\187\ PHMSA, ``Pipeline Safety: Pipeline Damage Prevention
Programs--Final Rule,'' 80 FR 43835 (July 23, 2015).
---------------------------------------------------------------------------

    But even in States with robust damage prevention programs, limited
information on buried gas pipelines can hamstring efforts to reduce
excavation damage and marshal emergency response to any resulting
incidents. This is particularly true for gas gathering pipelines.
Despite recently expanded requirements that operators of certain gas
gathering pipelines maintain sufficient damage prevention programs
under Sec.  192.614, PHMSA regulations do not currently require
operators of gas gathering pipelines to submit geospatial location data
into NPMS. This regulatory gap means that State and Federal regulatory
authorities (and even some operators) may have limited understanding of
the location of those pipelines, thereby inhibiting damage prevention
efforts as well as emergency response in the event of an excavation
incident.

E. The Limits of PHMSA Regulation and State and Operator Initiatives in
Reducing Intentional Methane Releases From Gas Pipeline Facilities

    In section 114 of the PIPES Act of 2020, Congress introduced
requirements for operators of gas pipeline facilities to update their
inspection and maintenance procedure to provide for the minimization of
all releases of natural gas from their facilities--including
intentional, vented emissions--in recognition of the significant
environmental harm from those emissions. As described in section II.C,
equipment venting, blowdowns, and other vented emissions of methane
account for a large portion of the total methane emissions from U.S.
natural gas pipeline facilities--particularly natural gas transmission
pipelines. However, despite the significant environmental impact of
those emissions, PHMSA and State pipeline safety regulations have
largely avoided explicit restrictions on vented emissions. Moreover,
the absence of robust reporting requirements for those emissions under
part 191 inhibits PHMSA's ability to identify systemic issues.
    Part 191 does not require any reporting on intentional releases of
methane or other gases (regardless of the total volume of gas emitted)
unless a release causes death, hospitalization, or significant property
damage. Similarly, part 192 and part 193 regulations do not require an
operator to minimize intentional releases unless they could give rise
to a public safety hazard.\188\ These regulatory gaps could permit
situations such as pressure relief devices being configured to
establish overly-conservative actuation setpoints--resulting in
avoidable emissions being released because those pressure relief
devices vent methane more frequently than necessary to maintain system
pressure within safe operating bands. Incident reports and National
Response Center (NRC) reports submitted to PHMSA for pressure relief
device malfunctions provide a sense of the magnitude of potential
emissions from improperly configured pressure relief devices: each
incident can result in the release of millions of cubic feet of
methane.
---------------------------------------------------------------------------

    \188\ See, e.g., Sec. Sec.  192.169 and 192.617(a)(2) (requiring
discharge piping for compressor station pressure relief devices and
emergency shutdown systems vent to locations that would avoid public
safety hazards) and 192.199(e) (requiring pressure relief and
limiting devices have discharge stacks, vents, or outlet ports be
located where gas can be discharged into the atmosphere without
undue hazard).
---------------------------------------------------------------------------

    Similar to voluntary leak detection and repair efforts, voluntary
industry efforts to reduce emissions from blowdowns fall short in
minimizing vented emissions. PHMSA is unaware of any industry-level,
voluntary initiatives among operators of part 193 facilities to reduce
vented emissions. And voluntary operator efforts among gas pipelines
either parallel or directly invoke best practices recommended by the
EPA's voluntary methane programs such as the Methane Challenge Program
and the Natural Gas STAR programs.\189\ For the ``Best Management
Practices'' option in the Methane Challenge Program, an operator can
commit to cutting pipeline blowdown emissions by at least 50 percent by
any of the following methods: \190\
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    \189\ EPA, ``Voluntary Methane Programs for the Oil and Natural
Gas Industry,'' https://www.epa.gov/natural-gas-star-program (last
accessed June 20, 2022). In 2018, members of the Interstate Natural
Gas Association of America (INGAA) agreed to adopt voluntary
commitments to minimize methane emissions from member transportation
and storage assets, including a commitment to reduce emissions from
blowdowns when repairs need to be made. The aforementioned EPA
programs and two industry initiatives, the ONE Future Coalition and
the Environmental Partnership, are featured prominently in the INGAA
commitments. The full list of commitments is available on INGAA's
website (https://www.ingaa.org/
File.aspx?id=38523&v=6553c6c8#:~:text=As%20part%20of%20our%20ongoing,
build%20a%20cleaner%20energy%20future) (last accessed July 20,
2022).
    \190\ EPA, ``Natural Gas STAR Methane Challenge Program BMP
Commitment Option Technical Document'' at 21 (May 2022).
---------------------------------------------------------------------------

     Routing gas to a compressor or capture system for
beneficial use;
     Routing gas to a flare;
     Routing gas to a low-pressure system by taking advantage
of existing piping connections between high- and low-pressure systems,
temporarily resetting or bypassing pressure regulators to reduce system
pressure prior to maintenance, or installing temporary connections
between high and low-pressure systems; or
     Utilizing hot tapping, a procedure that makes a new
pipeline connection while the pipeline remains in service, flowing
natural gas under pressure, to avoid the need to blowdown gas.
    The voluntary industry emissions reduction efforts above cannot
boast universal participation, but they hint at the potential for
significant reductions in vented emissions if applied across all gas
pipeline facility operators. In 2019 alone, a mere 8 participants in
the EPA's Methane Challenge transmission pipeline blowdown mitigation
program, operating 29 gas transmission pipeline facilities, reduced
emissions by 1.9 million metric tons of CO2 equivalent
estimated by calculation or measurement in accordance with 40 CFR part
98, subpart W or, for non-subpart W facilities, an alternative
method.\191\
---------------------------------------------------------------------------

    \191\ EPA, ``Methane Challenge Program Accomplishments,''
https://www.epa.gov/natural-gas-star-program/methane-challenge-program-accomplishments (last accessed July 20, 2022).
---------------------------------------------------------------------------

III. Federal Efforts To Address Climate Change by Reducing Methane
Emissions

    The urgency of reducing methane emissions to stave off or avoid the
worst

effects of climate change, coupled with the inability of existing
Federal, State, and industry efforts to rise to that challenge, have
catalyzed responses by the Federal legislative and executive branches
to reduce unintentional and vented methane releases from gas pipeline
facilities. Those efforts, which are discussed below, inform the
regulatory amendments proposed in this NPRM.

A. The PIPES Act of 2020

    The PIPES Act of 2020, which was signed into law with broad
bipartisan congressional and widespread industry and stakeholder
support on December 27, 2020, directed a fundamental shift in PHMSA's
regulation of gas pipeline facilities: environmental benefits would
join public safety as a principal object of PHMSA regulation.\192\
Concerned in particular with the contribution of methane releases from
natural gas pipelines to climate change,\193\ Congress included within
that legislation three sections that would be implemented by this NPRM:
sections 113, 114, and 118.
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    \192\ See 49 U.S.C. 60102(b)(5).
    \193\ See, e.g., 166 Cong. Rec. H7305 (Dec. 21, 2020)
(memorializing a statement by Rep. Pallone that ``[t]his is a big
win in the fight against climate change, along with the
reauthorization of the Pipeline Safety Act, which reduces methane
leaks.''); ``Press Release from Senate Commerce Committee Leaders
Commending Passage of Pipeline Safety Legislation'' (Dec. 22, 2020),
https://www.commerce.senate.gov/2020/12/committee-leaders-commend-passage-of-pipeline-safety-legislation (quoting Sen. Cantwell as
stating ``This legislation also ensures that the latest technology
will be used to detect and prevent costly methane leaks, which is
especially important because methane leaks are a significant hazard
and a major contributor to global warming.'').
---------------------------------------------------------------------------

    Section 113 of the PIPES Act of 2020 states that the Secretary of
Transportation shall issue regulations that require operators of gas
transmission pipeline facilities, gas distribution pipeline facilities,
and certain regulated gas gathering pipelines in Class 2, Class 3, and
Class 4 locations to conduct leak detection and repair programs to meet
the need for gas pipeline safety and to protect the environment. Such
regulations must include minimum performance standards that reflect the
capabilities of commercially available advanced leak detection
technologies that are appropriate for the type of pipeline, the
location of the pipeline, the pipeline's material of construction, and
the product transported by the pipeline. The leak detection and repair
programs must be able to identify, locate, and categorize all leaks
that are hazardous to human safety or the environment or that have the
potential to become explosive or otherwise hazardous to human safety.
The regulations must require the use of advanced leak detection
technologies and practices through continuous monitoring on or along
the pipeline, through periodic surveys with handheld equipment,
equipment mounted on mobile platforms, or other commercially available
technology. The regulations also must identify any scenarios where
operators may use leak detection practices that depend on human senses,
and include a schedule for repairing or replacing each leaking pipe,
except for a pipe with a leak so small that it poses no potential
hazard. Congress also expressly precluded the Secretary from reducing
the frequency of surveys or extending the duration of leak repair or
remediation timelines as required by PHMSA regulations on the date of
enactment of the PIPES Act of 2020. Section 113 does not alter the
Secretary's statutory authority to regulate gathering lines. Congress
directed PHMSA to issue regulations implementing section 113 no later
than December 27, 2021.
    Section 114 of the PIPES Act of 2020 adjusts the requirements for
inspection and maintenance procedures. This self-executing provision of
the statute requires that pipeline operators ensure their inspection
and maintenance plans contribute to eliminating hazardous leaks of
gases (not limited to natural gas) and minimizing releases of natural
gas specifically from pipeline facilities; protect the environment; and
address the replacement or remediation of pipelines (including cast-
iron, bare-steel, unprotected steel, wrought-iron, and certain plastic
pipelines) that are known to leak based on material, design, or past
operating and maintenance history. Operators had one year from the date
of the enactment of the PIPES Act of 2020 (i.e., no later than December
27, 2021) to update their inspection and maintenance plans to address
these self-executing requirements.\194\
---------------------------------------------------------------------------

    \194\ Section 114 also requires the Government Accountability
Office to conduct a study to evaluate the procedures used by PHMSA
and States when evaluating operators' inspection and maintenance
plans, and subsequently issue a report regarding the findings of the
study and recommendations for how to further minimize releases of
natural gas from pipeline facilities without compromising pipeline
safety. Additionally, the Secretary is to, not later than 18 months
after the enactment of the PIPES Act of 2020, submit to Congress a
report discussing the best available technologies or practices to
prevent or minimize the release of natural gas, without compromising
pipeline safety, when making planned repairs, replacements, or
maintenance to a pipeline facility; or when intentionally venting or
releasing natural gas, including when blowing down pipelines. The
report must also discuss whether pipeline facilities can be
designed, without compromising pipeline safety, to mitigate the need
to intentionally vent natural gas.
---------------------------------------------------------------------------

    Lastly, section 118 of the PIPES Act of 2020 amended the criteria
set forth at 49 U.S.C. 60102(b)(5) governing issuance of any new
rulemakings to elevate consideration of environmental benefits on par
with other (e.g., public safety) anticipated benefits. That statutory
amendment reinforced the environmental purpose of section 113 of the
PIPES Act of 2020, as well as historical provisions (e.g., 49 U.S.C.
60102(b)(1)(B)(ii) and (b)(2)(A)(3)) within the Federal Pipeline Safety
Laws that authorize PHMSA to issue regulations acknowledging the
environmental protection benefits from regulation of gas pipeline
facilities.
    Gas pipeline operators and related trade associations applauded the
passage through the Senate and later enactment of the PIPES Act of 2020
as part of the Consolidated Appropriations Act of 2021 (Pub. L. 116-
260). For example, API released a statement in support of the Senate's
passage of the legislation (S.2999) that became the PIPES Act of 2020,
stating that the ``PIPES Act takes important steps to make pipelines
safer for surrounding communities and the environment.'' \195\
Following enactment, INGAA described the PIPES Act of 2020 as a
``historic piece of legislation'' that ``enhances pipeline safety,
embraces the latest technologies, and aids in the further reduction of
methane emissions.'' \196\ At the 2021 Public Meeting, AGA et al.
expressed support for the PIPES Act of 2020 and initiatives that
protect the public and the environment, noting that their members have
committed to a range of initiatives to reduce methane emissions to
achieve goals for addressing climate change.\197\
---------------------------------------------------------------------------

    \195\ API, Press Release, ``API Statement of Senate Passage of
PIPES Act (Aug. 6, 2020), https://www.api.org/news-policy-and-issues/news/2020/08/06/api-statement-on-senate-passage-of-pipes-act.
    \196\ INGAA, Press Release, ``INGAA Hails Passage of Historic
Pipeline Safety Reauthorization Bill in 2021 Omnibus Package'' (Dec.
21, 2020), https://www.ingaa.org/News/PressReleases/38353.aspx
(quoting President and CEO of INGAA, Amy Andryszak, praising
Congress's direction to PHMSA to update its regulations ``to reflect
the latest technologies and practices [to] . . . both enhance safety
and benefit the environment'').
    \197\ Sames, Cristina. Pipeline Leak Detection, Leak Repair, and
Methane Emissions. AGA. May 5, 2021. Briefing materials, recordings,
and transcripts of the 2021 Public Meeting are available on the web
page for the meeting at https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152.
---------------------------------------------------------------------------

B. Administration Efforts Confronting the Climate Crisis

    The U.S. Federal Government is taking aggressive action in response
to climate change. During his first week in

office, President Biden established the National Climate Task Force,
assembling leaders from across Federal agencies--including the
Secretary of Transportation--to enable a whole-of-government approach
to combatting the climate crisis.\198\ Essential in those efforts are a
spectrum of regulatory actions being undertaken across the U.S. Federal
Government to reduce methane emissions described in the U.S. Methane
Emissions Reduction Action Plan published in November 2021.\199\
Parallel proposals by EPA and PHMSA to reduce methane emissions from
natural gas infrastructure occupy a critical role in the
Administration's whole-of-government strategy for tackling the climate
crisis.
---------------------------------------------------------------------------

    \198\ White House, ``Fact Sheet: President Biden Takes Executive
Actions to Tackle the Climate Crisis at Home and Abroad, Create
Jobs, and Restore Scientific Integrity Across Federal Government''
(Jan. 27, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/01/27/fact-sheet-president-biden-takes-executive-actions-to-tackle-the-climate-crisis-at-home-and-abroad-create-jobs-and-restore-scientific-integrity-across-federal-government/.
    \199\ White House Office of Domestic Climate Policy, U.S.
Methane Emissions Reduction Action Plan (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf; White House Office of Domestic Climate
Policy, Delivering on the U.S. Methane Emissions Reduction Action
Plan (Nov. 2022), https://www.whitehouse.gov/wp-content/uploads/2022/11/US-Methane-Emissions-Reduction-Action-Plan-Update.pdf.
---------------------------------------------------------------------------

1. Pertinent Executive Orders
    Several recent E.O.s direct PHMSA and other Federal agencies to
undertake efforts to achieve substantial reductions of methane
emissions from the oil and gas sector as soon as possible.
Executive Order 13990
    On January 20, 2021, the President signed E.O. 13990, titled
``Protecting Public Health and the Environment and Restoring Science to
Tackle the Climate Crisis'' \200\ announced the Administration's re-
commitment to environmental justice, science-based decision-making,
protecting public health and the environment, and ensuring Federal
agency actions account for the benefits of reducing climate pollution.
Toward that end, E.O. 13990 directed all executive departments and
agencies to immediately review and, as appropriate and consistent with
applicable law, take action to address the promulgation of Federal
regulations and other actions during previous years that conflict with
these important national objectives, and to immediately commence work
to confront the climate crisis.
---------------------------------------------------------------------------

    \200\ 86 FR 7037 (Jan 25, 2021).
---------------------------------------------------------------------------

Executive Order 14008
    On January 27, 2021, the President signed E.O. 14008, titled
``Tackling the Climate Crisis at Home and Abroad.'' \201\ E.O. 14008
puts ``the climate crisis at the center of U.S. foreign and domestic
policy,'' with a focus on a multilateral approach to putting the world
on a sustainable climate pathway and building resilience, both at home
and abroad, against the impacts of climate change. Abroad, E.O. 14008
expresses the Administration's intent for the United States to exercise
its leadership to meet the climate challenge by recommitting to the
Paris Agreement and engaging in international climate summits and
forums. Domestically, E.O. 14008 outlines a plan to focus on an all-in
approach that considers environmental justice for all communities
(especially those that have been underserved in the past), creates
clean energy jobs, and builds modern and sustainable infrastructure.
---------------------------------------------------------------------------

    \201\ 86 FR 7619 (Feb 1, 2021).
---------------------------------------------------------------------------

2. Renewal of U.S. Commitments to International Efforts To Address
Climate Change
    Consistent with the instruction in E.O. 13990, the President
returned the United States into the Paris Agreement on January 20,
2021.\202\ The Paris Agreement is an agreement within the United
Nations (UN) Framework Convention on Climate Change (UNFCCC) addressing
climate change mitigation, adaptation, and finance, that was drafted
throughout 2015 and was signed in 2016. The Paris Agreement was forged
to help the world avoid catastrophic planetary warming and to build
resilience around the world to the impacts from climate change that are
occurring, with a long-term goal of keeping the rise in global average
temperature to below 3.6 degrees Fahrenheit by reducing emissions of
GHGs. To achieve these goals, article 4 of the Paris Agreement requires
each party to prepare and maintain a ``nationally determined
contribution'' of emissions reduction or mitigation targets once every
5 years. As of October 2022, 194 members of the UNFCCC are parties to
the agreement; the United States had withdrawn from the agreement in
2020.
---------------------------------------------------------------------------

    \202\ https://unfccc.int/process-and-meetings/the-paris-agreement/the-paris-agreement. https://unfccc.int/process-and-meetings/the-paris-agreement/the-paris-agreement.
---------------------------------------------------------------------------

    Pursuant to section 102(e) of E.O. 14008, the United States also
submitted a new Nationally Determined Contribution (NDC), on April 4,
2021, after rejoining the Paris Agreement.\203\ In the NDC, the
Administration announced an ambitious ``economy-wide target of reducing
net greenhouse gas emissions by 50-52 percent below 2005 levels in
2030.'' The NDC includes a specific commitment to address methane
emissions by, among other efforts, ``plugging leaks from wells and
mains and across the natural gas distribution infrastructure.'' \204\
The NDC notes that the United States aims to achieve these targets with
a whole-of-government approach at the Federal level and ambitious
innovation from State, local, and tribal governments, and private
investment.
---------------------------------------------------------------------------

    \203\ UNFCCC, Nationally Determined Contribution Registry
(Interim), ``The United States of America Nationally Determined
Contribution'' (April 4, 2021).
    \204\ UNFCCC, Nationally Determined Contribution Registry
(Interim), ``The United States of America Nationally Determined
Contribution'' at 5 (April 4, 2021).
---------------------------------------------------------------------------

    The United States further reinforced its commitment to reducing
methane emissions by joining the European Union and several other
countries in committing to the Global Methane Pledge ahead of the 26th
global climate summit (the 26th Conference of the Parties, or
COP26).\205\ In its joint statement with the European Union, the Biden-
Harris Administration committed to direct the U.S. EPA and PHMSA to
``reduce methane leakage from pipelines and related facilities,'' \206\
and announced that more than 100 countries had joined the Global
Methane Pledge and a commitment to reduce the world's methane emissions
30% from 2020 levels by 2030.\207\ The Administration has since
released a U.S. Methane Emissions Reduction Action Plan detailing its
comprehensive whole-of-government plan to reduce methane emissions
through a combination of regulatory actions, financial incentives,
increased transparency and data disclosure, and public and private

partnerships.\208\ The Administration continues to lead nations around
the globe in methane reduction efforts, including by reconvening the
Major Economies Forum on Energy and Climate (MEF) on multiple
occasions. The President reconvened the MEF most recently on June 17,
2022, to encourage participant countries to accelerate emissions
reduction progress and provide a forum for participants to share the
results of their Global Methane Pledge efforts.\209\ The regulatory
requirements proposed in this NPRM would help align the United States
with ongoing efforts from international partners to enhance methane
mitigation requirements for gas pipeline infrastructure.\210\
---------------------------------------------------------------------------

    \205\ ``Joint U.S.-EU Statement on the Global Methane Pledge''
(Oct. 11, 2021), https://www.state.gov/joint-u-s-eu-statement-on-the-global-methane-pledge/https://www.state.gov/joint-u-s-eu-statement-on-the-global-methane-pledge/.
    \206\ White House, ``Joint U.S.-E.U. Press Release on the Global
Methane Pledge'' (Sept. 18, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/09/18/joint-us-eu-press-release-on-the-global-methane-pledge/.
    \207\ ``Fact Sheet: President Biden Tackles Methane Emissions,
Spurs Innovations, and Supports Sustainable Agriculture to Build a
Clean Energy Economy and Create Jobs'' (Nov. 2, 2021), https://www.whitehouse.gov/briefing-room/statements-releases/2021/11/02/fact-sheet-president-biden-tackles-methane-emissions-spurs-innovations-and-supports-sustainable-agriculture-to-build-a-clean-energy-economy-and-create-jobs/.
    \208\ White House Office of Domestic Climate Policy, U.S.
Methane Emissions Reduction Action Plan (Nov. 2021), https://www.whitehouse.gov/wp-content/uploads/2021/11/US-Methane-Emissions-Reduction-Action-Plan-1.pdf.
    \209\ https://www.whitehouse.gov/briefing-room/statements-releases/2022/06/18/chairs-summary-of-the-major-economies-forum-on-energy-and-climate-held-by-president-joe-biden/. At this meeting of
the MEF, the United States and the EU announced a new Global Methane
Pledge Energy Pathway which ``aims to encourage all nations to
capture the maximum potential of cost-effective methane mitigation
in the oil and gas sector and to eliminate routine flaring as soon
as possible, and no later than 2030.''
    \210\ For example, the European Union in December 2021 proposed
legislation that would require member states to impose requirements
that, at a minimum: (1) call for use of leak detection technologies
with a minimum sensitivity comparable to those proposed in this
rulemaking; (2) require leaks of at least 500 ppm to be immediately
repaired or replaced and leaks of less than 500 ppm to be repaired
or replaced within at least 3 months; and (3) create a default
prohibition on all venting of methane (subject to certain
exceptions). See European Parliament, ``EU Briefing--Fit for 55
Package: Reducing Methane Emissions in the Energy Sector'' (Mar.
2022), https://www.europarl.europa.eu/RegData/etudes/BRIE/2022/729313/EPRS_BRI(2022)729313_EN.pdf. Similarly, Canada in September
2022 issued a national Methane Strategy outlining policy options for
reducing methane emissions from natural gas pipeline infrastructure.
See Envt. & Climate Change Canada, Faster and Further: Canada's
Methane Strategy (Sept. 2022), https://publications.gc.ca/collections/collection_2022/eccc/En4-491-2022-eng.pdf.
---------------------------------------------------------------------------

3. EPA's Proposed New Source Performance Standards and Emissions
Guidelines for the Oil and Natural Gas Industry
    On November 15, 2021, the EPA proposed new source performance
standards and emission guidelines for crude oil and natural gas
facilities.\211\ This action was in response to the January 20, 2021,
Executive Order titled ``Protecting Public Health and the Environment
and Restoring Science to Tackle the Climate Crisis.'' The 2021 action
proposed to update VOC and methane \212\ standards on the books for new
sources (located at 40 CFR part 60, subparts OOOO and OOOOa),\213\ add
new standards for new sources (which would be located at 40 CFR part
60, subpart OOOOb), and establish the first nationwide Emission
Guidelines for states to regulate methane emissions from existing
sources (which would be located at 40 CFR part 60, subpart OOOOc).\214\
On December 6, 2022, in a supplemental proposal, EPA proposed further
updates to its November 2021 proposal.\215\ The proposed standards are
developed based on the EPA's determination of the ``best system of
emissions reduction'' (BSER) under section 111 of the Clean Air Act.
The EPA's proposed emission standards, including emissions monitoring,
repair, and maintenance requirements, would apply to numerous types of
facilities (including pneumatic controllers and pumps, storage vessels,
and sweetening units amongst others) across a defined source
category.\216\ Among the gas pipeline facilities within the scope of
EPA's 40 CFR part 60 regulatory scheme are compressor stations on gas
transmission pipelines and boosting stations on gas gathering
pipelines.
---------------------------------------------------------------------------

    \211\ EPA, ``Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review,'' 86 FR 63110 (Nov. 15,
2021).
    \212\ EPA regulates greenhouse gases expressed in the form of
limitations on methane.
    \213\ 40 CFR part 60, subpart OOOO regulates VOC only. 40 CFR
part 60, subpart OOOOa regulates both VOC and methane.
    \214\ The proposed Emission Guidelines would address methane
only.
    \215\ EPA, ``Standards of Performance for New, Reconstructed,
and Modified Sources and Emissions Guidelines for Existing Sources:
Oil and Natural Gas Sector Climate Review,'' 87 FR 74702 (Dec. 6,
2022) (EPA SNPRM).
    \216\ The EPA defines the Crude Oil and Natural Gas source
category to mean (1) crude oil production, which includes the well
and extends to the point of custody transfer to the crude oil
transmission pipeline or any other forms of transportation; and (2)
natural gas production, processing, transmission, and storage, which
include the well and extend to, but do not include, the local
distribution company custody transfer station. For purposes of EPA's
proposed rulemaking, for crude oil, the EPA's focus is on operations
from the well to the point of custody transfer at a petroleum
refinery, while for natural gas, the focus is on all operations from
the well to the local distribution company custody transfer station
commonly referred to as the ``city-gate''.
---------------------------------------------------------------------------

C. PHMSA Implementation of the PIPES Act of 2020

    PHMSA's efforts to implement requirements from the PIPES Act of
2020 efforts dovetail with policy goals of the Biden-Harris
Administration described above. This proposed rulemaking in particular
is a key part of PHMSA's efforts to address these policy priorities and
is referenced in the White House ``U.S. Methane Emissions Reduction
Action Plan.'' \217\
---------------------------------------------------------------------------

    \217\ White House Office of Domestic Climate Policy, U.S.
Methane Emissions Reduction Action Plan (Nov. 2021).
---------------------------------------------------------------------------

1. PHMSA's May 2021 Public Meeting
    PHMSA held a public meeting on May 5-6, 2021, (2021 Public Meeting)
to provide stakeholder groups and members of the public an opportunity
to share perspectives on improving gas pipeline methane leak detection
and repair programs consistent with sections 113 and 114 of the PIPES
Act of 2020. The agenda for the meeting included examining the sources
of methane emissions from gas pipeline systems, the current regulatory
requirements for managing fugitive and vented emissions, current leak
detection and repair practices of the industry, and the use of advanced
technologies and practices to reduce methane emissions from gas
pipeline systems.
    Stakeholders were invited to submit written comments in connection
with the 2021 Public Meeting. PHMSA received 7 comments from individual
pipeline operators, leak detection technology service providers, public
safety groups, and industry trade organizations, as summarized below.
The meeting itself included presentations and panel discussions from
representatives from PHMSA, EPA, NAPSR, EDF, PST, the United
Association of Plumbers and Pipefitters, GPTC, AGA, American Public Gas
Association, INGAA, GPA, Pipeline Regulatory Consultants, Gas
Technology Institute, the Methane Emissions Technology Evaluation
Center (METEC) at Colorado State University, QuakeWrap Inc., Bridger
Photonics, Safetylics, ProFlex Technologies, ABB, the Federal Energy
Regulatory Commission, and the National Association of Regulatory
Utility Commissioners. Presentations, recordings, and transcripts from
the meeting are available on PHMSA's public meeting web page.\218\
Certain comments made before, during, and after the meeting have been
summarized and discussed throughout this NPRM.
---------------------------------------------------------------------------

    \218\ https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=152.
---------------------------------------------------------------------------

2. June 2021 Advisory Bulletin
    PHMSA published an advisory bulletin on June 10, 2021, calling
operators' attention to the self-executing requirements of section 114
of the PIPES Act of 2020.\219\ The bulletin advised

operators of pipeline facilities to update their inspection and
maintenance plans to address the elimination of hazardous leaks and
minimize gas releases from their pipeline facilities, including
intentional venting during normal operations. The bulletin also noted
that, per the statutory mandate, operators must revise their plans to
address the replacement or remediation of pipeline facilities that are
known to leak based on their material, design, or past operating and
maintenance history. The advisory bulletin noted that the PIPES Act of
2020 requires pipeline facility operators to complete these updates by
December 27, 2021.
---------------------------------------------------------------------------

    \219\ PHMSA, ``Pipeline Safety: Statutory Mandate to Update
Inspection and Maintenance Plans to Address Eliminating Hazardous
Leaks and Minimizing Releases of Natural Gas from Pipeline
Facilities,'' 86 FR 31002 (June 10, 2021) (ADB-2021-01).
---------------------------------------------------------------------------

3. February 2022 PHMSA Webinar Addressing Inspection of Operators'
Plans To Eliminate Hazardous Leaks, Minimize Releases of Methane, and
Remediate or Replace Leak-Prone Pipe
    On February 17, 2022, PHMSA held an informational public webinar
reviewing the requirements for pipeline operator inspection and
maintenance plans introduced by section 114 of the PIPES Act of
2020.\220\ This webinar was informational, with attendees having the
opportunity to submit written comments to the public meeting docket.
More than 1,500 individuals registered for the public webinar,
including representatives from the gas gathering, transmission, and
distribution sectors. During the webinar, PHMSA discussed key elements
of the new section 114 requirements and reviewed the applicable
timelines for the actions required under section 114. PHMSA also
discussed its planned approach to inspection of operators' programs and
procedures to reduce methane emissions and replace or remediate leak-
prone pipes.
---------------------------------------------------------------------------

    \220\ PHMSA's presentation during this webinar and a recording
of the webinar meeting are available on PHMSA's public meeting web
page at https://primis.phmsa.dot.gov/meetings/MtgHome.mtg?mtg=159.
---------------------------------------------------------------------------

IV. Summary of Proposals

A. Leakage Survey and Patrol Frequencies and Methodologies

    Existing Federal regulations in subpart M of part 192 are focused
primarily on avoiding risks to public safety posed by of instantaneous,
large-volume releases or accumulated gas from gas pipelines, with less
attention given to environmental harms from methane leaks to the
atmosphere and releases of other flammable, toxic or corrosive gases.
Part 192 imposes leakage survey and patrol periodicities based on the
magnitude and probability of those public safety risks (via the proxies
of class location, business districts, and potential impact radius),
with operators required to conduct leakage surveys only once per
calendar year but with an interval between surveys not to exceed 15
months for most gas transmission pipelines, offshore gathering,
distribution pipelines inside of business districts, and some onshore
part-192 regulated gathering pipelines; distribution pipelines outside
of business districts are obliged to conduct surveys only once every
five years. Sections 192.706 and 192.723 outline requirements for
leakage surveys (including periodicity) on gas transmission and gas
distribution pipelines, respectively, and all offshore, Types A and B
gas gathering and certain Type C gathering pipelines must follow the
Sec.  192.706 leakage survey requirements for gas transmission lines.
Those existing prescribed periodicities are described in further detail
below.
    Current regulations do not specify what technologies or equipment
must be used in the performance of leakage surveys, and most gas
gathering and transmission pipelines are exempt from odorization
requirements that could help identify leaks. Currently, leakage surveys
on all distribution lines and certain unodorized gas transmission and
gathering pipelines must be performed using ``leak detection
equipment,'' but this term is not currently defined in part 192. PHMSA
has historically declined to establish technology or performance
standards regarding leak detection equipment. Leakage surveys on
transmission pipelines in Class 1 or Class 2 locations or Class 3 and
Class 4 locations that are odorized can rely entirely on human senses
such as smell or sight. This NPRM proposes to set more specific
technical standards for leak detection equipment used for leakage
surveys, and these are described in detail in section IV.B of this
NPRM.
    PHMSA regulations currently require only annual right-of-way
patrols on most gas transmission, offshore gathering, and Type A-
regulated onshore gathering lines. Patrols are visual surveys and do
not require the use of any equipment. Sections 192.705 and 192.721
define right-of-way patrolling requirements for gas transmission, (as
well as offshore and Type A gathering), and distribution pipelines,
respectively. While offshore and Type A gas gathering pipelines are
subject to the same requirements as transmission lines, Types B and C
gathering pipelines are not subject to any patrolling requirements.
Patrols are typically reliant on human senses (vision, sound, or scent)
and do not require the use of leak detection equipment (although
operators may incorporate leak detection equipment at their
discretion). An operator may combine a patrol with a leakage survey,
provided their procedures include both a visual survey of the right-of-
way and a leakage survey with leak detection equipment. Patrols can
detect unsafe conditions that may indicate a current or future leak or
incident. For example, visual right of way patrols can identify
construction activity that signifies a potential excavation damage
threat, earth and water movement that may indicate a natural force
damage threat, or population growth that may indicate change in class
location, change in HCA or Moderate Consequence Area status, and higher
potential consequences of an incident. Patrols can also detect certain
leaks by odor, by detecting dead vegetation, or by other indicia (e.g.,
bubbles from an offshore, submerged pipeline). However, those
approaches entail their own limitations; for example, reliance on smell
would not be effective unless the gas contains odorants and vegetation
surveys are only effective in certain soil and climate conditions (and
completely ineffective in areas with no or sparse vegetation such as
paved areas or deserts), and a noticeable impact on vegetation from a
leak may lag substantially behind the leak's emergence.
    The limitations of PHMSA's existing leakage survey and patrol
regulations thus currently allow for extended periods of time during
which leaks can degrade into catastrophic integrity failures, allow gas
to build up and ignite, or emit a substantial amount of methane or
other (flammable, toxic or corrosive) gases to the environment. For gas
gathering lines conveying unprocessed natural gas, the risks to public
safety and the environment from infrequent (or non-existent) leak
survey requirements are particularly acute as any leaks releasing VOCs
and HAPs, such as benzene, and corrosive materials entrained with the
unprocessed natural gas can expedite degradation of pipeline integrity.
And leaks of toxic or corrosive gases from other gas pipeline
facilities can adversely affect environmental resources. The
environmental impacts of gas pipeline leaks and the estimated
environmental and public safety benefits of the requirements proposed
herein are discussed in further detail in section 5 of the Preliminary
RIA for this NPRM, available in the rulemaking docket. Further, the
widespread use of human senses in leakage surveys is a missed
opportunity to leverage existing

commercially available leak detection technology to protect against
these risks to public safety and the environment by ensuring that leaks
are identified and addressed in a timely manner. In addition to the
public safety and human health risks of undetected methane leaks, long
intervals between surveys also result in increased emissions of methane
or other flammable and toxic gases. For example, in a presentation on
the Fugitive Emissions Abatement Simulation Toolkit (FEAST) model at
the 2021 EPA Methane Detection Technology Workshop, modeling based on
controlled tests and field evaluations demonstrated that at a given
detection threshold, survey frequency is directly proportional to
fugitive emissions reductions.\221\ While the modeling shows decreasing
emissions abatement returns to increasing survey frequency, large drop-
offs begin to appear only after semiannual OGI surveys.
---------------------------------------------------------------------------

    \221\ Ravikumar, Arvind Ph.D. ``FEAST-Based Evaluation of
Methane Leak Detection and Repair Programs Using New Technologies.''
EPA Methane Detection Technology Workshop (August 24, 2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day 2 at 1:33:50.
---------------------------------------------------------------------------

    PHMSA therefore proposes to strengthen minimum leakage survey
frequencies for gas transmission and gathering pipelines located in
HCAs, aboveground offshore gas transmission and gathering pipelines,
distribution pipelines outside of business districts, and distribution
pipelines at a high risk of leakage. PHMSA also proposes to introduce
patrolling requirements for Type B and Type C gathering pipelines and
to increase the minimum patrolling frequency for all gas transmission,
offshore gathering, and Type A regulated onshore gas gathering
pipelines. Finally, while all operators may supplement instrumented
leakage surveys with visual and other sensory survey techniques, PHMSA
proposes to limit the exclusive use of human senses for leakage surveys
to submerged offshore gas transmission and submerged offshore gas
gathering pipelines and, subject to notification to and review by
PHMSA, onshore gas transmission and regulated onshore gas gathering
pipelines in Class 1 and Class 2 locations outside of HCAs. These
amendments would ensure timely detection of leaks. The proposed changes
to patrolling frequency would also increase the likelihood that
conditions that could result in leaks, potentially fatal incidents, or
damage that could result in shutdowns and maintenance-related releases
of methane to the atmosphere are detected.
    These proposals (and all other proposed amendments to parts 191 and
192) apply generally to pipeline transportation of any ``gas,'' defined
in Sec. Sec.  191.3 and 192.3 as ``natural gas, flammable gas, or gas
which is toxic or corrosive.'' Although natural gas pipelines
constitute the vast majority of part 192-regulated gas pipeline mileage
today, the requirements for ``gas'' pipelines in parts 191 and 192
apply equally to pipelines transporting other gases, including over
1,500 miles of hydrogen gas pipelines in operation today.\222\ Unless
otherwise specified in the proposed amendments, the proposals in this
NPRM apply the same requirements to hydrogen gas pipelines (and other
gas pipelines) as to natural gas pipelines. PHMSA invites comment on
whether, within a final rule in this proceeding, there would be value
in adopting hydrogen gas pipeline-specific provisions (in lieu of or in
addition to the provisions proposed herein). Comments on this question
are especially helpful if they address the potential safety and
environmental benefits and potential costs of a particular approach,
including whether that approach would be technically feasible, cost-
effective, and practicable.
---------------------------------------------------------------------------

    \222\ See PHMSA Interpretation Response Letter No. PI-92-030
(July 14, 1992) (noting PHMSA regulates hydrogen pipelines under
part 192); PHMSA, ``Presentation of Vincent Holohan for Workgroup#4:
Hydrogen Network Components at December 2021 Meeting'' at slide 11
(Dec. 1, 2021), https://primis.phmsa.dot.gov/meetings/FilGet.mtg?fil=1227.
---------------------------------------------------------------------------

    PHMSA has not proposed in this NPRM to establish minimum leakage
survey frequencies or leak detection equipment requirements for UNGSFs.
This approach is consistent with current PHMSA regulations at Sec.
192.12, which do not require UNGSFs perform periodic leakage surveys
with leak detection equipment but rather oblige operators of UNGSFs to
perform an integrity assessment of each reservoir, cavern, and well as
often as necessary (but with a maximum interval between assessments
that does not exceed 7 years). Additionally, consensus industry
standards \223\ incorporated by reference in Sec.  192.12 include
recommendations and requirements for periodic UNGSF reservoir and
wellsite inspection and monitoring. However, PHMSA invites comment on
whether, within a final rule in this proceeding, there would be value
in prescribing leakage survey frequency and leak detection equipment
requirements for UNGSFs in Sec.  192.12. Comments on this question are
especially helpful if they address the potential safety and
environmental benefits and potential costs of a particular approach,
including whether that approach would be technically feasible, cost-
effective, and practicable.
---------------------------------------------------------------------------

    \223\ API Recommended Practice 1170, Design and Operation of
Solution-Mined Salt Caverns Used for Natural Gas Storage--First
Edition (July 2015); API Recommended Practice 1171, Functional
Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs
and Aquifer Reservoirs--First Edition (Sept. 2015).
---------------------------------------------------------------------------

1. Distribution--Sec.  192.723
    Section 192.723 outlines the current requirements for leakage
surveys on gas distribution systems. Leakage surveys on distribution
pipelines must be performed using leak detection equipment. Leakage
surveys in business districts must be performed at least once each
calendar year, with an interval between surveys not to exceed 15
months. On distribution pipelines outside of business districts that
are not cathodically protected and where electrical surveys for
corrosion are impractical (i.e., bare steel, unprotected steel, and
cast-iron systems), leakage surveys must be performed once every 3
calendar years, with an interval between surveys not to exceed 39
months. All other portions of a distribution system outside of business
district must currently be surveyed once every 5 calendar years at
intervals not exceeding 63 months. The term ``business district'' is
not defined. PHMSA invites comment on potential criteria for defining
the boundaries of a business district for potential inclusion within a
final rule in this proceeding. Comments on these potential criteria are
especially helpful if they address the potential safety and
environmental benefits and potential costs of a proposed or alternative
approach, including whether each proposal would be technically
feasible, cost-effective, and practicable.
    As described in section III.C, fugitive emissions from leaks
represent the vast majority of total methane emissions from natural gas
distribution systems. However, the current Sec.  192.723 neither
articulates minimum performance standards for leak detection equipment
nor prescribes a particular technology to ensure that all leaks are
identified during leakage surveys on distribution pipelines. PHMSA
therefore proposes several regulatory amendments that would increase
the frequency and effectiveness of leakage surveys to identify and
repair leaks on gas distribution pipelines. First, PHMSA proposes that
leakage surveys be incorporated within operator ALDPs meeting the
minimum performance standards proposed in this NPRM and any detected
leaks be graded and repaired consistent with the grading

framework in this NPRM (each discussed further in section IV.B). These
proposals would better address the leading causes of methane emissions
from gas distribution systems by ensuring that leaks are detected and
repaired in a timely manner. Second, PHMSA proposes more frequent
leakage surveys to promote earlier detection and repair of leaks,
thereby improving the environment by reducing emissions from those
leaks, and improving the likelihood that leaks are detected before they
adversely impact public safety.
    As described earlier, distribution leakage surveys are currently
required once every 1, 3, or 5 calendar years, depending on the
location and design of the pipeline. The 5-year maximum leakage survey
interval allows even leaks hazardous to people or property that must be
``repaired promptly'' under current Sec.  192.703 to remain undetected
for up to 5 years, often placing the burden on the general public to
detect and report potentially hazardous leaks via odor calls. In
addition to the potential hazard to public safety and human health, an
undetected leak will continue to emit methane to the environment until
it is detected and repaired. PHMSA therefore proposes to eliminate the
5-year survey frequency tier by moving leakage surveys outside of
business districts from at least once every 5 years into the next
frequency category: at least once every 3 calendar years, with an
interval between surveys not to exceed 39 months. Leakage surveys
inside of business districts would still be required annually. This
proposal would increase the frequency of leakage surveys on all
distribution pipelines outside of business districts, consistent with
the environmental and public safety risks of any leaks, while ensuring
that operators continue to prioritize frequency of surveys inside of
business districts where there is a higher risk to people and property.
Combined with the repair requirements proposed in the new Sec.
192.760, which proposes a maximum repair timeline of 24 months for
grade 3 leaks, this ensures that operators repair all leaks prior to
their next distribution leakage survey, preventing continued growth in
the backlog of unrepaired leaks. Some States have adopted similar
standards for leakage surveys outside of business districts, for
example the Commonwealth of Massachusetts requires leakage surveys
outside of ``principal business districts'' at least once every 24-
months.\224\
---------------------------------------------------------------------------

    \224\ 220 Code of Massachusetts Regulations 101.06(21)(b).
---------------------------------------------------------------------------

    Similarly, due to the increased environmental and safety risks of
distribution mains and service lines that are either without cathodic
protection, or known to leak based on material, design or past
operating and maintenance history, PHMSA proposes to require that
operators perform a leakage survey at least once each calendar year
with the interval between surveys not to exceed 15 months, mirroring
the high-priority survey frequency for unprotected pipelines and
pipelines inside of business districts. Currently, such pipelines mut
be assessed at the lowest frequencies: once every 3 calendar years for
cathodically unprotected distribution pipelines outside of business
districts; once every 5 calendar years for all other distribution
pipelines outside of business districts; or once every calendar year
for all distribution pipelines within business districts. As with
distribution pipelines outside of business districts, some States have
also adopted enhanced leak survey requirements for leak-prone pipe. For
example, the State of Kansas requires annual leakage surveys for
cathodically unprotected steel mains and ductile iron mains in class 2,
3, or 4 locations.\225\ Consistent with section 114 of the PIPES Act of
2020, materials known to leak include cast iron, unprotected steel,
wrought iron, and historic plastics with known issues. As described in
the emissions discussion in section II.C, certain materials are
responsible for a disproportionate amount of emissions from leaks, with
distribution mains composed of such materials being particularly
significant sources of emissions. PHMSA's proposal seeks to increase
the scrutiny of distribution systems outside of business districts at a
high risk of leakage by decreasing survey intervals and targeting
materials at a high risk of leakage. PHMSA's proposal also contemplates
that distribution pipeline operators would retain the option to
establish more frequent leakage surveys than proposed herein within
their operations and maintenance procedures or DIMP plans.
---------------------------------------------------------------------------

    \225\ Kansas Administrative Regulations 82-11-4(b)(34)(b)(2)(i).
---------------------------------------------------------------------------

    The following categories of distribution pipelines outside of
business districts would be subject to the proposed annual survey
requirement:
     Cathodically unprotected pipelines on which electrical
surveys are impracticable, typically bare and unprotected distribution
lines;
     Any distribution pipeline protected by a distributed anode
system where the cathodic protection survey under Sec.  195.463 showed
a deficient reading; and
     Pipelines known to leak based on the material (including,
but not limited to, cast iron, unprotected steel, wrought iron, and
historic plastics with known issues), design, or past operating and
maintenance history of the pipeline.
    PHMSA expects that, in determining whether a plastic pipe material
is a ``historic plastic with known issues'' making it at high risk of
leaks, operators should consider PHMSA and State regulatory actions and
industry technical resources identifying systemic integrity issues on
plastic pipe made from particular materials; or manufactured at
particular times or by particular companies, or fabricated and
installed pursuant to particular processes. By way of illustration,
PHMSA issues advisory bulletins cautioning operators regarding the
susceptibility of certain historic plastics to systemic integrity
issues. In 2007, in response to NTSB findings and data collection
performed by the Plastic Pipe Database Committee (PPDC), PHMSA issued
Advisory Bulletin ADB-07-01.\226\ That advisory bulletin called
operators' attention to cracking issues on pipe and components
manufactured by Century Utility Products, Inc.; low-ductile inner wall
``Aldyl A'' piping manufactured by Dupont before 1973; polyethylene gas
pipe made from PE 3306 resin; Delrin insert tap tees; and caps made of
Celcon (polyactal) on Plexco service tees. Similarly, State pipeline
safety regulatory actions, PHMSA pipeline failure investigation
reports, and NTSB findings can inform operator determinations whether
historic plastic pipe is at a high risk of leakage. Industry efforts
and resources are another resource for operators in determining whether
historic plastic pipe is known to leak. For example, the PPDC publishes
data submitted by program participants that incorporates information
regarding investigations of materials of concern or potential
concern.\227\ PHMSA expects that these and other authoritative
resources--coupled with an operator's own design expertise and
operational and maintenance history--would be adequate for a reasonably
prudent operator to determine whether the particular plastic pipe in
its distribution systems is at a high risk of leakage.

PHMSA invites comment on the value of either explicitly listing (either
within part 192 or within periodically-issued implementing guidance)
historic plastics known to leak, or deleting the scope qualification
``historic'' from the proposed regulatory text, for the purposes of the
proposed annual survey requirement or for replacement under section 114
of the PIPES Act of 2020. Comments on this question are especially
helpful if they address the potential safety and environmental benefits
and potential costs of a particular approach, including whether that
approach would be technically feasible, cost-effective, and
practicable.
---------------------------------------------------------------------------

    \226\ ``Pipeline Safety: Updated Notification of Susceptibility
to Premature Brittle-Like Cracking of Older Plastic Pipe-Advisory
Bulletin ADB-07-01,'' 72 FR 51301 (September 6, 2007).
    \227\ APGA, ``Plastic Pipe Database Collection Initiative,''
https://www.apga.org/programs/plasticpipedata (last accessed Dec.
20, 2022).
---------------------------------------------------------------------------

    PHMSA further proposes to require that operators perform a leakage
survey of a distribution pipeline segment after extreme weather events
or land movement occur that could damage that segment. This survey must
be completed within 72 hours of the cessation of the event, described
as the time when the location can be safely accessed by operator
personnel, or alternatively, within 72 hours of when the pipeline is
returned to service. Such a survey could qualify as a periodic survey,
and therefore reset the one- or three-year clock until the next
required periodic survey. Separately, PHMSA proposes to require
operators to investigate existing leaks when ground freezing and other
changes in environmental conditions (such as heavy rain or flooding-
inducing ground subsidence, erosion, or the installation of new
pavement) has occurred that could affect gas venting or migration to
nearby buildings. The required investigation would include conducting a
leakage survey for possible gas migration, but said survey would not
qualify as a periodic survey and would not reset the one- or three-year
clock until the next required periodic survey. Each of those changes in
environmental conditions can place new stresses on pipeline integrity
or can affect how and where gas vents from or migrates through the
ground. Therefore, each can cause new leaks or exacerbate or reveal
pre-existing leaks on distribution pipelines. These requirements are
designed to ensure prompt evaluation of whether environmental changes
have exacerbated existing leaks in a way that creates increased risk to
public safety and the environment. PHMSA invites comment on whether to
require assessments prior to extreme weather events in order for
operators to prepare for and prevent resulting leaks.\228\ Comments on
this question are especially helpful if they address the potential
safety and environmental benefits and potential costs of a particular
approach, including whether that approach would be technically
feasible, cost-effective, and practicable.
---------------------------------------------------------------------------

    \228\ See, e.g., EPA's notice of proposed rulemaking titled
``Accidental Release Prevention Requirements: Risk Management
Programs Under the Clean Air Act; Safer Communities by Chemical
Accident Prevention,'' 87 FR 53556 (Aug. 31, 2022) (proposing to
require, under the Clean Air Act Risk Management Program, that
industrial chemical facilities evaluate ways to address natural
disasters and consider steps to prevent releases that may result,
even before such events occur).
---------------------------------------------------------------------------

    The proposed amendments to gas distribution pipeline leakage survey
requirements are summarized in the table below.

            Summary of Distribution Leakage Survey Amendments
------------------------------------------------------------------------
            Facility                   Existing            Proposed
------------------------------------------------------------------------
Outside of Business Districts...  5 years not to      3 years not to
                                   exceed 63 months.   exceed 39 months.
Pipelines known to leak           3 years not to      Annually, not to
 (cathodically unprotected pipe    exceed 39 months.   exceed 15 months.
 in existing Sec.   192.723).
Inside Business Districts.......  Annually, not to    No change.
                                   exceed 15 months.
                                 ---------------------------------------
Other Proposals.................  --After environmental changes that can
                                   affect gas migration.
                                  --Following extreme weather events.
------------------------------------------------------------------------
Note: The most frequent survey would apply.

    PHMSA expects its proposed amendments to leakage survey practices
would be reasonable, technically feasible, cost-effective, and
practicable for affected gas distribution operators. As explained
above, operators are already subject to prescriptive periodic leakage
surveys and patrols, and individual operators may have more demanding
requirements specified within their DIMP plans or as a function of
state-imposed requirements; affected operators also have the option to
sync their patrol and leakage survey requirements to minimize
compliance burdens (provided that the operator includes both a visual
survey of the right-of-way and a leakage survey with leak detection
equipment). PHMSA's proposed amendments would merely increase
prescribed frequencies within Federal regulation as a function of
factors (presence of cathodic protection; extreme weather events;
material composition, operating and maintenance history) probative of
leak susceptibility--and by extension, risks to public safety and the
environment. PHMSA further notes that, insofar as those factors
employed in the NPRM as bases for increased leakage survey frequency
are widely understood to be potential threats to the integrity of gas
distribution pipelines, they are among the phenomena that reasonably
prudent operators would evaluate, and potentially adopt mitigation
measures to address, in ordinary course when implementing current DIMP
requirements to protect public safety from releases of (natural,
flammable, toxic, or corrosive) pressurized gases from their pipelines
and minimize loss of commercially valuable commodities. Additionally,
operators would have flexibility (as appropriate for their needs and
their pipelines' operational characteristics and environment) in
choosing between commercially available, advanced leakage detection
equipment satisfying the performance standards proposed in this NPRM
for use in those leakage surveys. Viewed against those considerations
and the compliance costs estimated in the Preliminary RIA, PHMSA
expects its proposed amendments will be a cost-effective approach to
achieving the commercial, public safety and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, the
proposed compliance timelines--based on an effective date of the
proposed requirements six months after the publication date of a final
rule in this proceeding--would provide operators ample time to
implement requisite changes in their leakage survey practices and
manage any related compliance costs.
    In the Preliminary RIA, PHMSA considers an alternative where the 5-

year survey interval outside of business districts is maintained for
plastic pipe distribution pipelines without known leak issues. This
alternative is not being proposed because while recent-vintage plastic
pipe is understood to leak less than cast iron and bare steel, some
studies indicate that plastic piping systems may be leaking more than
previously thought.\229\ PHMSA invites comment concerning the value of
more or less frequent leakage surveys of plastic pipe systems, as well
as potential means to identify plastic pipe known to leak (e.g., via a
surveillance or sampling program) for inclusion within a final rule in
this rulemaking proceeding. Likewise, PHMSA seeks comment on the
alternative considered in the Preliminary RIA where distribution mains
would be required to be surveyed annually; typically, mains are likely
to be more accessible to pipeline operators than service lines crossing
private property and may therefore be more convenient to survey.
Comments on these questions are especially helpful to PHMSA when they
are supported by research or operational experience with leaks from
plastic pipe systems or distribution mains (as applicable), along with
the potential safety and environmental benefits and potential costs of
a particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable).
---------------------------------------------------------------------------

    \229\ Weller et al., 2020, for example.
---------------------------------------------------------------------------

2. Transmission and Gathering--Sec. Sec.  192.9, 192.705, and 192.706
    Section 192.706 currently requires gas transmission and Types A and
B gathering pipelines that are not odorized to be surveyed with leak
detection equipment at least twice each calendar year in Class 3
locations, and at least four times each calendar year in Class 4
locations. All other gas transmission, offshore gathering, Type A and
Type B gathering, and certain Type C gathering pipelines must be
surveyed once each calendar year. For these annual surveys, PHMSA does
not require leak detection equipment on gas transmission and offshore
gas gathering pipelines; however, Sec.  192.9 requires the use of leak
detection equipment for leakage surveys on Type B and Type C gas
gathering pipelines. Section 192.705 specifies frequencies for right-
of-way patrols along gas transmission, offshore gathering, and Type A
gathering pipelines; Types B and C gathering lines are not required to
conduct right-of-way patrols by Sec.  192.705.
    Consistent with section 113 of the PIPES Act of 2020, PHMSA
proposes to require the use of leak detection equipment and practices
meeting the ALDP standard in proposed Sec.  192.763 (see section IV.B)
for leakage surveys on most onshore gas transmission and Types A, B and
C gathering pipelines. Leakage survey by human or animal senses would
be permitted for offshore gas transmission and offshore gathering
pipelines. Because leaks on submerged offshore pipelines are visibly
conspicuous due to bubbles or a sheen of gas condensate on the water's
surface, PHMSA is not proposing to require leak detection equipment be
used for leakage surveys of submerged offshore pipelines, including
platform risers up to the waterline. However, offshore platform piping
and riser piping above the waterline would be subject to the same
equipment and survey requirements as onshore gas transmission
pipelines. Leakage surveys for onshore pipelines would be permitted
without the use of leak detection equipment (i.e., with human senses or
animal senses) only for gas transmission and Types A, B, or C gathering
pipelines in non-HCA, Class 1 and Class 2 locations, and then only with
prior notification and review by PHMSA pursuant to Sec.  192.18. Visual
surveys and other survey methods depending exclusively on human or
animal senses would only be authorized if the operator can demonstrate
through tests and analyses included in the notification that the survey
method would be effective to meet the ALDP performance standard
proposed in Sec.  192.763(b) or (c). For example, a visual vegetation
survey would need to include procedures to ensure effective detection,
such as ensuing the location of a buried pipeline is determined before
a survey and performing vegetation surveys on foot rather than at a
distance from a vehicle or aircraft, and would not be approved in areas
where vegetation is absent. The notification must also include the
survey procedures and qualifications for surveyors. Leaks detected on
gas transmission, offshore gathering, and Types A, B, and C gathering
pipelines would need to be graded and repaired consistent with the
requirements proposed in this NPRM (see section IV.C). PHMSA welcomes
comments and data on the efficacy of the exclusive use of human senses
for leakage surveys, particularly on submerged offshore gas
transmission pipelines, submerged offshore gas gathering pipelines,
onshore gas transmission pipelines, and regulated onshore gas gathering
pipelines (for potential inclusion within a final rule in this
proceeding). Comments and data on this question are especially helpful
to PHMSA when they are supported by research or operational experience
with the exclusive use of human senses for leakage surveys, along with
the potential safety and environmental benefits and potential costs of
a particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable).
    As explained in section II.C above, leaks from natural gas
transmission line pipe are not as significant a source of methane
emissions compared with venting, blowdowns, and leaks from compressor
stations and other aboveground equipment. However, as explained above
in connection with leakage surveys on gas distribution lines, any leaks
of methane contribute to climate change and can entail public safety
risks--risks that are each more acute for gas transmission pipelines,
which generally operate at higher pressures and capacity than
distribution pipelines and are usually not odorized. Further, leaks
from gas pipeline facilities transporting other flammable, toxic, or
corrosive gases can entail significant public safety and environmental
consequences. PHMSA therefore proposes, to support more timely
detection and repair of leaks that pose a safety hazard, an increase in
the minimum leakage survey frequencies for each of the following,
calibrated based on a pipeline's proximity to occupied buildings or
HCAs: for gas transmission, offshore gathering, and Type A, B, and C
gathering pipelines located in HCAs from once each calendar year to
twice each calendar year (at intervals not exceeding 7\1/2\ months) if
within a Class 1, Class 2, or Class 3 location; and for gas
transmission and Types A or B gathering pipelines located within Class
4 locations within HCAs, from once each calendar year to four times
each calendar year (at intervals not exceeding 4\1/2\ months). For gas
transmission and Type A or B gas gathering pipelines that are
(consistent with the proposed revisions herein to Sec.  192.625) not
odorized, more frequent leak surveys would continue to be required to
account for the greater risks to public safety from their proximity to
occupied buildings: no less than twice each calendar year (at intervals
not exceeding 7\1/2\ months) for pipelines in Class 3 locations, and no
less than four times each calendar year (at intervals not exceeding
every 4\1/2\ months) in Class 4 locations. Leaks on gas transmission
pipelines, especially in Class 3 and Class 4 locations, would also be
subject to more stringent grading requirements

in the proposed leak grading and repair requirements described in
section IV.C.
    As explained in section II.C above, fugitive methane emissions from
natural gas compressor stations on gas transmission and gas gathering
pipelines comprise a significant share of fugitive emissions from those
facilities. Other pipeline facilities with relatively complex design
and configuration--such as valve sites (including the valve components,
flanges, and tie-ins with line pipe), in-line instrument (ILI)
launchers and receivers, and tanks--have fugitive emissions profiles
better resembling compressor stations than line pipe. PHMSA therefore
proposes more frequent leakage surveys for each of those facilities on
gas transmission, offshore gathering, and Types A, B, and C gathering
pipelines. Such facilities in Class 1, Class 2, and Class 3 locations
would need to be surveyed twice each calendar year (at intervals not
exceeding 7\1/2\ months), compared with once per year under current
regulations. This is the same survey interval used for fugitive methane
emissions monitoring for compressor stations under the existing and
proposed EPA requirements (for example, 40 CFR 60.5397a(g)(2) for new
sources). More frequent leakage surveys for such facilities would
ensure operators detect and repair leaks earlier, reducing total
emissions and reducing the risk that a leak can degrade into a rupture
or other incident. Facilities in Class 4 locations would need to be
surveyed at least 4 times each calendar year (at intervals not
exceeding 4\1/2\ months) due to the potential for comparatively more
significant public safety risks in the event of a leak due to their
proximity to ignition sources and densely occupied buildings.

     Summary of Transmission and Regulated Gathering Leakage Survey
                               Amendments
------------------------------------------------------------------------
            Facility                   Existing            Proposed
------------------------------------------------------------------------
Non-odorized Class 3............  Twice a year not    No change.
                                   to exceed 7\1/2\
                                   months.
Non-odorized Class 4............  Four times a year   No change.
                                   not to exceed 4\1/
                                   2\ months.
All other transmission..........  Once a year not to  No change.
                                   exceed 15 months.
HCA class 1, 2, or 3............  No specific         Twice a year not
                                   standard.           to exceed 7\1/2\
                                                       months.
HCA class 4.....................  No specific         Four times a year
                                   standard.           not to exceed 4\1/
                                                       2\ months.
Valves, flanges, pipeline tie-    No specific         Same as proposed
 ins with valves and flanges,      standard.           HCA frequencies.
 ILI launcher and ILI receiver
 facilities, and leak prone pipe.
Leak detection equipment........  Only required for   Required except
                                   non-odorized        for non-HCA class
                                   class 3 and class   1 and class 2
                                   4.                  with a
                                                       notification.
Regulated gathering.............  Existing            Require proposed
                                   transmission line   leakage survey
                                   requirements        requirements for
                                   apply to            all regulated
                                   offshore, Type A,   gathering lines.
                                   Type B, and
                                   certain Type C
                                   gathering lines.
------------------------------------------------------------------------
Note: The most frequent survey would apply.

    PHMSA also proposes to increase the frequency of patrols on gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines by replacing the current, scaled approach within Sec.
192.705(b) of between one and four patrols per year based on class
location and the presence of a highway or railroad crossing with a
global, baseline requirement for those operators to perform 12 patrols
along the entirety of their pipelines each calendar year (at intervals
not exceeding 45 days). Patrols are primarily visual surveys of the
right of way and may be performed with or without leak detection
equipment. PHMSA understands those increased frequencies to be
appropriate because patrols are valuable not only for identifying
existing leaks and incidents, but also because they are a relatively
low-cost method for preemptive identification and mitigation of
potential threats to pipeline integrity. In conducting patrols,
operators should consider potential threats such as right of way
incursions (such as construction, excavation, or agricultural
activities), signs of earth movement or flooding, or the presence of
new structures potentially indicating a change in class location. In
addition to the general leak detection and pipeline integrity benefits
associated with performing right of way patrols described in section
IV.A.2, requiring patrols provides an opportunity to update class
location surveys and potential impact circle surveys. PHMSA further
notes that operators can control their compliance burdens from the
proposed increased patrols by coupling them with other operations and
maintenance tasks such as leakage surveys (provided that the operator
includes both a visual survey of the right-of-way and a leakage survey
with leak detection equipment) or by leveraging mobile technologies.
    PHMSA expects its proposed amendments to leakage survey and right-
of-way patrol practices would be reasonable, technically feasible,
cost-effective, and practicable for affected gas transmission and
gathering pipeline operators. As explained above, operators of affected
gas transmission and gathering pipelines (some of which operators have
both gas transmission and gathering pipeline facilities within their
systems) are already subject to prescriptive periodic leakage surveys
requirements; affected operators also have the option to sync their
patrol and leakage survey requirements to minimize compliance burdens
(provided that the operator includes both a visual survey of the right-
of-way and a leakage survey with leak detection equipment). PHMSA's
proposed amendments would merely increase prescribed frequencies within
Federal regulation as a function of factors (including location in HCAs
and occupied buildings; components/equipment with complex
configurations; material composition; operating and maintenance
history) probative of leak susceptibility--and by extension, risks to
public safety and the environment. PHMSA further notes that, insofar as
those factors the NPRM employs as bases for increased leak detection
and patrol frequency are widely understood to be potential threats to
the integrity of pipelines, they are among the phenomena that
reasonably prudent operators would evaluate, and potentially adopt
mitigation measures to address, in ordinary course to protect public
safety and the environment from releases of pressurized (natural,
flammable, toxic, or corrosive) gases from their pipelines and minimize
loss of commercially valuable commodities. Additionally, operators
would have flexibility (as appropriate for their needs and their
pipelines' operational characteristics

and environment) in choosing between commercially available, advanced
leakage detection equipment satisfying the performance standards
proposed in this NPRM for use in those leakage surveys. Viewed against
those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, the proposed compliance timelines--based on an
effective date of the proposed requirements six months after the
publication date of a final rule in this proceeding (which would
necessarily be in addition to the time since issuance of this NPRM)--
would provide operators ample time to implement requisite changes in
their leakage survey practices and manage any related compliance costs.
3. Leakage Surveys and Patrols for Types B and C Gas Gathering
Pipelines--Sec. Sec.  192.9, 192.705, and 192.706
    PHMSA proposes to apply to Types B and C gas gathering pipelines
the leakage survey and patrol requirements proposed in this NPRM for
gas transmission, offshore gathering, and Type A gathering pipelines.
    PHMSA has long recognized the public safety risks associated with
gathering pipelines and has general authority under 49 U.S.C. 60102 to
issue minimum Federal pipeline safety standards necessary to ``meet the
need for gas pipeline safety [. . .] and protect [] the environment.''
For that reason, PHMSA has in the past extended select part 192
requirements--including leak survey requirements at Sec.  192.706--
applicable to gas transmission pipelines to a minority (only the
largest, or closest to occupied buildings) of the Type C gas gathering
pipelines posing the greatest risks to public safety. Existing Sec.
192.9 does not require operators of Type B and Type C gathering
pipelines to conduct patrols pursuant to Sec.  192.705.
    However, the historical, limited approach in applying Sec. Sec.
192.705 (patrol) and 192.706 (leakage survey) requirements to Types B
and C gathering lines is inadequately protective of public safety and
the environment. Recent aerial methane emissions surveys discussed in
section II.C above yield that leaks from gas gathering line pipe, the
vast majority of which are Type C or Type R pipelines located in Class
1 locations, in particular are a significant contributor to methane
emissions. Further, the GHGI data discussed in section II.E reveals
that fugitive methane emissions from all types of gas gathering line
pipe vastly exceed emissions from gas transmission line pipe both in
total and on a per-mile basis. Leaks from gathering line pipe can
therefore be correspondingly greater contributors to the climate crisis
than leaks from gas transmission line pipe. Further, because natural
gas gathering pipelines carry unprocessed natural gas, any leak from
those pipelines would release VOCs and HAPs such as benzene to the
environment and risk accelerated degradation of pipeline integrity from
corrosives entrained in the natural gas. PHMSA understands that leaks
from gathering lines transporting other gases that are flammable,
toxic, or corrosive could entail significant public safety and
environmental consequences as well. Because of these significant risks
to public safety and the environment posed by Types B and C gathering
lines, PHMSA has proposed that all Type C gathering lines be subject to
the same Sec.  192.706 requirements governing leakage survey equipment
and frequency as gas transmission and Types A and B gathering
pipelines. Similarly, PHMSA proposes to require patrol frequencies for
Type B and Type C gathering lines identical to the patrol requirements
for as transmission and Type A gathering pipelines. PHMSA understands
that its proposed extension of these mutually-reinforcing, enhanced
patrol and leakage survey requirements would ensure timely prevention,
discovery and remediation of leaks on Types B and C gas gathering
lines. PHMSA invites comments concerning the value of requiring more or
less frequent leakage surveys of transmission and gathering pipelines
(for potential inclusion within a final rule in this proceeding).
Comments on these questions are especially helpful to PHMSA when they
are supported by research or operational experience, along with the
potential safety and environmental benefits and potential costs of a
particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable).
    PHMSA expects its proposed amendments to extend leakage survey and
right-of-way patrol practices to all Types B and C gas gathering
pipeline operators would be reasonable, technically feasible, cost-
effective, and practicable. Patrols and leakage surveys using leak
detection equipment are widely-employed tools adopted by reasonably
prudent operators in ordinary course for identifying and mitigating
leaks on, or threats to the integrity of, pipelines transporting
commercially valuable pressurized (natural, corrosive, toxic, or
flammable) gases. Precisely for that reason, PHMSA expects that some
Types B and C gas gathering pipeline operators affected by this NPRM's
proposed requirements for leakage survey and right-of-way patrols may
already voluntarily undertake leakage surveys and patrols on their
facilities. Those and other operators of Types B and C gas gathering
pipelines (some of which operators may also operate either gas
transmission or Type A gathering pipelines) may also have pipelines
within their systems subject to prescriptive periodic leakage survey
and patrol requirements under Federal or State law. PHMSA's proposed
amendments would, therefore, better align leakage survey and right-of-
way patrol practices and requirements for Types B and C gas gathering
lines with requirements for other 192-regulated gas pipelines.
Additionally, PHMSA's proposed periodicities for such surveys and
patrols would also turn on factors (including location in HCAs and
occupied buildings; components/equipment; material composition;
operating and maintenance history) well-understood to be probative of
leak susceptibility--and by extension, risks to public safety and the
environment. Affected operators would also have the option to sync
their patrol and leakage survey requirements to minimize compliance
burdens (provided that the operator includes both a visual survey of
the right-of-way and a leakage survey with leak detection equipment).
And operators would have flexibility (as appropriate for their needs
and their pipelines' operational characteristics and environment) in
choosing between commercially available, advanced leakage detection
equipment satisfying the performance standards proposed in this NPRM
for use in their leakage surveys. Viewed against those considerations
and the compliance costs estimated in the Preliminary RIA, PHMSA
expects its proposed amendments will be a cost-effective approach to
achieving the commercial, public safety, and environmental benefits
discussed in this NPRM and its supporting documents. Lastly, the
proposed compliance timelines--based on an effective date of the
proposed requirements six months after the publication date of a final
rule in this proceeding (which would necessarily be in addition to the
time since issuance of this NPRM)--would provide operators ample time
to implement requisite leakage survey and patrol practices and manage
any related compliance costs.

    PHMSA solicits comment on whether it would be appropriate to apply
any of the requirements proposed herein to Type R gathering pipelines
not currently regulated under part 192. Comments on this question are
especially helpful if they address the potential safety and
environmental benefits and potential costs of that particular approach,
including whether that approach would be technically feasible, cost-
effective, and practicable.
4. Liquefied Natural Gas Facilities--Sec.  193.2624
    Part 193 does not currently require that operators perform periodic
surveys of LNG facility components and equipment for methane leakage to
the atmosphere. However, as described in section II.C.2, equipment
leaks and other fugitive methane emissions are the second largest
methane emissions source from LNG storage facilities and the largest
methane emissions source from LNG export terminals.
    PHMSA therefore proposes a new Sec.  193.2624 to require a
quarterly methane leakage survey using leak detection equipment and
remediation of any methane leaks discovered in accordance with the
operator's maintenance or abnormal operations procedures. Leaks
discovered would need to be remediated on a schedule established within
those procedures. Methane leakage surveys would only need to be
conducted on components and equipment containing methane or LNG in
normal operations. PHMSA further proposes a minimum equipment
sensitivity requirement of 5 ppm--along with validation and calibration
requirements--consistent with the proposed requirements governing the
performance of leak detection equipment described in section IV.B below
for part 192-regulated gas pipeline facilities. PHMSA expects that
these proposed enhanced methane leakage and repair requirements would
improve public safety by allowing for timely identification and
remediation of potential ignition sources within part 193-regulated LNG
facilities, as well as reduce a key source of fugitive GHG emissions
from those facilities. Additionally, eliminating product losses results
in cost savings that improve the competitiveness of LNG storage and
export facilities, further increasing the net benefits of this
proposal. PHMSA also proposes that, consistent with its proposed
revisions to part 191 leak detection and repair reporting requirements
for part 192-regulated gas pipeline facilities, PHMSA would propose
conforming revisions to its annual report form for part 193-regulated
facilities \230\ to ensure meaningful reporting of all methane leaks
detected or repaired by operators pursuant to Sec.  193.2624.
---------------------------------------------------------------------------

    \230\ PHMSA, Form 7300.1-3, ``Annual Report Form for Liquefied
Natural Gas Facilities (Oct. 2014). The instructions for Form
7300.1-3 states that ``a non-hazardous release that can be
eliminated by lubrication, adjustment, or tightening is not a
leak.'' PHMSA, Instructions for Form 7300.1-3 at 4 (Oct. 2014). That
historical understanding is inconsistent with PHMSA's understanding
of the PIPES Act of 2020 premise that all leaks of methane are
hazardous to the environment because they contribute to climate
change. PHMSA is not, however, proposing in this NPRM to modify the
historical reporting exception with respect to releases of other,
non-methane, hazardous materials within an LNG facility.
---------------------------------------------------------------------------

    PHMSA expects its proposed leakage survey practices would be
reasonable, technically feasible, cost-effective, and practicable for
affected LNG facility operators. PHMSA notes that some LNG facility
operators may operate transmission pipelines supplying natural gas to
their facilities; those operators could use their existing leakage
survey practices as a foundation for development of leakage survey
requirements tailored to their LNG facilities. PHMSA further notes
that, insofar as leakage surveys using leak detection equipment are
widely understood to be essential tools in identifying and mitigating
threats to the integrity of pipelines transporting methane within any
gas pipelines, they are among the practices that reasonably prudent
operators would adopt in ordinary course to protect public safety and
the environment from releases of methane from equipment and components
in LNG facilities and minimize loss of a commercially valuable
commodity. Additionally, operators would have flexibility in choosing
between leakage detection equipment satisfying the performance standard
proposed in this NPRM for use in those leakage surveys. Viewed against
those considerations and the compliance costs estimated in the
Preliminary RIA, PHMSA expects its proposed amendments will be a cost-
effective approach to achieving the commercial, public safety, and
environmental benefits discussed in this NPRM and its supporting
documents. Lastly, the proposed compliance timelines--based on an
effective date of the proposed requirements six months after the
publication date of a final rule in this proceeding (which would
necessarily be in addition to the time since issuance of this NPRM)--
would provide operators ample time to implement requisite changes in
their leakage survey practices and manage any related compliance costs.
    In order to avoid conflicting with existing regulatory requirements
and best practices in the National Fire Protection Association
standard, ``Standard for the Production, Storage, and Handling of
Liquefied Natural Gas (LNG)'' governing the requirements for LNG
facilities (NFPA 59A) and other standard practices, PHMSA has not
proposed in this NPRM for LNG facilities a comprehensive, advanced leak
detection and repair program framework along the lines of that
discussed below in section IV.B for part 192-regulated gas pipeline
facilities. For example, section 9.3 of the 2001 edition of NFPA
59A,\231\ which is incorporated by reference within PHMSA regulations
at Sec.  193.2801, requires continuous gas monitoring in the vicinity
of LNG process equipment, and section 12.4.2 requires an alarm at 25%
LEL or less. Additionally, certain equipment in LNG plants that are not
part of distribution systems may be subject to EPA leak detection and
repair requirements in 40 CFR part 60 depending on the purpose and
contents of the equipment. However, facilities storing or carrying
natural gas or LNG are typically subject to the standards for gas
production and transmission systems in 40 CFR part 60. The subpart OOOO
and OOOOa standards are described in greater detail in section IV.C.3
and include semiannual fugitive emissions monitoring surveys and repair
of all leaks visible with an OGI device or that produce an instrument
reading of 500 ppm or greater.\232\ For a subpart OOOOa facility, the
operator must attempt repair no later than 30 days after detecting the
fugitive emissions and must complete the repair within 30 days of the
first attempt or during the next scheduled shutdown.\233\ Finally,
detecting leaks on equipment such as at LNG plants is generally less
challenging than doing so on buried pipelines. PHMSA is pursuing a
parallel rulemaking (under RIN 2137-AF45) in which it could consider
leak monitoring, surveying, and patrolling requirements more
holistically.
---------------------------------------------------------------------------

    \231\ NFPA, NFPA-59A: Standard for the Production, Storage, and
Handling of Liquefied Natural Gas (LNG)--2001 Edition (2001).
    \232\ 40 CFR 60.5397a(a)(1) and (h).
    \233\ 40 CFR 60.5397(h).
---------------------------------------------------------------------------

B. Advanced Leak Detection Programs--Sec.  192.763

    Section 113 of the PIPES Act of 2020 requires PHMSA to issue
performance standards for operator leak detection and repair programs
reflecting the capabilities of commercially available, advanced leak
detection technologies

and practices. To satisfy this mandate, PHMSA proposes to introduce a
new Sec.  192.763 to require operators establish written Advanced Leak
Detection Programs (ALDPs) and to establish performance standards for
both the sensitivity of leak detection equipment and for the
effectiveness of those ALDPs. This new requirement would provide
benefits to both public safety and the environment by ensuring that
pipeline operators have programs in place to promptly detect and repair
leaks of all gas pipelines subject to part 192, thereby reducing harm
to public safety and the environment.
    An ALDP represents a complementary set of mutually reinforcing
technologies and procedures (including analytics) that the operator
uses to detect all leaks. PHMSA proposes to require that an operator's
written ALDP include four main elements: leak detection equipment
employing commercially available advanced technology, leak detection
procedures, prescribed leakage survey frequencies, and program
evaluation. Note that grading and repairing leaks after investigation
is governed by the proposed Sec.  192.760 described in section IV.C of
this NPRM. The proposed requirements in this section would apply to
operators of all gas distribution lines, gas transmission lines,
offshore gathering, and Types A, B, and C regulated onshore gathering
pipelines.
    PHMSA expects each of the proposed ALDP requirements discussed
below would be reasonable, technically feasible, cost-effective, and
practicable for all affected gas pipeline operators. PHMSA understands
that most operators of gas pipelines that would be subject to those
requirements may already employ one or more of its proposed ALDP
elements voluntarily because (inter alia) a reasonably prudent operator
would in ordinary course employ a systematic, defense-in-depth approach
to identifying leaks given the commercial value of, and potential risks
to public safety and the environment posed by, the commodities
transported (natural gas or flammable, toxic, or corrosive pressurized
gases). Alternatively, an operator may employ one of more of PHMSA's
proposed ALDP elements as a compliance strategy for existing PHMSA or
State leak detection or integrity management requirements. Regardless,
PHMSA's proposals build and on those existing practice by creating a
common, straightforward regulatory framework for addressing leak
detection across all part 192-regulated gas pipelines. Within that
common framework, moreover, operators would retain significant
flexibility to select (as appropriate for a pipeline's operational
needs and operating environment) a suite of mutually reinforcing leak
detection equipment, analytics, and practices, satisfying a baseline
leak detection performance standard derived from commercially available
advanced leak detection technology in a way that minimizes their
compliance costs. PHMSA's proposal even contemplates that some
operators of gas pipelines may employ (subject to PHMSA review) an
alternative performance standard as a function of location or gas
commodity being transported. Viewed against those considerations and
the compliance costs estimated in the Preliminary RIA, PHMSA expects
its proposed amendments will be a cost-effective approach to achieving
the commercial, public safety, and environmental benefits discussed in
this NPRM and its supporting documents. Lastly, the proposed compliance
timelines--based on an effective date of the proposed requirements six
months after the publication date of a final rule in this proceeding
(which would necessarily be in addition to the time since issuance of
this NPRM)--would provide operators ample time to implement requisite
protocols, obtain leak detection equipment, and manage any related
compliance costs.
1. Leak Detection Technology Standards--Sec.  192.763(a)(1)
    The first element in an ALDP is the leak detection technology that
the operator would use to perform leakage surveys, investigate leaks,
and pinpoint leak locations. These technology requirements are proposed
in Sec.  192.763(a)(1). Each operator's ALDP would include a list of
leak detection equipment that the operator uses for leakage surveys,
leak investigations, and pinpointing leaks. Consistent with the mandate
in section 113 of the PIPES Act of 2020, PHMSA proposes to specify when
leak detection equipment would be required and when an operator may
rely on methods that rely on human or animal senses. Specifically, the
NPRM proposes to amend Sec.  192.723 to require that all leakage
surveys on gas distribution pipelines be performed with leak detection
equipment in light of the high risk to public safety from distribution
pipelines, which are often located in the vicinity of population
centers. Additionally, as described in section IV.A.2 of this NPRM, all
leakage surveys on onshore gas transmission and gathering pipelines
performed under Sec.  192.706 would require the use of leak detection
equipment, except when the operator of a gas transmission or gathering
pipeline in a Class 1 or Class 2 location determines that a survey
using human senses would be sufficient, subject to review by PHMSA, as
provided in Sec.  192.706(a)(1). This default requirement that ALDPs of
onshore regulated gas gathering, transmission, and distribution
operators use leak detection equipment in leakage surveys would enhance
operators' ability to identify and repair leaks on pipelines in a
timely manner, and therefore minimize releases and prevent leaks from
degrading. It would also serve to improve leak detection data to
improve the predictive power of leak management programs, integrity
management programs, and artificial intelligence services that can
identify systemic pipeline design or repair issues.
    PHMSA further proposes that any leak detection equipment used must
have a minimum sensitivity of 5 ppm or less. A reading of 1% of the
lower-explosive limit of methane gas at atmosphere is approximately 500
ppm; a minimum sensitivity of 5 ppm would therefore provide a
protective threshold of detection sensitivity. That threshold is also
consistent with the performance of commercially available leak
detection equipment. Table 2 of the Appendix G-192-11 of the GPTC Guide
provides examples of commercially available methane detection
technologies and the sensitivity and detection ranges for those
technologies. That information is reproduced in the table below. In
addition to the devices listed below, OGI cameras, devices that are
capable of visualizing methane gas leaks and other fugitive emissions,
are commonly used for fugitive emissions monitoring at LNG plants,
compressor stations, and other facilities.

           Methane Leak Detection Technologies and Performance
------------------------------------------------------------------------
           Technology                 Sensitivity            Range
------------------------------------------------------------------------
Semiconductor...................  1-100 ppm.........  0-100 ppm.
Flame Ionization................  1 ppm.............  0-10,000 ppm.

Open Path Infrared (IR) Tunable   5 ppm-meter.......  0-100,000 ppm-
 diode laser absorption                                meter.
 spectroscopy.
Closed Path Bifringent IR.......  1 ppm.............  0-2,500 ppm.
Closed Path IR Laser............  0.03-100 ppm......  0-1000 ppm.
------------------------------------------------------------------------

    Although each of the technologies listed above has advantages and
limitations that may make it more or less appropriate for leakage
surveys on particular gas pipelines or operating conditions, PHMSA's
proposed 5 ppm performance standard balances each of the following: a
methane sensitivity threshold consistent with the performance of state-
of-the-art, commercially-available technologies; robust margin to risk
of ignition; and flexibility for operators to choose from a baseline of
high-quality equipment for their unique needs. For example, PHMSA
understands that modern FID units and closed-path IR and laser-based
systems are capable of sub-ppm and parts-per-billion detection.
However, quality semiconductor sensors and open-path IR devices have
important applications despite comparatively lower-sensitivity.
Semiconductor sensors are typically much smaller than other detection
devices and therefore are useful in confined spaces and other
situations where a smaller tool is necessary to access the space.
Additionally, semiconductor sensors are often designed to incorporate
intrinsically safe features, which minimizes the risk of ignition in
situations where a flammable atmosphere may be present. Similarly, some
handheld open-path IR systems can have a sensitivity of 5 ppm-meter at
its maximum effective range \234\ but have the advantage of allowing a
surveyor to detect methane plumes from a distance. This allows operator
leakage surveyors to safely and efficiently survey facilities that may
otherwise be difficult or unsafe to access. However, the proposed leak
detection performance standard would generally exclude each of odorant
``sniffers'' used to test the adequacy of odorization, less-sensitive
combustible gas indicators, and most gas monitors intended for confined
space gas monitoring rather than methane leak detection--even as PHMSA
acknowledges such devices may nevertheless be useful in connection with
leak grading (pursuant to proposed Sec.  192.760), as tools
supplementing ALDP-compliant leak detection equipment, or as authorized
pursuant to proposed Sec.  192.763(c).
---------------------------------------------------------------------------

    \234\ PPM-meter is a ``path integrated'' summation of measured
gas concentration used for open-path devices that sums gas
concentration per meter measured up to the effective range in front
of the device. Sensitivity may be higher at closer ranges depending
on the specific technology used.
---------------------------------------------------------------------------

    As discussed throughout this section, other ALDP programmatic
requirements backstop any limitations on the ability of particular leak
detection technologies to contribute to the program-wide performance
standard at Sec.  192.763(b) that an ALDP detects all leaks of 5 ppm or
more when measured 5 feet from the pipeline. For example, PHMSA
acknowledges that an operator may determine, based on its operational
needs or the operating environment of a particular pipeline, that leak
detection equipment more sensitive than 5 ppm is necessary to meet the
ALDP programmatic performance standard at Sec.  192.763(b). For
example, an operator may determine that an efficient means of meeting
the ALDP performance standard at Sec.  192.763(b) would be to perform
leakage surveys by first using very sensitive (in the sub-ppm or low
ppb range) vehicle or aircraft mounted sensors, followed thereafter by
spot-checks using handheld devices with the minimum sensitivity of 5
ppm proposed at Sec.  192.763(a)(1)(ii). Similarly, an operator may
supplement any leak detection equipment meeting the minimum sensitivity
requirements proposed at Sec.  192.763(a)(1)(ii) with other techniques
for pinpointing leak location (e.g., soap bubble testing) or
technologies (e.g., devices for measuring release rate for
differentiating between leak grades) for grading identified leaks
pursuant to PHMSA's proposed Sec.  192.760.
    PHMSA further notes that operators would be able to, pursuant to
the proposed Sec.  192.763(c), seek PHMSA review of use of an
alternative ALDP performance standard that may entail the use of
alternative (including less sensitive) leak detection technology than
that proposed under Sec.  192.763(a)(1). This process is available for
each of natural gas pipelines (other than distribution pipelines) in
Class 1 and 2 locations, and any part 192-regulated pipeline facility
transporting flammable, toxic, or corrosive gas other than natural
gas.\235\ PHMSA acknowledges the fast-evolving state-of-the-art in leak
detection technologies for methane and other gases and seeks comments
on whether and in what manner it could integrate within a final rule
requirements for technologies that may not have specified
sensitivities, including continuous pressure wave monitoring, fiber
optic sensing, OGI, and LIDAR based detection technologies, along with
the potential safety and environmental benefits and potential costs of
a particular approach (including whether that approach would be
technically feasible, cost-effective, and practicable). PHMSA expects
that it would consider the use of such technologies under the Sec.
192.763(c) process or as supplement to other equipment satisfying the
minimum sensitivity performance requirements proposed herein.
---------------------------------------------------------------------------

    \235\ Although PHMSA's proposed 5 ppm default performance
standard for all part 192-regulated gas pipelines is based
principally on commercially available, advanced methane leak
detection technology for use with natural gas pipelines, PHMSA
understands that commercially available, advanced leak detection
technology for use with other part 192-regulated gas pipeline
facilities may (when considered either separately or within a suite
of mutually-reinforcing technologies) offer comparable leak
detection ability. Further, as explained in the paragraph above, the
NPRM contemplates operators of gas pipeline facilities transporting
gases other than natural gas (e.g., hydrogen) may request the use of
an alternative leak detection performance standard and supporting
leak detection equipment.
---------------------------------------------------------------------------

    Apart from minimum sensitivity requirements described above, PHMSA
does not propose to require the use of any particular leak detection
equipment or technology for every operator or for each type of
pipeline. While the PIPES Act of 2020 directs PHMSA to require the use
of advanced leak detection technologies and practices, Congress defined
this requirement in terms of a performance standard for leak detection
and repair programs and described several possible approaches in the
statute. PHMSA therefore does not propose to narrowly define advanced
leak detection in terms of a particular technology, process,
manufacturer, or equipment. One type of technology may not always be
appropriate for every flammable, corrosive, or toxic gas, each type of
pipeline facility or even across

the range of operational/environmental conditions (e.g., seasonal
temperature, humidity, or precipitation patterns) within which a
particular pipeline operates. Rather than a technology standard, PHMSA
expects each of the periodic evaluation and improvement element of each
ALDP (proposed in Sec.  192.763(a)(4)), and the ALDP performance
requirement (proposed in Sec.  192.763(b), described later in this
section), would encourage operators to continually evaluate and
incorporate within their ALDPs such newly commercialized technologies
as appropriate for their systems over time. This flexible approach
would ensure that operators' leakage detection equipment keeps pace
with the state-of-the-art in leak detection technology. Additionally,
this NPRM proposes to require operators to select their leak detection
equipment based on a documented analysis that considers, at a minimum,
the gas being transported, the size, configuration, operating
parameters, and operating environment of the operator's system. An
operator would be required to choose leak detection technologies that
are best able to detect, investigate, and locate all leaks considering
these factors. For example, an advanced mobile leak detection system
could be an effective tool for detecting methane leaks in a suburban
distribution system but may not be optimal for surveying service lines
in an area with long setbacks or a transmission pipeline with poor road
access. PHMSA also proposes to require operators to analyze, at a
minimum, the appropriateness of the following examples of possible
advanced leak detection technologies and methods, some of which were
referenced in the PIPES Act of 2020: leakage surveys with optical,
infrared, or laser-based hand-held devices; continuous monitoring via
stationary gas sensors, pressure monitoring, or other means; mobile
surveys from vehicle, satellite, or aerial platforms; and systemic use
of other technologies capable of detecting and locating leaks
consistent with the proposed ALDP performance standard at Sec.
192.763. Operators would be required to maintain records of this
analysis for five years. Stationary gas detection systems are already
required on compressor stations under PHMSA's existing regulations at
Sec.  192.736. Likewise, section 16.4 of the 2001 edition of NFPA
59A,\236\ which is incorporated by reference into the federal safety
standards for LNG facilities in part 193, requires monitoring of
enclosed buildings and other areas that can have the presence of LNG or
other hazardous fluid (including natural gas), and specifies flammable
gas alarm settings in section 16.4.2. PHMSA invites comments on the
value of introducing requirements for continuous monitoring systems,
via stationary gas detection systems, pressure monitoring, or other
means (including requirements for the use of specific methods or
technologies), on other types of pipeline facilities (including whether
continuous monitoring would be most appropriate at any particular
facilities or locations, or in other particular conditions) within a
final rule in this rulemaking proceeding.\237\ Comments are especially
helpful to PHMSA when they are supported by research or operational
experience, along with the potential safety and environmental benefits
and potential costs of a particular approach (including whether that
approach would be technically feasible, cost-effective, and
practicable).
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    \236\ NFPA, NFPA-59A: Standard for the Production, Storage, and
Handling of Liquefied Natural Gas (LNG)--2001 Edition (2001).
    \237\ To the extent that a comment proposes to require
installation of such technologies on a pipeline, PHMSA also solicits
comment on the potential application of PHMSA's statutory
prohibition on retroactive design and installation standards. See 49
U.S.C. 60104(b).
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2. Leak Detection Practices--Sec.  192.763(a)(2)
    The second program element in proposed Sec.  192.763(a)(2) consists
of the operator's procedures related to leak detection, investigation,
and location. Generally, this would involve supplementing or revising
existing procedures in the operator's manual of procedures. At a
minimum, the ALDP would include procedures for performing leakage
surveys as well as subsequent investigation and location of identified
leaks; operator procedures would provide instruction on whether and how
each type of leak detection equipment included in the ALDP would be
used in performing those tasks. To ensure that operators use procedures
appropriate for environmental conditions such as temperature, wind,
time of day, precipitation and humidity, the operator must define under
which conditions the procedure may and may not be used. Additionally,
the procedures must be consistent with any instructions and allowable
operating and environmental parameters issued by the leak detection
equipment manufacturer to ensure equipment effectiveness. For example,
some devices or systems may be unsuitable for use in certain weather or
atmospheric conditions, or at certain times of day, or in certain
temperatures. As noted in the discussion of leak detection practices in
section II.F, establishing and following procedures with parameters
appropriate for the leak detection technologies and practices is
critical for reliably detecting leaks, especially in challenging
conditions. This requirement also addresses the findings from the
NTSB's investigation of a 2018 gas explosion involving failed leakage
surveys (discussed in section II.H of this NPRM.) due to the operator's
improper use of leak detection equipment.\238\
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    \238\ National Transportation Safety Board. ``Pipeline Accident
Report: Atmos Energy Corporation Natural Gas-Fueled Explosion:
Dallas, Texas: February 23, 2018.'' NTSB/PAR-21/01. Jan. 12, 2021.
Washington, DC https://www.ntsb.gov/investigations/AccidentReports/Reports/PAR2101.pdf.
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    PHMSA proposes to require that an operator's ALDP procedures
include investigating and pinpointing the location of all leak
indications. For onshore pipelines and offshore pipeline facilities
above the waterline, PHMSA proposes in Sec.  192.763(a)(2) to require
that pinpointing location be performed using handheld leak detection
equipment with a minimum sensitivity of 5 ppm. This proposed
requirement would complement PHMSA's proposed ALDP programmatic
performance standard in Sec.  192.763(b). If leak location is
pinpointed with handheld leak detection equipment during an initial
leakage survey, the initial survey would satisfy this requirement.
PHMSA proposes that pinpointing leak location on submerged offshore
pipelines (including riser piping up to the waterline) would not
require the use of leak detection equipment because submerged pipeline
leaks are visibly conspicuous.
    To ensure the effectiveness of leak detection equipment, PHMSA
proposes to require at Sec.  192.763(a)(2)(iii) that an operator have
procedures for validating that a leak detection device meets the 5-ppm
minimum sensitivity requirement in Sec.  192.763(a)(1)(ii)prior to
initial use. This would consist of testing the equipment measurements
against a known concentration of gas. Operators would have to maintain
records that their leak detection equipment has been validated for five
years after the date each device ceases to be used in the operator's
ALDP. This is a one-time validation separate from the periodic
calibration required under proposed Sec.  192.763(a)(2)(iv) described
below. PHMSA also proposes to require that operators have procedures
for the maintenance and calibration of leak detection equipment--
including at least

any maintenance and calibration procedures recommended by the equipment
manufacturer--to ensure that equipment is functioning as intended
throughout its service life. Finally, PHMSA proposes to require that
operators recalibrate leak detection equipment following an indication
of malfunction.
3. Leakage Survey Frequency--Sec.  192.763(a)(3)
    The third element that PHMSA proposes to require of an ALDP is the
frequency of leakage surveys, which is specified in proposed Sec.
192.763(a)(3). Minimum leakage survey frequencies are defined in Sec.
192.723 for gas distribution pipelines and in Sec.  192.706 for gas
transmission, offshore gathering, and Types A, B, and C gathering
pipelines. As noted in section IV.A, less sensitive survey equipment
may require more frequent surveys in order to provide an equivalent
degree of leak or emissions detection.\239\ If more frequent leakage
surveys are necessary to reliably meet the ALDP programmatic
performance standard in proposed Sec.  192.763(b), or as otherwise
specified by the operator, that must be noted in the operator's ALDP.
For example, more frequent leakage surveys may be appropriate for less
sensitive leak detection equipment authorized for use pursuant to
proposed Sec.  192.763(c), challenging survey conditions, or facilities
known to leak based on their material, design, or past operating and
maintenance history. As noted above in section IV.B.1, PHMSA invites
comments on the value of requiring continuous monitoring systems on
these types of facilities or any other pipeline facilities (for
potential inclusion within a final rule in this proceeding). Comments
are especially helpful to PHMSA when they are supported by research or
operational experience, along with the potential safety and
environmental benefits and potential costs of a particular approach
(including whether that approach would be technically feasible, cost-
effective, and practicable).
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    \239\ Ravikumar, Arvind Ph.D. ``FEAST-Based Evaluation of
Methane Leak Detection and Repair Programs Using New Technologies.''
EPA Methane Detection Technology Workshop (August 24, 2021). https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-methane-detection-technology-workshop. Day 2 at 1:33:50.
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4. Program Evaluation and Improvement--Sec.  192.763(a)(4)
    The fourth and final element of an ALDP in Sec.  192.763(a)(4) is
program evaluation and improvement. At least annually, operators would
have to re-evaluate the elements of their ALDPs considering, at a
minimum, the performance of the leak detection equipment used, the
adequacy of their leakage survey procedures, advances in leak detection
technologies and practices, the number of leaks initially detected by
third parties, the number of leaks and incidents on the pipeline, and
estimated emissions from detected leaks. This proposal is similar in
principle to the existing continuous improvement requirements under IM
requirements in part 192, subparts O and P, as well as requirements for
certain operators to periodically review procedures under Sec.
192.605(b)(8) and (c)(4). PHMSA expects this proposal would ensure
operators periodically evaluate ways to improve their leak detection
programs based on leak detection performance data and advances in
technology. For example, if an operator finds evidence that their ALDP
fails to detect leaks during leakage surveys, or that it is finding
grade 1 or 2 leaks but does not find any grade 3 leaks, changes to
program elements may be necessary to ensure that the minimum
performance standard in Sec.  192.763(b) described below is met. This
provision would offer potential environmental benefits and could also
result in cost-savings to operators and shippers, by helping further
reduce product losses from pipeline facilities.
5. Advanced Leak Detection Performance Standard--Sec.  192.763(b)
    The ultimate benchmark for the effectiveness of an operator's ALDP
would be a holistic, program-wide performance standard at Sec.
192.763(b). Specifically, PHMSA proposes to require that an ALDP must
be capable of detecting all leaks that produce a reading of 5 ppm or
greater of gas when measured from a distance of 5 feet from the
pipeline, or within a wall-to-wall paved area. As described in the
discussion of leak detection equipment above, the proposed 5 PPM
standard represents a protective, detection threshold achievable using
mainstream, commercially available, advanced leak detection equipment.
The Sec.  192.763(b) ALDP performance standard is consistent with that
minimum sensitivity for leak detection equipment, but it focuses on the
characteristics of the leak (in particular, whether the leak rate or
operating environment results in a reading of 5 ppm) rather than on the
sensitivity of the leak detection equipment employed by an operator.
For example, a walking survey conducted alongside a pipeline with
thorough, careful, procedures to ensure detection of all leaks could
achieve this standard with an FID or other handheld device with the 5
ppm sensitivity required by Sec.  192.763(a). But mobile leak detection
systems and aerial systems that use gas samplers or other sensors to
detect leaks at a greater distance may allow for more efficient leakage
surveying, but could require more sensitive (sensors in the ppb range)
leak detection equipment coupled with advanced analytics (followed by
the use of handheld leak detection equipment to pinpoint leak location)
to detect and locate the same leak. Similarly, leakage surveys
employing human or animal senses would have to employ leak detection
equipment to investigate and pinpoint the location of any leaks
detected during those non-instrumented surveys.
    Some stakeholders attending the 2021 Public Meeting commented that
leak flow rate would be a more appropriate metric for leak detection
and ALDP program performance than PHMSA's proposed volumetric
sensitivity metric.\240\ However, as discussed above in section II.D.4,
most currently available methane leak detection technologies are
focused on calculating the concentration of gas in the air rather than
leak flow rate. Moreover, PHMSA's choice of leak concentration-based
performance standard for leak detection equipment was informed by the
goal of (as much as possible) identifying a single performance standard
that would be well-suited for leak detection on both aboveground and
buried natural gas pipelines. Additionally, consistent with the GPTC
Guide grading criteria and as acknowledged in the comments of AGA et
al. to the 2021 Public Meeting, a concentration-based metric is
especially useful for addressing explosion risks to public safety
(regardless of a leak's flow rate). To the extent that operators find
that leak rate measurements are helpful for identifying or grading
leaks or in calculating estimated emissions consistent with changes to
part 191 reporting requirements discussed elsewhere in this NPRM,
operators may incorporate leak flow rate metrics within their ALDPs to
supplement leak concentration metrics used in PHMSA's proposed leak
detection and ALDP performance standard. In particular, leak rate
measurements may help operators quickly grade certain leaks as grade 2
leaks based on a leak rate in excess of 10 CFH. Based on available

information, PHMSA's current assessment is that the proposed Sec.
192.763(b) ALDP performance standard represents a threshold of
detection demanding enough to ensure that operator ALDPs are capable of
detecting nearly all leaks on gas gathering, transmission, and
distribution pipelines. That said, PHMSA invites comment on whether and
how an alternative ALDP performance standard--such as a more demanding
volumetric standard, or a flowrate-based standard--should be adopted in
the final rule. Proposed alternatives are most helpful when they are
supported by a discussion of their value for public safety and
environmental protection, as well as their technical feasibility, cost-
effectiveness, and practicability.