contain meaningful, demonstrable errors, including, for example, that
the third party did not use the appropriate methane detection
technology, or that the emissions event did not exceed the threshold.
Where such demonstrable error is identified, the owner and operator
would not be obligated to conduct the root-cause analysis and
corrective action discussed later in this section and could, instead,
submit a report indicating the error. The EPA would not allow use of
this type of mechanism to dispute the accuracy of technologies that
have been approved by the EPA. Given the intermittency of super-emitter
emissions events, the failure of the operator to find the source of the
super-emitter emissions event upon subsequent inspection would not be
proof, by itself, of demonstrable error on the part of the third-party
notifier. The EPA, in its discretion, may remove that third party from
the pre-approved list of third-party notifiers upon demonstration by
the owner or operator and/or a finding by the EPA that more than three
notifications to that same owner or operator were made in error.
    The design of the super-emitter response program ensures that the
EPA will make all of the critical policy decisions and fully oversee
the program. The proposed framework for the super-emitter response
program further includes a robust series of safeguards to ensure that
these notifications represent validly collected data and evidence of a
super-emitter emissions event. First, the qualified third party
permitted to submit notifications must be certified by the EPA as
having appropriate experience and expertise. Second, the qualified
third party may only use certain remote detection technology approved
by the EPA for use in the super-emitter response program. Third, the
EPA would establish the threshold defining what emissions events
detected by the qualified third parties would trigger any obligation on
the part of the owner and operator under the program. Fourth, the EPA
has prescribed the specific factual information that must be included
in any appropriate notification provided to an owner or operator. And
fifth, the EPA has proposed a mechanism for owners and operators to
seek a revocation of a notifier's certification from the EPA should
they establish that more than one notification contained demonstrable
errors. Accordingly, under this framework the qualified third party
would essentially only be permitted to engage in certain fact-finding
activities and issue fact-based notifications within the limited
confines that the EPA has authorized. Such fact-based notifications
originating from third parties would not represent the initiation of an
enforcement action by the EPA or a delegated authority.
    In addition, and as discussed in more detail later in this section,
owners and operators would have the opportunity to rebut any
information in a notification provided by the qualified third parties
in their written report to the EPA, by explaining, where appropriate,
that (a) there was a demonstrable error in the third party
notification; (b) the emissions event did not occur at a regulated
facility; or (c) the emissions event was not the result of malfunctions
or abnormal operation that could be mitigated. And, as just discussed,
the EPA proposes to retain the authority to revoke a third-party
certification upon evidence that the notifier has made repeated,
demonstrable errors in notifications provided to owners and operators.
    Thus, the EPA believes that the proposed program appropriately
limits third party notifiers' discretion and retains oversight by the
EPA over all key

decision-making elements of the program. In light of these
considerations, the EPA also believes that a greater role for the
Agency in reviewing third-party notifications would be an unnecessary
task and duplicative of the predicate approval processes and subsequent
revocation procedure. Indeed, were the EPA to review third-party
notifications, such review could potentially be limited to ensuring
that the third party is properly EPA-certified, has used an EPA-
approved remote monitoring technology, and has found emissions above
the super emitter threshold--all of which are elements that the
proposed program structure adequately ensures. The EPA believes other
facts necessary to rebut the information in a notification regarding a
particular emissions event are likely to only be known by the owner and
operator and are best presented in their written report to the EPA.
Moreover, given the urgency with which the EPA believes such large
emissions events should be addressed, any additional role for the EPA
in the notification process would unnecessarily delay mitigation of
ongoing harms. The EPA solicits comments on these conclusions, and
whether there would be a meaningful benefit to a greater role for the
EPA in reviewing and/or approving third-party notifications before the
obligation of the owner or operator to respond is triggered. And if so,
the EPA further solicits comment on what kind of role would be
appropriate without meaningfully delaying the mitigation of the large
emissions events this program is intended to target.
    Addressing a super-emitter emissions event. In the November 2021
proposal, the EPA solicited comment on what specific actions an owner
or operator would be required to take when they are notified of the
detection of a super-emitter emissions event. Examples of those
specific actions were provided for comment, including verifying the
location of the emissions, conducting ground investigations to identify
the specific emissions source, conducting a root cause analysis,
performing corrective action within a specific timeframe to mitigate
emissions, and preventing ongoing and future chronic or intermittent
events from that source. See 86 FR 63177 (November 15, 2021). One
commenter stated that not all sources of super-emitter emissions events
would require a root cause analysis with corrective actions because the
emissions may not be the result of malfunctions or abnormal operation
(e.g., an emergency blowdown of equipment).\110\ Other commenters
stated that a root cause analysis and immediate corrective actions
should be required for any event identified through this program.\111\
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    \110\ See Document ID No. EPA-HQ-OAR-2021-0317-1391.
    \111\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0586, EPA-HQ-
OAR-2021-0317-0605, and EPA-HQ-OAR-2021-0317-0832.
---------------------------------------------------------------------------

    The EPA agrees with commenters that swift action must be taken when
an owner or operator is notified about the detection of a super-emitter
emissions event to correct any malfunction or abnormal operation that
is identified as the cause of the event. First, the owner or operator
should confirm that the reported emissions event is traceable to a
source located on the notified owner or operator's site and investigate
to confirm if a super-emitter emissions event is still ongoing.
Further, the EPA agrees that a root cause analysis is necessary to
identify the causes of the super-emitter emissions event. Therefore, we
are proposing to require owners and operators to initiate a root cause
analysis to determine the cause of the super-emitter emissions event
and to take corrective actions to mitigate the emissions. Examples of a
root cause analysis and corrective action could range from a survey
using OGI or other technologies combined with repairs of any leaks
identified, to visual inspections of thief hatches and closing any
found open or unlatched. As explained in more detail later in this
section, such corrective actions are tasks that owners and operators
already would undertake to maintain normal operations. One commenter
\112\ noted that the investigation may find the emissions are
attributed to something other than a malfunction or abnormal emission;
in those cases, the responsive action may only need to include specific
documentation of the emissions source, such as maintenance activities,
which should be described in the report.
---------------------------------------------------------------------------

    \112\ See Document ID No. EPA-HQ-OAR-2021-0317-1391.
---------------------------------------------------------------------------

    The EPA is proposing to require initiation of the root cause
analysis and corrective actions within five calendar days of an owner
or operator receiving the notification of the super-emitter emissions
event, and completion of corrective actions within 10 days of the
notification. Because super-emitter emissions events are such large
mass emissions rates (100 kg/hr or greater), it is imperative that
mitigation is achieved in a timely manner. One commenter \113\
suggested a program where the investigation would start within 14 days
of notification, with repairs completed within 30 days of discovery of
the event. However, the EPA believes that identification of the
emissions source and remedial action in a much shorter timeframe is
both warranted and necessary.
---------------------------------------------------------------------------

    \113\ See Document ID No. EPA-HQ-OAR-2021-0317-0832.
---------------------------------------------------------------------------

    Notwithstanding the necessary urgency of mitigating super-emitter
emissions events, the EPA does recognize that in some cases,
significant efforts may be required to fully complete required
mitigation. It is possible that some corrective actions would take
longer than the proposed 10 days to complete. Therefore, the EPA is
proposing a requirement for owners and operators to develop and submit
a corrective action plan that describes the corrective action(s)
completed to date, additional measures that they propose to employ to
reduce or eliminate the emissions, and a schedule for completion of
those measures. This corrective action plan would be due within 30 days
of receipt of the notification of the super-emitter emissions event.
This timeframe allows for an additional 20 days beyond the repair
deadline to draft the corrective action plan and submit it to the
Agency or delegated state authority.
    Finally, the EPA is proposing to require the submission of a
written report within 15 days of completing the root cause and
corrective action to the Agency and delegated state authority. In the
case of a designated facility covered by a state plan, the EPA solicits
comment on whether such written report should be sent to the state in
addition to the EPA. The EPA would promptly post online all reports
received from the owner-operator in response to a notice of super-
emitter event. This written report would include information such as
the data included in the notification, the source of the emissions,
corrective actions taken to mitigate the emissions, and the compliance
status of the affected facilities. To the extent a deviation or
potential violation is identified as the root cause of the emissions,
the owner or operator would report that information. If the operator
finds that emissions above the super-emitter threshold are not
occurring, and there is no evidence that they may have occurred as
reported, then the method for making that determination and the
evidence in support should be included in the required report to the
EPA. To the extent an owner or operator determines that the
notification contains a demonstrable error (e.g., that the notifier was
not a qualified third party, that the third party did not use the
appropriate methane detection technology, or that

the reported emissions event did not exceed the threshold), the report
would need only include a description of the error and an explanation
as to why, under these circumstances, a root cause analysis was not
conducted. The EPA solicits comment on what other elements should be
included in the owner-operator reports to the state and the EPA.
    The EPA solicits comment on these proposed deadlines for initiating
the analysis and completion of corrective actions. For comments
requesting shorter or longer timeframes, we are requesting specific
examples that would support any changes to this proposal.
b. Statutory Basis of Super-Emitter Program
    There are several ways in which the proposed super-emitter response
program described above fits within the EPA's authority under section
111 of the CAA, and two legal frameworks are outlined below.
    First, the EPA could treat a super-emitter emissions event as a
separate and distinct source of emissions. Under this regulatory
framework, sources of super-emitter emissions events from unintended
venting would be an affected facility/designated facility, and the
super-emitter response program would serve as the standard reflecting
the BSER for these facilities.
    Specifically, the EPA is proposing a new ``super-emitter'' affected
facility under NSPS OOOOb (and designated facility under EG OOOOc),
which the EPA would define as any equipment or control devices, or
parts thereof, at a well site, centralized production facility,
compressor station, or natural gas processing plant, that causes a
super-emitter emissions event (i.e., any emissions detected using
remote detection methods with a quantified emission rate of 100 kg/hr
of methane or greater). While the other requirements proposed as part
of this rulemaking are intended to reduce or eliminate unintentional
releases, the super-emitter response program is intended as a backstop
to those provisions, to identify any super-emitter emissions events not
prevented as a result of other requirements of the proposed rule.
    As discussed above, the EPA believes that super-emitter emissions
events from unintentional releases tend to occur as a result of
equipment malfunctions and/or poor operations; therefore, the BSER for
super-emitter emissions events would be to correct the malfunction or
operational issues and resume normal operations consistent with the
standards or requirements applicable to the source(s) of the super-
emitter emissions event in this proposed rule. The November 2021
proposal and this supplemental proposal contain standards and
requirements that, if implemented correctly, would prevent or mitigate
these super-emitter emissions events. For example, if a root cause
analysis identifies a control device as a source of a super-emitter
emissions event, then complying with the requirements for that control
device in this proposed rule would bring such device back to normal
operation. If the source of a super-emitter emissions event is a
leaking fugitive emissions component or an open thief hatch, repairing
the component or ensuring that the thief hatch is closed in accordance
with the fugitive emissions standards in this proposal would resume
these components to normal operation. The super-emitter response
program would require that, where approved, qualified third parties or
state or Federal governments provide actionable data of known quality
about a super-emitter event to owners and operators of a super-emitter
affected facility, and owners and operators would conduct a root-cause
analysis to identify the sources of the super-emitter emissions and
take corrective actions to mitigate the problems in order to resume
normal operation. Because specific corrective actions required to
resume normal operations would depend on the equipment causing the
super-emitter emissions event, and because normal operations could
differ from site to site, the proposed program would allow owners and
operators to determine the appropriate corrective actions so long as
the event is mitigated.
    The EPA proposes to determine that these requirements are justified
as BSER for this proposed super-emitter affected/designated facility
for several reasons. First, we expect that, as part of normal
operations, owners and operators should already be correcting equipment
malfunctions and/or poor operations as such issues arise; therefore,
costs associated with maintaining normal operations should already be
accounted for in their operational costs. As mentioned above, the most
widely known sources of unintended super-emitter emissions events are
from equipment or control devices that would be subject to emission
limitations (e.g., 95 percent reduction) or associated compliance
assurance requirements in the proposed NSPS OOOOb/EG OOOOc. For these
sources, where a super-emitter emissions event suggests a violation of
one or more of these standards or requirements, owners and operators
would already be required to investigate the source of the super-
emitter emissions event to ensure that it is complying with all
applicable standards and requirements. The proposed super-emitter
response program would simply require the owner and operator to take
these same steps upon receiving notice of a super-emitter emissions
event, provided by a regulatory authority or an EPA approved qualified
third party, as determined under the proposed program. As explained in
more detail above, the proposed super-emitter response program would
include a certification process and other criteria to assure the
quality and reliability of third-party data regarding a super-emitter
emissions event. Having established the reliability and quality of the
third-party data regarding a super-emitter emissions event, it is
reasonable to require prompt investigation and remediation of the
emissions. Super-emitter emissions events could also be caused by
fugitive emissions components that, if persistent, would be detected
and repaired during the next fugitive monitoring survey; the super-
emitter program would simply make the same repair earlier. There would
be no associated monitoring cost for owners and operators, as
monitoring under this program would be conducted by EPA-approved
qualified third parties. Accordingly, the EPA anticipates that there
should be no additional cost associated with this work practice
standard for the super-emitter emissions event affected facility. The
EPA seeks comment on this issue.
    To the extent there are additional costs associated with the
investigation or mitigation of these events, the EPA anticipates that
the costs would be minor in relation to the benefits of stopping such a
huge emissions event, making them obviously cost-effective, as
explained below. The EPA proposes that it is reasonable to conclude
that these actions would be cost effective in light of the large mass
emissions rate (100 kg/hr of methane or greater) that would be reduced
and the value of the high volume and value of gas saved by mitigation
of the event. The EPA finds in the November 2021 proposal and this
supplemental proposal that some proposed standards are cost effective
when they result in an expected reduction of about 10 tons of methane
at a facility over the course of a year. The super-emitters that can be
identified through the super-emitter response program produce that
amount of methane in five days or less and the

remedies are the same or similar.\114\ For example, if the source of a
super-emitter emissions event is an open thief hatch on a controlled
tank battery, the first corrective action would be to close the thief
hatch, which would incur negligible costs. In other words, it is highly
unlikely that in general these actions would exceed the $2,185/ton of
methane reduced, which is the highest value we have determined to be
cost effective for reducing methane in rulemakings addressing methane
under section 111 of the CAA. The cost effectiveness for responses to
super-emitter emissions events will usually be substantially below this
threshold, given that, by definition, super-emitter emissions events
emit at least one ton of methane every nine hours, and over 18 tons in
a week. For the reasons stated above, the EPA anticipates that
requiring immediate corrective actions to resume normal operations to
eliminate the super-emitter emission event could be achieved at a
reasonable cost for this proposed affected/designated facility. The EPA
seeks comment on this conclusion.
---------------------------------------------------------------------------

    \114\ See Table 11, Summary of Emission Reductions and Cost-
Effectiveness: Well Sites with Major Production or Processing
Equipment, Quarterly Monitoring.
---------------------------------------------------------------------------

    The EPA finds that the above regulatory framework of treating
super-emitter emissions events from unintended venting as an affected
facility that would be subject to the super-emitter response program is
a clear, simple, and straight forward approach for addressing such
large emission events.
    Second, the super-emitter response program can be justified as part
of the standards and requirements that apply to individual affected/
designated facilities under this rule, a number of which are known to
be frequent causes of super-emitter emission events which, as explained
earlier, may not necessarily be identified and addressed through more
frequent monitoring that we have determined is not cost-effective. As
mentioned above, the most widely known sources of unintentional
releases resulting in super-emitter emissions events are from
controlled tank batteries, flares, natural gas-driven pneumatic
controllers, and fugitive emissions, all of which would be either
affected facilities or designated facilities under the NSPS OOOOb and
EG OOOOc, respectively, or are control devices used on affected
facilities/designated facilities for which the proposed rules include
specific requirements. The EPA proposes to incorporate the super-
emitter program into these standards by considering the super-emitter
program as: (1) An additional compliance assurance measure, in the case
of sources that are subject to numerical standards of performance and
associated control device requirements, and (2) an additional work
practice standard, in the case of sources for which the EPA is
proposing work practice standards under this rule. However, despite the
proposed incorporation, the super-emitter response program is
nevertheless severable from the standards of performance and work
practice standards that are being separately established for each of
the sources addressed in this rule. Each of these other proposed
standards in this rule reflects the use of a specific emission
reduction or detection technology or measure that the EPA has
determined to be BSER for a given emission source after evaluating its
performance, cost and other factors associated with its use, as
required by CAA section 111(a) (under the definition of a ``standard of
performance''). Because whether such technology or measure qualifies as
the BSER under CAA section 111(a) does not depend on the presence of
the super-emitter response program, the resulting standards of
performance and work practice standards proposed in this rulemaking
would continue to reflect the use of that technology or measure, and in
turn the BSER, even without the super-emitter response program.
    Compliance assurance. For super-emitter emissions events from
affected facilities/designated facilities subject to numerical
standards, the super-emitter response program would serve as an added
compliance assurance mechanism, aimed at ensuring compliance with the
numerical emissions standards and associated control device or other
compliance assurance requirements. Where one of these facilities is
determined to be the cause of a super-emitter emissions event, it is
reasonable to assume that the emissions source is out of compliance and
to require corrective action to bring the facility back into compliance
with the applicable standard or requirement.
    There are two known sources of unintended venting that could result
in super-emitter emissions events that would be subject to numerical
performance standards as affected facilities or designated facilities:
tank batteries with potential emissions above six tpy of VOC or 20 tpy
of methane and natural gas-driven pneumatic controllers. Specifically,
for storage vessel affected facilities/designated facilities, the EPA
is proposing a numerical standard of performance that would require
reducing VOC and methane emissions by 95 percent. Where a control
device is used to meet this standard, the EPA is proposing specific
compliance assurance measures, such as a requirement that thief hatches
and other openings remain closed (``closed cover requirements''). As
discussed in section IV.I of this preamble, the EPA is proposing to
require quarterly OGI inspections of thief hatches and other openings
to ensure the closed cover requirement, and in turn the 95 percent
emission reduction standard, are met. If these standards and
requirements are rigorously followed, the EPA anticipates that they
should prevent super-emitter emissions events from controlled storage
tanks. However, these thief hatches are a commonly known source of
super-emitter emissions events when they are not closed and properly
latched. The proposed super-emitter response program would therefore
serve as a backstop--an additional compliance assurance measure for the
storage vessels standards--by requiring corrective action where it is
determined that a super-emitter emissions event was caused (in whole or
in part) by noncompliant storage vessels. Similarly, with respect to
natural gas-driven pneumatic controllers, for which the EPA is
proposing a zero-emissions standard, the EPA is proposing to require
quarterly OGI inspections of self-contained natural gas-driven
pneumatic controllers to ensure there are no identifiable emissions
from the controller as a compliance assurance measure. The super-
emitter response program would serve as an additional compliance
assurance measure by requiring immediate corrective action where it is
determined that a super-emitter emissions event was caused (in whole or
in part) by a natural gas-driven pneumatic controller affected
facility.
    As mentioned above, flares are also a widely known cause of super-
emitter emissions events. To our knowledge, all flares located at well
sites, centralized production facilities, compressor stations, or
natural gas processing plants are (or would be) used to meet a
performance standard in NSPS OOOOb or EG OOOOc. As such, they would be
required to meet the design and operation requirements for flares in
this proposal, such as operation and monitoring for a continuous pilot.
Flares designed and operated according to the proposed requirements for
control devices should not cause a super-emitter emissions event. The
super-

emitter response program would help assure compliance with these flare
requirements (and in turn the relevant performance standards) by
requiring owners and operators to take immediate corrective actions to
bring that flare into compliance where it is determined that a super-
emitter emissions event is caused by a flare. For these sources, where
a super-emitter emissions event suggests a violation of one or more of
these standards or requirements, owners and operators would already be
required to investigate the source of the super-emitter emissions event
to ensure that it is complying with all applicable standards and
requirements. Since the proposed super-emitter response program would
require these same measures, we do not anticipate additional costs
associated with the program.
    To the extent there are additional costs associated with the
investigation or mitigation of these events, the EPA expects that the
costs would be minor in relation to the benefits of stopping such a
huge emissions event, making them obviously cost-effective. As
explained previously in this section, it is reasonable to conclude that
these actions would be cost effective in light of the large mass
emissions rate (100 kg/hr of methane or greater) that would be reduced
and the value of the high volume of gas saved by mitigation of the
event.
    Work practice standards for detecting and repairing fugitive
emissions. As discussed above, super-emitter emissions events may also
occur from fugitive emissions components, which are not subject to
numerical standards, but rather to a work practice standard that
requires periodic monitoring (using OGI, AVO, or an advanced
technology) and repair of emissions that are identified from fugitive
emissions components. A super-emitter emissions event could occur
between the required periodic monitoring and thus not be detected and
repaired until the next periodic monitoring event. In addition, if
required periodic monitoring is missed, or is not performed well,
super-emitter emissions events could be occurring that the periodic
monitoring program fails to identify. For affected facilities and
designated facilities (i.e., collection of fugitive emissions
components) subject to the periodic monitoring and repair requirements,
the super-emitter response program would serve as an additional work
practice standard that would require corrective action whenever the
owner or operator is notified of a super-emitter emissions event by an
EPA, a state, or an approved third party under the super-emitter
response program, and it is determined that fugitive emissions
components are (in whole or in part) the source of the event.
    While, as discussed in section IV.A.1, the EPA does not believe it
is cost-effective to require operators to conduct periodic OGI
monitoring more frequently than the intervals set out in Section
IV.A.1, if a super-emitter emissions event is detected by a regulatory
authority or approved qualified third party in between monitoring
requirements, the EPA proposes that the BSER include responding to that
event and addressing the root cause of the super emission.
    The more targeted super-emitter response program would thus be a
more effective solution for addressing sporadic, large emission events
that may occur outside the periodic OGI monitoring. The conclusion that
the super-emitter response program is appropriate for addressing these
particularly large emissions events does not undermine the EPA's
determination about the frequency of periodic monitoring otherwise
required under the fugitive emissions work practice standard. While
super-emitter emissions events are important to address as a
significant source of potential emission reductions, these events do
not occur regularly across all well sites and are not predictable.
Accordingly, while the periodic monitoring is appropriate to address
more routine leak detection and repair, and to help prevent the
occurrence of super-emitter emissions events, the super-emitter
response program will help ensure that the unpredictable but
potentially significant super-emitter emissions events are
expeditiously addressed.
    Further, the corrective action to mitigate a super-emitter
emissions event from this source has the potential to result in
significant emissions reductions earlier than would have been achieved
by the periodic monitoring requirements. The EPA therefore believes
that the super-emitter response program is a reasonable addition as
part of the BSER for fugitive components because the program would only
target particularly large emission events (measuring over 100 kg/hr)
from these affected or designated facilities and would not require any
action for smaller emissions events that would be addressed by the
periodic monitoring.
    We have considered the costs of adding the super-emitter response
program as an additional work practice standard to the periodic
monitoring and repair requirements for addressing fugitive emissions
and concluded that the cost is reasonable. First, owners and operators
do not bear the cost of monitoring and detecting super-emitter
emissions events, which would be conducted by EPA-approved qualified
third parties. Instead, as discussed in more detail below, the first
step of the program would be for owners and operators to investigate
and identify the source(s) of a super-emitter emissions event upon
receiving reliable information. Since owners and operators would
already have to perform this task for purposes of the compliance
assurance measure for other affected facilities and associated control
devices under the super-emitter response program, described above,
there would be little additional cost in including this same root-cause
analysis as part of the fugitive emissions work practice standards.
Second, to the extent a root-cause analysis reveals that the super-
emitter emissions event is caused by a fugitive emissions component,
there may be no additional cost associated with their repair, since
these fugitive emissions might be detected and repaired during the next
scheduled periodic monitoring; the super-emitter response program would
simply require such repair to occur sooner. In other words, for super-
emitter emissions events identified as resulting from fugitive
emissions components between scheduled monitoring surveys, the proposed
super-emitter response program would provide an opportunity for repairs
sooner than the next scheduled survey, thus resulting in fewer
emissions overall from the event.
    Moreover, even if there are costs associated with the investigation
and mitigation, the threshold for identifying a super-emitter emissions
event is so high that it ensures that the emissions reductions achieved
by the mitigation are cost-effective. In other words, it is reasonable
to conclude that these actions would be cost-effective in light of the
large mass rate of emissions (100 kg/hr of methane or greater) that
would be reduced, and the high volume of gas saved. It is highly
unlikely that these actions would exceed the $2,185/ton of methane
reduced, which is the highest value we have determined to be cost
effective for reducing methane from sources within this source
category.
    In summary, the EPA finds the data demonstrate that the super-
emitter response program is cost-effective, even though the EPA
recognizes that the total emissions reductions that will result from
the program are difficult to quantify. By definition, a super-emitter
emissions event emits more than 100 kg of methane/hour, which means
that an on-going super-emitter emissions event that lasts an extended
period may emit

more than 2.5 tons of methane in a day, and potentially almost 80 tons
if it continued undetected for a month. Applying the same social cost
of methane values used to develop the estimates in Table 5 above, such
an event could generate over $100,000 in avoidable climate
damages.\115\ The proposed fugitive emissions monitoring and repair
requirements for facilities with major production and processing
equipment, discussed in section IV.A, are cost-effective when they are
projected to reduce 10.85 tpy of methane. A super-emitter emissions
event may emit almost twice that, or in some cases substantially more,
in a single week. In addition, the cost of most of the repairs that
would be necessary to respond to a super-emitter emissions event may be
achieved at very low additional cost because the need for repair would
be discovered at the next required inspection, indicating that most
repairs in response to super-emitter emissions events may be simply
moving the repairs earlier in time. Furthermore, halting super-emitter
emissions events recovers natural gas for sale that would otherwise be
emitted to the atmosphere, so it is possible that for many super-
emitter emissions events identified, the revenues from recovered
natural gas may offset a significant portion of the costs of repair
incurred by the owner or operator. For all these reasons, the EPA finds
the super-emitter response program cost-effective. Because the costs of
this program incurred by owners and operators, the length of time over
which these events occur, and the emissions reductions that may be
achieved have uncertainties associated with them, the EPA solicits
comments on the various factors related to the cost-effectiveness of
the super-emitter response program, including any information further
detailing the costs and emissions reductions of this program.
Specifically, the EPA solicits comments on any relevant data,
appropriate methodologies, or reliable estimates to help quantify the
costs, emissions reductions, benefits, and potential distributional
effects of this program (including, for example, benefits for
communities with EJ concerns). We also take comment on how to improve
the accuracy of our estimates of baseline emissions levels, emissions
reduction opportunities, and the frequency and intensity of super-
emitter events, and how to incorporate any recent, reliable estimates
of methane emissions.
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    \115\ This damage estimate assumes a social cost of methane
estimate of at least $1,400 per metric ton of methane, which is less
than the interim estimate that EPA uses in the RIA for a 3% discount
rate for the first year that the proposed NSPS OOOOb is assumed to
go into effect (2023).
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c. Additional Solicitations for Comment
    While the EPA is proposing a general framework for the super-
emitter response program, there are several additional aspects of the
program for which we are soliciting additional information and comment.
These solicitations are described in the following paragraphs.
    First, the EPA is soliciting comment on the mechanism for
identifying the owners and operators to receive the super-emitter
emissions event notifications. Entities approved to make such
notifications need a way to identify to whom they should be sent and
how to assure they are received. The EPA specifically seeks comment on
what mechanisms exist to make such identifications now, the
reliability, accuracy, and timeliness of those mechanisms, and the
difficulty or cost of accessing those mechanisms.
    The EPA is also soliciting comment on the amount of time allowed
for notifications following detection of a super-emitter emissions
event. Clearly, timely notification of the event is essential to
maximize the emission reduction potential from the event, but it is the
EPA's understanding that each technology or remote measurement method
experiences a lag between when a survey is conducted and when the data
has been analyzed to demonstrate emissions were present. The EPA is
soliciting comment on what deadline for notifications following
detection survey is most advantageous and feasible given current data
analysis requirements for remote measurement technologies and methods.
Further, time will be required to properly identify the relevant owner
or operator of the site. One factor is that ownership of sites can
change frequently, or specific contacts may move into other roles or
leave the company. Therefore, the EPA is soliciting comment on the
amount of additional time that should be factored into the notification
process to account for this identification step.

D. Pneumatic Controllers

    Pneumatic controllers are devices used to regulate a variety of
physical parameters, or process variables, often using air or gas
pressure to control the operation of mechanical devices, such as
valves. The valves, in turn, control process conditions such as levels,
temperatures and pressures. When a pneumatic controller identifies the
need to alter a process condition, it will open or close a control
valve. In many situations across all segments of the Oil and Natural
Gas Industry, pneumatic controllers make use of the available high-
pressure natural gas to operate or control the valve. In these
``natural gas-driven'' pneumatic controllers, natural gas may be
released with every valve movement (intermittent) and/or continuously
from the valve control. Detailed information on pneumatic controllers,
including their functions, operations, and emissions, is provided in
the preamble for the November 2021 proposal (86 FR 63202-63203;
November 15, 2021).
1. NSPS OOOOb
a. November 2021 Proposal
    In the November 2021 proposal, a pneumatic controller affected
facility was defined as each single natural gas-driven pneumatic
controller, whether the controller was a continuous bleed controller or
an intermittent vent controller. This affected facility definition
would have applied at sites in all segments of the oil and natural gas
source category. We proposed the requirement that all controllers
(continuous bleed and intermittent vent) have a VOC and methane
emission rate of zero. The proposed rule did not specify how this
emission rate of zero was to be achieved, but a variety of viable
options were discussed. These options included the use of pneumatic
controllers that are not driven by natural gas such as instrument air-
driven pneumatic controllers and electric controllers, as well as
natural gas-driven controllers that are designed so that there are no
emissions, such as self-contained pneumatic controllers. Because we
proposed to define an affected facility as each pneumatic controller
that is driven by natural gas and that emits to the atmosphere,
pneumatic controllers not driven by natural gas would not have been
affected facilities. Controllers that are driven by natural gas but
that do not emit to the atmosphere would not have been affected
facilities either, according to the November 2021 proposed definition.
    The November 2021 proposed rule included an exemption from this
zero-emission standard for pneumatic controllers at sites in Alaska
that do not have access to electrical power. For these sites, the
proposed rule would have required the use of low-bleed, continuous
bleed controllers. It would also have required that intermittent vent
controllers not vent during idle periods and that periodic inspections
be performed on these controllers to ensure that such venting does not
occur.

b. Changes to Proposal and Rationale
    The proposed NSPS OOOOb requirements in this supplemental proposal
differ from the November 2021 proposal in several ways, starting with
the affected facility definition. As noted above, the pneumatic
controller affected facility definition proposed in November 2021 was
each individual natural gas-driven pneumatic controller. In this
supplemental proposal, a pneumatic controller affected facility is
defined as the collection of all the natural gas-driven pneumatic
controllers at a site.
    Another change from the November 2021 proposal is that two specific
types of natural gas-driven controllers that were proposed to be
excluded from the affected facility definition are now proposed to be
included. These are: (1) Controllers where the emissions are collected
and routed to a gas-gathering flow line or collection system to a sales
line, used as an onsite fuel source, or used for another useful purpose
that a purchased fuel or raw material would serve (i.e., generally
characterized as ``routing to a process''); and (2) self-contained
natural gas pneumatic controllers.
    There is no change to the fundamental proposed standard for
pneumatic controllers, which is that all pneumatic controllers would be
required to have a methane and VOC emission rate of zero. The proposed
standard does include requirements for the two specific types of
natural gas-driven controllers identified above. These controllers do
not emit methane or VOC from routine operations. However, since they
are powered by natural gas, the potential for emissions exists if they
are not maintained and operated properly. For instance, a self-
contained controller could malfunction or develop leaks, or a CVS that
is routing the controller emissions to a process could develop leaks.
Therefore, the proposed rule includes requirements to avoid such
situations so that the controllers have zero direct emissions. Since
routing to a process includes the option of using the natural gas
captured for use as a fuel source, emissions would occur downstream at
the engine, generator, or process heater resulting from the combustion
of the natural gas from the controllers. However, these emissions are
replacing those that would have resulted from the combustion of fuel
gas, meaning that the net result is still zero direct emissions.
    While the BSER conclusion did not change from the November 2021
analysis, the EPA did update the analysis based on information received
in the public comments, including an analysis of potential alternative
standards for small sites with few pneumatic controllers.
    Details on the proposed pneumatic controller requirements in this
supplemental proposal are provided below in section IV.D.1.c. The
following sections provide the rationale for the changes discussed
above, a discussion of other related issues raised by commenters, and
the updated BSER analysis.
i. Affected Facility, Modification, and Reconstruction
    As noted above, the pneumatic controller affected facility
definition changed from being based on a single continuous bleed or
intermittent vent controller in the November 2021 proposal to the
collection of natural gas-driven continuous bleed and intermittent vent
controllers at a site in this supplemental proposal.\116\ The EPA is
proposing this change based on the consistent recommendation of
numerous commenters, particularly commenters from the oil and natural
gas industry. Several comments on the November 2021 proposal noted the
disconnect between the pneumatic controller affected facility
definition (i.e., an individual controller) and the cost analysis,
which was based on the replacement of all pneumatic controllers with
zero-emitting devices at a site.\117\ One commenter pointed out the
complexities of tracking and managing the universe of pneumatic
controllers at a site when some are affected facilities and others are
not, and recommended that the EPA propose a simpler and more robust
system.\118\ Another commenter indicated that defining the affected
facility on a site-wide basis aligns with how emissions from pneumatic
controllers will likely be handled by owners and operators of oil and
natural gas facilities. This commenter opined that defining the
pneumatic controller affected facility on a single controller basis, as
opposed to as the collection of all controllers at a site, would be
unnecessarily burdensome.\119\ A separate commenter discusses the fact
that converting a single pneumatic controller to a zero-emitting device
typically requires a conversion of all controllers at the facility to
zero-emitting devices.\120\
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    \116\ The EPA notes that there are other sources of emissions in
this supplemental proposed rule that the EPA proposes to regulate as
a collection of emissions sources, rather than as individual
emission units. Namely, the EPA proposes to define tank batteries as
the group of all storage vessels that are manifolded together for
liquid transfer and proposes to define fugitive emissions components
as the collection of fugitive emissions components at all well
sites.
    \117\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0831, and EPA-HQ-OAR-2021-
0317-0777.
    \118\ See Document ID No. EPA-HQ-OAR-2021-0317-0742.
    \119\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \120\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808.
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    We agree with the commenters that defining the pneumatic controller
affected facility as the collection of all controllers at a site is the
most practical approach. Significantly, most of the zero-emissions
measures for pneumatic controllers are site-wide solutions. For
instance, a compressed air system installed at a site would be used to
power all of the pneumatic controllers at the site, rather than a
separate system for each controller. Similarly, a solution based on
solar energy would likely utilize a single array of solar panels to
provide power to all the controllers at the site. In fact, as pointed
out by the commenters, the analysis for the November 2021 proposed rule
was conducted on a ``model plant'' site-wide basis. As noted above, the
comments that the EPA received on the pneumatic controller affected
facility definition in the November 2021 proposal all advocated for a
change in the definition from a single controller to the collection of
all onsite pneumatic controllers. However, the EPA did not specifically
solicit comment on the particular question of how to define the
affected facility in November. Now that the EPA is proposing in this
supplemental proposal to define the affected facility as the collection
of natural gas-driven continuous bleed and intermittent vent
controllers at a site, the EPA solicits comment on the proposed changed
definition.
    Under the previous approach of treating each controller on an
individual basis, the installation or replacement of a pneumatic
controller would have resulted in that singular controller being a new
source and an affected facility subject to NSPS OOOOb. Under this
supplemental proposal approach to treat the collection of all
controllers at a site as the affected facility, clear descriptions of
modification and reconstruction are needed in order to indicate when an
existing collection of controllers would become subject to NSPS OOOOb.
In 40 CFR 60.14(a), a ``modification'' is defined as ``any physical or
operational change to an existing facility which results in an increase
in the emission rate to the atmosphere of any pollutant.'' To clarify
what constitutes a modification for the

collection of all controllers at a site, the supplemental proposed rule
specifies that if one or more pneumatic controllers is added to the
site, such addition constitutes a modification and the collection of
pneumatic controllers at the site becomes a pneumatic controller
affected facility. This is because the addition of a controller
represents a physical change to the site and would result in an
increase in emissions from the collection of controllers. Based on
information provided by industry commenters, the EPA believes that
owners and operators will implement zero-emissions controllers across a
site when a modification occurs because converting a single pneumatic
controller to a zero-emitting device typically requires converting all
controllers at the facility to zero-emitting devices. The EPA solicits
comment on the ways in which a modification to a pneumatic controller
affected facility would occur in light of the affected facility
definition proposed herein, which includes the collection of all
natural gas-driven continuous bleed and intermittent vent controllers
at a site.
    In 40 CFR 60.15(b), ``reconstruction'' is defined as the
replacement of components of an existing facility ``to such an extent
that the fixed capital cost of the new components exceeds 50 percent of
the fixed capital cost that would be required to construct a comparable
entirely new facility,'' and ``it is technologically and economically
feasible to meet the applicable standards.'' The proposed pneumatic
controller affected facility definition for this supplemental proposal
is the collection of all natural gas driven controllers at a site;
therefore, the cost that would be required to construct a ``comparable
entirely new facility'' would be the cost of replacing all existing
controllers with new controllers. Because individual controllers are
likely to have comparable replacement costs, it is reasonable to assume
that there would be a one-to-one correlation between the percentage of
controllers being replaced at a site and the percentage of the fixed
capital cost that would be required to construct a comparable entirely
new facility. Accordingly, we are proposing to include a second,
simplified method of determining whether a controller replacement
project constitutes reconstruction under 40 CFR 60.15(b)(1) whereby
reconstruction may be considered to occur whenever greater than 50
percent of the number of existing onsite controllers are replaced.\121\
The EPA believes that allowing owners or operators to determine
reconstruction by counting the number of controllers replaced is a more
straightforward option than requiring owners and operators to provide
cost estimate information. By providing this option, the EPA intends to
reduce the administrative burden on owners and operators, as well as on
the implementing agency reviewing the information. Owners and operators
would be able to choose whether to use the cost-based criterion or the
proposed number-of-controllers criterion. No matter which option an
owner or operator chooses to use, the remaining provisions of 40 CFR
60.15 apply--namely, 40 CFR 60.15(a), the technological and economical
provision of 40 CFR 60.15(b)(2), and the requirements for notification
to the Administrator and a determination by the Administrator in 40 CFR
60.15(d), (e) and (f). The EPA is proposing that the standard in 40 CFR
60.15(b)(1) specifying that the ``fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility'' can be met
through a showing that more than 50 percent of the number of existing
onsite controllers are replaced. Therefore, upon such a showing, an
owner or operator may demonstrate compliance with the remaining
provisions of 40 CFR 60.15 that reference the ``fixed capital cost''
criterion. The EPA solicits comment on its proposal to add an option
for owners or operators to use in determining whether reconstruction
occurs by showing the number of components replaced. The EPA reiterates
that this proposed option would supplement the existing option of
determining replacements by fixed capital cost, as set forth in 40 CFR
60.15.
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    \121\ Adding this method of determining ``reconstruction'' for
pneumatic controllers is in accordance with 40 CFR 60.15(g), which
states that ``[i]ndividual subparts of this part
[``Reconstruction''] may include specific provisions which refine
and delimit the concept of reconstruction set forth in this
section.''
---------------------------------------------------------------------------

    A second factor for consideration in the reconstruction of an
existing pneumatic controller affected facility is during what time
period the number of controllers replaced or the fixed capital cost of
the new components should be aggregated. Consider the following
scenario: an owner first seeks to replace 30 percent of the pneumatic
controllers of an existing facility and then, shortly after commencing
or completing those replacements, the owner seeks to replace an
additional 30 percent. The owner would have replaced 60 percent of its
controllers in total, and presumably, the fixed capital cost of those
two replacement programs would be approximately 60 percent of the fixed
capital cost that would be required to construct a comparable entirely
new facility. It is unclear under the language of 40 CFR 60.15(d)
whether this owner should be deemed to have proposed two distinct
replacement programs or instead a single replacement program. The EPA
believes that such a stepwise controller replacement program should not
be used by facilities undergoing numerous replacement programs close in
time to avoid compliance with the NSPS. Failure to regulate these
sources would undermine Congress' intent that air quality be enhanced
over the long term with the turnover of polluting equipment, and with
the intent of the EPA's reconstruction provisions, which are triggered
where an existing facility replaces its components ``to such an extent
that it is technologically and economically feasible for the
reconstructed facility to comply with the applicable standard of
performance.'' \122\ Where a number of controllers are replaced
relatively close in time such that the aggregate costs or number of
controllers is greater than 50 percent, the EPA proposes to conclude
that it is reasonable to treat those replacements as part of a
continuous program of controller replacement for purpose of determining
reconstruction.
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    \122\ See Modification, Notification, and Reconstruction, 40 FR
58,417 (December 16, 1975) (also stating that ``the purpose of the
reconstruction provision is to recognize that replacement of many of
the components of a facility can be substantially equivalent to
totally replacing it at the end of its useful life with a newly
constructed affected facility.'').
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    In order to clarify how the regulatory language in 40 CFR 60.15
would apply to the replacement of pneumatic controllers, we are
proposing that where an owner or operator applies the definition of
reconstruction in Sec.  60.15(b)(1), reconstruction occurs when the
fixed capital cost of the new pneumatic controllers exceeds 50 percent
of the fixed capital cost that would be required to replace all the
pneumatic controllers at the site. The ``fixed capital cost of the new
pneumatic controllers'' includes the fixed capital cost of all
pneumatic controllers which are or will be replaced pursuant to all
continuous programs of component replacement which are commenced within
any 2-year rolling period.\123\

Thus, the EPA will count toward the greater than 50 percent
reconstruction threshold all controllers replaced pursuant to all
continuous programs of controller replacement which commence within any
2-year rolling period following proposal of these standards. If the
owner or operator applies the definition of reconstruction based on the
percentage of pneumatic controllers replaced, reconstruction occurs
when greater than 50 percent of the pneumatic controllers at a site are
replaced. The percentage includes all pneumatic controllers which are
or will be replaced pursuant to all continuous programs of pneumatic
controller replacement which are commenced within any 2-year rolling
period.
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    \123\ As noted above, incorporating a set period of time within
which numerous component replacements amount to ``reconstruction''
is in accordance with 40 CFR 60.15(g), which provides that
``[i]ndividual subparts of this part [``Reconstruction''] may
include specific provisions which refine and delimit the concept of
reconstruction set forth in this section.'' In addition, the EPA
notes that numerous NSPS and EG regulatory provisions incorporate a
2-year time period into the definition of reconstruction. See, e.g.,
Standards of Performance for New Stationary Sources; Bulk Gasoline
Terminals, 48 FR 37582-83 (August 18, 1983) (explaining need for a
fixed period within which to determine reconstruction when component
replacement occurs over time and determining that two years is
reasonable); 40 CFR 60.506(b) (codifying reconstruction definition
to include such a time period for bulk gasoline terminals (40 CFR
part 60, subpart XX)). See also 40 CFR 60.383(b) (metallic mineral
processing plants (subpart LL)); 40 CFR 60.100(f), 60.100a(d)
(petroleum refineries (40 CFR part 60, subparts J and Ja)); 40 CFR
60.706(a) (volatile organic compound emissions from synthetic
organic chemical manufacturing industry reactor processes (40 CFR
part 60, subpart RRR)).
---------------------------------------------------------------------------

    In the Administrator's judgment, the 2-year rolling period provides
a reasonable method of determining whether an owner of an oil and
natural gas site with pneumatic controllers is actually proposing
extensive controller replacement, within the EPA's original intent in
promulgating 40 CFR 60.15. The EPA solicits comment on this proposed 2-
year rolling aggregation period for all continuous programs of
pneumatic controller and pneumatic pump replacement (see section
IV.E.b.i. for a discussion of proposing the same approach for
determining reconstruction for pneumatic pumps). The EPA is
particularly interested in comments regarding whether this approach
will make it easier for owners and operators to determine
reconstruction at their sites, whether using a set time frame is
reasonable and feasible to put into practice, whether two years is an
appropriate timeframe, and whether a rolling basis for the two-year
time frame is a reasonable calculation (for example, see Scenario 5
below). The EPA is also interested in understanding how frequently
controllers and pumps are typically replaced.
    The following are example scenarios of the application of these
proposed requirements for a site with 15 natural gas-driven pneumatic
controllers. Scenario 1: One of the controllers is to be replaced (at
any given time). The collection of controllers at the site would not
become a pneumatic controller affected facility because the emissions
from the collection of controllers would not be increased (so such
action does not constitute a modification). Also, such action would not
constitute reconstruction because the fixed capital cost of the
replacement of this single controller would not equal 50 percent or
greater of the fixed capital cost that would be required to replace all
the controllers in the affected facility. Scenario 2: Eight of the
controllers are to be replaced at the same time. This would represent
reconstruction (because more than 50 percent of the total are being
replaced which means that the fixed capital cost of the replacement
would exceed 50 percent of the fixed capital cost that would be
required to replace all the controllers in the affected facility), so
the 15 controllers (i.e., the ``collection'' of controllers at the
site) would become a pneumatic controller affected facility. This
affected facility would then be subject to the zero-emissions standard,
meaning that all controllers at the site, including the eight new
controllers and the seven existing controllers, must comply with a
methane and VOC emission rate of zero. Scenario 3--six of the pneumatic
controllers are replaced in January and seven more controllers are
replaced the following April (15 months later). This would represent
reconstruction because more than 50 percent of the total number of
controllers are being replaced over a 2-year period, so the 15
controllers (i.e., the ``collection'' of controllers at the site) would
become a pneumatic controller affected facility at the time the seven
controllers were replaced in April. This affected facility would then
be subject to the zero-emissions standard, meaning that all controllers
at the site must comply with a methane and VOC emission rate of zero.
Scenario 4: An additional pneumatic controller is added at any given
time. This would represent a modification since it would constitute a
physical change and would result in an increase in emissions. The 16
controllers would represent a pneumatic controller affected facility
and all would need to comply with a methane and VOC emission rate of
zero. Scenario 5: replacement of four of the pneumatic controllers is
commenced in January in year 1; replacement of two more controllers is
commenced the following April in year 2 (15 months later); replacement
of two more is commenced the following March in year 3 (26 months after
the initiating replacement in January); and replacement of four more is
commenced that August of year 3 (31 months after initiating replacement
in January). Only six controllers of the 15 controllers were replaced
in the discrete two-year time period that began in January of year 1,
and therefore would not meet the proposed reconstruction definition.
However, when considered on a rolling 2-year basis, eight of the 15
controllers were replaced over years 2 and 3, which would meet the
proposed reconstruction definition. EPA specifically solicits comment
on whether the two-year time frame should be implemented on a rolling
basis or as a discrete time period.
    The EPA also solicits comment on whether it would be appropriate to
apply either of the two elements of reconstruction that the EPA is
proposing for pneumatic controllers (and pneumatic pumps, as described
in section IV.E.) to any other affected facility in NSPS OOOOb and EG
OOOOc. Specifically, the EPA is interested in comments regarding
whether any other source category would benefit from either: 1) adding
an option to determine reconstruction based on the number of components
replaced (in addition to the existing option of determining
replacements by fixed capital cost, as set forth in 40 CFR 60.15), and/
or 2) setting a specific time period within which replaced components
will be aggregated toward the greater than 50 percent replacement
threshold (assessed either by number or cost), e.g., any two-year
period beginning when a continuous program of component replacement
commences.
    Commenters stated that the EPA should allow like-kind replacement
of existing individual controllers without causing the controller to
become an affected facility under NSPS OOOOb.\124\ The commenters
indicated that if the EPA were to not allow this, operators who are
voluntarily replacing high-bleed natural gas-driven controllers with
low-bleed controllers would likely stop doing so. The EPA's proposed
change to a site-wide pneumatic controller affected facility definition
would allow the replacement of existing high-bleed controllers with
low-bleed controllers without becoming an affected facility, provided
that 50

percent or less of the controllers are replaced at the same time.
---------------------------------------------------------------------------

    \124\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0817 and EPA-HQ-
OAR-2021-0317-0831.
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    Commenters also encouraged the EPA to provide an exemption for
``temporary sources.'' One commenter provided the example where an
operation may require use of temporary or portable equipment for a
short period of time (i.e., less than 180 days) where it may not be
possible to connect to the grid or route to an onsite control
device.\125\ Another commenter indicated that non-emitting \126\
requirements are not justified for short term controller usage related
to a non-stationary source, and exemption of controllers on temporary
equipment is consistent with state regulations proposed in New Mexico
and finalized in Colorado. The commenter indicated that the EPA should
also make it clear that the requirements for pneumatic controllers are
not applicable during drilling or completion.\127\
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    \125\ See Document ID No. EPA-HQ-OAR-2021-0317-0831.
    \126\ The terms ``zero emissions'' and ``non-emitting'' are used
to describe pneumatic controllers. In Colorado, 5 Code of Colorado
Regulations (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 as used by the commenter, 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 NSPS OOOOb.
    \127\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    The EPA acknowledges that the focus of the BSER analysis has been
on stationary sources and pneumatic controllers that are part of the
routine operation of oil and natural gas facilities. Although some type
of alternative approach may be warranted for pneumatic controllers
associated with temporary operations, we lack sufficient information to
include an exemption, or perhaps alternative standards, for pneumatic
controllers associated with temporary equipment. Therefore, the EPA is
requesting more information on these situations. The EPA would like
specific examples of when temporary equipment is utilized, the function
of the controllers during this time, how they are powered, and the
typical duration of their usage. The EPA also requests information
explaining in detail why the zero-emission solutions that are used for
the permanent equipment at the site cannot be also utilized for this
temporary equipment.
    Another change to the affected facility definition in this
supplemental proposal is that natural gas-driven controllers from which
all emissions are collected and routed to a process, as well as self-
contained natural gas-driven pneumatic controllers, are not excluded
from the pneumatic controller affected facility definition. The EPA is
proposing to include these types of natural gas driven controllers
because they are driven by natural gas. While the EPA understands that
these controllers have zero routine emissions from the operation of the
device and are therefore compliant with the proposed standard when they
are properly operated and maintained, they do have the potential to
emit methane and VOC if they are not operated and maintained properly.
Therefore, we are proposing that natural gas-driven controllers from
which all emissions are collected and routed to a process, as well as
self-contained natural gas-driven pneumatic controllers (which release
gas into the downstream piping and not to the atmosphere), are part of
a pneumatic controller affected facility, and therefore subject to the
zero methane and VOC emissions standards. Specifically, the proposed
rule would require that owners and operators ensure proper maintenance
and operation of the controllers. For natural gas-driven controllers
from which all emissions are collected and routed to a process, the CVS
collecting and routing the emissions to the process must comply with
the CVS no identifiable emissions requirements in proposed 40 CFR
60.5411b, paragraphs (a) and (c). Self-contained controllers would be
required to be designed and operated with no identifiable emissions, as
demonstrated by initial and quarterly inspections using optical gas
imaging and any necessary corrective actions.
    NSPS OOOOa exempts controllers from the standards for functional
needs, ``including but not limited to response time, safety, and
positive actuation.'' 40 CFR 60.6390a(a). The November 2021 proposed
rule did not include these functional needs exemptions, except for
locations in Alaska that did not have access to electrical power. The
NSPS OOOOa exemptions were based on the use of a low-bleed natural gas
driven pneumatic controller. Because the November 2021 proposed
standard would not have allowed the use of natural-gas driven
controllers, the EPA did not believe that this exemption was needed.
    Several commenters requested that the NSPS OOOOa functional needs
exemptions be included in NSPS OOOOb in their entirety, while other
commenters indicated that they should only be allowed in very limited
instances and only when justification is provided in an annual report.
Commenters consistently raised the need to utilize natural gas-driven
pneumatic controllers associated with emergency shutdown devices
(ESDs). One commenter explained that an ESD is designed to minimize
consequences of emergency situations and will only emit in certain
isolated circumstances, such as if a well must be shut in. A large
change in pressure is required to actuate an ESD, which may not be
deliverable in a sufficient time by a compressed air or electric
controller. Furthermore, if power is lost, these devices must still be
able to function. It is rare that ESDs are activated, and their
emissions impact is minimal, but their functional need is necessary and
critical to safe operations. The commenter noted that both the current
version of the proposed rule in New Mexico and finalized regulations in
Colorado offer similar exemptions for ESDs.\128\
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    \128\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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    The EPA still believes that the overall functional needs exemption
is not necessary, as the limitations inherent in low-bleed natural gas-
driven controllers are not present in many of the zero emissions
options, particularly compressed air. The EPA also notes that any
natural gas-driven controller is allowed, whether low or high-bleed, if
the emissions are collected and routed to process in a manner that
achieves zero methane emissions.
    The EPA recognizes the important function of natural gas-driven
controllers for ESDs. Rather than including such devices in the
affected facility, the EPA is proposing to specifically exclude them
from the affected facility definition.
    Relatedly, one commenter requested that the EPA allow companies the
option to continue to use, or install, a dual natural gas system as a
backup for key controller functions. Such a natural gas backup system
would be used in the case of electrically actuated controller failure,
loss of power, or other contingencies.\129\ Another commenter added
that if the zero-emissions system (i.e., instrument air) goes down,
there is no provision within the proposed rule

to allow for the temporary use of natural gas. The commenter urged the
EPA to evaluate the reliability and availability of such systems that
would be deployed at such breadth.\130\ The EPA is interested in
understanding these backup systems more fully. In particular, the EPA
is requesting information on these systems regarding how frequently and
for how long these systems are used or would be expected to be used.
The EPA is concerned that allowing these backup systems would result in
a potential loophole that would enable owners or operators to continue
to use natural gas-driven controllers in routine situations. Therefore,
the EPA is interested in how the use of these systems could be narrowly
defined and how a clear distinction could be drawn between the allowed
use of these backup systems and violations of the zero emissions
standard.
---------------------------------------------------------------------------

    \129\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \130\ See Document ID No. EPA-HQ-OAR-2021-0317-0599.
---------------------------------------------------------------------------

ii. BSER Analysis
    Based on comments received on the November 2021 BSER analysis and
updated information provided, the EPA revised the BSER analyses for
this supplemental proposal for pneumatic controllers for the production
and transmission and storage segments of the industry. The following
paragraphs describe the updated information, the changes to the BSER
analyses, and the updated results. The analysis for natural gas
processing plants, which can be found in the TSD for the November 2021
proposal, was not updated.
    Several commenters objected to the emission factors that were used
for the analysis. One commenter stated that the emission factors used
in the GHGRP petroleum and natural gas source category (40 CFR part 98,
subpart W, also referred to as ``GHGRP subpart W'') for pneumatic
controllers were developed in the 1990's and that they may no longer be
applicable considering technological improvements.\131\ Another
commenter indicated that the factors used underestimated emissions and
that recent research indicates that actual average emissions from
pneumatic controllers may be higher than estimated.\132\
---------------------------------------------------------------------------

    \131\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
    \132\ See Document ID No. EPA-HQ-OAR-2021-0317-0918.
---------------------------------------------------------------------------

    The emissions factors used for the November 2021 BSER analysis for
the production segment were from a recent study conducted by the
American Petroleum Institute (API).\133\ The factors for the
transmission and storage segment were from Table W-3B of GHGRP subpart
W (2021). Since the November 2021 proposal, the EPA has conducted a
comprehensive review of available information related to emissions from
natural gas-driven pneumatic controllers and has proposed to update the
emission factors in GHGRP subpart W to reflect this research (87 FR
36920; June 21, 2022). The EPA concluded that these results are the
most appropriate for use in this BSER analysis. The information
evaluated for the June 2022 proposed revisions to GHGRP subpart W
included the API study. Table 22 provides the emission factors used for
the November 2021 analysis and those used for the updated analysis in
this supplemental proposal.
---------------------------------------------------------------------------

    \133\ ``API Field Measurement Study: Pneumatic Controllers EPA
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburg
PA. Paul Tupper.

 Table 22--Natural Gas-Driven Pneumatic Controller Emission Factors for
          the Production and Transmission and Storage Segments
------------------------------------------------------------------------
                                         Emissions (scf whole gas/hr)
                                     -----------------------------------
     Segment/type of controller         2022 Updated      November 2021
                                          analysis          analysis
------------------------------------------------------------------------
Production:
    Low bleed.......................               6.8               2.6
    High bleed......................              21.2              16.4
    Intermittent vent...............               8.8               9.2
Transmission and Storage:
    Low bleed.......................               6.8              1.37
    High bleed......................              32.4              18.2
    Intermittent vent...............               2.3              2.35
------------------------------------------------------------------------

    As can be seen in Table 22, the emissions factors for low-bleed and
high-bleed increased from those used for the November 2021 analysis,
while the intermittent vent factors decreased slightly.
    One commenter indicated that while they appreciated that the EPA
utilized emission factors from the API's Field Measurement Study, they
believed that the use of the average intermittent pneumatic device vent
rate was incorrect in this application.\134\ They stated that under
this proposal, any intermittent device would be monitored routinely and
repaired or replaced if malfunctioning, so the more appropriate
emission factor is 0.28 scf whole gas/controller-hour, not the average
emission factor of 9.2 scf whole gas/controller-hour that the EPA used
in the November 2021 proposal. The commenter noted that the average
emission factor should only be used for controllers that are not
routinely monitored as part of a proactive monitoring and repair
program or where the monitoring status is unknown. The commenter stated
that the normal operation emission factor should be applied to
controllers that are found to be operating normally as part of a
proactive monitoring and repair program and contended that this
approach achieves a nearly similar level of emission reduction for much
less investment by operators.
---------------------------------------------------------------------------

    \134\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    The EPA agrees with the commenter that the lower emission factor is
appropriate to represent the emissions level for intermittent vent
controllers that are routinely monitored as part of a proactive
monitoring and repair program. While the EPA recognizes that some
companies have voluntarily implemented such programs, we do not have
information to suggest that the majority of the intermittent vent
controllers in operation are part of such a program. The average
emission factor that the EPA used considers those low-emitting properly
operating controllers, as well as those that are not operating

properly and that are venting during idle. The EPA finds that this
average factor is the correct factor to represent the ``uncontrolled''
emissions from the universe of intermittent vent controllers.
    One commenter noted that all three sizes of model plants (small,
medium, large) contained one high-bleed natural gas-driven controller.
The commenter indicated that some state regulations do not allow for
the use of high-bleed controllers and concluded that the EPA's baseline
emissions analysis was likely skewed high.\135\
---------------------------------------------------------------------------

    \135\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
---------------------------------------------------------------------------

    The EPA agrees with this commenter. In addition to state
regulations that do not allow the use of high-bleed controllers, in the
absence of NSPS OOOOb, NSPS OOOOa would not allow the installation of
high-bleed controllers at new sites. Therefore, in the updated analysis
for new sources, the EPA did not include any high-bleed controllers in
any of the model plants. Table 23 provides a summary of the pneumatic
controller model plants and emissions. The emissions shown consider the
changes in the emission factors provided above in Table 22.

                                         Table 23--Summary of Pneumatic Controller Model Plants for New Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            November 2021 analysis                                 2022 updated analysis
                                           -------------------------------------------------------------------------------------------------------------
            Segment/model plant                  Number of controllers         Emissions  (tpy)         Number of controllers         Emissions  (tpy)
                                           -------------------------------------------------------------------------------------------------------------
                                              HB \a\     LB \a\    INT \a\      CH4        VOC       HB \a\     LB \a\    INT \a\      CH4        VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production:
    Small.................................          1          1          2        5.7        1.6          0          2          2        4.7        1.3
    Medium................................          1          1          6       11.2        3.1          0          2          6       10.0        2.8
    High..................................          1          4         15       24.9        6.9          0          5         15       25.1        7.0
Trans/Storage:
    Small.................................          1          1          2        4.1        0.1          0          2          2        3.1       0.09
    Medium................................          1          1          6        5.7        0.2          0          2          6        4.6        0.1
    High..................................          1          4         15       10.0        0.3          0          5         15       11.6        0.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ HB--continuous high bleed, LB--continuous low bleed, INT--intermittent vent.

    Some commenters also disagreed with the costs used for the BSER
analysis. One commenter said that the EPA's cost estimates were taken
directly from the 2016 White Paper \136\ and that the EPA did not
update the cost numbers for zero-emission electronic controllers, solar
panels, or batteries.\137\ The EPA notes that the primary basis for the
costs used for the November 2021 analysis was not the White Paper, but
rather a 2016 report by Carbon Limits, a consulting company with
longstanding experience in supporting efficiency measures in the
petroleum industry.\138\ One commenter \139\ pointed out that Carbon
Limits updated their report in early 2022,\140\ and recommended that
the EPA utilize the more recent information in that report since it
included more up-to-date research on zero emissions options for
pneumatic controllers. We reviewed the updated 2022 Carbon Limits
report and we agree with the commenter that the information presented
is well researched and representative of the costs of zero-emission
pneumatic controller technologies.
---------------------------------------------------------------------------

    \136\ U.S. EPA OAQPS. Oil and Natural Gas Sector Pneumatic
Devices. Report for Oil and Natural Gas Sector Pneumatic Devices
Review Panel. April 2014.
    \137\ See Document ID No. EPA-HQ-OAR-2021-0317-0924.
    \138\ Carbon Limits. (2016) Zero emission technologies for
pneumatic controllers in the USA--Applicability and cost
effectiveness.
    \139\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
    \140\ Carbon Limits. (2022) Zero emission technologies for
pneumatic controllers in the USA Updated applicability and cost
effectiveness. Available at https://cdn.catf.us/wp-content/uploads/2022/01/31114844/Zero-Emissions-Technologoes-for-Pneumatic-Controllers-2022.pdf.
---------------------------------------------------------------------------

    In addition to updating the analysis to reflect the information in
the 2022 Carbon Limits report, we also increased the estimate of
installation costs and considered operation and maintenance costs for
all types of pneumatic controller systems not driven by natural gas.
    One commenter mentioned that for zero emission, electrical
controller setups, skilled electrical labor is required for wiring,
programming, and tuning, which cannot be conducted by lease operators
that would otherwise manage this equipment. According to the commenter,
one available estimate is as high as $20,000 in labor costs per multi-
well pad.\141\ In the November 2021 BSER analysis, we assumed that the
installation and engineering costs were 20 percent of the total cost of
the equipment. For the updated analysis, we increased those costs to 50
percent. The results were installation and engineering costs ranging
from $8,500 for a small electrical controller system to almost $52,000
for a large instrument air system.
---------------------------------------------------------------------------

    \141\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
---------------------------------------------------------------------------

    Another change to the capital cost estimate that the EPA made was
to adjust the capital cost to represent the difference in the capital
cost between the pneumatic controller system not driven by natural gas
and the natural gas-driven controllers that would be used in the
absence of a zero emissions requirement. These costs, which were
calculated based on $2,227 equipment costs and the $387 installation
cost per pneumatic controller, were subtracted from the total capital
investment of the pneumatic controller systems not driven by natural
gas.
    For the November 2021 analysis, the annual costs were estimated as
the capital recovery of the original capital investment. This assumed
that the operating and maintenance costs for a pneumatic controller
system not driven by natural gas was the same as for natural gas-driven
controllers. For this analysis, we took into account differences in
operating costs. In general, the operating and maintenance costs for
pneumatic controller systems not driven by natural gas is less than
that of natural gas driven controllers, particularly if the gas is wet
gas. To estimate the operating costs for natural gas-driven
controllers, we used the average between the wet gas and dry gas cost
from the 2022 Carbon Limits report. This resulted in a net savings in
the annual operations and maintenance costs for electric and solar-
powered controller systems. There are additional operating and
maintenance costs

associated with instrument air systems, which resulted in an overall
increase in these costs as compared to natural gas-driven controllers.
    The costs for electric controllers and instrument air systems
assume access to electrical power (that is, access to the grid). Solar-
powered controllers can be utilized at remote sites that do not have
access to electrical power. Instrument air systems can also be utilized
at sites without access to the electricity grid, but these would
require the installation and operation of a generator. These generators
could be powered by engines fueled by natural gas, diesel, or by solar
energy. One commenter provided estimated costs ranging from $60,000 to
over $200,000 for an instrument air system driven by a natural gas
generator.\142\ Using the information provided by the commenter, the
EPA estimated costs for the three model plants. Note that the largest
model plant contained 20 controllers and the highest cost provided by
the commenter was for a site with more than 200 controllers. Therefore,
this cost was not utilized. The EPA is specifically requesting more
detailed information on the use of generators at sites without access
to the grid to power pneumatic controllers, primarily to power
instrument air systems. The EPA is also interested in receiving more
information on the costs associated with this equipment. Table 24
provides the updated pneumatic controller systems not driven by natural
gas costs. This table also provides the costs from the November 2021
analysis for comparison.
---------------------------------------------------------------------------

    \142\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.

                           Table 24--Total Capital and Annual Costs for Pneumatic Controller Systems Not Driven by Natural Gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   November 2021 analysis                                  2022 Updated analysis
                                          --------------------------------------------------------------------------------------------------------------
               Model plant                                                                                Adjusted
                                                         TCI \a\                             TAC \b\                 TCI \a\      TCI \b\      TAC \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Electric:
    Small System.........................  $25,494...........................  $2,799............................      $25,742      $15,287         $762
    Medium System........................  45,889............................  5,038.............................       46,335       25,426          959
Solar:
    Small System.........................  28,171............................  3,093.............................       27,286       16,831        1,112
    Medium System........................  51,242............................  5,626.............................       49,424       28,515        1,679
Instrument Air System--Grid:
    Small System.........................  not estimated.....................  not estimated.....................       57,966       47,512        9,285
    Medium System........................  not estimated.....................  not estimated.....................       92,335       71,426       10,658
    Large System.........................  95,602............................  10,497............................      165,550      113,277       14,891
Instrument Air System--Natural Gas
 Generator:
    Small System.........................  not estimated.....................  not estimated.....................      105,570       95,115       12,604
    Medium System........................  not estimated.....................  not estimated.....................      121,240      100,231       11,914
    Large System.........................  not estimated.....................  not estimated.....................      242,850      190,577       19,565
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ TCI = Total capital investment includes capital cost of equipment plus engineering and installation costs.
\b\ Adjusted TCI = Total capital investment minus the cost that would have been incurred if natural gas-driven controllers had been installed.
\c\ TAC = Total annual costs including capital recovery (at 7 percent interest and 15-year equipment life) and operation and maintenance costs.

    The controllers not driven by natural gas do not emit methane or
VOC. Therefore, the emission reductions associated with these systems
equal the total emissions shown above in Table 23. The estimated cost
effectiveness values for the controllers not driven by natural gas are
provided in Table 25. In addition to the cost effectiveness values,
Table 25 provides a conclusion regarding whether the estimated cost
effectiveness value is within the range that the EPA has typically
considered to be reasonable. The ``overall'' reasonableness
determination is classified as ``Y'' if the cost effectiveness of
either methane or VOC is within the range that the EPA considers
reasonable for that pollutant, or ``N'' if both the methane and VOC
cost effectiveness values are beyond the range the EPA considers
reasonable on a multipollutant basis.

 Table 25--Summary of Pneumatic Controller Systems Not Driven by Natural Gas Cost Effectiveness for New Sources
----------------------------------------------------------------------------------------------------------------
                                                   Cost effectiveness ($/ton) \a\--reasonable?
                                --------------------------------------------------------------------------------
      Segment/model plant               Single pollutant                 Multipollutant
                                ----------------------------------------------------------------   Overall \a\
                                     Methane           VOC           Methane           VOC
----------------------------------------------------------------------------------------------------------------
Production:
    Small--Electric                      $162-Y          $581-Y           $81-Y          $291-Y               Y
     controllers--grid.........
    Small--Electric                       238-Y           856-Y           119-Y           428-Y               Y
     controllers--solar........
    Small--Compressed air--grid         1,969-Y         7,082-N           984-Y         3,541-Y               Y
    Small--Compressed air--             2,673-N         9,615-N         1,336-Y         4,807-Y               Y
     generator.................
    Medium--Electric                       96-Y           344-Y            48-Y           172-Y               Y
     controllers--grid.........
    Medium--Electric                      167-Y           602-Y            84-Y           301-Y               Y
     controllers--solar........
    Medium--Compressed air--            1,062-Y         3,820-Y           531-Y         1,910-Y               Y
     grid......................
    Medium--Compressed air--            1,187-Y         4,270-Y           594-Y         2,135-Y               Y
     generator.................
    Large--Electric                        62-Y           222-Y            31-Y           111-Y               Y
     controllers--grid.........
    Large--Electric                       130-Y           467-Y            65-Y           234-Y               Y
     controllers--solar........

    Large--Compressed air--grid           593-Y         2,135-Y           297-Y         1,067-Y               Y
    Large--Compressed air--               780-Y         2,805-Y           390-Y         1,402-Y               Y
     generator.................
Transmission and Storage:
    Small--Electric                       247-Y         8,942-N           124-Y         4,471-Y               Y
     controllers--grid.........
    Small--Electric                       364-Y        13,164-N           182-Y         6,582-N               Y
     controllers--solar........
    Small--Compressed air--grid         3,015-N       108,939-N         1,507-Y        54,469-N               N
    Small--Compressed air--             4,093-N       147,891-N         2,046-N        73,946-N               N
     generator.................
    Medium--Electric                      207-Y         7,474-N           103-Y         3,737-Y               Y
     controllers--grid.........
    Medium--Electric                      362-Y        13,082-N           181-Y         6,541-N               Y
     controllers--solar........
    Medium--Compressed air--            2,299-N        83,066-N         1,149-Y        41,533-N               N
     grid......................
    Medium--Compressed air--            2,570-N        92,854-N         1,285-Y        46,427-N               N
     generator.................
    Large--Electric                       134-Y         4,830-Y            67-Y         2,415-Y               Y
     controllers--grid.........
    Large--Electric                       281-Y        10,156-N           141-Y         5,078-Y               Y
     controllers--solar........
    Large--Compressed air--grid         1,285-Y        46,422-N           642-Y        23,211-N               Y
    Large--Compressed air--             1,688-Y        60,992-N           844-Y        30,496-N               Y
     generator.................
----------------------------------------------------------------------------------------------------------------
\a\ For the production and processing segments, the owners and operators realize the savings for the natural gas
  that not emitted and lost. The cost effectiveness values shown do not consider these savings. Note that the
  consideration of savings does not impact whether the cost effectiveness of any of these options falls within
  the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC
  on a single pollutant basis must be within the ranges considered reasonable by the EPA, or the cost
  effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered
  reasonable by the EPA.

iii. Proposed BSER Conclusion.
    As demonstrated in the analysis and shown in Table 25, there are
pneumatic controller options for controllers not driven by natural gas
at sites in the production and transmission and storage segments where
the cost effectiveness is within the ranges considered to be reasonable
by the EPA. These options can be utilized at sites with access to grid
electricity and remote sites that do not have this access. This
conclusion is consistent with the findings in the November 2021
proposal.
    In addition to these options that use pneumatic controllers not
driven by natural gas, there are two types of natural gas-driven
controllers that we are proposing as zero-emissions options: (1)
Controllers whose emissions are collected and routed to a process, and
(2) self-contained natural gas pneumatic controllers. As noted in
section IV.D.1.b.i, these natural-gas driven controllers are included
in the revised proposed definition of affected facility, meaning that
they would be subject to standards to ensure that they are operated and
maintained in a manner that ensures zero emissions of methane and VOC.
We are including these as compliance options in this proposed action
because: (1) they are included as compliance options under several
state rules, and (2) there is cursory information indicating that they
are utilized in some locations. However, the available information
about the prevalence of either of these options at sites in the oil and
natural gas production or transmission and storage segments is very
limited. Therefore, the EPA is requesting is requesting comment on
several issues related to these controllers.
    The EPA is interested in several aspects related to the option of
collecting the pneumatic controller emissions and routing them to a
process. First, we are soliciting information that describes specific
situations where owners and operators have utilized this option to use,
rather than lose, the valuable natural gas emitted from pneumatic
controllers. We are interested in the specific processes and equipment
needed, as well as their costs.
    Second, our understanding is that routing emissions from pneumatic
controllers to a process achieves a 100 percent reduction in emissions.
This understanding is based on the fact that the natural gas that is
emitted from pneumatic controllers is drawn directly from the raw
product gas stream that will be collected and routed to a gathering and
boosting station and eventually to a natural gas processing plant
(i.e., the gas ``sales line''). Therefore, the emissions from pneumatic
controllers are of the same composition as the gas in the sales line.
Since the emissions are at atmospheric pressure, it is likely that the
gas would need to be compressed prior to re-introduction to the sales
line. We do not expect that this compression would result in emissions.
Similarly, since the gas composition of these emissions is typically
high in methane, the heat content would make it amendable to being used
as fuel, or introduced with the primary fuel stream for use in an
engine without the need for additional processing that could result in
emissions. We are interested in information to support this
understanding that routing emissions from pneumatic controllers to a
process achieves a 100 percent reduction in emissions.
    The 100 percent emissions reductions that we believe can be
achieved for controllers contrasts with routing emissions from storage
vessels or centrifugal compressor wet seal fluid degassing systems to a
process where the emissions are of a different composition from the
sales gas. For these situations, a VRU or other treatment is necessary
to obtain a gas stream whose composition is suitable to be returned to
the sales line or used for another purpose. A VRU often includes a
scrubber, separator, condenser, or other component that has a small
vent stream emitted to the atmosphere. In addition, the complex nature
of VRUs results in the need for maintenance or other situations where
the VRU may be bypassed, and emissions vented for short periods of
time. Because of both of these situations, the EPA has historically
assumed that VRUs achieve

a 95 percent reduction or greater in emissions.
    The EPA requests information on the assumption that installation of
VRUs would not be needed to enable the use of emissions from pneumatic
controllers in a process. If there are situations where a VRU is
needed, the EPA is interested in the conditions that result in this
need, as well as the emissions reduction achieved and the costs.
    We are aware of technical limitations of self-contained
controllers, namely that their applicability is limited by a number of
conditions (e.g., pressure differential, downstream pressure, etc.).
The EPA is therefore specifically soliciting information on the
frequency of the use of these self-contained controllers in the field,
as well as confirmation of specific limitations and costs. We are also
interested in information to support our understanding that self-
contained controllers achieve 100 percent reduction in emissions when
maintained and operated properly.
    Several commenters maintain that there are technical limitations
that will not allow pneumatic controllers not driven by natural gas to
be utilized at sites without electricity, particularly solar-powered
controllers.\143\ One commenter stated that while the EPA suggested the
use of onsite solar generation paired with battery storage as an
alternative to grid electricity, such systems are currently ``uncommon,
unreliable, and will likely increase the frequency of facility upsets,
which will increase safety risks such as overpressure events and
spills.'' \144\ Another commenter stated that while there may be some
pilot projects within the industry, it has not been demonstrated that
reliable turnkey packages are available on a widescale basis.\145\
Several commenters noted that there are severe geographic limitations
to the use of any solar-powered devices. One noted that West Virginia
averages only 164 days of sunshine per year, compared with an average
of 205 days for the rest of the United States. Even in typically sunny
states, operations in canyons or mountain valleys receive significantly
limited sunlight exposure. Snow and ice raise additional reliability
concerns during winter months.\146\ Another commenter stated that
large-scale solar applications have not yet been tested in winter
months when there is more cloud coverage, increased snow cover, and
less sunlight in more northern locations (e.g., Colorado, North Dakota,
Idaho, and Wyoming).\147\ One industry organization agreed that solar
power might be an option but reported that their member companies have
not yet been able to demonstrate this to be universally true in Utah's
Uinta Basin. This organization cited specific problems such as the
requirement of excess generation and battery storage capacity to
maintain operations during wintertime inversions and challenges from
snowstorms, which could cover the solar panels and inhibit or prevent
electricity generation. They conclude that utilizing solar electricity
for oil and gas operations in Utah may be labor intensive, costly, and
unreliable such that operations would still require backup power from
the electric grid or from generators.\148\ Another commenter also
mentioned that it is probable that supplemental power via natural gas
or diesel-powered generators could be required during winter months
and/or severe weather events, which would be necessary to ensure a
continuous power supply, and, thus, a controlled operation. This
commenter also noted that interruptions within the control system pose
safety risks to operators and can damage processing equipment, which
could potentially lead to excess emissions associated with equipment
malfunctions.\149\
---------------------------------------------------------------------------

    \143\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0817, EPA-HQ-
OAR-2021-0317-0743, EPA-HQ-OAR-2021-0317-0749, and EPA-HQ-OAR-2021-
0317-0808.
    \144\ See Document ID No. EPA-HQ-OAR-2021-0317-0793.
    \145\ See Document ID No. EPA-HQ-OAR-2021-0317-0599.
    \146\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
    \147\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
    \148\ See Document ID No. EPA-HQ-OAR-2021-0317-0740.
    \149\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------

    One commenter indicated that they were unaware of any operators
converting to solar-powered electric controllers at this time. They
said while the technology seems promising, many of these solar systems
have not yet been proven reliable for all remote locations or facility
designs and are not ready for deployment across the country at the
large scale that the EPA's proposed rules would require. They note that
in 2014, the EPA stated ``solar-powered controllers can replace
continuous bleed controllers in certain applications but are not
broadly applicable to all segments of the oil and natural gas
industry.'' \150\
---------------------------------------------------------------------------

    \150\ Oil and Natural Gas Sector Pneumatic Devices, Review
Panel, USEPA, OAQPS, 2014: https://www.ourenergypolicy.org/wp-content/uploads/2014/04/epa-devices.pdf.
---------------------------------------------------------------------------

    However, other commenters disagreed and supported the EPA's
November 2021 proposal to require zero-emission controllers. Commenters
cited several state rules that require all new pneumatic controllers to
be non-emitting, including states with colder climates (Colorado). As
the EPA also indicated in the November 2021 proposal, there are
Canadian provinces that have successfully implemented non-emitting
controller regulations. Comments were also provided by vendors that
report the successful installation and operation of zero-emission
controller systems in a variety of climate conditions.\151\ One of
these vendors notes the installation of solar-driven instrument air
systems in several states, including Wyoming and Colorado.\152\
---------------------------------------------------------------------------

    \151\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0838 and EPA-HQ-
OAR-2021-0317-0802.
    \152\ See Document ID No. EPA-HQ-OAR-2021-0317-0838.
---------------------------------------------------------------------------

    In a supplement to their 2022 report that was provided in a late
comment, Carbon Limits addressed many of the alleged shortcomings of
solar and other zero-emitting controller technologies raised in public
comments. They state, ``[a]ddressing the queries on the reliability of
solar systems for remote locations and cold states, the technology
providers and operators interviewed as part of this assessment have
solar-powered controllers installed at well sites in remote and cold
locations such as Northern Alberta and British Colombia, without major
reliability issues. Some of the interviewed technology providers have
installed these systems in over 400 well-sites in these states and
provinces. The commenter further refers to a statement by the EPA from
2014. However, it is to be noted that solar technology has improved
drastically from 2014 to 2021. Efficiency has increased while costs
have gone down significantly. Solar-powered controllers are capable of
operating at low temperatures and remote locations, among different gas
sectors. When it comes to snow cover on panels affecting the
performance of solar cells, all the interviewees stated that the panels
are placed at a low angle, to catch ample sun in the winter months.
Most often, these panels are placed vertically, eliminating snow cover
on the solar panels.'' \153\ Commenters also indicated that at sites
without electricity, owners or operators could install a generator to
power an instrument air system.
---------------------------------------------------------------------------

    \153\ See Document ID No. EPA-HQ-OAR-2021-0317-1451.
---------------------------------------------------------------------------

    Under CAA section 111(b), EPA must show that a BSER determination
has been ``adequately demonstrated.'' The EPA concludes that zero-
emission

pneumatic controller systems that do not use natural gas meet this
standard at sites both with and without access to electricity. In
addition, as discussed above, we have concluded that there are options
available at sites in all segments of the industry that have cost-
effective values considered reasonable by the EPA.
    Secondary impacts from these non-natural gas-driven, zero-emission
controllers, particularly from the use of instrument air systems are
indirect, variable, and dependent on the electrical supply used to
power the compressor. The 2016 Carbon Limits report indicates that a
small instrument air compressor would require around 5 horsepower (HP)
of air compression capacity, while a larger facility would require up
to 20 HP. Assuming the compressor operates one-half of the total hours
in a year, and using an electricity factor of 0.75 HP/kilowatt, the
compressor yields an annual electricity usage of around 100 mmBtu/yr
for a 5 HP compressor and 400 mmBty/yr for a 20 HP compressor. There
would be secondary air pollution impacts associated with the generation
of this electricity. The secondary criteria pollutant emissions are
estimated to be 7 lbs/yr CO, 60 lbs/yr NO2, 3 lbs/yr PM, 1
lb/yr PM2.5, and 120 lbs/yr SO2 for a 5 HP
compressor and 29 lbs/yr CO, 239 lbs/yr NO2, 12 lbs/yr PM, 4
lb/yr PM2.5, and 478 lbs/yr SO2 for a 20 HP
compressor. The secondary GHG emissions generated as a result of this
electricity generation are 20,489 lbs/yr CO2, 2 lbs/yr
methane, and 1lb/yr N2O for a 5 HP compressor and 81,955
lbs/yr CO2, 10 lbs/yr methane, and 2 lbs/yr N2O
for a 20 HP compressor. Considering the global warming potential of
these GHGs, the total CO2e emissions would be 20,667 lbs
CO2e from a 5 HP compressor and 82,669 lbs CO2e
from a 20 HP compressor. These total CO2e would represent a
more than 90 percent reduction in the CO2e emissions when
compared to the uncontrolled methane emissions from natural gas driven
controllers. No other secondary impacts are expected.
    Commenters indicated that at sites without electricity, owners or
operators would likely install a generator to power an instrument air
system. These commenters contended that relying on a generator would
result in emissions of criteria pollutants and carbon monoxide (CO)
that could potentially offset the emissions reductions from the methane
and VOC. One commenter provided an estimate that a natural gas-fired
generator of approximately 200 horsepower would be needed to support
reliable operation of a large instrument air system without grid power.
This commenter estimated emissions from a generator that size to be
1.94 tpy NOX, 3.88 tpy of CO, 1.36 tpy of VOC, 0.12 tpy of
particulate matter with a diameter of 10 micrometers or less
(PM10), 0.14 tpy CH4 and 730 tpy of
CO2.\154\
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    \154\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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    The EPA recognizes that if owners and operators elect to comply by
installing and operating a generator, there will be secondary emissions
generated from the fuel combustion. However, we also point out that,
for a site with 100 controllers (a size cited by the commenter
requiring a large instrument air system), these secondary emissions
would represent approximately a 77 percent decrease in CO2
equivalent emissions and a 96 percent decrease in VOC emissions from a
site with 25 low bleed and 75 intermittent bleed controllers.
    In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven controllers in the production
and transmission and storage segments of the industry to be the use of
controllers that have a methane and VOC emission rate of zero. This
option results in a 100 percent reduction of emissions for both methane
and VOC. Therefore, for NSPS OOOOb, we are proposing to require that
each pneumatic controller affected facility be designed and operated
with a methane and VOC emission rate of zero in the production and
transmission and storage segments of the source category, with the
following exception for sites in Alaska that do not have access to grid
electricity.
    In the November 2021 proposal, we determined a separate BSER for
the subset of pneumatic controllers, specifically those at sites in
Alaska that do not have access to electricity. We also proposed
specific requirements for these controllers. We are not proposing any
changes to these requirements in this supplemental proposal.
Specifically, these sites would be required to use low-bleed
controllers (instead of high-bleed controllers) and would be allowed to
use high-bleed controllers instead of low-bleed based only upon a
showing of functional needs. In addition, we proposed that owners or
operators at such sites be required to inspect intermittent vent
controllers to ensure they are not venting during idle periods. The
rationale for this decision was discussed in the November 2021 proposal
(86 FR 63207; November 15, 2021).
    The EPA notes that the BSER determination for pneumatic controllers
at natural gas processing plants was also not revisited in this
supplemental proposal. Therefore, the November 2021 BSER determination
of zero emission controllers at natural gas processing plants is
retained in this supplemental proposal. The rationale for this decision
is contained in the November 2021 proposal (86 FR 63207- 63208;
November 15, 2021).
iv. Routing to an Existing Control Device
    Several commenters requested that the EPA include an option to
collect the emissions from natural gas-driven controllers and route
them to a flare or combustion device that achieves 95 percent reduction
in methane and VOC. These comments stated that in many situations, an
onsite control device already exists and that using it would be a cost-
effective method of achieving significant emission reductions.
    The EPA acknowledges that this is a viable option to achieve
emission reductions from natural gas-driven pneumatic controllers.
However, as discussed above, we have determined that BSER for pneumatic
controllers is use of one of the several types of controllers that have
zero methane and VOC emissions. Thus, routing to an existing control
device (i.e., achieving 95 percent reduction) would result in a less
stringent standard than the BSER. In the 2021 Inventory of U.S.
Greenhouse Gas Emissions and Sinks (GHGI), the estimated methane
emissions for 2019 from pneumatic controllers were 700,000 metric tons
of methane for petroleum systems and 1.4 million metric tons for
natural gas systems. These levels represent 45 percent of the total
methane emissions estimated from all petroleum systems (i.e.,
exploration through refining) sources and 22 percent of all methane
emissions from natural gas systems (i.e., exploration through
distribution). While we recognize that these emissions include
emissions from existing sources, it is clear that pneumatic controllers
represent a significant source of methane and VOC emissions. Allowing
an option that results in 5 percent more emissions would be a quite
significant increase.
    The EPA recognizes that there are other instances in the proposed
rule where there are options allowed that are less stringent than the
measures determined to be BSER. However, in each of these situations,
the EPA is convinced that there are genuine technical limitations or
safety issues that make compliance with the BSER infeasible. For
pneumatic controllers, the EPA maintains that there is a

technically feasible option available for all production, processing,
and transmission and storage sites, except for sites in Alaska without
access to electricity. Therefore, the proposed NSPS OOOOb does not
include any alternative non-zero emission standards for pneumatic
controllers. The EPA is interested in information that may dispute the
conclusion that there is a technically feasible option that does not
emit methane or VOC available for all sites in all segments. Some
commenters raised concerns about specific situations that may make
individual technologies impracticable to implement (e.g., the inability
of solar-powered controller systems to meet the needs at certain remote
locations that do not have access to electricity). Although the EPA
will consider any additional information commenters may submit about
such situations, the EPA notes that there are multiple options for
meeting the proposed zero-emission standard and that limitations on the
use of one technology at any given site does not mean that other
options for meeting the standard are unavailable. As a result, the EPA
is particularly interested in understanding whether there are site
characteristics that would make every zero-emitting option (electric
controllers powered by the grid or by solar power; instrument air
systems powered by the grid, a generator, or by solar power; collecting
the emissions and routing them to a process; self-contained
controllers, etc.) technically infeasible at the site.
c. Summary of Proposed Standards
    In this supplemental proposal, the pneumatic controller affected
facility is defined as the collection of natural gas-driven pneumatic
controllers at a well site, centralized production facility, onshore
natural gas processing plant, or a compressor station. This definition
applies in all segments of the oil and natural gas source category.
Natural gas-driven pneumatic controllers that function as emergency
shutdown devices and pneumatic controllers that are not driven by
natural gas are exempt from the affected facility, provided that the
records are maintained to document these conditions. In addition to the
modification definition in 40 CFR 60.14 and the reconstruction
definition in 40 CFR 60.15, the proposed rule includes clarification of
these terms for the pneumatic controller affected facility. A
modification occurs when the number of natural gas-driven pneumatic
controllers at a site is increased by one or more, and reconstruction
occurs when either the cost of the controllers being replaced exceeds
50 percent of the cost to replace all the controllers, or when 50
percent or more of the pneumatic controllers at a site are replaced.
    The proposed standard for pneumatic controller affected facilities
is zero emissions of methane and VOC to the atmosphere. An exception to
this standard exists for pneumatic controller affected facilities
located at sites in Alaska without access to electrical power. The
proposed rule does not specify how this emission rate of zero must be
achieved, but a variety of viable options are available. All
controllers at a site that are not driven by natural gas (e.g.,
pneumatic controllers driven by compressed air, electric controllers,
solar-powered controllers) are not part of the pneumatic controller
affected facility, provided that documentation is maintained as
previously discussed. If all pneumatic controllers at a site are not
natural gas-driven, then there would be no pneumatic controller
affected facility at the site, provided the documentation is
maintained.
    Natural gas-driven controllers can comply with the zero emissions
standard by collecting and routing emissions via a CVS to process, or
by using self-contained controllers. The proposed rule defines a self-
contained pneumatic controller as a natural gas-driven pneumatic
controller that releases gas into the downstream piping and not to the
atmosphere, resulting in zero methane and VOC emissions.
    If you comply by routing the emissions to a process, the CVS that
collects the emissions must be routed to a process through a CVS that
meets the requirements in proposed 40 CFR 60.5411b, paragraphs (a) and
(c). These requirements include certification by a professional or in-
house engineer that the CVS was designed properly, and that the CVS is
operated with no identifiable emissions as demonstrated through initial
and periodic inspections, observations, and measurements. This includes
monitoring using OGI at the same frequency as required under the
fugitive monitoring program. All issues identified must be corrected.
Required records would include the certification and records of all
inspections and any corrective actions to repair the defect or the
leak.
    If you comply by using a self-contained natural gas-driven
pneumatic controller, the controller must be designed and operated with
no detectable emissions, as demonstrated by conducting initial and
quarterly inspections using optical gas imaging. Required records would
include records of all inspections and any corrective actions to repair
the defect or the leak.
    The proposed rule includes an exemption from the zero-emission
requirement for pneumatic controllers in Alaska at locations where
electrical power is not available. In these situations, the proposed
standards require the use of a low-bleed controller (i.e., a controller
with a natural gas bleed rate less than or equal to 6 scfh). Records
would be required to demonstrate that the controller is designed and
operated to achieve a bleed rate less than or equal to 6 scfh. For
controllers in Alaska at location without electrical power, the
proposed rule includes the exemption that would allow the use of high-
bleed controllers instead of low-bleed based on functional needs
(including but not limited to response time, safety, or positive
actuation). To utilize this exemption, a demonstration of the
functional need must be made and submitted in the initial annual
report. The proposed rule also includes requirements for natural gas-
driven intermittent vent controllers at these sites in Alaska without
access to electrical power. Specifically, the proposed rule would
require that an intermittent vent not vent to the atmosphere during