\99\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems Final Rule. November 2016.
Docket Item No. EPA-HQ-OAR-2015-0764-0066; also available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    We are also proposing in 40 CFR 98.236(q) to require that the
emissions be reported at the aggregation of calculated or measured
values for the combination of component type and leak detection method.
As discussed in more detail in section III.P.1 of this preamble,
numerous studies have shown that different leak detection methods
identify different populations of leaking components; therefore,
consistent with the delineation of the default emission factors by leak
detection method, site-specific emission factors are proposed to be
delineated in the same way.
5. Removal of Additional Method 21 Screening Survey for Other Screening
Survey Methods
    We are proposing to remove the additional Method 21 screening when
a survey is conducted using a method other than Method 21. Currently,
facilities using survey methods other than Method 21 to detect
equipment leaks may then screen the equipment identified as leaking
using Method 21 to determine if the leak measures greater than 10,000
parts per million by volume (ppmv) (see, e.g., 40 CFR 98.234(a)(1)). If
the Method 21 screening of the leaking equipment is less than 10,000
ppmv, then reporters may consider that equipment as not leaking. In the
2016 subpart W revisions, we added a leak detection methodology at 40
CFR 98.234(a)(6) (proposed 40 CFR 98.234(a)(1)(ii) in this proposal)
for using OGI in accordance with NSPS OOOOa, which does not include an
option for additional Method 21 screening. As noted in response to
comments on the subpart W proposal regarding the absence of this
optional additional Method 21 screening when using OGI in accordance
with NSPS OOOOa, the additional screening of OGI-identified leaking
equipment using Method 21 requires additional effort from reporters (81
FR 86500, November 30, 2016). Furthermore, as noted previously in this
section, the average emissions of leakers identified by OGI are greater
than leaks identified by Method 21. Directly applying the number of
OGI-identified leaks to the subpart W leaker emission factor specific
to that survey method would provide the most accurate estimate of
emissions, while selectively screening OGI-identified leaks using
Method 21 to reduce the number of reportable leakers would yield a low
bias in the reported emissions. Additionally, this would be incongruous
with the proposed application and supporting rationale of the proposed
monitoring method-specific adjustment factor, k (where the k value for
Method 21 with a leak definition of 10,000 ppm would need to be
applied) if OGI-identified leaks could be considered non-leaks based on
subsequent Method 21 monitoring. Therefore, we are proposing to require
reporters to directly use the leak survey results for the monitoring
method used to conduct the complete leak survey and are proposing to
eliminate this additional Method 21 screening provision. These proposed
amendments are expected to provide more accurate emissions data,
consistent with section II.B of this preamble.
6. Amendments Related to Oil and Natural Gas Standards and Emissions
Guidelines in 40 CFR Part 60
    As noted in the introduction to section II. of this preamble, the
EPA recently proposed NSPS OOOOb and EG OOOOc for certain oil and
natural gas new and existing affected sources, respectively. Under the
proposed standards in NSPS OOOOb and the proposed presumptive standards
in EG OOOOc, owners and operators would be required to implement a
fugitive emissions monitoring and repair program for the collection of
fugitive emissions components at well site, centralized production
facility and compressor station affected sources. In addition, the
proposed NSPS OOOOb and EG OOOOc include a proposed appendix K to 40
CFR part 60, specifying an OGI-based method for detecting leaks and
fugitive emissions from all components that is not currently provided
in subpart W. The EPA also proposed provisions in NSPS OOOOb and EG
OOOOc for equipment leak detection and repair at onshore natural gas
processing facilities. Similar to the 2016 amendments to subpart W (81
FR 4987, January 29, 2016), the EPA is proposing to revise the
calculation methodology for equipment leaks in subpart W so that data
derived from equipment leak and fugitive emissions monitoring using one
of the methods in 40 CFR 98.234(a) which is conducted under NSPS OOOOb
or the applicable approved state plan or applicable Federal plan in 40
CFR part 62 would be used to calculate emissions, consistent with
section II.B of this preamble.
    First, under these proposed amendments, facilities with certain
fugitive emissions components at a well site, centralized production
facility or compressor station subject to NSPS OOOOb or an applicable
approved state plan or applicable Federal plan in 40 CFR part 62 would
use the data derived from the NSPS OOOOb or applicable 40 CFR part 62
fugitive emissions requirements along with the subpart W equipment leak
survey calculation methodology and leaker emission factors to calculate
and report their GHG emissions to the GHGRP. Specifically, the proposed
amendments would expand the existing cross-reference to 40 CFR 60.5397a
to also include the analogous requirements in NSPS OOOOb or 40 CFR part
62. Facilities with fugitive emissions components not subject to the
standards in the proposed NSPS OOOOb or addressed by standards in a
state or Federal plan following finalization of the proposed EG OOOOc
would continue to be able to elect to calculate subpart W equipment
leak emissions using the leak survey calculation methodology and leaker
emission factors (as is currently provided in 40 CFR 98.233(q)).
Therefore, reporters with other fugitive emission sources at subpart W
facilities not covered by NSPS OOOOb or a state or Federal plan in 40
CFR part 62 (e.g., sources subject to other state regulations and
sources participating in the Methane Challenge Program or other
voluntarily implemented programs) would continue to have the
opportunity to voluntarily use the proposed leak detection methods to
calculate and report their GHG emissions to the GHGRP. To facilitate
this proposed requirement, we are also proposing to clarify in proposed
40 CFR 98.233(q)(1)(vi)(B) and (C) that fugitive emissions monitoring
conducted using one of the methods in 40 CFR 98.234(a) to comply with
NSPS OOOOb or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62, respectively, is considered a ``complete leak
detection survey,'' so that onshore petroleum and natural gas

production and onshore petroleum and natural gas gathering and boosting
facilities would be able to comply with the proposed requirement to use
NSPS OOOOb or 40 CFR part 62 fugitive emission surveys directly for
their subpart W reports. We are also proposing to move the
specification that fugitive emissions monitoring conducted to comply
with NSPS OOOOa is considered a ``complete leak detection survey'' from
existing 40 CFR 98.233(q)(2)(i) to proposed 40 CFR 98.233(q)(1)(vi)(A)
so that all the provisions regarding what constitutes a ``complete leak
detection survey'' are together. In a corresponding amendment, we are
also proposing to expand the current reporting requirement in existing
40 CFR 98.236(q)(1)(iii) (proposed 40 CFR 98.236(q)(1)(iv)) to require
reporters to indicate if any of the surveys of well sites, centralized
production facilities or compressor stations used in calculating
emissions under 40 CFR 98.233(q) were conducted to comply with the
fugitive emissions standards in NSPS OOOOb or an applicable approved
state plan or applicable Federal plan in 40 CFR part 62.\100\ We
request comment on these proposed amendments and whether there are
other provisions or reporting requirements relative to NSPS OOOOb or EG
OOOOc that we should consider for revisions to requirements under
subpart W.
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    \100\ We are similarly proposing to revise the existing
reporting requirement in subpart W related to NSPS OOOOa, such that
reporters would report whether any of the surveys of well sites or
compressor stations used in calculating emissions under 40 CFR
98.233(q) were conducted to comply with the fugitive emissions
standards in NSPS OOOOa (rather than simply reporting whether the
facility has well sites or compressor stations subject to the
fugitive emissions standards in NSPS OOOOa).
---------------------------------------------------------------------------

    Second, we are proposing to revise 40 CFR 98.234(a) to clarify and
consolidate the requirements for OGI and Method 21 in 40 CFR
98.234(a)(1) and (2), respectively. In the 2016 amendments to subpart W
(81 FR 4987, January 29, 2016), the EPA added 40 CFR 98.234(a)(6) and
(7) to provide OGI and Method 21 as specified in NSPS OOOOa as leak
detection survey methods. In part, structuring the amendment this way
allowed the EPA to provide the NSPS OOOOa leak detection methods as
allowable methods under subpart W without affecting the requirements
for facilities and industry segments not subject to NSPS OOOOa.
However, as the EPA continues to propose additional standards with
slightly different variations on OGI and Method 21, it would be
unnecessarily convoluted organizationally to continue to add those
methods and cross-references to each standard to the end of 40 CFR
98.234(a). Therefore, the EPA is proposing to move 40 CFR 98.234(a)(1)
and 40 CFR 98.234(a)(6) to 40 CFR 98.234(a)(1)(i) and 40 CFR
98.234(a)(1)(ii), respectively, which would consolidate the OGI-based
methods in 40 CFR 98.234(a)(1). Similarly, the EPA is proposing to
revise 40 CFR 98.234(a)(2) such that 40 CFR 98.234(a)(2)(i) is Method
21 with a leak definition of 10,000 ppm and 40 CFR 98.234(a)(2)(ii) is
Method 21 with a leak definition of 500 ppm. This proposed amendment
would effectively move 40 CFR 98.234(a)(7) to 40 CFR 98.234(a)(2)(ii).
We are also proposing that the references to ``components listed in
Sec.  98.232'' would be replaced with a more specific reference to 40
CFR 98.233(q)(1). The references to specific provisions in 40 CFR
60.5397a in 40 CFR 98.234(a)(6) and (7) would be moved to 40 CFR
98.234(a)(1)(ii) and 40 CFR 98.234(a)(2), as applicable.
    In December 2022, the EPA proposed in NSPS OOOOb and EG OOOOc that
owners and operators of natural gas processing facilities would detect
leaks using an OGI-based monitoring method following the concurrently
proposed appendix K to 40 CFR part 60. We are proposing to include that
same method in subpart W at 40 CFR 98.234(a)(1)(iii) to ensure that
reporters of those facilities would be able to comply with the proposed
subpart W requirement to use data derived from the NSPS OOOOb or 40 CFR
part 62 fugitive emissions requirements for purposes of calculating
emissions from equipment leaks. In addition, as part of the December
2022 proposal of NSPS OOOOb and EG OOOOc, the EPA proposed an
alternative screening approach for fugitive emissions from well sites,
centralized production facilities and compressor stations that would
allow the use of advanced measurement technologies to detect large
equipment leaks. Under the NSPS OOOOb and EG OOOOc proposal, if
emissions are detected using one of these advanced technologies,
facilities would be required to conduct monitoring using OGI or Method
21 to identify and repair specific leaking equipment. Additionally,
under the NSPS OOOOb and EG OOOOc proposal, even if no emissions are
identified during a screening survey, some facilities using these
advanced technologies would still be required to conduct annual
fugitive emissions monitoring using OGI. The EPA's intent in this
proposed rule for subpart W is that the results of those NSPS OOOOb and
40 CFR part 62 OGI or Method 21 surveys would be used for purposes of
calculating emissions for subpart W, as OGI and Method 21 are capable
of identifying leaks from individual components and they are leak
detection methods provided in subpart W. The EPA also requests comment
on additional methods or advanced technologies that can identify
individual leaking components. Based on the information received, the
EPA would need to review the specific method and leak detection data
collected using that method to determine what default leaker emission
factors would apply for that method and whether any adjustments might
be needed to the subpart W equipment leak survey calculation
methodology when using that method. Following that review, the EPA may
undertake a future rulemaking process to include the additional leak
detection method(s) in 40 CFR 98.234(a).
    Third, we are proposing subpart W requirements for onshore natural
gas processing facilities consistent with certain requirements for
equipment leaks in the proposed NSPS OOOOb or EG OOOOc. Currently,
onshore natural gas processing facilities must conduct at least one
complete survey of all the components listed in 40 CFR 98.232(d)(7)
each year, and each complete survey must be considered when calculating
emissions according to 40 CFR 98.233(q)(2). Under the equipment leak
detection and repair program included in proposed NSPS OOOOb and the EG
OOOOc presumptive standards, different component types may be monitored
on different frequencies, so all equipment at the facility is not
always monitored at the same time. According to the current
requirements in 40 CFR 98.233(q), surveys that do not include all of
the applicable equipment at the facility are not considered complete
surveys and are not used for purposes of calculating emissions.
Therefore, we are proposing in 40 CFR 98.233(q)(1)(vi)(F) that onshore
natural gas processing facilities subject to NSPS OOOOb or an
applicable approved state plan or the applicable Federal plan in 40 CFR
part 62 would use the data derived from each equipment leak survey
conducted as required by NSPS OOOOb or the relevant subpart of 40 CFR
part 62 along with the subpart W equipment leak survey calculation
methodology and leaker emission factors to calculate and report GHG
emissions to the GHGRP, even if a survey required for compliance with
NSPS OOOOb or 40 CFR part 62 does

not include all the component types listed in 40 CFR 98.232(d)(7).
    Under this proposed amendment, reporters would still have to meet
the subpart W requirement to conduct at least one complete survey of
all applicable equipment at the facility per year, so if there were
components listed in 40 CFR 98.232(d)(7) not included in any NSPS OOOOb
or 40 CFR part 62-required surveys conducted during the year (e.g.,
connectors that are monitored only once every 4 years), reporters
subject to NSPS OOOOb or 40 CFR part 62 would need to either add those
components to one of their required surveys, making that a complete
survey for purposes of subpart W, or conduct a separate complete survey
for purposes of subpart W. We expect that reporters with onshore
natural gas processing plants implementing traditional leak detection
and repair programs are already making similar decisions regarding how
to meet the requirement to conduct a complete survey for subpart W, and
our intention with this proposed amendment is not to change those
decisions. Rather, this amendment would specify that surveys conducted
pursuant to NSPS OOOOb or 40 CFR part 62 that do not include all
component types listed in 40 CFR 98.232(d)(7) would be used for
calculating emissions along with each complete survey.
    We are also proposing to add leaker emission factors for all survey
methods for ``other'' components that would be required to be monitored
under NSPS OOOOb or an approved state plan or applicable Federal plan
in 40 CFR part 62 or that reporters elect to survey that are not
currently included in subpart W. These proposed THC leaker emission
factors for the ``other'' component type are of the same value as the
THC leaker emission factors for the ``other'' component type for the
Onshore Natural Gas Transmission Compression and the Underground
Natural Gas Storage industry segments (existing Table W-3A and Table W-
4A, respectively, proposed Table W-4). For more information on the
derivation of the original emission factors, see the 2010 subpart W
TSD,\101\ and for more information on the derivation of the ``other''
component type emission factor proposed to be applied to these types of
leaks at facilities in the Onshore Natural Gas Processing industry
segment, see the TSD for the 2016 amendments to subpart W.\102\ In a
corresponding amendment, we are also proposing to expand the reporting
requirement in existing 40 CFR 98.236(q)(1)(iii) (proposed 40 CFR
98.236(q)(1)(iv)) to require onshore natural gas processing reporters
to indicate if any of the surveys used in calculating emissions under
40 CFR 98.233(q) were conducted to comply with the equipment leak
standards in NSPS OOOOb or an applicable approved state plan or the
applicable Federal plan in 40 CFR part 62. We request comment on the
proposed amendments to subpart W for onshore natural gas processing
facilities subject to the equipment leak provisions of NSPS OOOOb or 40
CFR part 62, as well as whether there are other provisions or reporting
requirements for these facilities that we should consider.
---------------------------------------------------------------------------

    \101\ Greenhouse Gas Emissions Reporting from the Petroleum and
Natural Gas Systems Industry: Background Technical Support. November
2010. Docket Id. No. EPA-HQ-OAR-2009-0923-3610; also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \102\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id.
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    Finally, in our review of subpart W equipment leak requirements for
onshore natural gas processing facilities, we found that the leak
definition for the Method 21-based requirements for processing plants
in NSPS OOOOa (as well as proposed NSPS OOOOb and EG OOOOc presumptive
standards) is not consistent with the leak definition in the Method 21
option in current 40 CFR 98.234(a)(2), which is the only Method 21-
based method available to onshore natural gas processing facilities
under subpart W. Based on this review, and to complement the proposed
addition of default leaker emission factors for survey methods other
than Method 21 (as described previously in this preamble), we are
proposing several additions to the equipment leak survey requirements
for the Onshore Natural Gas Processing industry segment, beyond those
amendments already described related to the proposed NSPS OOOOb and EG
OOOOc presumptive standards. First, we are proposing default leaker
emission factors for Method 21 at a leak definition of 500 ppm in
proposed Table W-4. As with the proposed ``other'' component type
leaker emission factors, these proposed leaker emission factors (i.e.,
valve, connector, open-ended line, pressure relief valve and meter) are
of the same value as the THC leaker emission factors for the Onshore
Natural Gas Transmission Compression and the Underground Natural Gas
Storage industry segments (existing Table W-3A and Table W-4A,
respectively). For more information on the derivation of those emission
factors, see the TSD for the 2016 amendments to subpart W.\103\ In
addition, we are proposing to add 40 CFR 98.233(q)(1)(v) to indicate
that onshore natural gas processing facilities not subject to NSPS
OOOOb or an approved state plan or the applicable Federal plan in 40
CFR part 62 may use any method specified in 40 CFR 98.234(a), including
Method 21 with a leak definition of 500 ppm and OGI following the
provisions of appendix K to 40 CFR part 60. This proposed amendment
would ensure that equipment leak surveys conducted using any of the
approved methods in subpart W would be available for purposes of
calculating emissions, not just those surveys conducted using one of
the methods currently provided in 40 CFR 98.234(a)(1) through (5).
---------------------------------------------------------------------------

    \103\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems. November 1, 2016. Docket Id.
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

7. Exemption for Components in Vacuum Service
    Through correspondence with the EPA via e-GGRT, some reporters have
stated that certain equipment leak components at their facility are in
vacuum service. These reporters indicated that there are no fugitive
emissions expected from components in vacuum service. After
consideration of these comments and in order to be consistent with
other EPA equipment leak regulatory programs (e.g., 40 CFR part 60,
subpart VVa), we have determined that we agree with commenters.
Therefore, we are proposing an exemption in the introductory paragraphs
of 40 CFR 98.233(q) and (r) for leak components in vacuum service from
the requirement to estimate and report emissions from these components.
We are also proposing a definition in 40 CFR 98.238 for the term ``in
vacuum service.'' We are proposing to require the reporting of the
count of equipment in vacuum service to enable verification of the
reported data (i.e., ability to confirm that all equipment for which
emissions are expected has been accounted for and an indication that
other equipment has been confirmed to meet the proposed definition of
``in vacuum service'').

Q. Equipment Leaks by Population Count

    As noted in section III.P of this preamble, subpart W reporters are
currently required to quantify emissions from equipment leaks using the

calculation methods in 40 CFR 98.233(q) (equipment leak surveys) and/or
40 CFR 98.233(r) (equipment leaks by population count), depending upon
the industry segment. The equipment leaks by population count method
uses the count of equipment components, subpart W emission factors
(e.g., existing Table W-1A for the Onshore Petroleum and Natural Gas
Production industry segment), and operating time to estimate emissions
from equipment leaks. For the Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments, the count of equipment components currently may be
determined by counting each component individually for each facility
(Component Count Method 2) or the count of equipment components may be
estimated using the count of major equipment and subpart W default
average component counts for major equipment (Component Count Method 1)
in existing Tables W-1B and W-1C, as applicable. Reporters in other
industry segments currently must count each applicable component at the
facility. We are proposing several amendments to the calculation
methodology provisions of 40 CFR 98.233(r) and the reporting
requirements in 40 CFR 98.236(r) to improve the quality of the data
collected, consistent with sections II.B and II.C of this preamble.
1. Onshore Petroleum and Natural Gas Production and Onshore Petroleum
and Natural Gas Gathering and Boosting Population Count Method
    The current population emission factors for the Onshore Petroleum
and Natural Gas Production and Onshore Petroleum and Natural Gas
Gathering and Boosting industry segments are found in existing Table W-
1A of subpart W. The gas service population emission factors are based
on the 1996 GRI/EPA study Methane Emissions from the Natural Gas
Industry, Volume 8: Equipment Leaks (available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234). The oil service
population emission factors are based on the American Petroleum
Institute's (API) Emission Factors for Oil and Gas Production
Operations, Publication 4615, published in 1995.
    As noted previously in this section, when estimating emissions
using the population count method, onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities currently have the option to use actual
component counts (i.e., Component Count Method 2) or to estimate their
component counts using the count of major equipment (e.g., wellhead)
and default component counts per major equipment (e.g., valves per
wellhead) included in existing Tables W-1B and W-1C of subpart W (i.e.,
Component Count Method 1). In reviewing subpart W data, we find that
the vast majority (greater than 95 percent) of onshore production and
natural gas gathering and boosting facilities use Component Count
Method 1 to estimate the count of components.
    It is important to note that both the population count emission
factors and the default component counts per major equipment currently
included in Tables W-1A, W-1B and W-1C are service-specific (i.e., gas
or oil) as well as region-specific (i.e., eastern or western U.S.). The
regional designations are provided by U.S. state in existing Table W-1D
of subpart W such that a facility would determine the facility's region
and select the appropriate region- and service-specific factors.
    In the years that have followed the adoption of these emission
factors into subpart W, there have been numerous studies regarding
emissions from equipment leaks at onshore production and gathering and
boosting facilities. Two recent field studies, Pacsi et al. (2019)
\104\ and Zimmerle et al. (2020),\105\ have performed an equipment and
component inventory alongside equipment leak screening and measurement
results. Another recent study, Rutherford et al. (2021),\106\ included
synthesis and analysis of measurements from component-level field
studies. These studies' data allow development of study-estimated
population emission factors as well as study-estimated default
component counts per major equipment and comparison of them to those in
subpart W. Comparison of the study-estimated default component counts
per major equipment found that the subpart W values underestimate the
count of components found on major equipment in the field (Zimmerle et
al., 2020; Pacsi et al., 2019). Regarding a comparison of the
population emission factors and component counts per major equipment
between the subpart W eastern and western values, Zimmerle et al.
(2020) was the only field study to include both eastern and western
facilities, and the study values showed ``no statistically significant
differences between eastern and western U.S. regions.'' Rutherford et
al. (2021) also found their study-estimated population emission factors
to be higher than those in subpart W, noting that one of the
contributing factors to this difference was the use of the eastern
factors in subpart W, which appear to significantly undercount
emissions. Rutherford et al. (2021) noted that the impact of the use of
the eastern factors has grown over time as the production in the
eastern region of the U.S. has increased from less than 5 percent of
gas produced to nearly 30 percent of the gas produced.
---------------------------------------------------------------------------

    \104\ Pacsi, A.P. et al. Equipment leak detection and
quantification at 67 oil and gas sites in the Western United States.
Elementa (2019). https://doi.org/10.1525/elementa.368. Available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \105\ Zimmerle, D., et al. Methane Emissions from Gathering
Compressor Stations in the U.S. Environmental Science & Technology
54 (12), 7552-7561 (2020). https://doi.org/10.1021/acs.est.0c00516.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \106\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al.
Closing the methane gap in US oil and natural gas production
inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    In the 2022 Proposed Rule, we proposed to revise the current
population emission factors to use major equipment-based emission
factors developed using a combination of data from Zimmerle et al.,
2020 and Pacsi et al., 2019. As described in more detail below,
consistent with the 2022 Proposed Rule, we are again proposing revised
emission factors on a per major equipment basis rather than on a per
component basis. However, in this proposed rulemaking, we are proposing
to use the data from Rutherford et al. (2021), which is comprised of
several published studies including Pacsi et al. 2019, to inform the
emission factor values. As described in more detail below, the
Rutherford et al. (2021) study represents the largest dataset set
available and thus, more accurately accounts for the variability
observed in equipment leak measurement data in terms of the size and
frequency of leaks.
    Based on our review of these studies, our assessment is that they
support revision of the population count method and corresponding
emission factors for onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting facilities and
we are proposing to amend this population count method and
corresponding emission factors after consideration of these more recent
study data, consistent with section II.B of this preamble. These
proposed amendments include new population emission factors that are on
a per major equipment basis rather than a per component basis. As
mentioned previously, the vast majority of reporters estimate the
component counts using

Component Count Method 1. By providing emission factors on a major
equipment basis instead of by component, we would eliminate the step to
estimate the number of components. All facilities would be able to
count the actual number of major equipment and consistently apply the
same emission factor to calculate emissions. This would reduce reporter
burden and reduce the number of errors in the calculation of emissions,
as we find that numerous facilities incorrectly estimate the number of
components using Component Count Method 1 while providing consistently
estimated emission results.
    In comparing the recent study data for this proposal, our
assessment is that the Rutherford et al. (2021) study represents the
most robust sample size of approximately 3,700 measurements for
developing population emission factors by major equipment. The larger
sample size is likely more representative of varying degrees of leak
detection and repair programs (i.e., not only facilities conducting
frequent surveys), which can impact the number of leaks found during
surveys (i.e., if more frequent surveys are being conducted and leaks
are being repaired in a timely manner, then each survey likely finds
less leaks). The Rutherford et al. (2021) study also employs a
bootstrap resampling statistical approach \107\ that allows for the
inclusion of infrequent large emitters (i.e., ``super-emitters'') in
the development of the emission factors, improving the representation
of the inherent variability of equipment leaks in the developed
emission factors. Therefore, we are proposing major equipment emission
factors developed using Rutherford et al. (2021) to provide population
emission factors by major equipment and site type (i.e., natural gas
system or petroleum system). The proposed emission factors were taken
from Supplementary Tables 3 and 4 of Rutherford et al. (2021). The
average emission factors presented in these study tables were converted
from units of kilograms per day to standard cubic feet of whole gas per
hour for cumulative equipment component leaks from different types of
major equipment including wellheads, separator, heater, meter including
headers, compressor, dehydrator and tanks. The major equipment
indicating venting emissions (e.g., tanks--unintentional vents) or
emissions from other sources also covered by subpart W (e.g., liquids
unloading, flaring, pumps) are not included in the proposed equipment
leak population emission factors. Specific to meters/piping and
consistent with current requirements related to meters/piping at
existing 40 CFR 98.233(r)(2)(i)(A), we are proposing in 40 CFR
98.233(r)(2) to specify that one meters/piping equipment should be
included per well-pad for onshore petroleum and natural gas production
operations and the count of meters in the facility should be used for
this equipment category at onshore petroleum and natural gas gathering
and boosting facilities. As a consequence of the broader scope of
equipment surveyed in the study data that inform Rutherford et al.
(2021), the proposed emission factors in proposed Table W-1 include
more pieces of major equipment than are currently included in Table W-
1B and W-1C of subpart W. A complete description of the derivation of
the proposed emission factors is discussed in more detail in the
subpart W TSD, available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234. The proposed major equipment emission factors
would replace the current component-based emission factors in the
existing Table W-1A. We are also proposing to remove Tables W-1B, W-1C,
and W-1D since they would no longer be needed for the population count
method for these industry segments. We are proposing amendments to the
reporting requirements for the use of the population count method to
align with the reporting of major equipment counts consistent with the
proposed emission factors in 40 CFR 98.236(r). We are seeking comment
on the development of population count emission factors based on major
equipment. We are also seeking comment on the proposed use of the
Rutherford et al. (2021) study data instead of using study data from
Zimmerle et al. (2020) and/or Pacsi et al. (2019) to provide the
population count emission factors by major equipment, and the rationale
supporting the use of the respective study data.
---------------------------------------------------------------------------

    \107\ Bootstrapping is a type of resampling where a known
dataset is repeatedly drawn from, with replacement, to generate a
sample distribution.
---------------------------------------------------------------------------

2. Natural Gas Distribution Emission Factors
    Natural gas distribution companies currently quantify the emissions
from equipment leaks from pipeline mains and services, below grade
transmission distribution transfer stations, and below grade metering-
regulating stations following the procedures in 40 CFR 98.233(r). This
method uses the count of equipment, subpart W population emission
factors in existing Table W-7 (proposed Table W-5 in this proposal),
and operating time to estimate emissions. The population emission
factors for distribution mains and services in existing Table W-7
(proposed Table W-5) are based on information from the 1996 GRI/EPA
study.\108\ Specifically for plastic mains, additional data are sourced
from a 2005 ICF analysis.\109\ The population emission factors for
distribution mains are published per mile of main by pipeline material
and emission factors for distribution services are published per
service by pipeline material. The population emission factors for below
grade stations in existing Table W-7 (proposed Table W-5) are based on
information from the 1996 GRI/EPA study.\110\ The population emission
factors for below grade transmission-distribution transfer stations and
below grade metering-regulating stations are currently specified in the
existing Table W-7 per station by three inlet pressure categories (>300
pounds per square inch gauge (psig), 100-300 psig, < 100 psig).
---------------------------------------------------------------------------

    \108\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 9: Underground Pipelines. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L.
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234.
    \109\ ICF. Fugitive Emissions from Plastic Pipe, Memorandum from
H. Mallya and Z. Schaffer, ICF Consulting to L. Hanle and E.
Scheehle, EPA. June 30, 2005. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
    \110\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 10: Metering and Pressure Regulating Stations in Natural Gas
Transmission and Distribution. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell and B.E. Stapper, Radian
International LLC. GRI-94/0257.27, EPA-600/R-96-080j. June 1996.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    In this rulemaking, the EPA is proposing to update the population
emission factors in existing Table W-7 (proposed Table W-5) to subpart
W using the results of studies and information that were not available
when the rule was finalized in 2010. Notably, the EPA reviewed recent
studies and updated the emission factors for several natural gas
distribution sources, including pipeline mains and services and below
grade stations, for the 2016 U.S. GHG Inventory.\111\ The majority of
the U.S. GHG Inventory updates were based on

data published by Lamb et al. in 2015.\112\ Since the time that the
2016 U.S. GHG Inventory updates were made, additional studies for
pipeline distribution mains have been published and reviewed by the
EPA, notably Weller et al. in 2020.\113\ Our assessment of the studies
published since subpart W was finalized supports revising the emission
factors for pipelines in the Natural Gas Distribution industry segment
of subpart W.
---------------------------------------------------------------------------

    \111\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions.
April 2016. Available at https://www.epa.gov/sites/production/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \112\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing
Methane Emissions from Natural Gas Local Distribution Systems in the
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
    \113\ Weller, Z.D.; Hamburg, S.P.; and Von Fischer, J.C. 2020.
``A National Estimate of Methane Leakage from Pipeline Mains in
Natural Gas Local Distribution Systems.'' Environ. Sci. Technol.
2020, 54(1), 8958. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The population emission factors for distribution mains and services
are a function of the average measured leak rate (in standard cubic
feet per hour) and the frequency of annual leaks observed (leaks/mile-
year or leaks/service-year) by pipeline material (e.g., protected
steel, plastic). The Lamb et al. and Weller et al. studies utilized
different approaches for quantifying leak rates and determining the
pipeline material-specific frequency of annual leaks. The Lamb et al.
study quantified leaks from distribution mains and services using a
high volume sampling method and some downwind tracer measurements and
estimated the frequency of leaks by pipeline material using company
records and Department of Transportation (DOT) repaired leak records
from six local distribution companies (LDCs). This methodology was
consistent with the 1996 GRI/EPA study. The Weller et al. study
quantified leaks from only distribution mains using the AMLD technique,
which involves mobile surveying using high sensitivity instruments and
algorithms that predict the leak location and size, attributed leaks to
the pipeline material using geographic information system (GIS) data,
and estimated the frequency of leaks using modeling.
    In the 2022 Proposed Rule, we proposed to revise the pipeline main
equipment leak emission factors using a combination of data from Lamb
et al. (2015) and Weller et al. (2020). We sought comment on the
approach of combining data from these two studies. We received numerous
comments regarding the classification of pipeline materials and
respective quantified leaks in the Weller et al. (2020) study. In
response to these comments and as discussed in more detail below, we
agree with commenters that the categorization of pipeline leaks by
material type likely resulted in inaccuracies specifically for the
unprotected and protected steel pipeline material types. In this
rulemaking, we are continuing to propose revisions of the equipment
leak pipeline main emission factors using more recent study data, but
instead of combining data from Lamb et al. (2015) and Weller et al.
(2020), we are proposing to rely only on the Lamb et al. (2015) study.
    In subpart W, there are currently four categories of pipeline
mains: unprotected steel, protected steel, plastic, and cast iron. The
steel categories are differentiated by the presence of cathodic
protection, and, as evidenced by the 1996 GRI/EPA study and Lamb et al.
study data, unprotected steel pipelines are considered to be more leak
prone than cathodically protected steel pipelines. In the Weller et al.
study, the categories of pipeline mains include bare (unprotected)
steel, coated (protected) steel, cast iron, and plastic. We note that
steel pipelines can be protected by cathodic protection and/or coating,
and in the Weller et al. study, cathodically unprotected yet coated
steel pipeline mains appear to have been grouped with cathodically
protected steel pipeline mains. Using the unprotected and protected
steel classifications in the Weller et al. study would thus result in
emission factors for protected steel that are higher than for
unprotected steel, which would conflict with other study data (e.g.,
1996 GRI/EPA, Lamb et al.) as well as voluntary emissions reductions
programs (e.g., EPA Natural Gas STAR). The pipeline categories in the
Weller et al. study do not provide the necessary differentiation to
properly update the emission factors for unprotected (i.e., not
cathodically protected) steel and cathodically protected steel pipeline
mains. For more information on the review and analysis of the Lamb et
al. and Weller et al. studies, see the subpart W TSD, available in the
docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2023-0234).
    In consideration of our review and analysis of recent study data
relative to natural gas pipeline mains and services, and consistent
with the emission factors used in the 2016 U.S. GHG Inventory, we are
proposing to provide emission factors for distribution pipeline mains
and services based on the Lamb et al. study leak rates and the 1996
GRI/EPA study leak incidence data. For more information on the
derivation of the proposed emission factors, see the subpart W TSD,
available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-
2023-0234).
    We are also seeking comments on alternative methods for quantifying
and reporting emissions from distribution mains and services. For
distribution mains and services, we are seeking comments on the use of
direct measurement as well as application of a leaker emission factor
approach. For the use of direct measurement, we are seeking comment on
whether facilities should be permitted to develop facility-specific
distribution main and service emission factors for each type of
pipeline material based on direct measurements and if so, what the
appropriate number of measurements should be for determining a
representative emission factor for each pipeline material including
supporting rationale. For facility-specific emission factors based on
direct measurement, we are seeking comment on the development of both
leaker emission factors and population emission factors. We are seeking
comment on what quantification techniques are best suited for measuring
emissions from distribution pipeline leaks and whether these techniques
require digging down to the pipeline in order to quantify emissions and
also verify pipeline characteristics. For a leaker emission factor
approach, we are specifically interested in what survey techniques are
appropriate and why, including supporting information on specific
instruments and their detection capabilities and whether certain
methods are more suitable for the survey of distribution pipeline leaks
than others. We are seeking comment on the scope and frequency of leak
detection surveys for distribution pipelines and whether annual surveys
of the entire pipeline system or a reduced frequency of survey (i.e.,
partial surveys over a multi-year survey cycle in which the entire
system is surveyed during the survey cycle and approximately equal
portions of the system are surveyed each year of the multi-year survey
cycle) is more appropriate and why. Finally, we are seeking comment on
application of a leaker emission factor approach using default factors
(i.e., not facility specific based on direct measurement) and available
data that could be used in the development of default leaker emission
factors for distribution mains and services.
    For below grade stations, the 2016 U.S. GHG Inventory also began
applying a new emission factor from the data published by Lamb et al.
to the count of stations to estimate emissions from these sources. In
order to assess the

appropriateness of incorporating this revision into the subpart W
requirements for below grade stations (i.e., replacing the set of below
grade emission factors by station type and inlet pressure with one
single emission factor), the EPA performed an analysis of the reported
subpart W data for below grade stations compared to data from the
recent studies (see the subpart W TSD, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234). We found that the
subpart W reported station count combined with the current subpart W
emission factors yields an average emission factor similar to the U.S.
GHG Inventory emission factor; as such, using either set of emission
factors would yield approximately the same emissions results for the
GHGRP.
    Therefore, we are proposing to amend the emission factors for below
grade transmission-distribution transfer stations and below grade
metering-regulating stations in existing Table W-7 (proposed Table W-5)
to a single emission factor without regard to inlet pressure. We are
also proposing to amend the corresponding section header in existing
Table W-7 (proposed Table W-5) for below grade station emission factors
and the references to existing Table W-7 (proposed Table W-5) in 40 CFR
98.233(r)(6)(i) to clarify the emission factor that should be applied
to both types of below grade stations (i.e., transmission-distribution
transfer and metering-regulating). This proposed amendment would impact
the reporting requirements in 40 CFR 98.236(r) as well, as it would
consolidate six emission source types to two emission source types
(below grade transmission-distribution transfer stations and below
grade metering-regulating stations, without differentiating between
inlet pressures) for purposes of reporting under 40 CFR 98.236(r)(1).
This proposed amendment would improve the data quality through use of
more recent emission factors and would be consistent with changes made
to the U.S. GHG Inventory. It would also result in reporting of fewer
data elements, consistent with section II.C of this preamble.
3. Gathering Pipeline Emission Factors
    Facilities in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment currently quantify the emissions from
equipment leaks from gathering pipelines following the procedures in 40
CFR 98.233(r). This method uses the count of equipment, subpart W
population emission factors in existing Table W-1A, and operating time
to estimate emissions. The population emission factors for gathering
pipeline mains in existing Table W-1A are based on leak rates from
natural gas distribution companies and gathering pipeline-specific
activity data as provided in the 1996 GRI/EPA study.\114\ The
population emission factors for gathering pipelines are published per
mile by pipeline material.
---------------------------------------------------------------------------

    \114\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 9: Underground Pipelines. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L.
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA is aware of a recent study that characterized emissions
from gathering pipelines and could potentially be used to develop
population emission factors, Yu et al. (2022).\115\ The Yu et al.
(2022) study used measurements acquired over four aerial campaigns of
the Midland and Delaware sub-basins in the Permian basin. The resulting
emission rate provides a basin-level population emission factor
(megagrams CH4 per kilometer-year). The EPA is not proposing
to use this data in subpart W for the development of gathering pipeline
emission factors because it does not specify the pipeline material
type, as the current subpart W and proposed subpart W emission factors
do. The material-specific emission factors more readily allow operators
to track and quantify emission reductions from pipeline replacement
projects (e.g., replacing more leak prone pipeline materials such as
cast iron with less leak prone materials such as plastic). The
resulting emission factors from Yu et al. rely on emission estimation
techniques that have a lower degree of sensitivity than ground-based
measurements. In order to overcome this limitation, the study authors
performed sensitivity analyses to account for below detection limit
leaks. The major finding of this study is that gathering pipelines have
highly skewed emissions data distribution with very large leaks that
only occur every few hundred miles. Finally, our assessment is that
this study is geographically limited and are concerned that an emission
factor derived with these study data may not be nationally
representative. Additional discussion of the Yu et al. study, including
population emission factors developed using study data as they compare
to subpart W, is included in the subpart W TSD, available in the docket
for this rulemaking (Docket Id. No. v). We are seeking comment on the
EPA's decision not to use the Yu et al. study data in developing
proposed population emission factors, including rationale supporting
the EPA's decision or rationale for why this study should be used in
developing proposed population emission factors. Additionally, we are
seeking comments on whether there are other published studies the EPA
should evaluate for potential use in developing revised emission
factors for gathering pipelines.
---------------------------------------------------------------------------

    \115\ Yu, J. et al. ``Methane Emissions from Natural Gas
Gathering Pipelines in the Permian Basin.'' Environ. Sci. Technol.
Lett. 2022, 9, 969-974. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    As noted previously in this section, the EPA is proposing to update
the natural gas distribution population emission factors in existing
Table W-7 (proposed Table W-5) to subpart W using the results of
studies and information that were not available when the rule was
originally finalized. In particular, the EPA is proposing to update the
leak rate portion of the emission factor based on data published by
Lamb et al. in 2015.\116\
---------------------------------------------------------------------------

    \116\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing
Methane Emissions from Natural Gas Local Distribution Systems in the
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    The EPA has reviewed the recent studies published for Onshore
petroleum and natural gas gathering and boosting facilities including
the previously discussed Yu et al. study, as well as the additional
studies for pipeline distribution mains, and concluded none of the
studies provide new emissions data or activity data specific to
gathering pipelines suitable to update the existing emission factors.
Therefore, consistent with the updates to the emission factors for
distribution mains, and consistent with section II.B of this preamble,
we are proposing to revise the gathering pipeline population emission
factors in proposed Table W-1 to use the leak rates from Lamb et al.
(2015). We are not proposing to update the activity data (leaks per
mile of pipeline) portion of the emission factors, as the information
in the 1996 GRI/EPA study continues to be the best available data
specific to gathering pipelines. For more information on the proposed
updates to the gathering pipeline population emission factors, see the
subpart W TSD, available in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2023-0234).
    We are also seeking comments on alternative methods for quantifying
and reporting emissions from gathering pipelines. We are seeking
comments on the use of direct measurement as well as

application of a leaker emission factor approach. For the use of direct
measurement, we are seeking comment on whether facilities should be
permitted to develop facility-specific emission factors for each type
of pipeline material based on direct measurements and if so, what the
appropriate number of measurements should be for determining a
representative emission factor for each pipeline material including
supporting rationale. For facility-specific emission factors based on
direct measurement, we are seeking comment on the development of both
leaker emission factors and population emission factors. We are seeking
comment on what quantification techniques are best suited for measuring
emissions from gathering pipeline leaks and whether these techniques
require digging down to the pipeline in order to quantify emissions and
also verify pipeline characteristics. For a leaker emission factor
approach, we are specifically interested in what survey techniques are
appropriate and why, including supporting information on specific
instruments and their detection capabilities and whether certain
methods are more suitable for the survey of gathering pipeline leaks
than others. We are seeking comment on the scope and frequency of leak
detection surveys for gathering pipelines and whether annual surveys of
the entire pipeline system or a reduced frequency of survey (i.e.,
partial surveys over a multi-year survey cycle in which the entire
system is surveyed during the survey cycle and approximately equal
portions of the system are surveyed each year of the multi-year survey
cycle) is more appropriate and why. Finally, we are seeking comment on
application of a leaker emission factor approach using default factors
(i.e., not facility specific based on direct measurement) and available
data that could be used in the development of default leaker emission
factors for gathering pipelines.

R. Offshore Production

    Currently, subpart W requires offshore production facilities to
report emissions consistent with the methods published by the U.S.
Department of Interior, Bureau of Ocean Energy Management (BOEM). Since
subpart W was first promulgated, there have been a number of updates to
the BOEM requirements and how BOEM implements the requirements (e.g.,
the development of their Outer Continental Shelf Air Quality System
(OCS AQS) \117\), and the EPA is proposing to amend subpart W to
reflect those changes. Specifically, the EPA is proposing to update
outdated acronym ``BOEMRE'' to the current acronym ``BOEM'' in 40 CFR
98.232(b), 40 CFR 98.233(s), and 40 CFR 98.236(s); to update the cross
references to the BOEM requirements from ``30 CFR 250.302 through 304''
to ``30 CFR 550.302 through 304'' in 40 CFR 98.232(b), 40 CFR
98.233(s), and the introductory paragraph of 40 CFR 98.234; and to
remove the outdated references to ``GOADS'' from 40 CFR 98.233(s). The
EPA is also proposing to adjust some of the language in 40 CFR
98.232(b) and 40 CFR 98.233(s) to more accurately reflect the current
BOEM program and requirements (e.g., adjusting the number of years
between BOEM data collection efforts from 4 to 3 years, referring to
published data and data submitted to BOEM rather than an emissions
study).
---------------------------------------------------------------------------

    \117\ For more information on this system and the emissions
inventories collected by the system, see https://www.boem.gov/environment/environmental-studies/ocs-emissions-inventories.
---------------------------------------------------------------------------

    Emissions data are collected by BOEM every few years. In years that
coincide with a year in which BOEM collects data, offshore production
facilities that report emissions inventory data to BOEM report the same
annual emissions to subpart W as calculated and reported to BOEM
(existing 40 CFR 98.233(s)(1)) and facilities that do not report
emissions inventory data to BOEM must use the most recent monitoring
and calculation methods published by BOEM (existing 40 CFR
98.233(s)(2)). In the intervening years, reporters currently are
required to adjust emissions based on the operating time for the
facility in the current reporting year relative to the operating time
in the most recent BOEM data submission or BOEM emissions study
publication year. The EPA is proposing two revisions for these
intervening years. First the EPA is proposing to require reporters to
report two new data elements in these years, the facility's operating
hours in the current year and the facility's operating hours from the
BOEM emission study publication year that is the basis for the reported
emissions. This information would improve verification, consistent with
section II.C of this preamble. Second, as an alternative to the current
adjustment using operating hours in years that do not overlap with the
most recent BOEM data submission or BOEM emissions study publication
year, as applicable, the EPA is also proposing to allow reporters to
calculate emissions using the most recent monitoring and calculation
methods published by BOEM referenced in 30 CFR 550.302 through 304
(implemented through the OCS AQS). This alternative is expected to
improve data quality through the use of more empirical data, consistent
with section II.B of this preamble.
    Finally, to better align the emissions reported by offshore
production facilities between BOEM's Outer Continental Shelf Emissions
Inventory and the GHGRP, the EPA is proposing that offshore production
facilities report the BOEM Facility IDs that constitute the GHGRP
facility. Having a definitive point of reference between the two
datasets would allow the EPA to better verify the emissions reported to
the GHGRP.

S. Combustion Equipment

1. Clarifications of Calculation Methodology Applicability
    All facilities reporting under subpart W except those in the
Onshore Natural Gas Transmission Pipeline industry segment must include
combustion emissions in their annual report. Facilities in the Onshore
Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas
Gathering and Boosting, and Natural Gas Distribution industry segments
calculate emissions in accordance with the provisions in 40 CFR
98.233(z) and report combustion emissions per 40 CFR 98.236(z).
Reporters in the other industry segments calculate and report
combustion emissions under subpart C (General Stationary Fuel
Combustion Sources). Subpart W refers reporters in these segments to
the calculation methodologies in subpart C to determine combustion
emissions for certain fuels. Specifically, 40 CFR 98.233(z)(1)
specifies that reporters may use any tier of subpart C if the fuel
combusted is listed in Table C-1; the paragraph further specifies that
the subpart C methodologies may only be used for fuel meeting the
definition of ``natural gas'' in 40 CFR 98.238 if it is also of
pipeline quality specification and has a minimum HHV of 950 British
thermal units per standard cubic foot (Btu/scf). If the fuel is natural
gas that does not meet these criteria, field gas, process vent gas, or
a blend containing field gas or process vent gas, 40 CFR 98.233(z)(1)
specifies that the procedures in 40 CFR 98.233(z)(2) should be used to
calculate combustion emissions.
    Certain stakeholders have identified several concerns with these
requirements. In general, these stakeholders have stated that the
ability to use subpart C calculation methodologies is too restrictive,
and some of their feedback also indicates

they may have been misinterpreting some of the provisions. We are
proposing several amendments to these provisions to address these
concerns, which would improve the accuracy of the emissions calculated
and therefore the quality of data collected, consistent with section
II.B of this preamble.
    First, a stakeholder indicated that some member companies have been
interpreting the existing provisions of 40 CFR 98.233(z)(1)(ii) that
require emissions to be reported according to 40 CFR 98.236(z) and not
subpart C to mean that reporters with combustion sources at onshore
petroleum and natural gas production facilities, at onshore petroleum
and natural gas gathering and boosting facilities, and at natural gas
distribution facilities must use the calculation methodologies in
subpart W for all fuel types rather than subpart C (even given the
provisions in 40 CFR 98.233(z)(1) that reference subpart C for certain
fuels).\118\ The existing provisions of 40 CFR 98.233(z)(1)(ii) are
intended to refer only to the reporting requirements and are not
intended to define which calculation methodologies can be used. In the
existing rule, the provisions in the 40 CFR 98.233(z)(1) introductory
text define which calculation methodologies can be used, and 40 CFR
98.233(z)(1)(ii) simply indicates that all reporters with combustion
sources at onshore petroleum and natural gas production facilities, at
onshore petroleum and natural gas gathering and boosting facilities,
and at natural gas distribution facilities must report those emissions
in the e-GGRT system under subpart W rather than under subpart C. As
part of the amendments described in this section, consistent with
section II.D of this preamble, 40 CFR 98.233(z)(1)(ii) is proposed to
be moved to 40 CFR 98.233(z)(5), and we are proposing wording changes
to highlight that this paragraph refers only to the requirement to
report combustion emissions under subpart W and does not preclude
reporters from using subpart C methods to calculate emissions if they
qualify to do so under proposed 40 CFR 98.233(z)(1) (and proposed 40
CFR 98.233(z)(2), as described later in this section. We are also
proposing to add a reference to this new proposed paragraph 40 CFR
98.233(z)(5) in both proposed 40 CFR 98.233(z)(1)(ii) and proposed
98.233(z)(2)(ii).
---------------------------------------------------------------------------

    \118\ Letter from GPA Midstream Association to Mark de
Figueiredo, U.S. EPA, providing information in response to EPA
questions during the meeting on March 23, 2016. May 18, 2016.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    Second, a stakeholder has asked for EPA guidance regarding whether
field gas that is of pipeline quality meets the criteria to use the
subpart C methodologies under the existing 40 CFR 98.233(z)(1),\119\
and the stakeholder noted that ``field gas'' is not defined within
existing subpart W or subpart A (General Provisions). The terms ``field
gas'' and ``field quality'' are frequently used interchangeably by the
industry, but the EPA also recognizes that some streams in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segment that
industry would generally call ``field gas'' can be natural gas (as
defined in 40 CFR 98.238) of pipeline quality with a minimum HHV of 950
Btu/scf. After consideration of these concerns, the EPA is proposing to
revise 40 CFR 98.233(z)(1) to remove the references to field gas and
process vent gas and include only the characteristics for the fuels
that can use subpart C methodologies. The EPA's intent is to indicate
that a stream colloquially referred to as ``field gas'' that otherwise
meets the three criteria to use the subpart C methodologies for
combustion emissions (i.e., (1) meets the definition of ``natural gas''
in 40 CFR 98.238; (2) is of pipeline quality specification; and (3) has
a minimum HHV of 950 Btu/scf) may use subpart C methodologies. The EPA
is also proposing conforming edits to existing 40 CFR 98.233(z)(2)
(proposed 40 CFR 98.233(z)(3) in this proposed rule) for consistency.
---------------------------------------------------------------------------

    \119\ Letter from GPA Midstream Association to Mark de
Figueiredo, U.S. EPA, providing information in response to EPA
questions during the meeting on March 23, 2016. May 18, 2016.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

    Third, certain reporters have indicated in questions submitted to
the GHGRP Help Desk that the term ``pipeline quality'' is used in
existing 40 CFR 98.233(z)(1) but it is not defined in subpart W. In
addition, a stakeholder has opined that the emissions calculated using
subpart C and subpart W calculation methodologies are similar for many
fuel streams that are not natural gas of pipeline quality specification
with a minimum HHV of 950 Btu/scf. Therefore, the stakeholder suggested
that the EPA should allow subpart C calculation methodologies to be
used for a wider variety of fuels (if not all fuels in the segments
that report combustion emissions under subpart W).\120\
---------------------------------------------------------------------------

    \120\ See Letter from GPA Midstream Association to Mark de
Figueiredo, U.S. EPA, providing information in response to EPA
questions during the meeting on March 23, 2016. May 18, 2016. See
also Letter from Matt Hite, GPA Midstream Association, to Mark de
Figueiredo, U.S. EPA, Re: Additional Information on Suggested Part
98, Subpart W Rule Revisions to Reduce Burden. September 13, 2019.
Both letters are available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    We have reviewed this stakeholder's analysis and conducted our own
analysis of additional hypothetical fuel compositions. In general, we
observed that the agreement of emissions as calculated using subpart C
calculation methodologies for natural gas and using subpart W
calculation methodologies varies based on the composition, with the
largest differences resulting for fuel streams with high CO2
content. We also observed that for these fuels, emissions calculated
using subpart W calculation methodologies generally showed better
agreement with emissions calculated using the subpart C calculation
methodology for natural gas when using a site-specific HHV (Tier 2)
than with emissions calculated using the subpart C calculation
methodology that uses a default HHV (Tier 1). For more information on
our fuel composition analysis and the comparison of emissions using
various composition thresholds, see the subpart W TSD, available in the
docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2023-0234).
    Based on our analysis, we are proposing to add numeric composition
thresholds for natural gas to a new proposed paragraph in 40 CFR
98.233(z)(2) that define the fuels for which an owner or operator may
use subpart C methodologies. In particular, we are proposing that
subpart C methodologies Tier 2 or higher may be used for fuel meeting
the definition of ``natural gas'' in 40 CFR 98.238 if it has a minimum
HHV of 950 Btu/scf, a maximum CO2 content of 1 percent by
volume, and a minimum CH4 content of 85 percent by volume. We are not
proposing to amend the existing provisions in 40 CFR 98.233(z)(1) that
allow the use of any subpart C calculation methodology for natural gas
of pipeline quality specification with a minimum HHV of 950 Btu/scf
(other than the proposed clarifications noted earlier in this section).
We are also proposing to move the existing provisions for fuels that do
not meet the specifications to use subpart C methodologies from 40 CFR
98.233(z)(2) to a new proposed paragraph 40 CFR 98.233(z)(3). This
proposed amendment would allow reporters to use subpart C methodologies
for a wider variety of fuel streams while still ensuring data quality.
We request comment on the natural gas specifications included in
proposed 40 CFR 98.233(z)(2), including the values proposed for the
maximum

CO2 content and minimum CH4 content, as well as
whether additional specification criteria should be included (e.g., a
maximum HHV).
2. Methane Slip from Internal Combustion Equipment
    The authors of several recent studies have examined combustion
emissions at Onshore Petroleum and Natural Gas Gathering and Boosting
facilities and have demonstrated that a significant portion of
emissions can result from unburned CH4 entrained in the
exhaust of natural gas compressor engines (also referred to as
``combustion slip'' or ``methane slip''). These studies contend that
emissions from natural gas compressor engines included in the GHGRP are
significantly underestimated because they do not account for combustion
slip.\121\ The EPA performed a review of each of these studies and the
U.S. GHG Inventory to determine whether and how combustion slip
emissions have been incorporated into published data and how the
incorporation of combustion slip would affect the emissions from the
petroleum and natural gas system sector reported to the GHGRP (see the
subpart W TSD, available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234).
---------------------------------------------------------------------------

    \121\ Zimmerle et al., Characterization of Methane Emissions
from Gathering Compressor Stations: Final Report (October 2019
Revision) and Vaughn et al., ``Methane Exhaust Measurements at
Gathering Compressor Stations in the United States,'' Environmental
Science & Technology. 2021, 55 (2), 1190-1196, both available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    In the 2022 Proposed Rule, we proposed methods to quantify and
report combustion slip in subpart C and subpart W from compressor
drivers for all subpart W industry segments that currently report
combustion emissions in subpart C or subpart W. The emission estimation
methods provided in the 2022 Proposed Rule were the use of default
emission factors or default combustion efficiencies for compressor
drivers based on recent study data. We received comments on the 2022
Proposed Rule requesting methods to quantify combustion slip using
original equipment manufacturer (OEM) data and direct measurement. We
also received comments that while compressor drivers likely represent
the largest number of reciprocating engines in service at petroleum and
natural gas facilities, there are reciprocating engines that do not
drive compressors and other engine types (e.g., GT) that emit
CH4 from combustion slip. We have performed additional
review of the combustion slip emission source type as detailed below.
In this rulemaking, we are continuing to propose the quantification and
reporting of combustion slip from subpart W facilities that currently
report combustion emissions in subpart C or subpart W. However, in
consideration of the comments received on the 2022 Proposed Rule and
the directives under CAA 136(h), we are broadening the applicability of
the combustion slip quantification and reporting methods to all RICE
and GT and additionally providing three methods for quantifying slip
including default emission factors or combustion efficiencies, OEM
data, or direct measurement. We are also proposing some revisions to
the 2022 Proposed Rule for the reporting of combustion emissions for
RICE and GT for subpart W facilities that report their combustion
emissions to subpart C after performing a more detailed review of the
subpart C e-GGRT combined unit reporting configurations.
    Based on the EPA's review and analysis, there appears to be
combustion slip for RICE and GT, which are used primarily to drive
compressors, at oil and gas facilities. In addition, while the recent
studies are focused on the Onshore Petroleum and Natural Gas Gathering
and Boosting industry segment, the EPA's literature review found the
presence of combustion slip in different industry segments, so it
appears that combustion slip is dependent on the type of internal
combustion equipment and not the application (i.e., we expect
combustion slip from RICE or GT regardless of the industry segment). We
also considered that other EPA programs such as AP-42: Compilation of
Air Pollutant Emissions Factors; 40 CFR part 60, subpart JJJJ; and 40
CFR part 63, subpart ZZZZ consider emissions from internal combustion
equipment (i.e., RICE or GT) irrespective of their use to drive a
compressor or the industry segment in which the engine operates.
    Therefore, consistent with section II.A of this preamble, we are
proposing to revise the methodologies for determining combustion
emissions from RICE and GT, including those that drive compressors, to
account for combustion slip. For the three subpart W industry segments
reporting combustion emissions to subpart W (Onshore Petroleum and
Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and
Boosting, and Natural Gas Distribution), we are proposing that RICE and
GT combusting natural gas that qualify to determine emissions using the
subpart C calculation methodologies per 40 CFR 98.233(z)(1) and
proposed new 98.233(z)(2),\122\ would have three options in proposed 40
CFR 98.233(z)(4) to quantify emissions from combustion slip, including
direct measurement using a performance test, the use of OEM data, or
the use of default emission factors. For facilities that conduct a
performance test to calculate combustion slip, we are proposing in 40
CFR 98.233(z)(4)(i) that the performance test would be required one
time, in accordance with one of the test methods in proposed 40 CFR
98.234(i), which include EPA Methods 18 and 320 as well as an alternate
method, ASTM D6348-12. If a facility is required to or elects to
conduct a performance test for any reason, we are proposing that they
must use the results of the test for estimating emissions. The results
of the performance test would be used to develop an emission factor for
use in the emissions calculations for CH4. For facilities
electing to use OEM data, which may include manufacturer specification
sheets, emissions certification data, or other manufacturer data
providing expected emission rates from the RICE or GT, we are proposing
that the reporter would use the OEM data to develop an emission factor
for use in their emissions calculations for CH4. Concerning
OEM data, we are seeking comment on whether OEM data is expected to be
representative of field conditions. Further, we are considering
proposing requirements for the OEM supplied data including defining a
standardized testing program for engine families similar to those that
underly the emissions certification process for the engine NSPS in 40
CFR part 60 subparts IIII and JJJJ (e.g., Parts 1054 and 1065). These
programs define the number of engines in a family that are required to
be tested as a number (e.g., 30) or a percentage of engines produced in
a year. The programs also define the methods for testing the engines
(including engine load, test duration, etc.) as well as deterioration
factors for adjusting for the degradation of performance that is
expected over time. Alternatively, we are considering that
manufacturers perform the same type of testing incorporated in proposed
40 CFR 98.234(i) for a certain number of engines in an engine family.
We are seeking comments on these considerations including how the
manufacturer testing program should be structured and more
specifically: how many engines should be tested in an engine family;
under

what load(s) should the engines be tested; what testing methods should
be used; what is the appropriate duration of the test; and whether a
deterioration factor be included to account for degradation of
performance over time. We are also considering whether to add reporting
requirements for the results of performance tests conducted by
manufacturers. Finally, for facilities electing to the use the default
emission factors, which were developed using data from Zimmerle et al.
(2019), we are proposing that the reporter would be required to select
the appropriate emission factor by equipment type (e.g., 2-stroke lean-
burn, 4-stroke lean-burn, 4-stroke rich-burn, or GT) in proposed new
Table W-7 rather than the emission factors in Table C-2 for use in
their emissions calculations for CH4. The precise derivation
of the proposed emission factors is discussed in more detail in the
subpart W TSD, available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    \122\ See section III.S.1 of this preamble for information on
the proposed amendments to 40 CFR 98.233(z) to increase the
flexibility for reporters to use the subpart C calculation
methodologies.
---------------------------------------------------------------------------

    For the three subpart W industry segments reporting combustion
emissions to subpart W (Onshore Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural
Gas Distribution), we are proposing a default equipment specific
combustion efficiency (proposed to be provided in equations W-39A and
W-39B) for RICE and GT that must be used to determine emissions using
the subpart W calculation methodologies per existing 40 CFR
98.233(z)(2) (proposed 40 CFR 98.233(z)(3)). The default combustion
efficiency would account for methane slip, and be combined with fuel
composition to calculate emissions. We are not proposing to provide
options for reporters to conduct performance tests or use OEM data for
such RICE and GT. The fuel types covered by the methods in existing 40
CFR 98.233(z)(2) (proposed 40 CFR 98.233(z)(3)) are expected to be
highly variable in composition over the course of the year, such that a
one-time performance test or OEM data are not expected to be
representative of the annual emissions.
    We expect that the records necessary to confirm the value for the
development of an emission factor based on the results of a performance
test or OEM data are already required to be maintained by the facility
per 40 CFR 98.237; thus, no new recordkeeping provisions relative to
the combustion slip amendments are being proposed. We are proposing to
add new reporting requirements to 40 CFR 98.236(z)(2) specifically for
internal combustion engines that combust natural gas that meets the
criteria of proposed 40 CFR 98.233(z)(1) or (2) to specify the
equipment type of reported internal combustion units, the method used
to estimate the CH4 emission factor, and the value of the
emission factor to facilitate verification of the reported emissions.
Under the existing reporting structure, facilities can group internal
combustion engines by the unit type and the fuel type. The proposed
amendments would require further disaggregation of the reporting of
natural gas-fired internal combustion engine and GT CH4
emissions as units grouped for reporting must share the same equipment
type (e.g., 4-stroke rich burn), fuel type, and method for determining
the CH4 emission factor, which will allow the EPA to
adequately verify the data.
    For the subpart W industry segments that estimate and report their
combustion emissions to subpart C, we are proposing amendments in
subpart C analogous to the proposed amendments described in this
section for the three industry segments that estimate and report their
combustion emissions to subpart W (i.e., Onshore Petroleum and Natural
Gas Production, Onshore Petroleum and Natural Gas Gathering and
Boosting, and Natural Gas Distribution). Specifically, the facilities
that report their combustion emissions to subpart C and currently use
either equation C-8, C-8a, C-8b, C-9, C-9a, or C-10 in 40 CFR 98.33(c),
as it corresponds to the Tier methodology selected to estimate their
CO2 emissions, to estimate CH4 emissions. These
equations rely on the use of a default CH4 emission factor
from Table C-2 to estimate emissions. We are proposing to require that
natural gas-fired RICE or GT located at these facilities would be
required to use one of the options in proposed 40 CFR 98.233(z)(4) to
estimate CH4 emissions. Specifically, we are proposing to
revise the ``EF'' term in each of the equations in 40 CFR 98.33(c)
(i.e., equations C-8, C-8a, C-8b, C-9a, C-9b, and C-10) to reference
the options for developing a CH4 emission factor in proposed
40 CFR 98.233(z)(4) for natural gas-fired RICE or GT. We are also
proposing to add a footnote to Table C-2 that specifies that for
reporters subject to subpart W, the default CH4 emission
factor in Table C-2 for natural gas may only be used for natural gas-
fired combustion units that are not RICE or GT. Finally, we are
proposing to amend 40 CFR 98.36(b), (c)(1), and (c)(3) specifically for
RICE or GT at facilities that are subject to subpart W. These
provisions currently provide the requirements for reporting by emission
unit, by aggregation of units or by common pipe configurations. Under
the proposed amendments, we are requiring reporters which report
emissions in accordance with 40 CFR 98.36(b), (c)(1), or (c)(3) to
provide the equipment type (e.g., two stroke lean burn RICE), the
method used to determine the CH4 emission factor and the
average value of the CH4 emission factor. This proposed
change would ensure that sufficient data in the overall aggregation of
units or common pipe (i.e., multiple units combusting natural gas) is
reported such that we can perform review of the supplied emission
factor data and perform verification on the corresponding emissions.
Overall, these proposed amendments to the subpart C reporting
requirements are analogous to and consistent with what is being
required for RICE or GT for facilities that report combustion emissions
to subpart W.
3. Higher Heating Value for Calculating N2O
    As noted previously, there are subpart W specific methods for
quantifying combustion equipment emissions for facilities that report
their combustion emissions to subpart W in existing 40 CFR 98.233(z)(2)
(proposed (z)(3) in this proposed rule). For quantifying emissions from
N2O specifically, the existing rule specifies the use of
equation W-40. This equation requires the fuel throughput, the HHV of
the fuel, and the use of a default emission factor. For field gas or
process vent gas, the variable definition for the HHV provides that
either a site-specific or default value may be used. We are proposing,
consistent with section II.B of this preamble, to amend the definition
of the variable for the HHV to require the use of a site-specific value
because we believe the site-specific value more accurately accounts for
the more variable fuel compositions that exist in field or process gas.
Our assessment is that the methods for calculating CO2 and
CH4 in 40 CFR 98.233(z)(2)(ii) (proposed (z)(3)(ii) in this
proposed rule) already require the use of site-specific values for the
hydrocarbon streams going to the combustion unit; therefore, we expect
that a site-specific HHV is known (or can be calculated using the
compositional data) without incurring additional burden, while
increasing the accuracy of the emissions estimate.
4. Other Calculation Methodology Clarifications Applicability
    To determine the concentrations of hydrocarbon constituents in the
flow of gas to the combustion unit, existing 40

CFR 98.233(z)(2)(ii) specifies that reporters must either use a
continuous gas composition analyzer (if one is present) or the
procedures specified in 40 CFR 98.233(u)(2). For onshore petroleum and
natural gas gathering and boosting facilities, 40 CFR 98.233(u)(2)
specifies use of the annual average gas composition based on the most
recent available analysis of the gas received at the facility. However,
one stakeholder has indicated that for fuels using the existing
provisions of 40 CFR 98.233(z)(2) to calculate emissions, the
requirements for determining the gas composition could result in
inaccurate calculations of emissions for some facilities because
onshore petroleum and natural gas gathering and boosting facilities do
not necessarily use the gas received at their facility for
combustion.\123\ For example, if the gas received at the facility is
not suitable for combustion, they may mix the gas with purchased
natural gas. In that case, the annual average composition of gas
received at the facility would not be representative of the gas sent to
the combustion unit (as required by existing 40 CFR 98.233(z)(2)),
which could result in inaccurate emissions. Therefore, the EPA is
proposing to revise the language in 40 CFR 98.233(z)(2)(ii) (proposed
40 CFR 98.233(z)(3)(ii)(B) in this proposed rule) to allow the use of
engineering estimates based on best available data to determine the
concentration of gas hydrocarbon constituent in the flow of gas to the
unit. This proposed amendment would allow reporters to use the best
information available to determine the gas composition while
maintaining the option for reporters to use 40 CFR 98.233(u)(2) if they
do not have other stream-specific information. This proposed amendment
is expected to improve the accuracy of the emissions calculated and
therefore the quality of data collected, consistent with section II.B
of this preamble.
---------------------------------------------------------------------------

    \123\ See Letter from GPA Midstream Association to Mark de
Figueiredo, U.S. EPA, providing information in response to EPA
questions during the meeting on March 23, 2016. May 18, 2016. See
also Letter from Matt Hite, GPA Midstream Association, to Mark de
Figueiredo, U.S. EPA, Re: Additional Information on Suggested Part
98, Subpart W Rule Revisions to Reduce Burden. September 13, 2019.
Both letters are available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

    We are also proposing amendments to clarify that emissions may be
calculated for groups of combustion units. The existing provisions of
40 CFR 98.233(z)(2) (proposed 40 CFR 98.233(z)(3)(ii)) could be
interpreted to specify that emissions must be calculated for each
individual combustion unit. However, because combustion emissions and
activity data are reported as combined totals for each type of
combustion device, fuel type, and method for determining the
CH4 emission factor (for RICE and GT), it is generally not
necessary to calculate emissions for each individual unit before
aggregating the total emissions. For example, if the volume of fuel
combusted is determined at a single location upstream of several
combustion units, emissions may be determined for that combined volume
of fuel (i.e., for that group of combustion units). In other words, it
would not be necessary in this example case to apportion a volume of
fuel to each unit, calculate emissions separately, and then combine
them again. If the combustion units downstream of this shared
measurement point are a mix of combustion device types, the emissions
and the volume of fuel would still need to be apportioned between those
combustion device types for reporting purposes; however, reporters may
elect to perform that apportioning either before or after emissions are
calculated, as appropriate, as long as the group of combustion units
does not include any natural gas internal combustion equipment
including RICE or GT. If any of the combustion units downstream of this
shared measurement point are natural gas-driven internal combustion
equipment including RICE or GT, the volumes of fuel for those units
would have to be separated from the total before emissions are
calculated to account for the differences in combustion efficiency, as
described in section III.S.2 of this preamble. Some of the tiers in
subpart C similarly allow for calculation of emissions by groups of
units combusting the same fuel, so we are proposing to include
analogous language to that in subpart C in 40 CFR 98.233(z)(1)(ii) and
40 CFR 98.233(z)(2)(ii) to provide for these clarifications in how to
calculate.
5. Location of Reporting Requirements for Combustion Equipment
    Section 136(h) of the CAA specifies the following concerning
reporting: ``Not later than 2 years after the date of enactment of this
section, the Administrator shall revise the requirements of subpart W
of part 98 of title 40, Code of Federal Regulations, to ensure the
reporting under such subpart, and calculation of charges under
subsections (e) and (f) of this section, are based on empirical data,
including data collected pursuant to subsection (a)(4), accurately
reflect the total CH4 emissions and waste emissions from the
applicable facilities, and allow owners and operators of applicable
facilities to submit empirical emissions data, in a manner to be
prescribed by the Administrator, to demonstrate the extent to which a
charge under subsection (c) is owed.'' As noted in this excerpt, the
IRA directs the Administrator to ensure reporting under subpart W
accurately reflects total CH4 emissions from applicable
facilities.
    Apart from onshore natural gas transmission pipeline facilities,
all facilities subject to subpart W must include combustion emissions
in their annual report. As noted in section III.S.1 of this preamble,
facilities in the Onshore Petroleum and Natural Gas Production, Onshore
Petroleum and Natural Gas Gathering and Boosting, and Natural Gas
Distribution industry segments must calculate combustion emissions in
accordance with 40 CFR 98.233(z) and report emissions under subpart W.
Facilities in the remaining industry segments (i.e., Offshore Petroleum
and Natural Gas Production, Onshore Natural Gas Processing, Onshore
Natural Gas Transmission Compression, Underground Natural Gas Storage,
LNG Storage, and LNG Import and Export Equipment) are required to
calculate combustion emissions in accordance with the provisions of 40
CFR 98.33 and report emissions under subpart C.
    The EPA is seeking comment on amending subpart W to specify that
all industry segments would be required to report their combustion
emissions, including CH4, under subpart W to more accurately
reflect the total CH4 emissions from such facilities within
the emissions reported under subpart W. Using RY2021 data for
combustion sources, we determined that requiring combustion emissions
from all oil and gas operations to be reported to subpart W rather than
subpart C would increase total subpart W CH4 emissions by
less than 1 percent. If the amendments to combustion slip discussed in
section III.S.2 of this preamble are finalized, the reported
CH4 emissions from combustion are expected to increase, but
we estimate the increase in total CH4 emissions from
combustion devices at facilities subject to subpart W would be less
than 5 percent. Under this approach, we would consider continuing to
allow all the industry segments that currently report combustion
emissions under subpart C (i.e., Offshore Petroleum and Natural Gas
Production, Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage, LNG Storage,
and LNG Import and Export Equipment) to use the same subpart C
calculation methodologies as they

currently use in order to minimize the burden on affected facilities.
This amendment, however, would result in changes to their reporting
structure, as subpart W does not currently contain the same methods to
report via a common pipe for fuel streams or by aggregation of units as
provided in subpart C. Instead, for subpart W, combustion emissions are
aggregated by fuel type, combustion equipment type, and if finalized,
by the method used for estimating combustion slip, when applicable.
There are also exclusions for reporting combustion emissions in 40 CFR
98.233(z)(5) and (6), specifically for external combustion equipment
with a rated heat capacity of less than 5 million British thermal units
per hour (MMBtu/hr) and internal combustion equipment with a rated heat
capacity of less than 1 MMBtu/hr. Under this approach, we expect that
these exemptions would apply to the facilities newly subject to subpart
W. Similarly, under this approach, we expect that the exemptions in
subpart C would no longer apply to these facilities. The exemptions
that we expect may impact facilities under this approach are the
subpart C exclusions of reporting emissions from portable and emergency
equipment in 40 CFR 98.30(a) and (b).

T. Leak Detection and Measurement Methods

1. Acoustic Leak Detection
    For emission source types for which measurements are required,
subpart W specifies the methods that may be used to make those
measurements in 40 CFR 98.234(a). To improve the quality of the data
when an acoustic leak detection device is used, consistent with section
II.B of this preamble, we are proposing two revisions to the acoustic
measurement requirements in 40 CFR 98.234(a)(5). First, for stethoscope
type acoustic leak detection devices (i.e., those designed to detect
through-valve leakage when put in contact with the valve body and that
provide an audible leak signal but do not calculate a leak rate), we
are proposing that a leak is detected if an audible leak signal is
observed or registered by the device. Second, we are proposing that if
a leak is detected using a stethoscope type device, then that leak must
be measured using one of the quantification methods specified in 40 CFR
98.234(b) through (d) and that leak measurement must be reported
regardless of the volumetric flow rate measured. These proposed
revisions would improve the accuracy of emissions reported for
compressors and transmission tanks when an acoustic leak detection
device is used.
2. High Volume Samplers
    We are proposing two revisions to the high volume sampler methods
to improve the quality of the data when high volume samplers are used
for flow measurements, consistent with section II.B of this preamble.
First, we are proposing to add detail to 40 CFR 98.234(d)(3) to clarify
the calculation methods associated with high volume sampler
measurements. Generally, high volume samplers measure CH4
flow, not whole gas flow. However, the current calculation methods in
40 CFR 98.234(d)(3) treat the measurement as a whole gas measurement.
Therefore, we are proposing to clarify the calculation methods needed
if the high volume sampler outputs CH4 flow in either a mass
flow or volumetric flow basis. Specifically, we are proposing methods
to determine natural gas (whole gas) flows based on measured
CH4 flows.
    Second, we are proposing to add a paragraph at 40 CFR 98.234(d)(5)
to clarify how to assess the capacity limits of a high volume sampler.
Currently, 40 CFR 98.234(d) simply states to ``Use a high volume
sampler to measure emissions within the capacity of the instrument'';
there is no other information provided to clarify what ``within the
capacity of the instrument'' means or how it is determined. We
understand that there are different manufacturers, but most common high
volume samplers report maximum sampling rates of 10 to 11 cubic feet
per minute (cfm) and maximum CH4 flow quantitation limits of
6 to 8 cfm. Based on our review of reported high volume sampler
measurements, we found that 2 to 5 percent of high volume sampler
measurements for all types of compressor sources (for both centrifugal
and reciprocating compressors) are likely at or beyond the expected
capacity limits of the high volume sampler instrument. Considering
actual sampling rates, gas collection efficiencies near the sampling
rates, and reported CH4 quantitation limits relative to
maximum sampling rates, we determined that whole gas flow rates
exceeding 70 percent of the device's maximum rated sampling rate is an
indication that the device will not accurately quantify the volumetric
emissions, which we deem to exceed the capacity of the device.
Therefore, we are proposing to specify that CH4 flows above
the manufacturer's CH4 flow quantitation limit or total
volumetric flows exceeding 70 percent of the manufacturer's maximum
sampling rate indicate that the flow is beyond the capacity of the
instrument and that flow meters or calibrated bags must be used to
quantify the flow rate. For more information on our review, see the
subpart W TSD, available in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2023-0234).

U. Industry Segment-Specific Throughput Quantity Reporting

1. Throughput Information for the Future Implementation of the Waste
Emissions Charge
    As noted in section I.E of this preamble, the waste emissions
charge specifies segment-specific thresholds (Waste Emissions
Threshold) for segments subject to the waste emissions charge. For the
Onshore Petroleum and Natural Gas Production and Offshore Petroleum and
Natural Gas Production industry segments, the Waste Emissions Threshold
is specified in CAA section 136(f)(1) as, ``(A) 0.20 percent of the
natural gas sent to sale from such facility;'' or ``(B) 10 metric tons
of methane per million barrels of oil sent to sale from such facility,
if such facility sent no natural gas to sale.'' For the Onshore
Petroleum And Natural Gas Gathering And Boosting, Onshore Natural Gas
Processing, Onshore Natural Gas Transmission Compression, LNG Storage,
LNG Import and Export Equipment, and Onshore Natural Gas Transmission
Pipeline industry segments, the Waste Emissions Threshold is defined in
CAA section 136(f)(2) and (3) as a percentage of ``natural gas sent to
sale from or through such facility,'' with the percentages specified
varying by segment.
    To align the subpart W reporting elements with text used in CAA
section 136 and enable verification of throughput-related reporting
elements, consistent with section II.C of this preamble, we are
proposing a combination of new reporting elements and amendments to
existing segment-specific throughput reporting requirements in 40 CFR
98.236(aa).
    We are proposing to add the word ``natural'' in front of ``gas'' at
each occurrence where it is used in the throughput reporting elements
in subpart W that are being revised to align with CAA section 136. We
note that the CAA section 136 text uses the term ``oil'' and we are
clarifying in this preamble that for the purposes of subpart W the term
``oil'' has the same meaning as ``crude oil,'' which is used in the
throughput reporting elements in subpart W and defined in subpart A of
part 98.
    We are also generally proposing revisions to ensure that the
verbiage of ``sent to sales'' or ``through the facility'' is reflected
in the reporting elements, as

applicable. We are also proposing in 40 CFR 98.236(aa) that the
quantities sent to sales or through the facility be measured, as it is
reasonable to expect that the quantities of these products are closely
tracked. We request comment on situations in which a reporter may not
be measuring the quantity ``sent to sales'' or ``through the
facility.''
    Aside from these overarching proposed amendments, there are
industry segment-specific proposed amendments for the Onshore Petroleum
and Natural Gas Production, Offshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Onshore Natural Gas Processing industry segments as described in
the remainder of this section.
a. Onshore Petroleum and Natural Gas Production and Offshore Petroleum
and Natural Gas Production
    For the Onshore Petroleum and Natural Gas Production and Offshore
Petroleum and Natural Gas Production industry segments, the current
requirements for reporting throughputs of crude oil are combined with
volumes of condensate. These volumes will need to be reported
separately in order to align with the CAA section 136(f) oil threshold
for production facilities, when applicable. Therefore, we are proposing
the separation of these reporting elements into two distinct reporting
elements in both 40 CFR 98.236(aa)(1)(i) and 98.236(aa)(2).
    For consistency with CAA section 136, we are proposing to use the
phrase ``sent to sale'' in 40 CFR 98.236(aa)(1)(i)(B) through (D), 40
CFR 98.236(aa)(1)(iii)(C) through (E), and 40 CFR 98.236(aa)(2)(i)
through (vi) instead of ``for sale,'' the phrase used in the existing
data elements. This proposed amendment is for consistency in language
rather than any expected difference in the volumes to be reported or
the interpretation of the terms, as the existing term was intended to
have the same meaning. As described in section III.D of this preamble,
we are also proposing additional throughput data elements to provide
separate, well-level reporting of throughputs associated with wells in
the Onshore Petroleum and Natural Gas Production and Offshore Petroleum
and Natural Gas Production industry segments that are permanently shut-
in and plugged. These proposed data elements, if finalized, are
anticipated to be useful in the future evaluation of the associated
exemptions in CAA section 136(f)(7).
    Specifically for the Offshore Petroleum and Natural Gas Production
industry segment, the existing throughput requirements are for ``gas
handled'' at the platform, which includes production volumes as well as
volumes transferred via pipeline from another location. We note that
the term ``gas handled'' is not used by other reporting programs to
which offshore production facilities also report, such as the BOEM or
the U.S. Energy Information Administration (EIA). We have also recently
received a question through the GHGRP Help Desk asking about
differences in throughput between the published BOEM data for the
parameter, lease production reporting, and throughput volumes published
in the subpart W data, so there are potentially differences in the ways
reporters are interpretating and reporting the ``gas handled'' data
element as compared to production volumes reported to other programs.
In order to provide consistency with the language in CAA section 136
across both production industry segments and help the EPA implement CAA
section 136, we are proposing to revise the reporting elements in 40
CFR 98.236(aa)(2) for the Offshore Petroleum and Natural Gas Production
industry segment so they are analogous to those in Onshore Petroleum
and Natural Gas Production. We are seeking comment on whether we should
add the proposed throughputs as new data elements and continue to
retain the existing reporting elements in 40 CFR 98.236(aa)(2)(i) and
(ii), including the rationale for maintaining the existing reporting
elements.
b. Onshore Petroleum and Natural Gas Gathering and Boosting
    Through our verification efforts, it has become apparent that the
reporting of some of the throughput volumes for the Onshore Petroleum
and Natural Gas Gathering and Boosting industry segment are incomplete
in the sense that they do not include all the quantities of natural gas
(and hydrocarbon liquids) transported from the facility (i.e., leaving
the facility). In some cases, this appears to be due to the specific
wording of the reporting elements in existing 40 CFR 98.236(aa)(10)(ii)
and (iv) that appear to limit the quantities to the quantities
transported to four specific downstream endpoints (e.g., processing
plants). However, the EPA indicated in the preamble to the final rule
that added the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segment that the throughputs transported from the facility
were intended to be the total quantities transported downstream (80 FR
64280, October 22, 2015). Therefore, be consistent with the EPA's
original intent for these data elements, we are proposing to amend 40
CFR 98.236(aa)(10)(ii) and (iv) to clarify that the downstream
endpoints listed in the current reporting elements are examples of
potential destinations and to specify that the reported quantities
should be the natural gas or hydrocarbon liquids, respectively,
transported to downstream operations such as one of those endpoints. We
are also proposing to add storage facilities to the list of downstream
operations to make the list of examples more comprehensive. Finally,
for consistency with the text in CAA section 136 and to help the EPA
implement CAA section 136 in the future, we are proposing to amend 40
CFR 98.236(aa)(10)(ii) to specify that the natural gas is transported
``through the facility'' and then to a downstream operation. As a
result of these proposed amendments, the reported quantities should
include all natural gas and hydrocarbon liquids transported downstream
from the facility (i.e., leaving the basin or leaving the gathering
system owner or operator).
    In addition to reviewing the reported throughputs, we also reviewed
the definitions in subpart W associated with the industry segment and
the facility. For the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment, we found that the definitions for
``Gathering and boosting system'' and ``Gathering and boosting system
owner or operator'' in 40 CFR 98.238 specified that an onshore
petroleum and natural gas gathering and boosting system or owner or
operator must receive natural gas or petroleum from an onshore
petroleum and natural gas production facility. Those definitions would
exclude facilities that receive natural gas or petroleum from other
onshore petroleum and natural gas gathering and boosting facilities and
do not receive any natural gas or petroleum from onshore petroleum and
natural gas production facilities. Therefore, there are potentially
entire onshore petroleum and natural gas gathering and boosting
facilities or volumes of gas through onshore petroleum and natural gas
gathering and boosting facilities that are unaccounted for under the
existing rule. We are proposing to amend the definition of ``Gathering
and boosting system'' and ``Gathering and boosting owner or operator''
in 40 CFR 98.238 to specify that these systems may receive natural gas
and/or petroleum from one or more other onshore petroleum and natural
gas gathering and boosting systems in addition to production
facilities.

c. Onshore Natural Gas Processing
    Subpart W currently requires onshore natural gas processing
facilities to report the quantity of natural gas received at the gas
processing plant in existing 40 CFR 98.236(aa)(3)(i), however, the rule
does not currently specify whether the volume is all natural gas that
enters the facility--including natural gas that passes through the
facility without being processed further (i.e., ``pass-through
volumes'')--or just natural gas received for processing. As discussed
in section III.U.1 of this preamble, to maintain consistency with
subpart NN and reduce burden for fractionators, the EPA is proposing to
revise 40 CFR 98.236(aa)(3)(i) to specify that the subpart W quantity
of gas received is the gas received for processing and is also
proposing that fractionators do not have to report a quantity under 40
CFR 98.236(aa)(3)(i) if they report under subpart NN. Subpart NN does
not require reporting of the gas leaving the facility, but to maintain
consistency in the interpretation of the throughputs, to date, the EPA
has provided guidance to facilities that the volume reported in
accordance with 40 CFR 98.236(aa)(3)(ii) is that which has been
processed at the facility and should exclude volumes of gas that are of
pipeline specification and only passed through the facility.
    However, to be consistent with CAA section 136(f)(2), the
throughput should include all volumes of natural gas which pass through
the facility or are sent to sales. Therefore, considering the proposed
amendments to 40 CFR 98.236(aa)(3)(i) and guidance that has been
historically provided for 40 CFR 98.236(aa)(3)(ii), a new reporting
element for natural gas processing throughput is needed to fully
capture all volumes through the facility (i.e., those that are
processed and those that pass through the facility which are not
processed). As such, we are proposing to add a new reporting element
for the Onshore Natural Gas Processing industry segment in 40 CFR
98.236(aa)(3)(ix) to capture all natural gas that is processed and/or
passed through the facility consistent with the text in CAA section 136
(i.e., ``natural gas sent to sale from or through facilities'').
2. Onshore Natural Gas Processing and Natural Gas Distribution
Throughputs Also Reported Under Subpart NN
    Onshore Natural Gas Processing plants are required to report seven
facility-level throughput-related items under subpart W, as specified
in existing 40 CFR 98.236(aa)(3). These seven data reporting elements
include: quantities of natural gas received and processed gas leaving
the gas processing plant, cumulative quantities of NGLs received and
leaving the gas processing plant, the average mole fractions of
CH4 and CO2 in the natural gas received, and an
indication of whether the facility fractionates NGLs. Natural Gas
Distribution companies are also required to report seven throughput
volumes under subpart W, as specified in existing 40 CFR 98.236(aa)(9).
These seven data reporting elements include: the quantity of gas
received at all custody transfer stations; the quantity of natural gas
withdrawn from in-system storage; the quantity of gas added to in-
system storage; the quantity of gas delivered to end users; the
quantity of gas transferred to third parties; the quantity of gas
consumed by the LDC for operational purposes; and the quantity of gas
stolen.
    The EPA has received stakeholder comments related to some of these
reporting elements.\124\ These stakeholders have commented that the
reporting elements included in subpart W are redundant with data
reported elsewhere within the GHGRP, specifically under subpart NN
(Suppliers of Natural Gas and Natural Gas Liquids). Subpart NN requires
NGL fractionators and LDCs to report the quantities of natural gas and
natural gas liquid products supplied downstream and their associated
emissions. For example, for natural gas processing plants, commenters
stated that both subparts require reporting of the volume of natural
gas received and the volume of NGLs received. Subpart W also requires
reporting of total NGLs leaving the processing plant, while subpart NN
requires reporting of the volume of each individual NGL product
supplied. For LDCs, these commenters have stated that some duplicative
reporting is required as well. For example, commenters stated that both
subparts require reporting of the volume of natural gas received,
volume placed into and out of storage each year, and volume transferred
to other LDCs or to a pipeline as well as some other duplicative data.
In addition, commenters stated that the reporting elements included in
subparts W and NN for LDCs are redundant with data reported to the EIA
on Form EIA-176, the Annual Report of Natural and Supplemental Gas
Supply and Disposition.\125\ The commenters explained that subpart W
and subpart NN collect nearly the same data, and stated that
discrepancies between the data sets are due to the use of inconsistent
terminology. Commenters also suggested that due to the redundancy and
availability of data reported to the EIA for LDCs, the EPA should
remove the throughput-related reporting requirements for the Natural
Gas Distribution industry segment from the GHGRP altogether. Commenters
added that if the requirements are maintained, the EPA should reconcile
the terminology used within the GHGRP and clarify the reporting
elements.
---------------------------------------------------------------------------

    \124\ See Docket Id. Nos. EPA-HQ-OA-2017-0190-46726, EPA-HQ-OA-
2017-0190-1958, EPA-HQ-OA-2017-0190-2066 available in Compilation of
Comments Related to the Greenhouse Gas Reporting Program submitted
to the Department of Commerce under Docket ID No. DOC-2017-0001 and
the Environmental Protection Agency under Docket ID No. EPA-HQ-OA-
2017-0190 and in the docket for this rulemaking, Docket Id. No. EPA-
HQ-OAR-2023-0234.
    \125\ Form EIA-176 is available at the U.S. EIA website at
https://www.eia.gov/survey/form/eia_176/form.pdf; the Form EIA-176
Instructions are available at https://www.eia.gov/survey/form/eia_176/instructions.pdf.
---------------------------------------------------------------------------

    The EIA report is submitted in the spring of each year and covers
the previous calendar year. After completing internal audits of the
reports, EIA publishes the data for each LDC on its website in the
fall. The EIA data provides detailed information on the volume of gas
received, gas stored, gas removed from storage, gas deliveries by
sector, and HHV data. The EPA previously reviewed the possibility of
obtaining data by accessing existing Federal Government reporting and
provided the following response in the subpart NN response to public
comments document accompanying the 2009 Final Rule: \126\
---------------------------------------------------------------------------

    \126\ See page 7 of EPA Response to Public Comment Vol. 39
Subpart NN at https://www.epa.gov/ghgreporting/ghgrp-2009-final-rule-response-comments-documents, also available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------

     The EPA ``decided not to modify the final rule because
collecting data directly in a central system will enable the EPA to
electronically verify all data reported under this rule quickly and
consistently, to use the information for non-statistical purposes, and
to handle confidential business information in accordance with the
Clean Air Act.''
     In the specific case of subpart NN, the EPA also
``determined that it could not rely on EIA data to collect facility-
level data from fractionators and company-level data from LDCs.''
     Additionally, the EPA ``seeks data that is beyond what EIA
collects, such as quality assurance information, verification data, and
information on odorized propane'' and ``data on site-specific HHV and
carbon content from those sites that choose to sample and

test products rather than use default emission factors.''
    After further review of the data available through EIA, the
stakeholder comments described earlier in this section, and the
reporting requirements in subpart W and subpart NN, the EPA is
proposing to eliminate duplicative elements from subpart W for
facilities that report to subpart NN, consistent with section II.C of
this preamble. The EPA is proposing to amend the reporting requirements
in 40 CFR 98.236(aa)(3) for Onshore Natural Gas Processing plants that
both fractionate NGLs (approximately 100 of the 450 subpart W natural
gas processing plants) and also report as a supplier under subpart NN.
For this subset of facilities, the EPA reviewed the data from subpart W
and subpart NN and determined that there are no gas processing plants
that report as fractionators under subpart W that do not also report
under subpart NN without supplying a valid explanation.\127\ During
this review, the EPA found that some of the data elements included in
subpart W overlap with data elements in subpart NN. Specifically, the
data elements in 40 CFR 98.236(aa)(3)(i), (iii) and (iv) of subpart W
overlap with data elements in subpart NN as specified in 40 CFR
98.406(a)(3), 98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii),
respectively.\128\
---------------------------------------------------------------------------

    \127\ One such explanation is that the gas processing plant
fractionates NGLs to supply fuel for use entirely on-site (i.e., the
fuel is not supplied downstream). Due to definitional differences
between the two subparts, this facility is defined as a fractionator
for purposes of subpart W but is not a supplier that must report
under subpart NN.
    \128\ While it is the EPA's intention that the reported quantity
of natural gas received at the facility in existing 40 CFR
98.236(aa)(3)(i) should be the quantity of natural gas received for
processing, consistent with the requirement to report the annual
volume of natural gas received for processing in existing 40 CFR
98.406(a)(3), some reporters have indicated in correspondence with
the EPA via e-GGRT that they are including gas that is received at
but not processed by the onshore natural gas processing facility
(i.e., gas that was processed elsewhere and passes through the
onshore natural gas processing facility). Therefore, to clarify the
EPA's intention and reinforce the consistency of the subpart W and
subpart NN quantities, the EPA is proposing to revise 40 CFR
98.236(aa)(3)(i) to indicate that that reported quantity should be
natural gas received at the gas processing plant for processing in
the calendar year.
---------------------------------------------------------------------------

    To eliminate reporting redundancies, the EPA is proposing several
amendments to 40 CFR 98.236(aa)(3). First, to clarify which facilities
have data overlap between subparts W and NN, the EPA is proposing to
add a reporting element for natural gas processing plants at 40 CFR
98.236(aa)(3)(viii) to indicate whether they report as a supplier under
subpart NN. Next, the EPA is proposing that facilities that indicate
that they both fractionate NGLs and report as a supplier under subpart
NN would no longer be required to report the quantities of natural gas
received or NGLs received or leaving the gas processing plant as
specified in 40 CFR 98.236(aa)(3)(i), (iii) and (iv); this data would
continue to be reported under subpart NN as specified in 40 CFR
98.406(a)(3), 98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii),
respectively, thus, maintaining the ability to verify associated
emissions reported under subpart W. See Table 3 of this preamble for
more information.
    These facilities would, however, be required to continue reporting
the data elements specified in 40 CFR 98.236(aa)(3)(ii) and (v) through
(viii), as these reporting elements do not overlap with subpart NN
reporting elements. Natural gas processing plants that do not
fractionate or that fractionate but do not report as a supplier under
subpart NN would continue to report all of the reporting elements for
natural gas processing plants as specified in 40 CFR 98.236(aa)(3).
    The EPA is also proposing to remove the reporting elements for
throughput for LDCs in 40 CFR 98.236(aa)(9). The EPA reviewed the data
from subpart W and subpart NN and determined that there are no LDCs
that report under subpart W that do not also report under subpart NN.
In fact, an average of 385 LDCs report under subpart NN, while 170 LDCs
report under subpart W. Subpart NN therefore provides more
comprehensive coverage of the Natural Gas Distribution industry
segment. Additionally, subpart NN has been in effect for LDCs since
RY2011 while subpart W throughput information has only been collected
since RY2015; thus, subpart NN has a more robust historical data set.
During this review, the EPA determined that the data elements found in
40 CFR 98.236(aa)(9)(i) through (v) of subpart W overlap with data
elements in subpart NN as specified in 40 CFR 98.406(b)(1) through (3),
98.406(b)(5) and (6), and 98.406(b)(13). To eliminate reporting
redundancies, the EPA is proposing to remove these reporting elements
from subpart W.
    Table 3 of this preamble shows all the duplicative data elements
that the EPA is proposing to remove from subpart W for facilities that
also report to subpart NN.

  Table 3--List of Proposed Subpart W Data Elements To Be Removed Where Analogous Subpart NN Data Elements are
                                                    Reported
----------------------------------------------------------------------------------------------------------------
       Subpart W data elements proposed to be eliminated               Analogous Subpart NN data elements
----------------------------------------------------------------------------------------------------------------
             Citation                       Description                Citation               Description
----------------------------------------------------------------------------------------------------------------
                                          Local Distribution Companies
----------------------------------------------------------------------------------------------------------------
Sec.   98.236(aa)(9)(i)...........  Quantity of natural gas     Sec.   98.406(b)(1)    Annual volume of natural
                                     received at all custody     Sec.   98.406(b)(5).   gas received by the LDC
                                     transfer stations.                                 at its city gate
                                                                                stations and Annual
                                                                                volume natural gas that
                                                                                bypassed the city
                                                                                gate(s).
Sec.   98.236(aa)(9)(ii)..........  Quantity of natural gas     Sec.   98.406(b)(3)..  Annual volume natural gas
                                     withdrawn from in-system                           withdrawn from on-system
                                     storage.                                           storage and annual
                                                                                volume of vaporized LNG
                                                                                withdrawn from storage.
Sec.   98.236(aa)(9)(iii).........  Quantity of natural gas     Sec.   98.406(b)(2)..  Annual volume of natural
                                     added to in-system                                 gas placed into storage
                                     storage.                                           or liquefied and stored.
Sec.   98.236(aa)(9)(iv)..........  Quantity of natural gas     Sec.                   Annual volume of natural
                                     delivered to end users.     98.406(b)(13)(i)       gas delivered by the LDC
                                                                 through (iv).          to residential
                                                                                consumers, commercial
                                                                                consumers, industrial
                                                                                consumers, electricity
                                                                                generating facilities.

Sec.   98.236(aa)(9)(v)...........  Quantity of natural gas     Sec.   98.406(b)(6)..  Annual volume of natural
                                     transferred to third                               gas delivered to
                                     parties.                                           downstream gas
                                                                                transmission pipelines
                                                                                and other LDCs.
----------------------------------------------------------------------------------------------------------------
                               Natural Gas Processing Plants That Fractionate NGLs
----------------------------------------------------------------------------------------------------------------