrate compliance with the no detectable
emissions requirements (in lieu of EPA Method 21) such as those for CVS
at onshore natural gas processing plants.
b. Changes From November 2021 Proposal
    In this supplemental proposal, the EPA is proposing specific
requirements for the individual process unit equipment type included in
the LDAR program at onshore natural gas processing plants. This section
describes those specific requirements for pressure relief devices,
open-ended valves or lines, and CVS.
    Pressure Relief Devices. Consistent with the November 2021
proposal, the EPA is proposing to require bimonthly OGI monitoring (or
quarterly EPA Method 21 monitoring, if the alternative is used) as well
as monitoring of each pressure relief device within 5 calendar days
after each pressure release to detect leaks using either OGI or EPA
Method 21. A leak is detected if any emissions are observed using OGI,
or if an instrument reading of 500 ppm or greater is provided using EPA
Method 21. The EPA is proposing this requirement instead of requiring a
NDE demonstration (which is also required in NSPS OOOOa) because after
reviewing the record to NSPS KKK (the original LDAR requirements for
onshore natural gas processing plants), it was clear that the basis for
the standards for pressure relief devices was a routine LDAR
program.\241\ Because we have determined that OGI is BSER for equipment
leaks at onshore natural gas processing plants, it is appropriate to
require bimonthly OGI monitoring for this process unit equipment. In
addition to this bimonthly OGI monitoring requirement, the EPA is also
proposing to require OGI monitoring of each pressure relief device
after each pressure release, as it is important to ensure the pressure
relief device has reseated and is not allowing emissions to vent to the
atmosphere. The EPA is soliciting comment on this change from a no
detectable emissions standard to a bimonthly monitoring requirement.
Where the EPA Method 21 option is used, we are proposing quarterly
monitoring of the pressure relief device in addition of monitoring
after each pressure relief. A leak is defined as an instrument reading
of 500 ppm or greater when using EPA Method 21.
---------------------------------------------------------------------------

    \241\ See 49 FR 2645 (January 24, 1984) and EPA-450/3-82-024b.
---------------------------------------------------------------------------

    Open-Ended Valves or Lines. For open-ended valves or lines, the EPA
is proposing to require closure devices to seal the open end,
consistent with the requirements in NSPS OOOOa. Consistent with the
November 2021 proposal, the proposed regulatory text would require this
equipment standard (i.e., cap, blind flange, plug, or a second valve)
for open-ended valves and lines. The EPA solicited comment on whether
to require bimonthly OGI monitoring for open-ended valves and lines in
the November 2021 proposal. We are not proposing to require routine
periodic monitoring for open-ended valves or lines. The primary control
requirement for open-ended valves or lines is a closure device (i.e.,
caps, blind flanges, plugs, or a second valve) and this standard is
designed to achieve nearly 100 percent emission reductions. While it is
possible that leaks past the closure device could occur, the EPA does
not believe it would be cost-effective to require a full LDAR program
for each open-ended valve or line, and has previously found this type
of requirement not cost-effective for this type of facility.\242\
However, the EPA recognizes that there are opportunities to identify
when there is a leak past the closure device as part of daily operating
duties or required OGI surveys for other process unit equipment.
Therefore, the EPA is proposing a requirement to complete repairs on an
open-ended valve or line so that the closure device seals the open end
of the valve or line when emissions are identified through any means.
The EPA notes that repairs for this type of leak are generally
straightforward (e.g., install new plug or cap) and cost-effective to
complete. Further, the repair is necessary to comply with the general
duty provisions of 40 CFR 60.5370b(b).
---------------------------------------------------------------------------

    \242\ See Document ID Nos. EPA-HQ-OAR-2010-0505-0045 and EPA-HQ-
OAR-2010-0505-7631.
---------------------------------------------------------------------------

    Closed Vent Systems. In NSPS OOOO and NSPS OOOOa, the EPA relied on
separate CVS requirements for ones located at an onshore natural gas
processing facility than those requirements for CVS used for other
purposes in NSPS OOOO and NSPS OOOOa. In this proposal, the EPA is
standardizing the requirements for CVS, as described in section IV.K of
this preamble, with one difference.
    For CVS associated with process unit equipment affected facilities
that are

used to route emissions from leaking equipment to a control device, the
EPA is proposing a requirement to monitor the CVS at the same frequency
(i.e., bimonthly OGI in accordance with appendix K or quarterly EPA
Method 21) as other equipment in the process unit and to repair any
leaks identified during the routine monitoring. Additionally, when
leaks are identified as part of daily operating duties by any means of
detection, we are proposing to require repairs in order to be
consistent with the good air pollution control practices for minimizing
emissions specified in 40 CFR 60.5370b(b). We believe it is most
efficient and cost effective to monitor the CVS at the same frequency
and according to the same methodology as other equipment in the process
unit equipment affected facility (i.e., bimonthly OGI in accordance
with appendix K or quarterly with EPA Method 21) and it is reasonable
and prudent to require any leaks identified to be repaired.
    These proposed standards differ from our November 2021 proposal,
which maintained EPA Method 21 inspections for CVS associated with
process unit equipment, consistent with what is required in NSPS OOOO
and NSPS OOOOa. Both NSPS OOOO and NSPS OOOOa require initial
monitoring of a CVS used to comply with the equipment leak standards
using EPA Method 21 followed by annual monitoring using visual
inspections for defects (if constructed of hard piping) or annually
using EPA visual inspections for defects and EPA Method 21 inspections
(if constructed of ductwork). In this supplemental proposal, the EPA is
proposing to allow initial monitoring using OGI in accordance with
appendix K (or EPA Method 21 as an alternative) and annual visual
methods for CVS where each joint, seam, or other connection is
permanently or semi-permanently sealed (hard piping). This approach for
initial instrument monitoring and annual visual monitoring for defects
is consistent with the hard-piping requirements in NSPS OOOO and NSPS
OOOOa and is also consistent with the requirements for other affected
facilities which use a hard-piped CVS to route to a control device.
    Potential To Emit Methane or VOC. Consistent with the November 2021
proposal, the EPA is proposing to apply the LDAR standards to process
unit equipment that has the potential to emit methane or VOC.\243\
Further, the EPA is proposing that each piece of equipment is presumed
to have the potential to emit methane or VOC unless an owner or
operator demonstrates that the piece of equipment does not have the
potential to emit methane or VOC. For a piece of equipment to be
considered not to have the potential to emit methane or VOC, the owner
or operator would need to demonstrate that the process fluids in
contact with the process unit equipment do not contain either methane
or VOC. Commenters \244\ suggested that the EPA maintain the 10 percent
by weight VOC concentration threshold and add a one percent by weight
methane concentration threshold so as to exclude ethane product
streams, produced water streams, and wastewater streams. However, no
additional data or analyses were provided to demonstrate that a
threshold of one percent by weight methane would be appropriate.
Further, recent studies indicate that produced water and wastewater
streams can be significant sources of VOC and/or methane
emissions.\245\ Therefore, the EPA maintains that a definition based on
the potential to emit VOC or methane is appropriate to determine which
process unit equipment must be monitored and repaired.
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    \243\ See 86 FR 63182 (November 15, 2021).
    \244\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
    \245\ ``Measurement of Produced Water Air Emissions from Crude
Oil and Natural Gas Operations.'' Final Report. California Air
Resources Board. May 2020. Available at: Measurement of Produced
Water Air Emissions from Crude Oil and Natural Gas Operations
(ca.gov).
    And ``Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-
2019: Updates for Produced Water Emissions.'' April 2021. Available
at: https://www.epa.gov/sites/default/files/2021-04/documents/2021_ghgi_update_-_water.pdf.
---------------------------------------------------------------------------

    Repair Requirements. In this supplemental proposal, the EPA is
proposing a definition of ``first attempt at repair'' consistent with
the November 2021 proposal, which means an action taken for the purpose
of stopping or reducing fugitive emissions to the atmosphere. First
attempts at repair include, but are not limited to, the following
practices where practicable and appropriate: tightening bonnet bolts;
replacing bonnet bolts; tightening packing gland nuts; or injecting
lubricant into lubricated packing. Further, we are proposing a
definition of ``repaired,'' specific to process unit equipment affected
facilities, meaning that equipment is adjusted, or otherwise altered,
in order to eliminate a leak, and is re-monitored to verify that
emissions from the equipment are below the applicable leak definition.
Pumps subject to weekly visual inspections which are designated as
leaking and repaired are not subject to remonitoring. We are adding
these definitions to clarify the requirements for leak repair
associated with process unit equipment. The EPA is not proposing to
require replacement of leaking equipment with low-emissions (``low-e'')
valves or valve packing or require drill-and-tap with a low-e
injectable because it is not appropriate for all valve repairs.
However, because this low-e equipment, which meets the specifications
of API 622 or 624, generally will include a manufacturer written
warranty that it will not emit fugitive emissions at a concentration
greater than 100 ppm within the first 5 years, we believe that they can
be a viable option for repair in some instances, as demonstrated by the
remonitoring requirements in the rule.
    As described in the November 2021 proposal, the EPA is proposing to
allow for delay of repair for leaks identified with OGI (or EPA Method
21), where it is technically infeasible to complete repairs within 15
days without a process unit shutdown. Generally, a process unit
shutdown will generate more emissions than allowing the leak to
continue; therefore, we are proposing to retain this delay of repair
provision.
    Alternative Use of EPA Method 21. As discussed in the November 2021
proposal, the EPA is proposing to allow the use of EPA Method 21 as an
alternative to the required OGI monitoring. However, unlike NSPS OOOO
and NSPS OOOOa, the EPA is not cross-referencing the requirements in
NSPS VVa and is instead proposing regulatory text which incorporates
the requirements directly into 40 CFR 60.5401b, with conforming changes
consistent with the OGI standards, as described above for pressure
relief devices, CVS, and repairs.
c. Summary of Proposed Requirements.
    The proposed standards will apply to the ``process unit equipment''
affected facility and will require that each piece of equipment that
has the potential to emit methane or VOC conduct bimonthly (i.e., once
every other month) OGI monitoring in accordance with appendix K to
detect equipment leaks from pumps, valves, connectors, pressure relief
devices, and CVS. As an alternative to the bimonthly OGI monitoring,
EPA Method 21 may be used to detect leaks from the same equipment as
frequencies specific to the process unit equipment type (e.g., monthly
for pumps, quarterly for valves).
    Furthermore, this proposed rule requires that any leaks identified
by AVO, or other detection methods from any equipment in any service,
including open-ended valves or lines, must be repaired. The proposed
rule includes

requirements for a first attempt at repair for all leaks identified
within five days of detection, and final repair completed within 15
days of detection (unless the delay or repair provisions are
applicable). Delay of repair would be allowed where it is technically
infeasible to complete repairs within 15 days without a process unit
shutdown.
    In addition to the monitoring and repair requirements summarized
above, this proposal includes requirements for specific types of
equipment. First, the EPA is proposing that each open-ended valve or
line must be equipped with a closure device (i.e., cap, blind flange,
plug, or a second valve) that seals the open end at all times except
during operations which require process fluid flow through the open-
ended valve or line. Next, CVS used to comply with the standards for
process unit equipment must be monitored bimonthly using OGI (or
quarterly using EPA Method 21 if the alternative is used). We are also
proposing that control devices used to comply with the equipment leak
provisions must comply with the requirements described in section IV.G
of this preamble.
    The EPA is proposing that pressure relief devices must be monitored
bimonthly using OGI (or quarterly using EPA Method 21 if the
alternative is used) and five days after a pressure release to ensure
the device has reseated after a pressure release. The proposed rule
allows exceptions to the five-day post-pressure release monitoring
requirement for pressure relief devices that are located in a
nonfractionating plant (instead, the pressure relief device may
monitored after a pressure release the next time monitoring personnel
are onsite, but in no event may it be allowed to operate for more than
30 calendar days after a pressure release without monitoring) or that
are routed to a process, fuel gas system or control device.
    This proposed rule requires AVO, or other detection methodologies
for pumps, valves, and connectors in heavy liquid service and pressure
relief devices in light liquid or heavy liquid service and requires
repair where a leak is found using any of those methods.
    Reporting would be required semiannually, which differs from the
reporting for other affected facilities in NSPS OOOOb. In the initial
semiannual report, the proposed rule will require the owner or operator
to identify: each process unit associated with the process unit
equipment affected facility; the number of each type of equipment
subject to the monitoring requirements; for each month of the reporting
period, the number of leaking equipment for which leaks were
identified, the number of leaking equipment for which leaks were not
repaired and the facts that explain each delay of repair; and dates of
process unit shutdowns.
    In subsequent semiannual reports, owners and operators would be
required to report the name of each process unit associated with the
process unit equipment affected facility; any changes to the process
unit identification or the number or type of equipment subject to the
monitoring requirements; for each month of the reporting period, the
number of leaking equipment for which leaks were identified, the number
of leaking equipment for which leaks were not repaired and the facts
that explain each delay of repair; and dates of process unit shutdowns.
    Required records in the proposed rule include inspection records
consisting of equipment identification, date and start and end times of
the monitoring inspection, inspector name, leak determination method,
monitoring instrument identification, type of equipment monitored,
process unit identification, appendix K records (if applicable), EPA
Method 21 instrument readings and calibration results (if applicable)
and, for visual inspections, the date, name of inspector and result of
inspection. For each leak detected, the proposed rule requires
reporting of the instrument and operator identification (or record of
AVO method, where applicable), the date the leak was detected, the date
and repair method applied for first attempts at repair, indication of
whether the leak is still detected, and the date of successful repair,
which includes results of a resurvey to verify repair. For each delay
of repair, the proposed rule requires that the equipment is identified
as ``repair delayed'' along with the reason for the delay, the
signature of the certifying official, and the dates of process unit
shutdowns which occurred while the equipment is unrepaired.
Additionally, the proposed rule requires records of equipment
designated for no detectable emissions; the identification of valves,
pumps, and connectors that are designated as unsafe-to-monitor, an
explanation stating why it is unsafe-to-monitor, and the plan for
monitoring that equipment; a list of identification numbers for valves
that are designated as difficult-to-monitor, an explanation stating why
it is difficult-to-monitor, and the schedule for monitoring each valve;
a list of identification numbers for equipment that is in vacuum
service and a list of identification numbers for equipment designated
as having the potential to emit methane or VOC less than 300 hr/yr.
Finally, for CVS and control devices used to control emissions from
process unit equipment affected facilities, the reports and records
that demonstrate proper design and operation of the control device also
must be maintained (see sections IV.G and IV.J. of this preamble).
2. EG OOOOc
    The application of an LDAR program at an existing source is the
same as at a new source because there is no need to retrofit equipment
at the site to achieve compliance with the work practice standard. The
cost effectiveness for implementing a bimonthly OGI LDAR program for
all process unit equipment that has the potential to emit methane is
approximately $850/ton methane reduced. As explained in section III.E
of this preamble, the cost effectiveness of this OGI monitoring option
is within the range of costs we believe to be reasonable for methane
reductions in this rule. Therefore, we consider a bimonthly OGI LDAR
program following appendix K that includes all process unit equipment
that have the potential to emit methane to be BSER for existing
sources. The presumptive standards that are proposed in this action are
the same as those described above for NSPS OOOOb.

M. Sweetening Units

    The EPA proposed to retain the standards found in NSPS OOOO and
NSPS OOOOa for reducing SO2 emissions from sweetening units
in the November 15, 2021, proposal. The EPA is proposing regulatory
text at 40 CFR 60.5405b through 60.5408b reflect the standards of
performance as proposed in the November 15, 2021, proposal. To clarify
and align compliance requirements (including recordkeeping and
reporting) for sweetening units with those of other affected
facilities, the EPA is proposing specific language at 40 CFR 60.5405b
which ``points'' the owner or operator to the appropriate compliance
requirement sections (i.e., those containing initial compliance,
continuous compliance, recordkeeping and reporting) and is proposing to
enumerate the initial compliance requirements (of the unchanged
standards) in section 40 CFR 60.5410b(i) and the continuous compliance
requirements (of the unchanged standards) at 40 CFR 60.5415b(k).

N. Recordkeeping and Reporting

    In the November 2021 proposal, the EPA proposed to require
electronic reporting of performance test reports, annual reports, and
semiannual reports through the Compliance and Emissions

Data Reporting Interface (CEDRI). CEDRI can be accessed through the
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). As noted in
that proposal, a description of the electronic data submission process
is provided in the memorandum Electronic Reporting Requirements for New
Source Performance Standards (NSPS) and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for
this action. The EPA also proposed to allow owners and operators the
ability to seek extensions for electronic reporting for circumstances
beyond the control of the facility (i.e., for a possible outage in CDX
or CEDRI or for a force majeure event).
    In this action, the EPA is not proposing any changes from what was
proposed in the November 2021 proposal. As noted in the November 2021
proposal, owners and operators would be required to use the appropriate
spreadsheet template to submit information to CEDRI for annual and
semiannual reports. A draft version of the proposed templates for these
reports is included in the docket for this action.\246\ The EPA
specifically requests comment on the content, layout, and overall
design of the templates.
---------------------------------------------------------------------------

    \246\ See Part_60_Subpart_OOOOb_60.5420b(b)_Annual_Report.xlsm
and Part_60_Subpart_OOOOb_60.5422b(b)_Semiannual_Report.xlsx,
available in the docket for this action.
---------------------------------------------------------------------------

V. Supplemental Proposal for State, Tribal, and Federal Plan
Development for Existing Sources

A. Overview

    In the November 2021 proposal, the EPA proposed EG for states to
follow in developing their plans to reduce emissions of GHGs (in the
form of limitations on methane) from designated facilities within the
Crude Oil and Natural Gas source category.\247\ That proposal provided
a general overview of the state planning process triggered by the EPA's
finalization of EG under CAA section 111(d), the EG process and
proposed state plan requirements in more detail, and solicited comment
on various issues related to the EG. In this supplemental proposal, the
EPA is proposing some adjustments from the November 2021 proposal, and
additional requirements to provide states with information needed for
purposes of state plan development. In the following sections, in the
same six-part ordering as the November 2021 proposal, we summarize and
rationalize the updated and new proposed requirements. The EPA is not
soliciting additional comment on aspects of the November 2021 proposed
EG that are not substantively addressed or changed in this supplemental
proposal.
---------------------------------------------------------------------------

    \247\ See 86 FR 63110 (November 15, 2021).
---------------------------------------------------------------------------

    First, we discuss changes to the proposed requirements for
establishing standards of performance in state plans in response to a
finalized EG. Second, we discuss changes to the proposed components of
an approvable state plan submission. Third, we discuss the proposed
timing for state plan submissions, and changes to the proposed timeline
for designated facilities to come into final compliance with the state
plan. While this section describes the requirements of the implementing
regulations under 40 CFR part 60, subpart Ba, proposes requirements for
states in the context of this EG, and solicits comments in the context
of this EG, nothing in this proposal is intended to reopen the
implementing regulations themselves for comment.

B. Establishing Standards of Performance in State Plans

    After the EPA establishes the BSER in the final EG, as described in
preamble section XII of the November 2021 proposal and preamble section
IV of this supplemental proposal, each state that includes a designated
facility must develop, adopt, and submit to the EPA its state plan
under CAA section 111(d). Under the Tribal Authority Rule (TAR) adopted
by the EPA, tribes may seek authority to implement a plan under CAA
section 111(d) in a manner similar to a state. See 40 CFR part 49,
subpart A. Tribes may, but are not required to, seek approval for
treatment in a manner similar to a state for purposes of developing a
tribal implementation plan (TIP) implementing the EG. The November 2021
proposal included proposed requirements regarding two key aspects of
implementation: establishing standards of performance for designated
facilities, and providing measures that implement and enforce such
standards. The November 2021 proposal additionally discussed and
solicited comments on accommodating state programs, remaining useful
life and other factors (RULOF), emissions inventories, and meaningful
engagement. In the subsections below, the EPA proposes updates to
certain presumptive standards included in the November 2021 proposal,
and further proposes requirements related to leveraging state programs,
RULOF, certain implementation and enforcement measures, emissions
inventories, and meaningful engagement with pertinent stakeholders. The
EPA believes these proposed requirements, in addition to those
described in the November 2021 proposal, will be necessary for states
to prepare their CAA section 111(d) state plans. The EPA is not
reopening for comment any aspect described in the November 2021
proposal that the EPA is not proposing to substantively address or
update in this supplemental proposal.
    The November 2021 proposal included proposed requirements regarding
two key aspects of implementation: establishing standards of
performance for designated facilities and providing measures that
implement and enforce such standards. The November 2021 proposal
additionally discussed and solicited comments on accommodating state
programs, RULOF, emissions inventories, and meaningful engagement. In
the following subsections, the EPA proposes updates to certain
presumptive standards included in the November 2021 proposal, and
further proposes requirements related to leveraging state programs,
RULOF, certain implementation and enforcement measures, emissions
inventories, and meaningful engagement with pertinent stakeholders. The
EPA believes these proposed requirements, in addition to those
described in the November 2021 proposal, will be necessary for states
to prepare their CAA section 111(d) state plans. The EPA is not
reopening for comment any aspect described in the November 2021
proposal that the EPA is not proposing to substantively address or
update in this supplemental proposal.

1. Establish Standards of Performance for Designated Facilities

    In the November 2021 proposal, the EPA proposed the degree of
emission limitation achievable through application of the BSER in the
form of presumptive standards for designated facilities.\248\ The EPA
described that there is a fundamental requirement under CAA section
111(d) that a state plan's standards of performance reflect the
presumptive standard, which derives from the definition of ``standard
of performance'' in CAA section 111(a)(1). The EPA is updating Tables
35 and 36 to reflect the updated presumptive standards in this
supplemental proposal.
---------------------------------------------------------------------------

    \248\ 86 FR 63249 (November 15, 2021).
    \249\ As described in section IV.C of this preamble, the EPA is
proposing a super-emitter response program under the statutory
rationale that super-emitters are a designated facility. The EPA is
also proposing the program under a second rationale that the super-
emitter response program constitutes work practice standards for
certain sources and compliance assurance measures for other sources.
Under either rationale, state plans are required to adopt the super-
emitter response program either as presumptive standards or as
measures that provide for the implementation and enforcement of such
standards.

  Table 35--Summary of Proposed EG Subpart OOOOc Presumptive Numerical
                                Standards
------------------------------------------------------------------------
                                         Proposed presumptive numerical
         Designated facility            standards in the draft emissions
                                              guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with     95 percent reduction of methane.
 PTE of 20 tpy or More of Methane.
Pneumatic Controllers: Natural gas-    Methane emission rate of zero.
 driven that Vent to the Atmosphere.
Pneumatic Pumps......................  Methane emission rate of zero.
Wet Seal Centrifugal Compressors       Volumetric flow rate of 3 scfm.
 (except for those located at well
 sites).
Dry Seal Centrifugal Compressors       Volumetric flow rate of 3 scfm.
 (except for those located at well
 sites).
Reciprocating Compressors (except for  Volumetric flow rate of 2 scfm.
 those located at well sites).
------------------------------------------------------------------------

Table 36--Summary of Proposed EG Subpart OOOOc Presumptive Non-Numerical
                                Standards
------------------------------------------------------------------------
                                           Proposed presumptive non-
         Designated facility            numerical standards in the draft
                                         emissions guidelines for GHGs
------------------------------------------------------------------------
Super-Emitters.......................  Root cause analysis and
                                        corrective action following
                                        notification by an EPA-approved
                                        entity or regulatory authority
                                        of a super-emitter emissions
                                        event.\249\
Fugitive Emissions: Single Wellhead    Quarterly AVO inspections. Repair
 Only Well Sites and Small Well Sites.  for indications of potential
                                        leaks within 15 days of
                                        inspection.
                                       Fugitive monitoring continues for
                                        all well sites until the site
                                        has been closed, including
                                        plugging the wells at the site
                                        and submitting a well closure
                                        report.
Fugitive Emissions: Multi-wellhead     Quarterly AVO inspections. Repair
 Only Well Sites (2 or more             for indications of potential
 wellheads).                            leaks within 15 days of
                                        inspection.
                                       Semiannual OGI monitoring
                                        (Optional semiannual EPA Method
                                        21 monitoring with 500 ppm
                                        defined as a leak).
                                       First attempt at repair within 30
                                        days of finding fugitive
                                        emissions. Final repair within
                                        30 days of first attempt.
                                       Fugitive monitoring continues for
                                        all well sites until the site
                                        has been closed, including
                                        plugging the wells at the site
                                        and submitting a well closure
                                        report.
Fugitive Emissions: Well Sites and     Well sites with specified major
 Centralized Production Facilities.     production and processing
                                        equipment: Quarterly OGI
                                        monitoring. (Optional quarterly
                                        EPA Method 21 monitoring with
                                        500 ppm defined as a leak).
                                       First attempt at repair within 30
                                        days of finding fugitive
                                        emissions. Final repair within
                                        30 days of first attempt.
                                       Fugitive monitoring continues for
                                        all well sites until the site
                                        has been closed, including
                                        plugging the wells at the site
                                        and submitting a well closure
                                        report.
Fugitive Emissions: Compressor         Monthly AVO monitoring.
 Stations.                             AND
                                       Quarterly OGI monitoring.
                                        (Optional quarterly EPA Method
                                        21 monitoring with 500 ppm
                                        defined as a leak).
                                       First attempt at repair within 30
                                        days of finding fugitive
                                        emissions. Final repair within
                                        30 days of first attempt.
Fugitive Emissions: Well Sites and     Annual OGI monitoring. (Optional
 Compressor Stations on Alaska North    annual EPA Method 21 monitoring
 Slope.                                 with 500 ppm defined as a leak).
                                       First attempt at repair within 30
                                        days of finding fugitive
                                        emissions. Final repair within
                                        30 days of first attempt.
Fugitive Emissions: Well Sites and     (Optional) Alternative periodic
 Compressor Stations.                   screening with advanced
                                        measurement technology instead
                                        of OGI monitoring.
Fugitive Emissions: Well Sites and     (Optional) Alternative continuous
 Compressor Stations.                   monitoring system instead of OGI
                                        monitoring.
Pneumatic Controllers: Alaska (at      Natural gas bleed rate no greater
 sites where onsite power is not        than 6 scfh.
 available--continuous bleed natural
 gas-driven).
Pneumatic Controllers: Alaska (at      OGI monitoring and repair of
 sites where onsite power is not        emissions from controller
 available--intermittent natural gas-   malfunctions.
 driven).
Gas Well Liquids Unloading...........  Perform liquids unloading with
                                        zero methane or VOC emissions.
                                        If this is not feasible for
                                        safety or technical reasons,
                                        employ best management practices
                                        to minimize venting of emissions
                                        to the maximum extent possible.
Equipment Leaks at Natural Gas         LDAR with OGI following
 Processing Plants.                     procedures in appendix K.

Oil Wells with Associated Gas........  Route associated gas to a sales
                                        line. If access to a sales line
                                        is not available, the gas can be
                                        used as an onsite fuel source or
                                        used for another useful purpose
                                        that a purchased fuel or raw
                                        material would serve. If
                                        demonstrated that a sales line
                                        and beneficial uses are not
                                        technically feasible, the gas
                                        can be routed to a flare or
                                        other control device that
                                        achieves at least 95 percent
                                        reduction in methane emissions.
------------------------------------------------------------------------

2. Leveraging State Programs
a. Overview
    In the November 2021 proposal, the EPA acknowledged that many
states have programs they may want to leverage for purposes of
satisfying their CAA section 111(d) state plan obligations (86 FR
63252; November 21, 2021). The EPA proposed that a state plan which
relies on a state program must establish standards of performance that
are in the same form as the presumptive standards. The EPA further
solicited comment on whether states relying on state programs should be
authorized to include a different form of standard in their plans so
long as they demonstrate the equivalency of such standards to the level
of stringency required under the final EG, and how such equivalency
demonstrations can be made in a rigorous and consistent way.
    The EPA also proposed to require that, in situations where a state
wishes to rely on state programs (statutes and/or regulations) that
pre-date finalization of the EG proposed in this document to satisfy
the requirements of CAA section 111(d), the state plan should identify
which aspects of the state programs are being submitted for approval as
federally enforceable requirements under the plan, and include a
detailed explanation and analysis of how the relied upon state programs
are at least as stringent as the requirements of the final EG. The EPA
noted that the completeness criteria in 40 CFR 60.27a(g) requires a
copy of the actual state law/regulation or document submitted for
approval and incorporation into the state plan. Put another way, where
a state is relying on a state program for its plan, a copy of the pre-
existing state statute or regulation underpinning the program would be
required by this criterion and would be a critical component of the
EPA's evaluation of the approvability of the plan. The EPA solicited
comment on various ways in which state programs can be adopted into
state plans particularly in situations where state programs that
regulate both designated facilities and sources not considered as
designated facilities under this EG could be tailored for a state plan
to meet the requirements of CAA section 111(d).
    The EPA believes that for states to successfully leverage their
state programs to satisfy their CAA section 111(d) state plan
obligations, specific criteria need to be identified for states and the
EPA to follow in determining that a state plan meets the level of
stringency required under the final EG, and how such equivalency
demonstrations can be made in a rigorous and consistent way. The EPA is
proposing such criteria for a source-by-source equivalency
determination in this supplemental proposal.
    Some commenters requested that the EPA make an equivalency
determination on a programmatic, rather than source-specific basis.
Some of these commenters suggested that the EPA approve plans that are
as stringent as EG even if they do not include identical standards or
sources.\250\ Commenters also suggested that the EPA allow states to
include a different form of numerical standard as long as it is
determined to be equivalent.\251\ In addition to the suggestion
provided, some commenters argued that the EPA is not authorized to
approve state limitations that were not derived using CAA section
111(d) standard setting methods.
---------------------------------------------------------------------------

    \250\ See Docket ID Nos. EPA-HQ-OAR-2021-0317-0581, EPA-HQ-OAR-
2021-0317-0775, EPA-HQ-OAR-2021-0317-0926, and EPA-HQ-OAR-2021-0317-
1267.
    \251\ See Docket ID Nos. EPA-HQ-OAR-2021-0317-0558, EPA-HQ-OAR-
2021-0317-0761, EPA-HQ-OAR-2021-0317-0769, and EPA-HQ-OAR-2021-0317-
1267.
---------------------------------------------------------------------------

    The following sections discuss EPA's proposal for how states with
programs that regulate GHGs in the form of methane from oil and natural
gas sources may establish source-by-source equivalency with the EPA's
designated facility presumptive standards under EG OOOOc. Consistent
with that discussion, the EPA is also proposing to interpret CAA
section 111 to authorize states to establish standards of performance
for their sources that, in the aggregate, would be equivalent to the
presumptive standards. The 2019 Affordable Clean Energy (ACE) Rule
interpreted CAA section 111 to require that each state establish for
each source a standard of performance that reduces that source's
emissions, and to preclude the type of compliance flexibility that the
EPA is now proposing. 84 FR 32556-57 (July 8, 2019). In 2021, the D.C.
Circuit vacated the ACE Rule, holding, among other things, that CAA
section 111(d) does not preclude states from allowing certain
compliance flexibilities, including trading or averaging of emission
limits. American Lung Ass'n v. EPA, 985 F.3d 914, 957-58 (D.C. Cir.
2021). In 2022, the U.S. Supreme Court reversed the D.C. Circuit's
judgment regarding the ACE Rule's embedded repeal of the Clean Power
Plan on other grounds. West Virginia v. EPA, 142 S. Ct. 2587 (2022).
The Supreme Court made clear that CAA section 111 authorizes the EPA to
determine the BSER and the amount of emission limitation that state
plans must achieve, id. at 2601-02, but the Supreme Court did not
address the D.C. Circuit's interpretation of CAA section 111 as to the
state's compliance flexibilities. Id. at 2615-16.
    The EPA has reconsidered the ACE Rule's interpretation of CAA
section 111, and now disagrees with it. Section 111(d) does not, by its
terms, preclude states from having flexibility in determining which
measures will best achieve compliance with the EPA's emission
guidelines. Such flexibility is consistent with the framework of
cooperative federalism that CAA section 111(d) establishes, which vests
states with substantial discretion. CAA section 111(d) thus permits
each state, when appropriate, to adopt measures that allow its sources
to meet their emission limits in the aggregate. In addition, the EPA
agrees with the separate set of reasons that the D.C. Circuit gave in
holding that CAA section 111(d) does not preclude a state from allowing
its sources compliance flexibilities. American Lung Ass'n v. EPA, 985
F.3d 914, 957-58. Thus, it is the EPA's

position that CAA section 111(d) authorizes the EPA to allow states, in
particular rules, to achieve the requisite emission limitation through
the aggregate reductions from their sources, and the EPA is accordingly
proposing to authorize states to leverage their state programs to
satisfy their CAA section 111(d) state plan obligations pursuant to EG
OOOOc, subject to requirements discussed in the following sections.
    The EPA intends shortly to propose revisions to the implementing
regulations for CAA section 111(d) at 40 CFR part 60, subpart Ba. The
EPA intends, in that rulemaking, to further clarify that CAA section
111(d) and the implementing regulations authorize the EPA to, in
particular rules, allow states flexibility and discretion in
establishing standards of performance that meet the emission
guidelines, including standards that permit their sources to comply via
methods such as trading or averaging. The EPA encourages interested
persons to submit comments on this issue in that rulemaking for the
implementing regulations, and the EPA intends to finalize that
rulemaking before finalizing this oil and gas rulemaking.
b. Types of Equivalency Evaluations
    For purposes of this supplemental proposal, the EPA contemplated
two types of equivalency evaluations that could be considered when
comparing state programs against the stringency of EG OOOOc. These
include: (1) Total program evaluation, and (2) source-by-source
evaluation.
i. Total Program Evaluation
    The first type of equivalency evaluation the EPA assessed is a
total program evaluation, meaning assessing reductions and controls
across all or different designated facilities. A total program
evaluation could entail that some sources would get more reductions
than the presumptive standards in the EG and others less reductions,
but overall reductions are equal or greater than what would be achieved
in the aggregate across all designated facilities by implementing the
presumptive standards. A total program evaluation may look different
for states that have designated facilities in the production,
processing, and transmission and storage segments compared to states
that only have designated facilities in the transmission and storage
segment. The EPA recognizes that potentially allowing for total program
equivalency could, in theory, reduce burden on states by allowing
states with programs to rely more on those programs for their state
plan submittal without needing to revise standards for specific
designated facilities in order to match the presumptive standards.
Furthermore, the EPA recognizes that burden may be reduced for owners
and operators of designated facilities because they would not have to
comply with two different sets of regulations. However, the EPA has
identified the following challenges and complexities that are unique to
the Crude Oil and Natural Gas source category and is therefore
proposing to disallow state plans from using total program equivalence
to meet the requirements of a final OOOOc EG.
    One such consideration is that state programs may include sources
that are not designated facilities. For example, New Mexico,
Pennsylvania, and Ohio have state standards for pigging activities. The
EPA is not proposing to determine a BSER or presumptive standards for
pigging activities in this supplemental proposal. Because CAA section
111(d)(1) only provides that state plans may include standards of
performance and certain other requirements for designated facilities,
the EPA interprets the statute as not allowing the EPA to approve, and
thereby render federally enforceable, state plan requirements that
extend to sources that are not designated facilities. Therefore, it is
not appropriate to allow a state to account for non-designated
facilities as part of their state plan submission for any purpose,
including for demonstrating program equivalency, even if a state
regulates such sources as a matter of state law.\252\
---------------------------------------------------------------------------

    \252\ The EPA acknowledges that states may choose to regulate
non-designated facilities under state law for other purposes than to
satisfy their CAA section 111(d) state plan submission.
---------------------------------------------------------------------------

    In addition, the EPA also interprets CAA section 111(d) as not
allowing the EPA to approve state plan requirements for different
pollutants than those designated pollutants that are regulated in the
EG. The EPA is aware that while numerous states have programs in place
that regulate emissions from the designated facilities that the EPA is
proposing presumptive standards for, many of those programs do not
regulate GHGs in the form of limitations on methane.
    The EPA also proposed in the November 2021 proposal that states are
generally expected to establish the same non-numerical standards and if
a state chooses to utilize a different design, equipment, work
practice, and/or operational standard then the state must include in
its plan a demonstration of equivalency that is consistent with
alternative means of emissions limitations (AMEL) provisions. Some
state commenters agreed with the EPA that states are expected to
establish the same non-numerical standards.\253\ The EPA recognizes if
a state sought to utilize a different design, equipment, work practice,
and/or operational standard, a demonstration of equivalency that is
consistent with AMEL provisions would likely be technically difficult
because many of the presumptive standards in the EG OOOOc are work
practice standards that do not quantify emissions. This would suggest
that the equivalency evaluation would need to be a qualitative analysis
rather than a quantitative analysis because not all states have
comprehensive source and source-specific emissions inventory data to
base a stringency comparison on emissions reductions alone. The EPA
believes this qualitative comparison would be extremely complicated on
a holistic total program basis given that there are nine types of
designated facilities with proposed presumptive standards, of which,
five have numerical limits and two are in the format of work practice
standards. Without a clear structure for this evaluation to address the
complexities of the Crude Oil and Natural Gas source category, the EPA
is concerned that emission reductions and controls consistent with the
EG, and consistency of implementation across state plans, would be
compromised. Similarly, the EPA proposed that for designated facilities
with numerical presumptive standards, states are expected to establish
the same form of numerical standards, but the EPA also took comment on
whether to allow states to include a different form of numerical
standards for these facilities so long as states demonstrate
equivalency. Some state commenters suggested that the ability to
include a different form of numerical standard in state plans is
consistent with the cooperative federalism structure of CAA section
111(d).\254\ While states asked for this flexibility, state commenters
did not clearly provide specific examples of where a state already has
a different form of a numerical standard that would necessitate this
flexibility. The EPA is also concerned that there may be insufficient
state comprehensive source and source-specific emissions inventory data
to make the requisite technical evaluation.
---------------------------------------------------------------------------

    \253\ See Docket ID No. EPA-HQ-OAR-2021-0317-1267.
    \254\ See Docket ID No. EPA-HQ-OAR-2021-0317-1267.

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

    Another complicating scenario informing the EPA's proposal to
disallow total program equivalence is that there are instances where a
state covers part or subset of the EG designated facility's
applicability definitions. For example, Colorado requires the use of
non-emitting \255\ pneumatic controllers with specific exceptions. One
exception is that operators do not have to retrofit their controllers
to become non-emitting if on a company-wide basis, the average
production from producing wells in 2019 is less than 15 barrel of oil
equivalent/day/well. However, the EPA's supplemental proposal for
pneumatic controllers, as discussed in section VII.D of this preamble,
proposes a methane emission rate of zero with no applicability site
wide production or other threshold thus covering a broader group of
pneumatic controllers. If the EPA were to permit total program
equivalence where state programs do not align with the EG, then there
could be situations where a state would be allowed to forgo regulating
some designated facilities that the EPA has determined are reasonable
to control.
---------------------------------------------------------------------------

    \255\ The terms ``zero emissions'' and ``non-emitting'' are used
to describe pneumatic controllers. In Colorado, 5 CCR Regulation 7,
Part D, Section III, defines a ``non-emitting'' controller as ``a
device that monitors a process parameter such as liquid level,
pressure or temperature and sends a signal to a control valve in
order to control the process parameter and does not emit natural gas
to the atmosphere. Examples of non-emitting controllers include but
are not limited to: no-bleed pneumatic controllers, electric
controllers, mechanical controllers and routed pneumatic
controllers.'' A routed pneumatic controller is defined as ``a
pneumatic controller that releases natural gas to a process, sales
line or to a combustion device instead of directly to the
atmosphere.'' The EPA is proposing that pneumatic controllers must
be ``zero emission'' controllers. The difference in non-emitting, as
defined by Colorado and zero emissions, as proposed in this action,
is that pneumatic controllers for which emissions are captured and
routed to a combustion device are not considered to be ``zero
emission'' controllers. Therefore, routing to a combustion device is
not an option for compliance with the proposed EG OOOOc.
---------------------------------------------------------------------------

    For these reasons and the critical need to provide clear regulatory
certainty to the hundreds of thousands of designated facilities in this
uniquely large source category, the EPA does not think a total program
evaluation would guarantee that the same emissions reductions as
required by the EG would be achieved. The EPA solicits comments on how
a total program evaluation could be established in a way that would
address the complexities of the Crude Oil and Natural Gas source
category and concerns the EPA has identified.
ii. Source-by-Source Evaluation
    The second type of equivalency considered is a source-by-source
evaluation for a specific designated facility, such as between all
storage vessels located in a state or between a subset of centrifugal
compressors. A source-by-source evaluation could entail a state
conducting equivalency evaluation for one or more designated facilities
and their respective presumptive standards. In theory, if a state were
to do a source-by-source evaluation for each individual designated
facility in its state, this could be considered a form of total program
evaluation that is distinct from the type of total program evaluation
described above that the EPA is proposing to disallow, where
equivalence can be evaluated across different designated facilities
rather than designated facilities of the same type. A source-by-source
evaluation assumes that all sources in a state that meet the
applicability definition for a specific designated facility (e.g.,
pneumatic controllers, pneumatic pumps, and reciprocating compressors),
would in the aggregate have to achieve the same or better reductions of
the same designated pollutant as if the state instead imposed the
presumptive standards required under the EG. A source-by-source
evaluation, in theory, may push states to make changes to their state
rules, which may increase burden on states, but is likely a more
reliable way to determine that the state is achieving all emission
reductions equivalent to implementing the presumptive standards. Given
that state programs do vary considerably, a source-by-source evaluation
would allow states to pick and choose which state standards they want
to leverage for purpose of their state plan development. It is
theoretically less technically difficult to evaluate equivalency on a
source-by-source basis for the Crude Oil and Natural Gas source
category compared to total program equivalence. The EPA is proposing
five basic criteria for when states may use a source-by-source
evaluation as part of their state plans (discussed in section
V.B.2.b.iii of this preamble).
    An example of a source-by-source stringency comparison is the
comparison the EPA prepared when assessing the stringency of state
fugitive emissions monitoring programs compared to what was required
under NSPS OOOOa.\256\ Similar to that example, the EPA proposes that
any stringency comparison conducted to determine equivalence with the
proposed presumptive standards that are work practices will need to be
designated facility specific and the qualitative assessment will need
to be tailored to ensure that the correct technical metrics are being
compared.
---------------------------------------------------------------------------

    \256\ Memorandum: Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Proposed
Standards at 40 CFR part 60, subpart OOOOa. See Document ID No. EPA-
HQ-OAR-2017-0483-2277.
---------------------------------------------------------------------------

iii. Source-by-Source Evaluation Criteria and Methodology
    In order to implement a source-by-source evaluation, the EPA is
proposing five basic criteria to determine whether a source-by-source
evaluation can be considered for equivalency. The criteria are: (1)
Designated facility, (2) designated pollutant, (3) standard type/format
of standard (e.g., numeric, work practice), (4) emission reductions
(with consideration of applicability thresholds and exemptions), and
(5) compliance assurance requirements (e.g., monitoring, recordkeeping,
and reporting).
    In the following paragraphs, the EPA proposes a source-by-source
equivalency step-by-step approach followed by an example for
hypothetical state rules illustrating how states could implement the
proposed approach when conducting a state rule equivalency
determination with the proposed presumptive standards.
    Step One. Is state rule designated facility definition, pollutant,
and format the same? The first questions that a state needs to answer
is whether their program defines their regulated emissions source
similar to how the EPA defines a designated facility. Do their program
requirements for the designated facility regulate the same pollutant,
and is the format of the standard the same (e.g., work practice or
performance based numerical standard)? If the answer is no to any of
these questions (e.g., state program regulates VOC and not methane),
then the state plan cannot include an equivalency determination with
the EPA's proposed presumptive standards for the designated facility.
If the answer is yes to all of these questions, a state would proceed
to Step Two.
    Step Two. Emissions Reductions. A state plan needs to include a
demonstration that the state requirements for designated facilities
achieve the same or greater emissions reduction as the designated
facility presumptive standards. A state would have several options to
make this demonstration.

    The first option would be to make a demonstration that the
designated facility state standard achieves the same emission reduction
as the designated facility BSER analysis using the EPA model plant/
representative facility. The second option would be to make a
demonstration that the designated facility state standard achieves the
same or greater emissions reduction ``in real life'' as the designated
facility model plant/representative facility emission reduction in the
BSER analysis. The third option would be that a state could apply the
designated facility presumptive standard to ``real life'' (e.g., using
activity (number of sources) and actual emissions data) and calculate
the state-wide emission reduction that would be achieved, and then
demonstrate that the state program requirements for a designated
facility would achieve the same or greater emissions reduction. If
emissions reductions from the implementation of the state rule are less
than would be achieved from the implementation of the presumptive
standards, the state cannot make an equivalency determination with the
EPA's proposed presumptive standards. If emissions reductions from the
implementation of the state rule are the same or greater than would be
achieved from the implementation of the presumptive standards, a state
would proceed to Step Three.
    Step Three. Make demonstration that compliance measures included
for a designated facility under a state program are at least as
effective as those in the presumptive standard. Once a state has
determined that the emission reductions from the implementation of the
state requirements for a designated facility are the same or greater
than would be achieved by the implementation of the presumptive
standards for a designated facility under Step Two, a state plan would
need to include a demonstration that compliance measures (e.g.,
monitoring, recordkeeping and reporting requirements) are sufficient to
ensure continued compliance with the standards and projected emission
reductions.
    Centrifugal Compressor Examples--Comparison of Primary Presumptive
Standards With 4 Hypothetical Examples.
    Table 37 provides examples of the application of the steps outlined
above for five hypothetical state rules for reciprocating compressors
at gathering and boosting stations in the production segment. The
parameters for the presumptive standard for reciprocating compressors
are as follows.
    (1) The designated facility is a single reciprocating compressor.
    (2) The designated pollutant is methane, using volumetric flow rate
as a surrogate for methane).
    (3) The standard type/format of standard is a numerical standard (2
scfm volumetric flow rate).
    (4) The estimated methane emission reductions for the model
compressor in the BSER analysis for the presumptive standard was 92
percent reduction.
    (5) The compliance assurance requirements include the requirement
to measure the flow rate once every 8,760 operating hours and maintain
records.

  Table 37--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples
----------------------------------------------------------------------------------------------------------------
                                                            Equivalency determination steps
                                     ---------------------------------------------------------------------------
  Designated facility requirements           Step one--
                                         applicability and       Step two--emission     Step three-- compliance
                                         format of standard           reduction            assurance measures
----------------------------------------------------------------------------------------------------------------
Example A:
    Designated Facility: Single       FAIL--format of
     Reciprocating Compressor at       standard not
     Gathering and Boosting.           equivalent.
    Designated Pollutant: Methane...
    Format of Standard: Work
     Practice (Change out rod
     packing every 3 years).
    Estimated Emission Reduction
     (Basis): 56% (model compressor
     basis).
    Compliance Assurance
     Requirements: Records of
     changeout.
Example B:
    Designated Facility: Single       PASS...................  PASS..................  PASS.
     Reciprocating Compressor at
     Gathering and Boosting.
    Designated Pollutant: Total
     hydrocarbon as Surrogate for
     Methane.
    Format of Standard: Numerical
     (Collect and route to control
     to achieve 95% reduction).
    Estimated Emission Reduction
     (Basis): 95% (model compressor
     basis).
    Compliance Assurance
     Requirements: Performance test
     of control device, continuous
     parameter monitoring,
     recordkeeping and reporting.
Example C:
    Designated Facility: Single       FAIL--format of
     Reciprocating Compressor at       standard not
     Gathering and Boosting.           equivalent.
    Designated Pollutant: Total Gas
     Flow rate as surrogate for
     methane.
    Format of Standard: Directed
     Inspection and Maintenance
     (Measure flow rate annually and
     replace or repair if volumetric
     flow is greater than 3 scfm).
    Estimated Emission Reduction
     (Basis): 92% (model compressor
     basis).
----------------------------------------------------------------------------------------------------------------

 Table 37--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples--
                                                    Continued
----------------------------------------------------------------------------------------------------------------
                                                            Equivalency determination steps
                                     ---------------------------------------------------------------------------
  Designated facility requirements           Step one--
                                         applicability and       Step two--emission     Step three-- compliance
                                         format of standard           reduction            assurance measures
----------------------------------------------------------------------------------------------------------------
    Compliance Assurance
     Requirements: Records of
     measurements, records of
     corrective actions if greater
     than 3 scfm, records of new
     measurement to demonstrate less
     than 3 scfm after corrective
     action.
Example D:
    Designated Facility: Single
     Reciprocating Compressor at
     Gathering and Boosting.
    Designated Pollutant: Total gas
     flow rate as surrogate for
     methane.
    Format of Standard: Numerical: 5
     scfm.
    Estimated Emission Reduction
     (Basis): using analysis of
     state-wide emissions from
     actual reciprocating
     compressors, estimated that
     presumptive standard would
     achieve 85% reduction over the
     state, state rule would achieve
     87% reduction..
    Compliance Assurance              PASS...................  PASS Demonstrated that  PASS.
     Requirements: Measure                                      the ``real life''
     volumetric flow rate once every                            state-wide emission
     six months, record results..                               reduction for state
                                                                rule was greater than
                                                                the ``real-life''
                                                                reduction for the
                                                                presumptive standard..
Example E:
    Designated Facility: Single       PASS...................  FAIL--did not           .........................
     Reciprocating Compressor at                                demonstrate that the
     Gathering and Boosting.                                    BSER presumptive
                                                                standard model
                                                                facility reduction
                                                                was met.
    Designated Pollutant: Total gas
     flow rate as surrogate for
     methane.
    Format of Standard: Numerical: 4
     scfm.
    Estimated Emission Reduction
     (Basis): 88% (analysis of state-
     wide emissions from actual
     reciprocating compressors).
    Compliance Assurance
     Requirements: Measure
     volumetric flow rate once every
     six months, record results.
----------------------------------------------------------------------------------------------------------------

    The EPA solicits comment on the EPA's proposed state program
equivalency demonstration methodology and evaluating criteria for when
state plans may include standards of performance based on an
equivalency demonstration. Specifically, the EPA solicits comments on
other criteria than what the EPA is proposing should be considered; and
whether there are other additional qualitative factors/criteria need to
be included to make an effective stringency evaluation for different
types of different design, equipment, work practice, and/or operational
standards.
c. General Permitting Programs
    The EPA also recognizes that some states may regulate the
designated facilities proposed to be regulated under the EGs through a
general permit program. For example, general permits often include
standardized terms and conditions related to emissions control,
compliance certification, notification, recordkeeping, reporting, and
source testing requirements. The EPA is not proposing a regulatory
amendment on this point but confirms that the implementing regulations
under subpart Ba allows for standards of performance and other state
plan requirements to be established as part of state permits and
administrative orders, which are then incorporated into the state plan.
See 40 CFR 60.27a(g)(2)(ii).
    However, the EPA notes that the permit or administrative order
alone may not be sufficient to meet the requirements of an EG or the
implementing regulations, including the completeness criteria under 40
CFR 60.27a(g). For instance, a plan submission must include supporting
material demonstrating the state's legal authority to implement and
enforce each component of its plan, including the standards of
performance. Id. at 40 CFR 60.27a(g)(2)(iii). In addition, EG OOOOc may
also require demonstrations that may not be satisfied by terms of a
permit or administrative order. To the extent that these and other
requirements are not met by the terms of the incorporated permits and
administrative orders, states will need to include materials in a state
plan submission demonstrating how the plan meets those requirements.
3. Remaining Useful Life and Other Factors (RULOF)
    Under CAA section 111(d), the EPA is required to promulgate
regulations under which states submit plans establishing standards of
performance for designated facilities. While states establish the
standards of performance, there is a fundamental obligation under CAA
section 111(d) that such standards reflect the degree of emission
limitation achievable through the application of the BSER, as
determined by the EPA. As previously described, this obligation derives
from the definition of ``standard of performance'' under CAA section
111(a)(1). The EPA identifies the degree of emission limitation
achievable through application of the BSER as part of its EG. 40 CFR
60.22a(b)(5).
    While standards of performance must generally reflect the degree of
emission limitation achievable through application of the BSER, CAA
section 111(d)(1) also requires that the EPA regulations permit the
states, in

applying a standard of performance to a particular designated facility,
to take into account the designated facility's RULOF. The EPA's
implementing regulations under 40 CFR 60.24a(e) allows a state to
consider a designated facility's RULOF in applying a standard of
performance less stringent than the presumptive level of stringency
given in an EG to a particular source, provided that the state makes
the required demonstration under this provision. However, as described
further below, this provision does not provide clear parameters for
states on how and when to apply a standard less stringent than the
presumptive level of stringency given in an EG to a particular source.
The EPA intends to propose clarifying revisions to this provision under
the implementing regulations in an upcoming rulemaking that would apply
generally to new EG promulgated under CAA section 111(d). While
inviting comments on the application of these proposed revisions in the
context of the oil and gas sector in this rulemaking, the EPA also
encourages the public to provide comments on these proposed revisions
more generally in that upcoming rulemaking process to amend the
implementing regulations. The EPA intends to finalize that rulemaking
before finalizing this oil and gas rulemaking.
    Consistent with its intended revisions to the implementing
regulations, the EPA is proposing to supersede the current 40 CFR
60.24a(e) by providing requirements specific to EG OOOOc for the
consideration of RULOF in state plans to set a less stringent standard
for a particular source. The EPA notes that the EPA considers the
application of the proposed RULOF provisions to apply in circumstances
distinct from source-by-source evaluation discussed earlier in section
V.B.2. In other words, these provisions apply where a state intends to
depart from the presumptive standards in EG OOOOc and propose a less
stringent standard for a designated facility (or class of facilities),
and not where a state intends to comply by demonstrating that a
facility or group of facilities subject to a state program would, in
the aggregate, achieve equivalent or better reductions than if the
state instead imposed the presumptive standards required under the EG.
The EPA's proposed RULOF requirements for the application of a less
stringent standard and rationale are as follows.
    The RULOF provision currently under 40 CFR 60.24a(e) allows states
to consider RULOF to apply a less stringent standard of performance for
a designated facility or class of facilities if they demonstrate one of